EDGAR 10-K Filing

Company CIK: 874499
Filing Year: 2025
Filename: 874499_10-K_2025_0001628280-25-008043.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS
Our Business
Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal properties are located in eastern Ohio targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and Springer formations. Gulfport's Predecessor was incorporated in the State of Delaware in July 1997. Our corporate headquarters are located in Oklahoma City, Oklahoma and shares of Gulfport's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol “GPOR”. Our corporate strategy is focused on the economic development of our asset base in an effort to generate sustainable free cash flow.
As of December 31, 2024, we had 4.0 Tcfe of proved reserves with a Standardized Measure of $1.75 billion and a PV-10 of $1.76 billion. See “Definitions” above for our definition of PV-10 (a non-GAAP financial measure) and “Oil, Natural Gas and NGL Reserves and Estimation” below for a reconciliation of our standardized measure of discounted future net cash flows (the most directly comparable GAAP measure) to PV-10.
Information About Us
Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of our recent news releases. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.
Emergence From Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
On November 13, 2020, we, and certain of our subsidiaries, filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases were administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ). The Bankruptcy Court confirmed the Plan and entered the confirmation order on April 28, 2021, and the Debtors emerged from the Chapter 11 Cases on the Emergence Date. On May 18, 2021, we began trading on the NYSE under the symbol “GPOR”.
Business Strategy
Gulfport aims to create sustainable value through the economic development of our significant resource plays in the Utica/Marcellus and SCOOP operating areas. Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, improving margins and operating efficiencies and returning capital to shareholders. To accomplish these goals, we generally allocate capital to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts. We believe our plan to generate free cash flow on an annual basis will allow us to further strengthen our balance sheet, return capital to shareholders and increase our resource depth through incremental leasehold opportunities that provide optionality to our future development plans.
2025 Outlook
Our 2025 capital expenditure program is expected to be in a range of $370 million to $395 million. In the Utica, we intend to complete drilling on approximately 17 gross (17.0 net) operated horizontal wells and commence sales on approximately 22 gross (21.9 net) operated horizontal wells. In the Marcellus, we intend to complete drilling on approximately 8 gross (8.0 net) operated horizontal wells and commence sales on approximately 4 gross (4.0 net) operated horizontal wells. In the SCOOP, we intend to complete drilling on approximately two gross (1.8 net) operated horizontal wells and commence sales on two gross (1.8 net) operated horizontal wells. We expect to fund these expenditures with our operating cash flow and borrowings under our Credit Facility.
We expect this drilling program to result in approximately 1,040 to 1,065 MMcfe per day of production in 2025.
Additionally, in 2025, we expect a continuation of shareholder return actions through our Repurchase Program. During 2024, we repurchased 1.2 million shares for $184.5 million at a weighted average price of $153.35 per share, leaving $415.9 million remaining on our Repurchase Program, which expires on December 31, 2025.
Operating Areas
Utica/Marcellus - The Utica covers hydrocarbon-bearing rock formations located in the Appalachian Basin of the United States and Canada. We have approximately 208,000 net reservoir acres located primarily in Belmont, Harrison, Jefferson and Monroe Counties in eastern Ohio where the Utica ranges in thickness from 600 to over 750 feet.
The Marcellus covers hydrocarbon-bearing rock formations that overlay the Utica. We have identified approximately 20,500 net reservoir acres of our existing leasehold for Marcellus development and have 22 PUD Marcellus locations within our Utica operating area. In 2023 we drilled, completed, and turned to sales two Marcellus wells and have plans to drill eight Marcellus wells and complete and turn to sales four Marcellus wells in 2025. Our Marcellus development area is approximately 3,500 to 4,500 feet shallower than the Utica. During 2024, we produced approximately 842 MMcfe per day net to our interests in Utica/Marcellus and it accounted for approximately 80% of our total production.
SCOOP - The SCOOP is a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko Basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations. We have approximately 73,000 net reservoir acres (comprised of approximately 43,000 in the Woodford formation and approximately 30,000 in the Springer formation) located primarily in Garvin, Grady and Stephens Counties. The Woodford Shale across our position ranges in thickness from 200 to over 400 feet and directly overlies the Hunton Limestone and underlies the Sycamore formation, both of which are also locally productive reservoirs. The Sycamore formation consists of hydrocarbon-bearing interbedded shales and siliceous limestones ranging in thickness from 150 to over 450 feet and is overlain by the Caney Shale. The Springer formation across our position is comprised of a series of lenticular sand and shale units. The primary targets are a series of porous, low clay and organic-rich packages within the Goddard Shale member ranging in thickness from 50 to over 250 feet. During 2024, we produced approximately 212 MMcfe per day net to our interests in the SCOOP and it accounted for approximately 20% of our total production.
Oil, Natural Gas and NGL Reserves and Estimation
Reserve engineering is a subjective process of estimating volumes of economically recoverable oil, natural gas and NGL that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the reserve estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A. “Risk Factors” contained elsewhere in this Form 10-K.
As discussed above, the process of estimating oil, natural gas and NGL reserves is complex and requires significant judgment. As a result, we have developed internal policies and controls for estimating and recording reserves. Estimates of proved developed and undeveloped reserves and related information are presented in accordance with the requirements of the SEC's rules for the Modernization of Oil and Gas Reporting. These rules permit the use of reliable technologies to estimate and categorize reserves and require the use of the unweighted average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for the prior 12 months (unless contractual arrangements designate the price) to calculate economic producibility of reserves and the discounted cash flows reported as the Standardized Measure of Future Net Cash Flows Relating to Proved Reserves. Reliable technologies were used to support the undeveloped locations in the Utica/Marcellus and SCOOP operating areas. The Company used public and proprietary geologic and engineering data to establish continuity of the formation and its producing properties. This data included performance data, seismic data, open hole log information, petro-physical analysis of log data, mud logs, log cross-sections, gas sample analysis, statistical analysis and measurements of total organic content and thermal maturity. In our development area, these data demonstrated consistent and continuous reservoir characteristics. Refer to Note 20 of our consolidated financial statements for more information pertaining to our proved reserves and the preparation of such estimates.
Our Senior Vice President of Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum engineer with over 28 years of reservoir and operations experience. In addition, our geoscience staff has approximately 51 years combined industry experience and our reservoir staff has approximately 61 years combined experience.
During 2024, our total net natural gas, NGLs and oil proved reserves estimates attributable to the Company's interests were prepared by our engineers and Netherland, Sewell & Associates, Inc. (“NSAI”) conducted an audit of the proved reserves as of December 31, 2024. NSAI is an independent petroleum engineering firm and were selected for their historical experience and geographic expertise in engineering similar resources. In the course of its audit, NSAI conducted a detailed review of properties making up approximately 85% of the total proved reserves and accounting for approximately 95% of the present worth of those reserves. The estimates prepared by the Company and audited by NSAI were within the recommended 10% tolerance threshold set forth in the Standards Pertaining to the Estimation and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers A copy of the summary reserve report is included as Exhibit 99.1 to this Annual Report on Form 10-K. Our internal staff of petroleum engineers and geoscience professionals work closely with NSAI to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. As needed, we provide historical information to NSAI for our properties such as ownership interest, oil and gas production, well test data, commodity prices, operating and development costs and other considerations, including availability and costs of infrastructure and status of permits. Reserve estimates for the years ended 2023 and 2022, were prepared by NSAI for 100% of our operating areas.
Internal Controls Over Proved Reserve Estimates
Our proved reserve estimates are prepared in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
•review and verification of historical production, operating, marketing and capital data, which data is based on actual production as reported by us;
•verification of property ownership by our land department;
•audit of year-end reserve estimates by NSAI;
•direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer;
•review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;
•provision of quarterly updates to our Board of Directors regarding operational data, including production, drilling and completion activity levels and any significant changes in our reserves;
•annual review by our Board of Directors of our year-end reserve report and year-over-year changes in our proved reserves;
•annual review by our senior management of adjustments to our previously adopted development plan and considerations involved in making such adjustments, including the substitution, removal or deferral of PUD locations; and
•annual review and approval by our senior management and our Board of Directors of a multi-year development plan.
The tables below set forth information as of December 31, 2024, with respect to our estimated proved developed and undeveloped oil, natural gas and NGL reserves, the associated estimated future net revenue, the PV-10 and the standardized measure. None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated oil, natural gas and NGL reserves we own. All of our estimated reserves are located within the United States.
December 31, 2024
Oil
(MMBbl) Natural Gas
(Bcf) NGL
(MMBbl) Total
(Bcfe)
Utica & Marcellus
Proved developed(1)
4 1,427 8 1,498
Proved undeveloped(1)
13 1,189 36 1,480
Total proved(1)
17 2,616 44 2,978
SCOOP
Proved developed 4 451 23 611
Proved undeveloped 2 289 13 380
Total proved 5 740 36 991
Total
Proved developed 7 1,879 31 2,109
Proved undeveloped 15 1,478 49 1,861
Total proved 22 3,356 80 3,969
Totals may not sum or recalculate due to rounding.
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(1) Includes approximately 12 Bcfe and 174 Bcfe of net developed and undeveloped reserves, respectively, located in the Marcellus target formation.
December 31, 2024
Proved Developed Proved Undeveloped Total Proved
($ in millions)
Estimated future net revenue(1)
$ 1,620 $ 1,876 $ 3,496
Present value of estimated future net revenue (PV-10)(1)
$ 1,059 $ 699 $ 1,757
Standardized measure(1)
$ 1,747
Totals may not sum due to rounding.
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(1) 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, 2024, 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, 2024. The prices used in our PV-10 measure were the average WTI Spot price of $76.32 per barrel and the average Henry Hub Spot price of $2.13 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, 2024. 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 $10 million as of December 31, 2024.
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.
The following table summarizes the changes in our estimated proved reserves during 2024 (in Bcfe):
Proved Reserves, December 31, 2023 4,214
Sales of oil and natural gas reserves in place -
Extensions and discoveries 547
Revisions of prior reserve estimates (406)
Current production (386)
Proved Reserves, December 31, 2024 3,969
Total may not sum due to rounding.
Extensions and discoveries. These are additions to our proved reserves that result from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery. Extensions of approximately 547 Bcfe of proved reserves were primarily attributable to the continued development of our Utica/Marcellus and SCOOP acreage. We added 46 PUD locations in the Utica/Marcellus which included 33 Utica locations for 341 Bcfe and 13 Marcellus locations for 92 Bcfe. In the SCOOP, we added 16 PUD locations for 114 Bcfe.
Revisions of prior reserve estimates. Revisions represent changes in previous reserve estimates, either upward or downward, resulting from development plan changes, new information normally obtained from development drilling and production history or a change in economic factors, such as commodity prices, operating costs or development costs.
We experienced total downward revisions of 406 Bcfe in estimated proved reserves. These consisted of upward revisions of 16 Bcfe as a result of positive well performance and 171 Bcfe due to an increase in working interest and net revenue interest as a result of our successful leasing efforts through 2024. These were offset by downward revisions of 488 Bcfe which were associated with commodity price changes. Commodity prices experienced volatility throughout 2024 and the 12-month average price for natural gas decreased from $2.64 per MMBtu for 2023 to $2.13 per MMBtu for 2024, the 12-month average price for NGL decreased from $31.42 per barrel for 2023 to $31.30 per barrel for 2024, and the 12-month average price for crude oil decreased from $78.21 per barrel for 2023 to $76.32 per barrel for 2024. Additionally, downward revisions of 172 Bcfe were primarily a result of development schedule changes with some PUD well design changes. The schedule changes moved the development of 11 Utica/Marcellus PUD locations and 6 SCOOP PUD locations beyond the SEC requirement of developing these wells five years from initial booking. The development schedule changes reflect our ongoing commitment to optimizing the long-term plan to best develop our asset and maximize cash flow and overall economic returns. These locations excluded from our SEC reserves report remain in Gulfport's development plan. Finally, upward revisions of 67 Bcfe were a result of a combination of various economic assumption updates.
Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2024, 2023 and 2022, and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information, in Note 20 of our consolidated financial statements.
Proved Undeveloped Reserves
As of December 31, 2024, our PUDs totaled 1,478 Bcf of natural gas, 15 MMBbl of oil and 49 MMBbl of NGL, for a total of 1,861 Bcfe. Approximately 80% and 20% of our PUD reserves at year-end 2024 were located in Utica/Marcellus and SCOOP, respectively. Our PUDs will be converted from undeveloped to developed as the applicable wells commence production or when there are no material incremental completion capital expenditures associated with such proved developed reserves.
We record PUD locations only after a development plan has been approved by our senior management and Board of Directors to complete the associated development drilling within five years from the time of initial booking. The PUD locations identified in our development plan are determined based on an analysis of the information that we have available at that time. After a development plan has been adopted, we may periodically make adjustments to the approved development plan due to events and circumstances that have occurred subsequent to the time the plan was approved. These circumstances may include changes in commodity price outlook and costs, delays in the availability of infrastructure, well permitting delays and new data from recently completed wells.
The following table summarizes the changes in our estimated proved undeveloped reserves during 2024 (in Bcfe):
Proved Undeveloped Reserves, December 31, 2023 2,011
Sales of oil and natural gas reserves in place -
Extensions and discoveries 547
Conversion to proved developed reserves (341)
Revisions of prior reserve estimates (357)
Proved Undeveloped Reserves, December 31, 2024 1,861
Total may not sum due to rounding.
Extensions and discoveries. Our extensions of approximately 547 Bcfe were primarily attributed to the addition of 62 PUD locations as a result of our current five-year development plan that is focused on generating sustainable cash flow. These additions included 46 PUD locations in the Utica/Marcellus and 16 PUD locations in the SCOOP.
Conversion to proved developed reserves. Our 2024 development activities resulted in the conversion of approximately 341 Bcfe into proved developed producing reserves, attributable to 16 PUD locations in the Utica and 5 PUD locations in the SCOOP. These 21 PUDs represent a conversion rate of 13% for 2024.
Revision of prior reserve estimates. We experienced total downward revisions of 357 Bcfe in estimated proved undeveloped reserves. This included 300 Bcfe of downward revisions associated with commodity price changes. Commodity prices experienced volatility throughout 2024 and the 12-month average price for natural gas decreased from $2.64 per MMBtu for 2023 to $2.13 per MMBtu for 2024, the 12-month average price for NGL decreased from $31.42 per barrel for 2023 to $31.30 per barrel for 2024, and the 12-month average price for crude oil decreased from $78.21 per barrel for 2023 to $76.32 per barrel for 2024. Additionally, downward revisions of 172 Bcfe were associated with changes in our development schedule. The schedule changes moved the development of 11 Utica/Marcellus PUD locations and 6 SCOOP PUD locations beyond the SEC requirement of developing PUDs five years from initial booking. The development schedule changes reflect our ongoing commitment to optimizing the long-term plan to best develop our asset and maximize cash flow, and overall economic returns. These locations excluded from our SEC reserves report remain in Gulfport's development plan. These downward revisions were offset by upward revisions of 116 Bcfe in estimated proved reserves from a combination of changes including working interest and net revenue interest and well forecasts.
Costs incurred relating to the development of PUDs were approximately $326.4 million in 2024.
All PUD locations included in our 2024 reserve report are scheduled to be drilled within five years of initial booking.
As of December 31, 2024, 1.20% of our total proved reserves were classified as proved developed non-producing.
PV-10 Sensitivities
As noted above, our proved reserves at December 31, 2024, were calculated using prices based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for 2024 of $76.32 per barrel and $2.13 per MMBtu. Holding production and development costs constant, if SEC pricing were $83.95 per barrel and $2.34 per MMBtu, or a 10% increase, this would have resulted in an increase of 87 Bcfe of our total proved reserves and a $0.54 billion increase in PV-10 value at December 31, 2024. Holding production and development costs constant, if SEC pricing were $68.69 per barrel and $1.92 per MMBtu, or a 10% decrease, this would have resulted in a decrease of 494 Bcfe of our total proved reserves and a $0.51 billion decrease in PV-10 value at December 31, 2024. For the low price scenario 128 PUDs were PV-10 economic.
Acreage
The following table presents our total gross and net developed and undeveloped acres as of December 31, 2024:
Developed
Acreage Undeveloped
Acreage
Field Gross Net Gross Net
Utica & Marcellus 161,391 133,638 77,387 74,359
SCOOP 49,922 35,896 9,829 7,134
Total 211,313 169,534 87,216 81,493
Of our leases that are not held by production, most have a five-year primary term, many of which include options to extend the primary term. We manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our operations to establish production in paying quantities in order to hold leases prior to the expiration dates, paying the prescribed lease extension payments, planning non-core divestitures or strategic acreage trades with other operators to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. The following table sets forth the potential expiration periods of gross and net undeveloped leasehold acres as of December 31, 2024:
Undeveloped Acres
Years Ending December 31, Gross Acres Net Acres
2025 2,203 2,195
2026 3,682 3,661
2027 2,812 2,775
After 2027 18,673 18,667
Held by production 59,846 54,195
Total 87,216 81,493
Productive Wells
The following table presents our total gross and net productive wells, expressed separately for oil and gas, as of December 31, 2024:
NRI/WI Productive
Oil Wells Productive
Gas Wells Total Wells
Field Percentages Gross Net Gross Net Gross Net
Utica & Marcellus 49.66/60.84 15 5.15 712 437.2 727 442.4
SCOOP 21.41/26.49 119 12.23 531 159.92 650 172.1
Total(1)
143 17.4 1,411 597.1 1,554 614.5
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(1) We also have override/royalty interests in 177 wells with an average NRI of 0.6%, which are not material to our operations. Totals may not sum due to rounding.
Drilling Activity
The following table sets forth information with respect to operated wells drilled during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.
Year Ended December 31,
2024 2023 2022
Gross Net Gross Net Gross Net
Development:
Productive 21 19.8 24 21.9 25 21.7
Dry - - - - - -
Total 21 19.8 24 21.9 25 21.7
Exploratory:
Productive - - - - - -
Dry - - - - - -
Total - - - - - -
The following table presents activity by operating area for the year ended December 31, 2024:
Operated Non-Operated
Field Drilled Turned to Sales Drilled Turned to Sales
Gross Net Gross Net Gross Net Gross Net
Utica & Marcellus(1)
18.0 17.4 16.0 15.4 16.0 0.1 8.0 0.1
SCOOP(2)
3.0 2.4 3.0 2.4 18.0 0.2 16.0 0.1
Total 21.0 19.8 19.0 17.8 34.0 0.3 24.0 0.2
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(1) Of the 18 gross wells drilled in 2024, 10 were completed as producing wells and eight were in various stages of drilling and completion as of December 31, 2024.
(2) The three gross wells that were drilled in 2024 were completed as producing wells as of December 31, 2024.
Production, Prices and Production Costs
The following table presents our production volumes, average prices received and average production costs during the periods indicated (sales totals in thousands):
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Natural gas sales
Natural gas production volumes (MMcf) 354,154 350,306 322,366
Natural gas production volumes (MMcf) per day 968 960 883
Total sales $ 714,160 $ 831,812 $ 1,998,452
Average price without the impact of derivatives ($/Mcf) $ 2.02 $ 2.37 $ 6.20
Impact from settled derivatives ($/Mcf) $ 0.80 $ 0.42 $ (3.11)
Average price, including settled derivatives ($/Mcf) $ 2.82 $ 2.79 $ 3.09
Oil and condensate sales
Oil and condensate production volumes (MBbl) 1,459 1,363 1,610
Oil and condensate production volumes (MBbl) per day 4 4 4
Total sales $ 101,589 $ 99,854 $ 147,444
Average price without the impact of derivatives ($/Bbl) $ 69.64 $ 73.27 $ 91.58
Impact from settled derivatives ($/Bbl) $ 0.11 $ (2.53) $ (24.32)
Average price, including settled derivatives ($/Bbl) $ 69.75 $ 70.74 $ 67.26
NGL sales
NGL production volumes (MBbl) 3,818 4,386 4,483
NGL production volumes (MBbl) per day 10 12 12
Total sales $ 112,855 $ 119,717 $ 184,963
Average price without the impact of derivatives ($/Bbl) $ 29.56 $ 27.29 $ 41.26
Impact from settled derivatives ($/Bbl) $ (0.56) $ 2.07 $ (2.80)
Average price, including settled derivatives ($/Bbl) $ 29.00 $ 29.36 $ 38.46
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe) 385,814 384,802 358,924
Natural gas equivalents (MMcfe) per day 1,054 1,054 983
Total sales $ 928,604 $ 1,051,383 $ 2,330,859
Average price without the impact of derivatives ($/Mcfe) $ 2.41 $ 2.73 $ 6.49
Impact from settled derivatives ($/Mcfe) $ 0.73 $ 0.40 $ (2.94)
Average price, including settled derivatives ($/Mcfe) $ 3.14 $ 3.13 $ 3.55
Production Costs:
Average lease operating expenses ($/Mcfe) $ 0.18 $ 0.18 $ 0.18
Average taxes other than income ($/Mcfe) 0.08 0.09 0.17
Average transportation, gathering, processing and compression ($/Mcfe) 0.91 0.91 1.00
Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.17 $ 1.17 $ 1.34
Totals may not sum or recalculate due to rounding.
The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2024:
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Utica & Marcellus
Net Production
Natural gas (MMcf) 296,548 279,428 246,123
Oil (MBbl) 847 255 244
NGL (MBbl) 1,072 856 885
Total (MMcfe) 308,060 286,095 252,895
Average price without the impact of derivatives:
Natural gas ($/Mcf) $ 1.99 $ 2.34 $ 6.14
Oil ($/Bbl) $ 66.84 $ 70.18 $ 90.60
NGL ($/Bbl) $ 37.01 $ 33.63 $ 48.21
Production Costs:
Average lease operating expenses ($/Mcfe) $ 0.16 $ 0.16 $ 0.17
Average taxes other than income ($/Mcfe) 0.06 0.05 0.06
Average transportation, gathering, processing and compression ($/Mcfe) 0.93 0.97 1.08
Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.15 $ 1.18 $ 1.31
SCOOP
Net Production
Natural gas (MMcf) 57,605 70,878 76,242
Oil (MBbl) 612 1,108 1,366
NGL (MBbl) 2,746 3,530 3,598
Total (MMcfe) 77,753 98,707 106,024
Average price without the impact of derivatives:
Natural gas ($/Mcf) $ 2.13 $ 2.53 $ 6.38
Oil ($/Bbl) $ 73.51 $ 73.98 $ 91.71
NGL ($/Bbl) $ 26.65 $ 25.76 $ 39.56
Production Costs:
Average lease operating expenses ($/Mcfe) $ 0.28 $ 0.25 $ 0.20
Average taxes other than income ($/Mcfe) 0.13 0.17 0.38
Average transportation, gathering, processing and compression ($/Mcfe) 0.83 0.73 0.78
Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.24 $ 1.15 $ 1.36
Our Investments
Grizzly Oil Sands. We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.5% interest in Grizzly. As of December 31, 2024, Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly's operations have been suspended since 2015. Additionally, Grizzly had no proved reserves as of December 31, 2024. We elected to cease funding capital calls in 2019, and we have no obligation to fund any future projects Grizzly may consider pursuing. Failure to fund capital calls will lead to continued dilution of our equity ownership interest in Grizzly.
Marketing
The principal function of our marketing operations is to provide natural gas, oil and NGL marketing services, including securing and negotiating commodity transactions, gathering, hauling, processing and transportation services, contract administration and nomination services for production from Gulfport-marketed wells. Generally, natural gas and NGL production is sold to purchasers under both spot and term transactions. Oil production is sold under both spot and term transactions with the majority of our sales contracts being shorter term in nature.
We have entered into long-term gathering, processing and transportation contracts with various parties that reserve capacity for fixed, determinable quantities of production over specified periods of time. Some contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including risk mitigation and satisfaction of our firm transportation delivery commitments. These marketing activities often enhance the value of our production by aggregating volumes and allowing improved flexibility in relation to deal structure, size and counterparty exposure whether through intermediary markets or direct end markets. See Note 17 of our consolidated financial statements for further discussion of our commitments.
Major Customers
Our total natural gas, oil and NGL sales, before the effects of hedging, to major customers (purchasers in excess of 10% of total natural gas, oil and NGL sales) for the years ended December 31, 2024, 2023 and 2022 were as follows:
% of Sales
Year Ended December 31, 2024
Vitol Inc. 15 %
Year Ended December 31, 2023
Vitol Inc. 12 %
Year Ended December 31, 2022
ECO-Energy 20 %
Clearwater 11 %
Competition
The oil and natural gas industry is intensely competitive, and we compete with many other companies that have greater resources than we have. Competition can negatively impact our ability to successfully source quality vendors, service providers, employees and contractors to secure optimal pipeline access and end markets in which to sell our production, to acquire new properties, and our search for, and the development of, reserves. Many of our competitors not only explore for and produce oil and natural gas, but also have midstream and further downstream operations and market a variety of hydrocarbon products on a regional, national or worldwide basis. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include renewable sources such as wind or solar energy in addition to coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.
Seasonality
Gulfport drills and completes wells throughout the year, but adverse weather conditions can impact drilling, completion, and field operations, as well as third-party midstream and downstream pipeline operations, which can impact overall production volumes. Seasonal anomalies can minimize or exaggerate the impact on these operations, while extreme weather events can materially constrain our operations for short periods of time.
Title to Oil and Natural Gas Properties
It is customary in the oil and natural gas industry to make only a preliminary review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title examinations at the time we are preparing to develop the undeveloped leases and when acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas properties may be subject to certain imperfections in title, encumbrances, easements, servitudes or other restrictions, none of which, in management's opinion, will in the aggregate materially restrict our operations.
Regulation - Environment, Health and Safety
Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations
Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:
•reporting of workplace injuries and illnesses;
•industrial hygiene monitoring;
•worker protection and workplace safety;
•approval or permits to drill and to conduct operations;
•provision of financial assurances (such as bonds) covering drilling and well operations;
•calculation and disbursement of royalty payments and production taxes;
•seismic operations and data;
•location, drilling, cementing and casing of wells;
•well design and construction of pad and equipment;
•construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;
•method of completing wells;
•hydraulic fracturing;
•water withdrawal;
•well production and operations, including processing and gathering systems;
•emergency response, contingency plans and spill prevention plans;
•air emissions and fluid discharges;
•climate change;
•use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
•surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;
•plugging and abandoning of wells; and
•transportation of production.
In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases (“GHG”). We consider the costs of environmental, safety and health protection and compliance to be necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on policy and regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters. See the Risk Factors described in Item 1A. of this report for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.
Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States, some states allow the compulsory pooling or integration of tracts to facilitate exploration and development. Other states rely on voluntary pooling of lands and leases which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations often impose additional operational costs to us and can also limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.
Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could reduce the amount of natural gas, oil and NGL that we are ultimately able to produce in commercial quantities from our properties.
Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. If future developments result in additional restrictions on drilling, limitations on the availability of leases, or restrictions on the ability to obtain required permits, it could have a material adverse impact on our operations. Permitting activities on federal lands are also subject to frequent delays.
Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.
Operating Hazards and Insurance
The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.
We maintain a control of well insurance policy with a minimum limit of $25 million for single well limits and $37.5 million limit for multi-well pads. This policy insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $51 million comprehensive general liability umbrella insurance program. In addition, we maintain a $10 million pollution liability insurance policy providing coverage for gradual pollution related risks and in excess of the general liability policy for sudden and accidental pollution risks. We provide workers' compensation insurance coverage to employees in all states in which we operate, as well as auto liability for our company vehicles. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to our working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.
We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities in response to federal and state requirements. The plans go through a technical review every five years and are updated as necessary. As required by applicable regulations, our facilities are built with secondary containment systems to capture potential releases. We also own additional spill kits with oil booms and absorbent pads that are readily available, if needed. In addition, we have emergency response companies on retainer. These companies specialize in the clean-up of hydrocarbons as a result of spills, blow-outs and natural disasters, and are on call to us 24 hours a day, seven days a week when their services are needed. We pay these companies a retainer plus additional amounts when they provide us with clean up services. Our aggregate payments for the retainer and clean-up services during each of 2024, 2023 and 2022 were immaterial. While these companies have been able to meet our service needs when required from time to time in the past, it is possible that the ability of one or more of them to provide services to us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the areas in which we operate and the nature of our production, we believe other companies would be available to us in the event our primary remediation companies are unable to perform.
Human Capital Management
Employees
As of December 31, 2024, we had 235 employees, an increase of approximately 4% from the 226 employees as of December 31, 2023. All of our employees are non-bargaining.
The attraction and retention of qualified employees continues to be one of our highest priorities. We focus on making substantive improvements to key areas that impact our employees. During 2024, we continued making significant investments in our talent management and retention processes, including increasing funds allocated to annual salary increases, short-term incentive payments, long-term incentive equity awards, 401(k) matches for eligible employees, and other enhancements to our benefits offerings. We remain committed to providing fair and competitive compensation programs and adequate development and advancement opportunities to our employees. We believe these practices serve as talent acquisition and retention tools, as our employees' continued engagement and commitment to the Company is critical to our success.
Over the course of 2024, Gulfport continued to develop and revise Company policies, including those intended to implement our Business Code of Conduct and Ethics, which provides a framework for how we interact with our employees, vendors and other stakeholders when conducting our operations. To that end, we provided all of our employees with annual trainings focused on the guidelines, rules, and principles that must be followed when acting on the Company's behalf. We remain committed to maintaining the highest standards of business ethics.
Health, Safety & Environment
Safety is at the forefront of everything we do. We have a robust annual training program, including environmental, health, and safety topics. Our safety program, WORK SAFE, is comprised of twelve key topics including critical tasks and cultural conditions. We hold regular safety briefings to discuss daily operations and routinely have safety stand-down meetings highlighting potential risks. Every employee is empowered to use their stop-work authority to cease operating if work is being performed in an unsafe manner. We monitor employee safety by establishing annual company-wide key safety metrics tied to leading indicators (i.e., incident reporting and investigations, hazard observations, safety and health meetings) and lagging indicators (i.e., injury rates and preventable motor vehicle accidents).
As part of our focus on continuous improvement, we monitor and communicate key environmental and safety metrics both internally and externally. Trend analysis guides us to make operational changes and policy updates as necessary to protect our employees, the public and the environment. We establish and carefully track key environmental and safety metrics that are a component of every employee’s incentive compensation opportunity annually.
We have established several programs to ensure that our employees and external partners are appropriately trained to perform the critical work we do safely and effectively. We continued to reinforce our WORK SAFE program and provided training to leaders on reinforcement strategies. Additionally, we continued the WORK GREEN program, which focuses on protecting the air, land and water where we operate and includes community-based volunteer events targeting environmental clean-up and habitat improvement initiatives. An environmental training on the elements of WORK GREEN was created and delivered to all employees.
Training & Development
Gulfport invests in our employees' professional growth to build strong teams and develop leaders for today and the future. We build our dynamic team of industry-leading professionals by engaging them in interesting and rewarding work and providing training and development opportunities. We utilize training sessions with content developed by experts in the safety, legal, information security, and regulatory compliance fields, and we offer a blend of training sessions through both computer-based modules and live, instructor-led sessions. We believe our training efforts support a compliant safety-first mindset in everything we do. We continue to provide professional and workplace-related training resources to employees through universities, electronic content services and specialized courses related to our industry through our tuition reimbursement program or third-party providers.
Executive Officers
John Reinhart, President, Chief Executive Officer and Director
On January 18, 2023, the Board of Directors appointed Mr. Reinhart, 56, as President, Chief Executive Officer and Director, effective as of January 24, 2023. Mr. Reinhart joined the Company with over two decades of oil and gas industry leadership experience. Most recently, he served as President, Chief Executive Officer and member of the board of directors of Montage Resources Corporation where he led actions that positioned Montage as an attractive strategic partner with sufficient scale, low debt profile and achievement of top-quartile operational and financial metrics. Mr. Reinhart previously served as President, Chief Executive Officer and member of the board of directors of Blue Ridge Mountain Resources and as Chief Operating Officer at Ascent Resources. He started his oil and gas career at Schlumberger before joining Chesapeake Energy Corporation, where he held operations roles with increasing responsibility. Mr. Reinhart began his career in the United States Army, serving tours in Panama and Iraq. Mr. Reinhart graduated from West Virginia University with a Bachelor of Science degree in Mechanical Engineering.
Michael Hodges, Executive Vice President and Chief Financial Officer
On April 3, 2023, the Board of Directors appointed Mr. Hodges, 46, as Executive Vice President and Chief Financial Officer. Most recently, Mr. Hodges served as Senior Vice President, Finance and Accounting at Leon Capital Group. Prior to joining Leon Capital, he was the Executive Vice President and Chief Financial Officer for Montage Resources Corporation until its merger with Southwestern Energy Company in November 2020. From 2012 until joining Montage Resources in 2018, Mr. Hodges served as the Chief Financial Officer for three upstream energy companies focused on near-term value creation through the acquisition and early-stage development of oil and natural gas resources. Mr. Hodges received his Bachelor of Business Administration in Finance from the University of Oklahoma and a Master of Science in Energy Management from Oklahoma City University and is a Certified Public Accountant in the State of Oklahoma.
Patrick Craine, Executive Vice President and Chief Legal and Administrative Officer
Mr. Craine, 52, has served as Chief Legal and Administrative Officer since June 2021 and joined Gulfport as Executive Vice President, General Counsel and Corporate Secretary in May 2019. Prior to joining the Company, Mr. Craine served as Deputy General Counsel - Chief Risk and Compliance Officer at Chesapeake Energy Corporation. Prior to joining Chesapeake in 2013, Mr. Craine was a partner with Bracewell LLP, a global law firm, where his practice focused on securities and corporate regulatory matters and investigations. Before Mr. Craine entered private practice, he served as a lawyer with the U.S. Securities and Exchange Commission and the Financial Industry Regulatory Authority where he held leadership positions in their Oil and Gas Task Forces. Mr. Craine has over 25 years of extensive senior-level experience handling a broad range of securities, corporate, regulatory, governance, compliance and litigation matters, with particular expertise in the energy industry. Mr. Craine received his Bachelor of Arts degree, summa cum laude, Phi Beta Kappa, from Wabash College, and his Juris Doctorate, cum laude, from the Southern Methodist University Dedman School of Law.
Matthew Rucker, Executive Vice President and Chief Operating Officer
Mr. Rucker, 39, joined Gulfport as the Senior Vice President of Operations in March 2023. On February 24, 2025, Matthew Rucker was promoted to Executive Vice President and Chief Operating Officer. He joined Gulfport from Javelin Energy Partners where he previously served as Vice President of Production Operations starting in August 2022. Mr. Rucker joined Javelin in July 2022 as the Vice President of Business Development. Prior to joining Javelin, Mr. Rucker served as the Executive Vice President, Chief Operating Officer for Montage Resources Corporation following Montage’s successful business combination transaction with Blue Ridge Mountain Resources in June 2020. Prior to Montage, Mr. Rucker served as Vice President, Resource Planning and Development of Blue Ridge from 2016 to 2020. Prior to joining Blue Ridge, Mr. Rucker served as a Production Superintendent for Chesapeake Energy Corporation from January 2014 to October 2016, overseeing Chesapeake’s Utica Shale production. As a member of Chesapeake’s Eastern Division leadership team, Mr. Rucker focused on the safe and efficient optimization of production in the Utica Shale and led an operating team of over 45 employees. During his service at Chesapeake, Mr. Rucker held several engineering positions in the Marcellus and Utica Shale asset teams within reservoir, primarily focused on strategic joint ventures, divestitures, acquisitions and resource development planning. Mr. Rucker received his Bachelor of Science degree in Petroleum Engineering from Marietta College and a Master of Business Administration in Energy from Texas Christian University. He serves on the Marietta College Industry Advisory Council and is a member of the Society of Petroleum Engineers.
Michael Sluiter, Senior Vice President of Reservoir Engineering
Mr. Sluiter, 52, joined Gulfport as the Senior Vice President of Reservoir Engineering in December 2018 from Noble Energy, Inc., where he most recently served as the Permian Basin Business Unit Manager. Prior to that role, he spent over 17 years developing his skills and expertise in unconventional resource development, reservoir engineering, subsurface development, business development/M&A, and leadership at Noble Energy, Santos Australia and Santos USA. Mr. Sluiter began his career as a wireline field services engineer for Schlumberger in Thailand. Mr. Sluiter is a graduate of the University of Sydney, Australia, with a Bachelor of Science degree in Chemical Engineering.
Lester Zitkus, Senior Vice President of Land
Mr. Zitkus, 59, has served as Senior Vice President of Land since January 2017 and joined the Company as Vice President of Land in March 2014. Prior to joining the Company, Mr. Zitkus served as an independent consultant from October 2013 to March 2014 and as Vice President of Land for Chesapeake Energy Corporation from May 2007 to October 2013. During his 20-year tenure with Equitable Resources Inc. (now EQT Corp.), he held various positions, including Vice President of Operations and Senior Vice President of Land, between 1987 and 2007. He holds a degree in Mineral Land Management from the University of Evansville. Mr. Zitkus is a member of the American Association of Professional Landmen and Past Regional Director of the Independent Petroleum Association of America.
There is no family relationship between any of our officers or between any of them and the Company's Board of Directors. The executive officers serve at the pleasure of the Company's Board of Directors.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a summary of significant factors that might cause our future results to differ materially from those currently expected. The risks described below are not the only risks facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of these risks actually occur, our business, financial position, operating results, cash flows, reserves or our ability to pay our debts and other liabilities could suffer, the trading price and liquidity of our securities could decline and you may lose all or part of your investment in our securities.
Financial, Liquidity and Commodity Price Risks
Natural gas, oil and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.
Our revenues, cash flows, profitability, future rate of growth, production and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for natural gas and, to a lesser extent, oil and NGL. We incur substantial expenditures to replace reserves, sustain production and fund our business plans. Low natural gas, oil and NGL prices can negatively affect the amount of cash available for capital expenditures, debt service and debt repayment and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves. In addition, periods of low natural gas, oil and NGL prices may result in ceiling test write-downs of our oil and natural gas properties.
Historically, the markets for natural gas, oil and NGL have been volatile, and they are likely to continue to be volatile. For example, during 2023, WTI prices ranged from $66.61 to $93.67 per barrel and the Henry Hub spot market price of natural gas ranged from $1.74 to $3.78 per MMBtu. During 2024, WTI prices ranged from $66.73 to $87.69 per barrel and the Henry Hub spot market price of natural gas ranged from $1.21 to $13.20 per MMBtu.
Wide fluctuations in natural gas, oil and NGL prices may result from factors that are beyond our control, including:
•domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves;
•the level of prices, and expectations about future prices, of oil and natural gas;
•changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns, such as the recent coronavirus;
•the cost of exploring for, developing, producing and delivering oil and natural gas;
•the expected rates of declining current production;
•the price and availability of alternative fuels;
•technological advances and changing consumer attitudes affecting energy consumption;
•risks associated with operating drilling rigs;
•the effectiveness of worldwide conservation measures;
•the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;
•the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
•U.S. exports of oil, natural gas, liquefied natural gas and NGL;
•the price and level of foreign imports and exports, including as a result of U.S. trade policy;
•the nature and extent of domestic and foreign governmental regulations and taxes;
•the ability of the members of the Organization of Petroleum Exporting Countries and others to agree to and maintain oil price and production controls;
•political or economic instability or armed conflict in oil and natural gas producing regions;
•weather conditions;
•acts of terrorism; and
•domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and NGL price movements with any certainty. Even with natural gas, oil and NGL derivatives currently in place to mitigate price risks associated with a portion of our 2025 cash flows, we have substantial exposure to natural gas prices, and to a lesser extent, oil and NGL prices, in 2025 and beyond. In addition, a prolonged extension of lower prices could reduce the quantities of reserves that we may economically produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.
Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.
To manage our exposure to price volatility, we enter into natural gas, oil and NGL price derivative contracts. Our natural gas, oil and NGL derivative arrangements may limit the benefit we would receive from increases in commodity prices. The fair value of our natural gas, oil and NGL derivative instruments can fluctuate significantly between periods. Our decision to mitigate cash flow volatility through derivative arrangements, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to enter into derivatives if the pricing environment for certain time periods is not deemed to be favorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions for the purpose of funding our capital program.
Natural gas, oil and NGL derivative transactions expose us to the risk that our counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. During periods of declining commodity prices, the value of our commodity derivative asset positions increase, which increases our counterparty exposure. Although the counterparties to our hedging arrangements are required to secure their obligations to us under certain scenarios, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future cash flows being exposed to commodity price changes.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase.
Our earnings are exposed to interest rate risk associated with borrowings under our Credit Facility, which is structured under floating rate terms. As such, our interest expense is sensitive to fluctuations in the SOFR benchmark. For the year ended December 31, 2024, amounts borrowed under our Credit Facility bore interest at the weighted average rate of 8.23%. A 1% increase in the average interest rate would increase our interest expense by approximately $0.4 million based on outstanding borrowings under our Credit Facility at December 31, 2024. An increase in our interest rate at the time we have variable interest rate borrowings outstanding under our Credit Facility will increase our costs, which may have a material adverse effect on our results of operations and financial condition. As of December 31, 2024, we did not hedge our interest rate risk.
Our debt and other financial commitments may limit our financial and operating flexibility.
Our total principal debt was approximately $713.7 million at December 31, 2024. We also had various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services, products and properties. Our financial commitments could have important consequences to our business, including, but not limited to, limiting our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, to pay dividends, to repurchase shares of our common stock, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flows from operations to make payments on our debt or to comply with restrictive terms of our debt. Higher levels of debt may make us more vulnerable to general adverse economic and industry conditions. Additionally, the agreement governing our credit facility and the indentures governing our senior notes contain a number of covenants that impose constraints on us, including requirements to comply with certain financial covenants and restrictions on our ability to dispose of assets, make certain investments, incur liens and additional debt, and engage in consolidations, mergers and acquisitions. If commodity prices decline and we reduce our level of capital spending and production declines or we incur additional impairment expense or the value of our proved reserves declines, we may not be able to incur additional indebtedness, may need to repay outstanding indebtedness and may not be in compliance with the financial covenants in our debt instruments in the future. Refer to “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of this Annual Report on Form 10-K and Note 4 of our consolidated financial statements for more information regarding the financial covenants and our Credit Facility.
Our development, acquisition and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.
Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. We have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves.
Historically, we have financed capital expenditures primarily with cash flow from operations and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:
•our proved reserves;
•the volume of oil and natural gas we are able to produce from existing wells;
•the prices at which oil and natural gas are sold;
•our ability to acquire, locate and produce economically new reserves; and
•our ability to borrow under our credit facility.
We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital through a variety of means. We cannot guarantee that we will be able to obtain debt or equity financing on terms favorable to us, or at all.
If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves. In addition, we may be unable to implement our development plan, complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.
Under our method of accounting for oil and natural gas properties, declines in commodity prices may result in impairment of asset value.
We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proved oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting oil and NGL to one Mcf of natural gas at the ratio of six Mcf of natural gas to one barrel of oil.
Under the full cost method of accounting for oil and gas properties, we are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or non-cash write-down is required. A ceiling test impairment can result in a significant loss for a particular period. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase. Future non-cash asset impairments could negatively affect our results of operations.
A change of control could limit our use of net operating losses to reduce future taxable income.
As of December 31, 2024, we had a net operating loss, or NOL, carryforward of approximately $1.6 billion for federal income tax purposes. If we were to experience an “ownership change,” as determined under IRC Section 382, our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate for the month in which such ownership change occurs. In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year period.
Industry, Business and Operational Risks
The oil and gas development, exploration and production industry is very competitive, and some of our competitors have greater financial and other resources than we do.
We face competition in every aspect of our business, including buying and selling reserves and leases, obtaining goods and services needed to operate our business and marketing natural gas, oil or NGL. Competitors include multinational oil companies, independent production companies and individual producers and operators. Some of our competitors have greater financial and other resources than we do and may have greater access to the capital and credit markets. Many of these companies not only explore for and produce oil and natural gas but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. As a result, these competitors may be able to address these competitive factors more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.
Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively may be diminished. We also compete for the equipment required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield equipment and services, which could adversely affect our ability to execute our development plans on a timely basis and within budget.
The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
The estimates of our proved reserves and the estimated future net revenues from our proved reserves included in this report are based upon various assumptions, including assumptions required by the SEC relating to natural gas, oil and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating natural gas, oil and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to future revisions.
Actual future production, natural gas, oil and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas, oil and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
As of December 31, 2024, approximately 47% of our total estimated proved reserves were PUDs and may not be ultimately developed or produced. Recovery of PUDs requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. Estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not be as estimated. Delays in the development of our reserves, further decreases in commodity prices or increases in costs to drill and develop such reserves will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. If we choose not to develop our PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove them from our reported proved reserves. In addition, under the SEC's reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUDs that are not developed within this five-year time frame.
You should not assume that the present values included in this report represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The price on the date of estimate is calculated as the average natural gas and oil price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2024 present value is based on a $2.13 per MMBtu of gas price and a $76.32 per Bbl of oil price, before considering basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
Actual future net revenues from our oil and natural gas properties will also be affected by factors such as:
•actual prices we receive for oil and natural gas;
•the amount and timing of actual production;
•supply of and demand for oil and natural gas; and
•changes in governmental regulations or taxation.
The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect both the timing of future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor that is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
We acquire unproven properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such undeveloped properties or wells.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling and completion operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and produced water disposal, and a decline in commodity prices, among others. The profitability of wells, particularly in certain of the areas in which we operate, will be reduced or eliminated if commodity prices decline. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for natural gas, oil and NGL, costs associated with producing natural gas, oil and NGL and our ability to add reserves at an acceptable cost. Drilling results in our newer oil and liquids-rich shale plays may be more uncertain than in shale plays that are more developed and have longer established production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize recoveries will be ultimately successful when used in newly developed shale formations. All costs of development and exploratory drilling activities are capitalized under the full cost method, even if the activities do not result in commercially productive discoveries, which may result in a future impairment of our oil and natural gas properties if commodity prices decrease.
We rely to a significant extent on seismic data and other technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of undeveloped properties, or drilling a well, whether oil or natural gas is present or may be produced economically. If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.
Part of our strategy involves using the latest available horizontal drilling and completion techniques; therefore, the results of our planned drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Furthermore, certain of the development activities we employ, such as offset drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of offset drilling, adjacent wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Although approximately 86% of our Utica/Marcellus acreage is held by existing production, the remaining acreage is subject to expiration. Of the remaining 14% of our Utica/Marcellus acreage not held by production, approximately 7% will be subject to expiration in 2025, 12% in 2026, 9% in 2027 and approximately 72% thereafter, although a portion of our Utica/Marcellus leases generally grant us the right to extend these leases for an additional three or five-year period. Approximately 99% of our SCOOP acreage is held by existing production; the remaining acreage is subject to expiration. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties. The cost to renew expiring leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. If we are unable to fund renewals of expiring leases, we could lose portions of our acreage and our actual drilling activities may differ materially from our current expectations, which could adversely affect our business.
Oil and natural gas operations are uncertain and involve substantial costs and risks. Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.
Our oil and gas properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:
•unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
•loss of drilling fluid circulation;
•equipment failures or accidents;
•fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground migration of fluids and chemicals;
•risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives;
•adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures, which may be exacerbated by climate change;
•issues with title or in receiving governmental permits or approvals;
•restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;
•environmental hazards or liabilities, including liabilities for environmental damage caused by previous owners of properties purchased by us;
•restrictions in access to, or disposal of, water used or produced in drilling and completion operations;
•shortages or delays in the availability of services or delivery of equipment; and
•unexpected or unforeseen changes in regulatory policy, and political or public opinions.
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities.
While we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, cybersecurity breaches, war, terrorism and piracy, we have limited or no insurance coverage. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
Multi-well pad drilling may result in volatility in our operating results and delay the conversion of our PUD reserves.
We utilize multi-well pad drilling where practical. For example, in the Utica/Marcellus we drill multiple wells from a single pad. Wells drilled on a pad are not turned to sales until all wells on the pad are drilled and cased and the drilling rig is moved from the location. In addition, existing wells that offset newly drilled wells may be temporarily shut in during the drilling and completion process. As a result, multi-well pad drilling delays the completion of wells and the commencement of production from new wells and may negatively affect the production from existing offset wells, all of which may cause volatility in our operating results from period to period. Finally, delays in completion of wells may impact planned conversion of PUD reserves to PDP reserves.
We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.
We are not the operator of all of the properties in which we have an interest, and have limited ability to exercise influence over the operations of such non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploration activities on properties operated by others will depend upon a number of factors that will be largely outside of our control, including:
•the timing and amount of capital expenditures;
•the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
•the operator's expertise and financial resources;
•approval of other participants in drilling wells;
•selection of technology; and
•the rate of production of the reserves.
In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.
Oil and natural gas production operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Our ability to produce natural gas, oil and NGL economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations. For water sourcing, we first seek to use non-potable water supplies for our operational needs. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must then be obtained from other sources and transported to the drilling site. An inability to secure sufficient amounts of water or to dispose of or recycle the water used in our operations could adversely impact our operations in certain areas. The imposition of new environmental regulations could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of things such as produced water and drilling fluids.
All of our producing properties are located in eastern Ohio and central Oklahoma, making us vulnerable to risks associated with operating in only these regions.
Our largest fields by production are located in eastern Ohio and central Oklahoma. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production in these geographic regions caused by weather conditions such as snow, ice, fog, rain, hurricanes, tornados or other natural disasters or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at rates we consider reasonable and it is possible that certain types of coverage may not be available.
The loss of one or more of the purchasers of our production could adversely affect our business, results of operations, financial condition and cash flows.
The largest purchaser of our oil and natural gas during the year ended December 31, 2024, accounted for approximately 15% of our total natural gas, oil and NGL revenues. If this purchaser or one or more other significant purchasers, are unable to satisfy its contractual obligations, we may be unable to sell such production to other customers on terms we consider acceptable. Further, the inability of one or more of our customers to pay amounts owed to us could adversely affect our business, financial condition, results of operations and cash flows.
The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for and wage rates of qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. Shortages of and increased costs for drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.
Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash flow.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of natural gas lines, trucks and transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to them may be limited or denied. In certain resource plays, the capacity of gathering and transportation systems is insufficient to accommodate potential production from existing and new wells. A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations.
With respect to our Utica/Marcellus acreage where we are focusing a portion of our exploration and development activity, operations may be delayed due to challenges in obtaining rights-of-way and acquiring necessary state and federal permitting and the completion of facilities by our midstream service provider. Capital constraints could limit the construction of new pipelines and gathering systems and the providing or expansion of trucking services by third parties in the Utica/Marcellus and the other areas in which we operate. As a result, we may experience delays or curtailments in producing and selling our natural gas, oil and NGL. In such event, we might have to shut in or curtail our wells awaiting a pipeline connection or capacity or sell natural gas, oil or NGL production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.
A portion of our natural gas, oil and NGL production in any region may be interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow.
We are required to pay fees to some of our midstream service providers based on minimum volumes regardless of actual volume throughput.
We have contracts with some of our third-party service providers for gathering, processing and transportation services with minimum volume delivery commitments under which we are obligated to pay certain fees on minimum volumes regardless of actual volume throughput. As of December 31, 2024, our aggregate long-term contractual obligation under these agreements was approximately $1.1 billion. These fees could be significant and may have a material adverse effect on our results of operations.
A deterioration in general economic, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, tariffs, energy costs, geopolitical issues, inflation, the availability and cost of credit and the European, Asian and the United States financial markets have contributed to economic volatility and diminished expectations for the global economy. Historically, concerns about global economic growth have had a significant impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and materially adversely impact our results of operations, liquidity and financial condition.
Terrorist activities could materially and adversely affect our business and results of operations.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices, or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business and results of operations. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, have in the past precipitated, and may in the future precipitate, an economic slowdown.
Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed.
Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our customers, employees and third-party partners. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of our vendors, suppliers and other business partners, have been and may become the target of cyberattacks or information security breaches that could result in the unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. If our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations, which may include drilling, completion, production and corporate functions. A cyberattack involving our information systems and related infrastructure, or that of our business associates, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, non-compliance leading to regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customer’s, supplier’s or royalty owners’ data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.
In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cybersecurity risks may not be sufficient. As cyberattacks continue to evolve, including those leveraging artificial intelligence, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In addition, new laws and regulations governing data privacy, cybersecurity, and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.
We may engage in acquisition and divestiture activities that involve substantial risks.
We may make acquisitions that complement or expand our current areas of operations. If we are unable to make attractive acquisitions, our future growth could be limited. Furthermore, even if we do make acquisitions, they may not result in an increase in our cash flow from operations or otherwise result in the benefits anticipated due to various risks, including, but not limited to:
•mistaken estimates or assumptions about reserves, potential drilling locations, revenues and costs, including synergies and the overall costs of equity or debt;
•difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and
•unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.
In addition, from time to time, we may sell or otherwise dispose of certain of our properties or businesses as a result of an evaluation of our asset portfolio or to help enhance our liquidity. These transactions also have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets or businesses and potential post-closing claims for indemnification. Moreover, volatility in commodity prices may result in fewer potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to terminate a transaction prior to closing.
Environmental, Legal and Regulatory Risks
We are subject to extensive governmental regulation and ongoing regulatory changes, which could adversely impact our business.
Our operations are subject to extensive federal, state, tribal, local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGL, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. For example, in March 2024, the United States Environmental Protection Agency (USEPA), issued its final methane rules to reduce methane emissions from both new and existing oil and natural gas facilities and the Inflation Reduction Act of 2022 (“IRA 2022”) established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from the same facilities, the rule for which was finalized in November 2024. Further, the Bureau for Land Management (BLM) issued a final Methane Waste Prevention Rule on April 10, 2024. The rule adds additional requirements for operators on federal and Indian leases and includes new air quality requirements along with waste prevention provisions. Constrained supply chain for environmental control devices along with the significant estimated costs of compliance with these new and proposed rules could have a material impact on our operations. We may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or orders.
In addition, changes in public policy have affected, and in the future could further affect, our operations. Regulatory changes could, among other things, restrict production levels, impose price controls, alter environmental protection requirements and increase taxes, royalties and other amounts payable to the government. Our operating and compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. We do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity. As is discussed below this is particularly true of changes related to pipeline safety, seismic activity, hydraulic fracturing, climate change and endangered species designations. As of January 2025, however, the Trump Administration issued a series of executive orders that signal a shift in the United States' energy polices, including directing federal agencies to identify and exercise emergency authorities to facilitate conventional energy production, transportation, and refining, and call for the use of emergency regulations to expedite energy infrastructure projects, promote energy exploration and production on federal lands and waters, and mandate a review of existing regulations that may burden domestic energy development.
Pipeline Safety. The pipeline assets owned by our midstream service providers are subject to stringent and complex regulations related to pipeline safety and integrity management. The Pipeline and Hazardous Materials Safety Administration (PHMSA) has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas”. Recent PHMSA rules have also extended certain requirements for integrity assessments and leak detections beyond high consequence areas. Further, legislation funding PHMSA through 2023 requires the agency to engage in additional rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines. At this time, we cannot predict the cost of these requirements or other potential new or amended regulations, but they could be significant, and any such costs incurred by our midstream service providers could result in increased midstream gathering and processing expenses for us. Moreover, violations of pipeline safety regulations by our midstream service providers could result in the imposition of significant penalties which may impact the cost or availability of pipeline capacity necessary for our operations.
Seismic Activity. Earthquakes in some of our operating areas and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. For example, the OCC issued guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing or water disposal activities. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In addition, we could be subject to third-party lawsuits seeking damages or other remedies as a result of alleged induced seismic activity in our areas of operation.
Hydraulic Fracturing. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations. Three states (New York, Maryland and Vermont) have banned the use of high-volume hydraulic fracturing. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. There have also been certain governmental reviews that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. Governments may continue to study hydraulic fracturing. We cannot predict the outcome of future studies, but based on the results of these studies to date, federal and state legislatures and agencies may seek to further regulate or even ban hydraulic fracturing activities. In addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected.
We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.
Climate Change. Continuing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane, and incentivizing energy conservation or the use of alternative energy sources. Policy makers at both the federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations or taxes on greenhouse gas emissions and encourage consumers to the alternative energy sources. The IRA 2022, both imposes new climate related requirements on oil and gas operations and appropriates significant federal funding for renewable energy initiatives. Also, for the first time ever, the law imposes a fee on GHG emissions from certain facilities. The emissions fee and funding provisions of the IRA 2022 could increase our operating costs and accelerate the transition away from fossil fuels, which could in turn adversely affect our business, results of operations and financial position. On January 26, 2024, the Biden Administration paused approvals for pending and future applications to export liquified natural gas (LNG) on non-FTA countries. On January 20, 2025, President Trump issued an executive order reversing the pause implemented by the Biden Administration, resuming the processing of export permit applications for new LNG projects. Additionally, in January 2025 President Trump signed executive orders that, among other things, direct federal executive departments and agencies to initiate a regulatory freeze for certain rules that have not taken effect, pending review by the newly appointed agency head, and call upon the USEPA to submit a report on the continuing applicability of its endangerment finding for GHGs under the Clean Air Act and issue guidance on the “social cost of carbon” to consider whether such metric should be eliminated, and pause the disbursement of funds appropriated through the IRA 2022. The impact on these federal actions remain unclear.
States in which we operate have imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of cap and trade or carbon tax programs. Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time. The development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level or other initiatives to incentivize the use of renewable energy could reduce the demand for oil and gas, thereby adversely impacting our earnings, cash flows and financial position. Cap and trade programs offer greenhouse gas emission allowances that are gradually reduced over time. A cap and trade program or expanded use of cap and trade programs at the state level could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.
In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to greenhouse gases and climate change, before investing in our common units. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable to improve our sustainability performance and to meet the specific requirements to perform services for certain customers. If we are unable to meet the ESG standard or investment, lending, ratings, or voting criteria and policies set by these parties, we may lose investors, investors may allocate a portion of their capital away from us, we may become a target for ESG-focused activism, our cost of capital may increase, the price of our securities may be negatively impacted, and our reputation may also be negatively affected.
These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity. Furthermore, increasing attention to climate change risks has resulted in increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business.
Severe weather events, such as storms, hurricanes, droughts, or floods, which may be exacerbated by climate change, could have an adverse effect on our operations and could increase our costs. Potential adverse effects could include damages to our facilities, the costs of less efficient or non-routine operating practices necessitated by weather events, or increased costs for insurance coverage. If climate changes result in more intense or frequent severe weather events, the physical and disruptive effects could have a material adverse impact on our operations and assets.
Air Emissions. The US Federal Clean Air Act and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before operations can commence, and existing facilities may be required to obtain additional permits, and incur capital costs, in order to remain in compliance. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. In general, we believe that compliance with the Clean Air Act and similar state laws and regulations will not have a material impact on our operations or financial condition.
Endangered Species. The Endangered Species Act (ESA) prohibits the taking of endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, the designation of previously unidentified endangered or threatened species in areas where we intend to conduct construction activity or the imposition of seasonal restrictions on our construction or operational activities could materially limit or delay our plans.
Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
State and federal regulatory agencies have focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states, including in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells.
In our Utica/Marcellus and SCOOP operations, we make an effort to reuse/recycle all produced water from production and completion activities through our fracture stimulation operations when active. While our objective is to recycle or share 100% of all produced water, we do inject water into third-party commercially operated disposal wells in line with all state and federal mandated practices and cease produced water recycle whenever fracture stimulation operations are idle once sharing opportunities with other operators have been exhausted. In the state of Ohio, all water used during drilling operations is disposed of through injection into third-party salt water disposal wells regulated by applicable state agencies.
Increased attention to ESG matters may impact our business, financial results, or stock price.
In recent years, increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, activist investors, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change, advocating for changes to companies’ boards of directors, and promoting the use of energy saving building materials. On January 20, 2025, however, President Trump signed an executive order to withdraw the United States from the Paris Agreement, marking a significant shift in U.S. federal climate policy. Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026. State and local GHG initiatives may continue despite the U.S. withdrawal from the Paris Agreement. A potential global transition to a low carbon economy may result in reduced demand for our oil, natural gas and NGL, reduced profits, increased investigations and litigation, each of which could have negative impacts on our access to capital markets.
In addition, we note that standards and expectations regarding carbon accounting and the processes for measuring and counting GHG emissions and GHG emission reductions are evolving, and it is possible that our approach to measuring both our emissions and our approaches to reducing emissions may be, either currently by some stakeholders or at some future point, considered inconsistent with common or best practices. A failure to comply with investor or customer expectations and standards, which are evolving, or if we are perceived to not have responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, could cause reputational harm to our business, increase our risk of litigation, and could have a material adverse effect on our results of operations.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESG matters. These ratings are used by some investors to inform their investment and voting decisions. We may take certain actions to improve the ESG profile of our company and/or products, but we cannot guarantee that such actions will have the desired effect. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.
Future U.S. and state tax legislation may adversely affect our business, results of operations, financial condition and cash flow.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and gas industry. For example, legislative proposals have been introduced in the U.S. Congress in the past that, if enacted, would (i) eliminate the immediate deduction for intangible drilling and development costs, (ii) repeal the percentage depletion allowance for oil and natural gas properties, and (iii) extend the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. In addition, at the state level, legislative changes imposing increased taxes on oil and gas production have periodically been considered in Ohio and Oklahoma. These proposed changes in the U.S. federal and state tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flows.
Our business is subject to complex and evolving laws and regulations regarding privacy and data protection.
The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate our costs as we collect, use, share, and store personal data related to royalty owners. Any failure to comply with these laws and regulations could result in significant penalties and legal liability. For example, the California Consumer Privacy Act (CCPA), as amended by the California Privacy Rights Act (CPRA), establishes certain transparency rules and creates new data privacy rights for individuals, including limitations on our use of certain sensitive personal information and more ability for individuals to control the purposes for which their data is shared with third parties. The CPRA also provides for statutory fines for data security breaches or other CPRA violations. Meanwhile, many other states enacted, and others have considered, privacy laws like the CPRA. We will continue to monitor and assess the impact of these state laws, which may impose substantial penalties for violations, impose significant costs for investigations and compliance, require us to change our business practices, allow private class-action litigation and carry significant potential liability for our business should we fail to comply with any such applicable laws.
Any failure, or perceived failure, by us to comply with applicable data protection laws could result in heightened risk of litigation, including private rights of action, and proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and complexity of compliance, and adversely affect our business. As noted above, we are also subject to the possibility of cyber incidents or attacks, which themselves may result in a violation of these laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.
Risks Associated with an Investment in Us
The market price of our securities is subject to volatility.
The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, future sales of additional stock and changes in our capital structure, compliance with governmental regulations and taxation laws, actual or anticipated variations in our operating results and cash flow, allocation of free cash flow including any determination by our board of directors regarding repurchasing stock, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Part I, Item 1A. of this Annual Report on Form 10-K.
Future sales or the availability for sale of substantial amounts of our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and could impair our ability to raise capital through future sales of equity securities.
A significant percentage of our common stock is held by a single investor. In connection with our emergence from bankruptcy protection in 2021, we entered into the Registration Rights Agreement pursuant to which we have agreed to file a registration statement with the SEC to facilitate potential future sales of our common stock by such investors. Sales of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur (such as upon the filing of the aforementioned registration statement), could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.
We cannot predict the effect that future sales of our common stock will have on the price at which the common stock trades. Sales of substantial amounts of our common stock, or the perception that such sales could occur, may adversely affect the trading price of our common stock.
Certain of our stockholders own a significant portion of our outstanding equity securities and their interests may not always coincide with the interests of other holders of the common stock.
A large percentage of our equity is held by a relatively small number of investors. As a result, these investors could have significant influence over all matters presented to our stockholders for approval, including election and removal of our directors, change in control transactions and the outcome of all actions requiring majority stockholder approval.
The interests of these investors may not always coincide with the interests of the other holders of the common stock, and the concentration of control in these investors may limit other stockholders' ability to influence corporate matters. The concentration of ownership and voting power of these investors may also delay, defer or even prevent an acquisition by a third party or other change of control transactions of our Company. This may make some transactions more difficult or impossible without their support, even if such events are in the best interests of our other stockholders. In addition, the concentration of voting power may adversely affect the trading price and liquidity of the common stock.
There may be future dilution of our common stock, which could adversely affect the market price of our common stock.
We are not restricted from issuing additional shares of our common stock. In the future, we may issue shares of our common stock to raise cash for future capital expenditures, acquisitions or for general corporate purposes. We may also issue securities that are convertible into, exchangeable for or that represent the right to receive our common stock. Lastly, we currently issue restricted stock units and performance vesting restricted stock units to certain employees and directors as part of their compensation. Any of these events will dilute our shareholders' ownership interest in Gulfport and may reduce our earnings per share and have an adverse effect on the price of our common stock.
Our amended and restated certificate of incorporation provides, subject to certain exceptions, that the Court of Chancery of the State of Delaware will be the sole and exclusive forum for certain stockholder litigation matters, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or stockholders.
Our amended and restated certificate of incorporation provides, subject to limited exceptions, that the Court of Chancery of the State of Delaware will, to the fullest extent permitted by law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf; (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors or officers to us, our stockholders, our creditors or other constituents; (iii) any action asserting a claim against us, any director or our officers arising pursuant to any provision of the DGCL, our certificate of incorporation or our by-laws; or (iv) any action asserting a claim against us, any director or our officers that is governed by the internal affairs doctrine. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or any of our directors or officers or stockholders which may discourage lawsuits with respect to such claims. Alternatively, if a court were to find the choice of forum provision contained in our certificate of incorporation to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could have a material adverse effect on our business, financial condition and results of operations.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
Information regarding our properties is included in Item 1 and in the Supplemental Information on Oil and Gas Exploration and Production Activities in Note 20 of our consolidated financial statements.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business.
While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.
The information with respect to this Item 3. Legal Proceedings is set forth in Note 18 of our consolidated financial statements.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Stock
Shares of our common stock are listed on the NYSE under the symbol “GPOR”. See Note 6 of our consolidated financial statements for further discussion of our common stock.
Shareholders
At the close of business on February 12, 2025, there were approximately 20,947 holders of record of our common stock.
Dividends
During the years ended December 31, 2024, 2023 and 2022, the Company has not paid dividends on our common stock. The declaration and payment of any future common stock dividend will be at the full discretion of the Board of Directors and will depend on our financial results, cash requirements, future prospects and other factors deemed relevant by our Board. Our Credit Facility also requires us to meet certain financial covenants at the time dividend payments are made.
During the years ended December 31, 2024, 2023 and 2022, the Company paid $4.2 million, $4.8 million and $5.4 million, respectively, of cash dividends to holders of our preferred stock.
Issuer Purchases of Equity Securities
In November 2021, the Company's Board of Directors approved the Repurchase Program to acquire up to $100 million of common stock, which has subsequently been increased up to $1.0 billion and extended through December 31, 2025. Purchases under the Repurchase Program may be made from time to time in open market or privately negotiated transactions, and will be subject to available liquidity, market conditions, credit agreement restrictions, applicable legal requirements, contractual obligations and other factors. The Repurchase Program does not require the Company to acquire any specific number of shares of common stock. The Company intends to purchase shares under the Repurchase Program with available funds while maintaining sufficient liquidity to fund its capital development program. The Repurchase Program may be suspended from time to time, modified, extended or discontinued by the Board of Directors at any time. As of December 31, 2024, the Company had repurchased 5.6 million shares for $584.1 million at a weighted average price of $104.88 per share.
The following table provides a summary of our common stock repurchase activity for the three months ended December 31, 2024:
Period Total Number of Shares Purchased(1)
Average Price Paid per Share Total number of shares purchased as part of publicly announced plans or programs Approximate maximum dollar value of shares that may yet be purchased under the plans or programs
October 1 - October 31 115,448 $ 146.66 115,403 $ 129,071,000
November 1 - November 30 221,208 $ 169.14 221,208 $ 441,657,000
December 1 - December 31 154,569 $ 166.82 154,557 $ 415,874,000
Total 491,225 $ 163.13 491,168
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(1) We repurchased and canceled 45 and 12 shares of our common stock at a weighted average price of $143.69 and $174.48 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards during October and December 2024, respectively.
Recent Sales of Unregistered Securities
None.
Stock Performance Graph
The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filings.
The performance graph below illustrates changes over the period of May 19, 2021, through December 31, 2024, in cumulative total stockholder return on the common stock as measured against the cumulative total return of the S&P 500 Index and the S&P Oil & Gas Exploration and Production Index. The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends for the index securities) from May 19, 2021, to December 31, 2024.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis represents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its 2023 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, 2024 to the year ended December 31, 2023. Discussions of our results from 2022 to 2023 that are not included in this Form 10-K can be found in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2023.
Overview
Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal properties are located in eastern Ohio targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and Springer formations. Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, improving margins and operating efficiencies and returning capital to shareholders. To accomplish these goals, we generally allocate capital to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts.
Recent Developments
Long-Term Debt and Credit Facility
In September 2024, Gulfport Operating purchased approximately 95%, or $524.3 million of the 2026 Senior Notes in a tender offer using the net proceeds received from the issuance of $650 million of its 2029 Senior Notes. The net impact of these transactions resulted in the Company extending the maturity of substantially all of the senior notes from 2026 to 2029.
Additionally, on September 12, 2024, the Company entered into the Commitment Increase, Borrowing Base Reaffirmation Agreement, and Fourth Amendment to Credit Agreement (the “Fourth Amendment”), which amended the Company’s Third Amended and Restated Credit Agreement. The Fourth Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $1.0 billion, (b) reaffirmed the borrowing base under the Credit Facility at $1.1 billion, (c) extended the maturity date under the Credit Facility to September 12, 2028, and (d) reduced the pricing grid 50 bps.
Stock Repurchase Program
On November 4, 2024, the Company's Board of Directors approved an increase to the authorized Repurchase Program from $650.0 million to $1.0 billion and extended the authorization through December 31, 2025. During the year ended December 31, 2024, the Company repurchased 1.2 million shares for $184.5 million at a weighted average price of $153.35 per share. As of December 31, 2024, the Company repurchased 5.6 million shares for $584.1 million at a weighted average price of $104.88 per share since the inception of the Repurchase Program.
2024 Operational and Financial Highlights
During 2024, we had the following notable achievements:
•Reported total net production of 1,054 MMcfe per day.
•Generated $650.0 million of operating cash flows.
•Turned to sales 19 gross operated (17.8 net) wells.
•Expanded common share repurchase program to $1.0 billion and returned $184.5 million to shareholders through the repurchase of 1.2 million shares at a weighted average price of $153.35 per share.
•Extended the maturity of substantially all long-term senior notes from 2026 to 2029.
•Extended the maturity of the Credit Facility to 2028 and increased the available commitments under the Credit Facility by $100 million.
•Exited the year with total liquidity of $899.7 million.
•Achieved MIQ certification for all Appalachian assets for the second consecutive year.
•Reported year-end estimated net proved reserves of 4.0 Tcfe.
Business and Industry Outlook
The Company's primary focus going into 2025 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately support our expected free cash flow generation. We are committed to an emphasis on sustainability and we will continue to prioritize safety, environmental stewardship, and maintaining strong relationships with the communities in which we operate. Throughout the year, we plan to maintain capital discipline, prioritizing free cash flow generation and preserving our strong financial position, while returning capital to shareholders and increasing our resource depth through incremental leasehold opportunities.
In 2024, natural gas prices continued to be volatile as spot prices ranged from $1.21 to $13.20 per MMBtu. Henry Hub averaged $2.19 per MMBtu in 2024 vs $2.53 per MMBtu in 2023. As we look into 2025, we expect continued volatility in natural gas prices. To mitigate our exposure to commodity market volatility and to help provide a level of certainty around our financial strength, we have entered into a combination of natural gas swaps and collars, representing approximately 46% of our expected 2025 production, at an average floor price of $3.59 per Mcf.
Our 2025 capital expenditure program is expected to be in a range of $370 million to $395 million.
Results of Operations
Comparison of the Year Ended December 31, 2024 and 2023
We reported net loss of $261.4 million for the year ended December 31, 2024, compared to a net income of $1.5 billion for the year ended December 31, 2023. The material changes that led to the decrease in net loss are further discussed by category on the following pages. Some totals and changes throughout the below section may not sum or recalculate due to rounding.
Natural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands)
Year Ended December 31, 2024 Year Ended December 31, 2023
Natural gas (MMcf/day)
Utica & Marcellus production volumes 810 766
SCOOP production volumes 157 194
Total production volumes 968 960
Total sales $ 714,160 $ 831,812
Average price without the impact of derivatives ($/Mcf) $ 2.02 $ 2.37
Impact from settled derivatives ($/Mcf) $ 0.80 $ 0.42
Average price, including settled derivatives ($/Mcf) $ 2.82 $ 2.79
Oil and condensate (MBbl/day)
Utica & Marcellus production volumes 2 1
SCOOP production volumes 2 3
Total production volumes 4 4
Total sales $ 101,589 $ 99,854
Average price without the impact of derivatives ($/Bbl) $ 69.64 $ 73.27
Impact from settled derivatives ($/Bbl) $ 0.11 $ (2.53)
Average price, including settled derivatives ($/Bbl) $ 69.75 $ 70.74
NGL (MBbl/day)
Utica & Marcellus production volumes 3 2
SCOOP production volumes 8 10
Total production volumes 10 12
Total sales $ 112,855 $ 119,717
Average price without the impact of derivatives ($/Bbl) $ 29.56 $ 27.29
Impact from settled derivatives ($/Bbl) $ (0.56) $ 2.07
Average price, including settled derivatives ($/Bbl) $ 29.00 $ 29.36
Total (MMcfe/day)
Utica & Marcellus production volumes 842 784
SCOOP production volumes 212 270
Total production volumes 1,054 1,054
Total sales $ 928,604 $ 1,051,383
Average price without the impact of derivatives ($/Mcfe) $ 2.41 $ 2.73
Impact from settled derivatives ($/Mcfe) $ 0.73 $ 0.40
Average price, including settled derivatives ($/Mcfe) $ 3.14 $ 3.13
Year Ended December 31, 2024 Year Ended December 31, 2023 % Change
Natural gas $ 714,160 $ 831,812 (14) %
Oil and condensate 101,589 99,854 2 %
NGL 112,855 119,717 (6) %
Total natural gas, oil and condensate and NGL sales $ 928,604 $ 1,051,383 (12) %
The decrease in natural gas sales without the impact of derivatives when comparing the year ended December 31, 2024, to the year ended December 31, 2023, was primarily due to a 15% decrease in realized natural gas prices, partially offset by a 1% increase in sales volumes. The realized price change was primarily driven by the decrease in the average Henry Hub gas index from $2.74 per Mcf in the year ended December 31, 2023, to $2.27 per Mcf during the year ended December 31, 2024. The 1% increase in natural gas production was primarily due to our 2023 and 2024 development programs in the Utica/Marcellus partially offset by natural declines and limited activity in the SCOOP.
The increase in oil and condensate sales without the impact of derivatives when comparing the year ended December 31, 2024, to the year ended December 31, 2023, was due to a 7% increase in sales volumes, partially offset by a 5% decrease in realized oil prices. The 7% increase in oil and condensate production was primarily due to commencement of sales on new wells targeting the Utica liquids window. The realized price change was primarily driven by the decrease in the average WTI crude index from $77.62 per barrel in the year ended December 31, 2023, to $75.72 per barrel during the year ended December 31, 2024.
The decrease in NGL sales without the impact of derivatives when comparing the year ended December 31, 2024, to the year ended December 31, 2023, was due to a 13% decrease in NGL sales volumes, partially offset by an 8% increase in realized prices. The 13% decrease in NGL production was primarily due to natural declines and limited 2023 development in the SCOOP. The realized price change was primarily driven by the increase in the average Mont Belvieu NGL index from $30.07 per barrel in the year ended December 31, 2023, to $32.73 per barrel during the year ended December 31, 2024.
Natural Gas, Oil and NGL Derivatives (in thousands)
The total natural gas, oil and NGL volumes hedged for the year ended December 31, 2024 and 2023, represented approximately 80% and 95%, respectively, of our total sales volumes for the applicable year.
Year Ended December 31, 2024 Year Ended December 31, 2023
Natural gas derivatives - fair value (losses) gains $ (251,019) $ 584,563
Natural gas derivatives - settlement gains 284,626 146,381
Total gains on natural gas derivatives 33,607 730,944
Oil and condensate derivatives - fair value gains 2,351 5,971
Oil and condensate derivatives - settlement gains (losses) 166 (3,272)
Total gains on oil and condensate derivatives 2,517 2,699
NGL derivatives - fair value losses (4,442) (2,414)
NGL derivatives - settlement (losses) gains (2,155) 9,090
Total (losses) gains on NGL derivatives (6,597) 6,676
Total gains on natural gas, oil and NGL derivatives $ 29,527 $ 740,319
We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. The significant change in the total gain for the year ended December 31, 2024 compared to the year ended December 31, 2023, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. The fair value losses of our hedging program totaled $253.1 million for the year ended December 31, 2024 compared to gains of $588.1 million for the year ended December 31, 2023. Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 12 of our consolidated financial statements. Our hedging program generated cash receipts of $282.6 million for the year ended December 31, 2024, compared to cash receipts of $152.2 million for the year ended December 31, 2023.
Lease Operating Expenses (in thousands, except per unit)
Year Ended December 31, 2024 Year Ended December 31, 2023 % Change
Lease operating expenses
Utica & Marcellus $ 48,321 $ 44,394 9 %
SCOOP 21,791 24,254 (10) %
Total lease operating expenses $ 70,112 $ 68,648 2 %
Lease operating expenses per Mcfe
Utica & Marcellus $ 0.16 $ 0.16 - %
SCOOP 0.28 0.25 12 %
Total lease operating expenses per Mcfe $ 0.18 $ 0.18 - %
The increase in total LOE for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily the result of increased production in Utica/Marcellus as described above.
Taxes Other Than Income (in thousands, except per unit)
Year Ended December 31, 2024 Year Ended December 31, 2023 % Change
Production taxes $ 19,385 $ 25,564 (24) %
Property taxes 8,174 6,160 33 %
Other 2,178 1,993 9 %
Total taxes other than income $ 29,737 $ 33,717 (12) %
Total taxes other than income per Mcfe $ 0.08 $ 0.09 (11) %
The decrease in total and per unit taxes other than income for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily related to a decrease in production taxes resulting from the decrease in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.
Transportation, Gathering, Processing and Compression (in thousands, except per unit)
Year Ended December 31, 2024 Year Ended December 31, 2023 % Change
Transportation, gathering, processing and compression $ 351,237 $ 348,631 1 %
Transportation, gathering, processing and compression per Mcfe $ 0.91 $ 0.91 - %
Transportation, gathering, processing and compression for the year ended December 31, 2024, compared to the year ended December 31, 2023, increased in total primarily as a result of our small increase in production.
Depreciation, Depletion and Amortization (in thousands, except per unit)
Year Ended December 31, 2024 Year Ended December 31, 2023 % Change
Depreciation, depletion and amortization of oil and gas properties $ 324,078 $ 318,473 2 %
Depreciation, depletion and amortization of other property and equipment 1,645 1,242 32 %
Total depreciation, depletion and amortization $ 325,723 $ 319,715 2 %
Total depreciation, depletion and amortization per Mcfe $ 0.84 $ 0.83 1 %
Depreciation, depletion and amortization of our oil and gas properties for the year ended December 31, 2024, compared to the year ended December 31, 2023, increased 2% primarily the result of our drilling and development activities during 2023 and 2024.
Impairment of Oil and Natural Gas Properties
At September 30, 2024, the net book value of our oil and gas properties exceeded the calculated ceiling. As a result, we recorded a non-cash ceiling test impairment of $30.5 million in the third quarter of 2024. The impairment resulted from declines in the full cost ceiling, which primarily resulted from the significant decrease in the 12-month average trailing price for natural gas. The 12-month average trailing price for natural gas in the third quarter of 2024 was $2.21 per MMBtu.
At December 31, 2024, the net book value of our oil and gas properties exceeded the calculated ceiling. As a result, we recorded a non-cash ceiling test impairment of $342.7 million in the fourth quarter of 2024. The impairment resulted from declines in the full cost ceiling, which primarily resulted from the significant decrease in the 12-month average trailing price for natural gas. The 12-month average trailing price for natural gas in the fourth quarter of 2024 was $2.13 per MMBtu.
Lower natural gas, oil and NGL prices can reduce the value of our assets. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine the actual ceiling test calculation and impairment analysis in future periods. Given the decline of natural gas prices through December 2024, we may have additional ceiling test impairments of our oil and natural gas properties in subsequent quarters if the 12-month average trailing price does not improve from the $2.13 per MMBtu utilized in the fourth quarter 2024 ceiling test. Any such ceiling test impairment could be material to our net earnings; however, given the inter-relationship of the various judgements made to estimate proved reserves, it is impractical to estimate the potential changes in these estimates and their impact on the impairment.
We did not record an impairment during any quarter in 2023.
General and Administrative Expenses (in thousands, except per unit)
Year Ended December 31, 2024 Year Ended December 31, 2023 % Change
General and administrative expenses, gross $ 82,478 $ 75,180 10 %
Reimbursed from third parties (14,582) (13,770) 6 %
Capitalized general and administrative expenses (25,338) (22,810) 11 %
General and administrative expenses, net $ 42,558 $ 38,600 10 %
General and administrative expenses, net per Mcfe $ 0.11 $ 0.10 10 %
The increase in total and per unit general and administrative expenses for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily driven by increases in employee compensation and headcount.
Restructuring Costs
During the year ended December 31, 2023, Gulfport recognized $4.8 million in personnel-related restructuring expenses associated with changes in the organizational structure and leadership team resulting from the appointment of Gulfport's new CEO in January 2023. Of these expenses, $1.3 million resulted from accelerated vesting of share-based grants, which are non-cash charges. The organizational changes were completed in the second quarter of 2023 and there are no remaining employee termination liabilities associated with these changes.
Interest Expense (in thousands, except per unit)
Year Ended December 31, 2024 Year Ended December 31, 2023 % Change
Interest on 2026 Senior Notes $ 31,417 $ 44,000 (29) %
Interest on 2029 Senior Notes 13,163 - 100 %
Interest on Credit Facility 14,143 13,810 2 %
Amortization of loan costs 4,208 3,256 29 %
Capitalized interest (4,771) (4,147) 15 %
Other 1,822 150 1115 %
Total interest expense $ 59,982 $ 57,069 5 %
Interest expense per Mcfe $ 0.16 $ 0.15 7 %
Due to the tender offer for the 2026 Senior Notes in the third quarter of 2024 described below, interest paid on the 2026 Senior Notes decreased 29% for the year ended December 31, 2024, compared to the year ended December 31, 2023. The Company also paid $13.2 million of interest on the 2029 Senior Notes for the year ended December 31, 2024. Interest expense on our Credit Facility increased 2% for the year ended December 31, 2024, compared to the year ended December 31, 2023, as a result of a higher average balance outstanding. Amortization of loan costs increased 29% for the year ended December 31, 2024, compared to the year ended December 31, 2023, as a result of the Third Amendment to the Credit Facility which increased the elected commitments and borrowing base and the Fourth Amendment to the Credit Facility which increased the elected commitments. The Company also capitalized $4.8 million and $4.1 million in interest expense for the years ended December 31, 2024 and 2023, respectively.
Loss on Debt Extinguishment
In September 2024, Gulfport Operating purchased and retired $524.3 million of the 2026 Senior Notes in a tender offer using net proceeds from the 2029 Senior Notes offering. The 2026 Senior Notes were tendered at an average price equal to 102.3% of the principal amount. The retirement of the 2026 Senior Notes resulted in a loss on debt extinguishment of $13.4 million, which included cash costs of $12.9 million.
Other, net (in thousands)
Year Ended December 31, 2024 Year Ended December 31, 2023 % Change
Other, net $ 7,336 $ (27,982) (126) %
Other, net in the Company's consolidated statements of operations for the year ended December 31, 2024, included approximately $4.9 million related to changes in the Company's legal reserves for certain litigation and regulatory proceedings. Additionally, Other, net included approximately $1.9 million write-down of certain of its pipe inventory that the Company does not expect to utilize in its drilling and completion activities.
As part of its Chapter 11 Cases and restructuring efforts, the Company filed motions to reject certain firm transportation agreements between the Company and affiliates of TC Energy Corporation (“TC”) and Rover Pipeline LLC (“Rover”). During the first quarter of 2023, Gulfport finalized a settlement agreement with Rover that was approved by the Bankruptcy Court on February 21, 2023. Pursuant to the settlement agreement, Gulfport and Rover agreed that the firm transportation contracts between them would be rejected. As part of the settlement, Gulfport paid a $1.0 million administrative claim, which is included in Other, net. On February 24, 2023, Gulfport received an additional $17.8 million interim distribution for its TC claim, which is also included in Other, net. Other, net in the second quarter of 2023 included a $5.0 million recoupment of previously placed collateral for certain firm transportation commitments during the Company's Chapter 11 Cases. Additionally, in the fourth quarter of 2023, Gulfport received an additional $8.3 million distribution related to its TC claim.
Income Taxes (in thousands)
For the year ended December 31, 2024, we had an effective tax rate of 18% and an income tax benefit of $56.1 million. For the year ended December 31, 2023, the Company's effective tax rate was (56)% and an income tax benefit of $525.2 million. The higher effective tax rate for the year ended December 31, 2024 is primarily related to the valuation allowance the Company released during the third quarter of 2023. See Note 10 of our consolidated financial statements for further discussion of our income tax benefit.
Liquidity and Capital Resources
Overview. We strive to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility, fund our development projects, operations and capital expenditures and return capital to shareholders. We utilize derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company’s cash flows. We generally fund our operations, planned capital expenditures and any share repurchases with cash flow from our operating activities, cash on hand, and borrowings under our Credit Facility. Additionally, we may access debt and equity markets and sell properties to enhance our liquidity. There is no guarantee that the debt or equity capital markets will be available to us on acceptable terms or at all.
For the year ended December 31, 2024, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations and access to the debt markets, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases, dividend payments on our preferred stock and discretionary acreage acquisitions.
We believe our annual free cash flow generation, borrowing capacity under the Credit Facility and cash on hand will provide sufficient liquidity to fund our operations, capital expenditures, interest expense and share repurchases during the next 12 months and the foreseeable future.
To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes.
As of December 31, 2024, we had $1.5 million of cash and cash equivalents compared to $1.9 million as of December 31, 2023, and a net working capital deficit of $114.2 million as of December 31, 2024, compared to net working capital of $52.4 million as of December 31, 2023. As of December 31, 2024, our net working capital deficit includes no debt due in the next 12 months. Our total principal amount of funded debt as of December 31, 2024, was $713.7 million compared to $668.0 million as of December 31, 2023. See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.
As of February 20, 2025, we had $3.1 million of cash and cash equivalents, $10.0 million borrowings under our Credit Facility, $63.9 million of letters of credit outstanding, $25.7 million of outstanding 2026 Senior Notes and $650.0 million of outstanding 2029 Senior Notes.
Debt. In May 2021, we issued our 2026 Senior Notes. The 2026 Senior Notes are guaranteed on a senior unsecured basis by each of the Company’s subsidiaries that guarantee the Credit Facility. In September 2024, Gulfport Operating purchased approximately 95%, or $524.3 million, of the 2026 Senior Notes in a tender offer using net proceeds received from the private placement of the 2029 Senior Notes. This resulted in extending the maturity of substantially all of our senior notes from 2026 to 2029.
Additionally, on May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Credit Facility. The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $900 million, (b) increased the borrowing base under the Credit Facility to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility to $75 million, and (d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not been refinanced, redeemed or repaid in full on or prior to such 91st day. On April 18, 2024, Gulfport completed its semi-annual borrowing base redetermination under its Credit Facility during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million.
On September 12, 2024, the Company entered into the Commitment Increase, Borrowing Base Reaffirmation Agreement, and Fourth Amendment to Credit Agreement (the “Fourth Amendment”), which amended the Company’s Third Amended and Restated Credit Agreement. The Fourth Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $1.0 billion, (b) reaffirmed the borrowing base under the Credit Facility at $1.1 billion, (c) extended the maturity date under the Credit Facility to September 12, 2028, and (d) reduced the pricing grid 50 bps.
We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt and preferred stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.
See Note 4 of our consolidated financial statements for additional discussion of our outstanding debt.
Dividends on Preferred Stock. As discussed in Note 5 of our consolidated financial statements, holders of preferred stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of preferred stock (“PIK Dividends”). We currently have the option to pay either cash dividends or PIK Dividends on a quarterly basis.
During the years ended December 31, 2024 and 2023, the Company paid $4.2 million and $4.8 million, respectively, of cash dividends to holders of our preferred stock.
Supplemental Guarantor Financial Information. The 2026 Senior Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our Credit Facility or certain other debt (the “2026 Senior Notes Guarantors”). The 2026 Senior Notes are not guaranteed by Grizzly Holdings or Mule Sky, LLC. The 2026 Senior Notes Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the 2026 Senior Notes Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The 2026 Senior Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the 2026 Senior Notes.
The 2029 Senior Notes are guaranteed on a senior unsecured basis by Gulfport and certain of Gulfport’s wholly owned subsidiaries (collectively, the “2029 Senior Notes Guarantors” and, together with the 2026 Senior Notes Guarantors, the “Guarantors”) and certain future subsidiaries of Gulfport that become borrowers or guarantors under any credit agreement with an aggregate principal amount outstanding or commitment amount in excess of $15 million. The 2029 Senior Notes Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the 2029 Senior Notes Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank (i) senior in right of payment to any future subordinated indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (ii) pari passu in right of payment with all existing and future unsecured senior indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (iii) effectively junior to any secured indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, including indebtedness under the credit agreement, to the extent of the value of the collateral securing such indebtedness, and (iv) structurally subordinated in right of payment to all indebtedness and other liabilities of Gulfport Operating’s subsidiaries that are not 2029 Senior Notes Guarantors.
SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements. The Parent and Guarantor subsidiaries comprise our material operations. Therefore, we concluded that the presentation of the Summarized Financial Information is not required as our Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements.
Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 12 of our consolidated financial statements for further discussion of derivatives and hedging activities.
Subsequent to December 31, 2024 and as of February 20, 2025, we entered into the following natural gas, oil, and NGL derivative contracts:
Period Type of Derivative Instrument Index Daily Volume Weighted
Average Price
Natural Gas (MMBtu/d) ($/MMBtu)
2025 Swaps NYMEX Henry Hub 18,301 $3.85
2026 Basis Swaps Rex Zone 3 40,000 $(0.17)
Oil (Bbl/d) ($/Bbl)
2025 Swaps NYMEX WTI 1,000 $70.87
Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2024 (in thousands):
Payment due by period
Contractual Obligations Total 2025 2026-2027 2028-2029 2030 and Thereafter
Long-term debt(1):
Principal $ 713,702 $ - $ 25,702 $ 688,000 $ -
Interest 220,923 44,481 88,692 87,750 -
Firm transportation and gathering contracts(2)
1,147,946 140,434 270,729 273,366 463,417
Other operational commitments(3)
13,791 13,791 - - -
Operating lease liabilities(4)
6,228 5,657 571 - -
Total contractual cash obligations(5)
$ 2,102,590 $ 204,363 $ 385,694 $ 1,049,116 $ 463,417
_____________________
(1) The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations. See Note 4 of our consolidated financial statements for a description of our long-term debt.
(2) See Note 17 of our consolidated financial statements for further discussion of our firm transportation and gathering commitments.
(3) See Note 17 of our consolidated financial statements for a description of our other operational commitments.
(4) See Note 9 of our consolidated financial statements for a description of our operating lease liabilities.
(5) This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 12 and 3 of our consolidated financial statements, respectively.
Off-balance Sheet Arrangements. We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2024, our material off-balance sheet arrangements and transactions include $63.8 million in letters of credit outstanding against our Credit Facility and $44.9 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily for certain firm transportation agreements. Additionally, the Company entered into various contractual commitments to purchase inventory and other material to be used in future activities. The Company's commitment to purchase these materials exists through 2025, with approximately $13.8 million remaining. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 17 of our consolidated financial statements for further discussion of the various financial guarantees we have issued.
Capital Expenditures. Our capital expenditures have historically been related to the execution of our drilling and completion activities in addition to certain lease acquisition activities. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices. For the year ended December 31, 2024, the Company's incurred capital expenditures totaled $430.1 million, of which $327.4 million related to drilling and completion activities, $57.9 million related to maintenance leasehold and land investment and $44.8 million related to discretionary acreage acquisitions.
Our drilling and completion capital expenditures for 2025 are currently estimated to be in the range of $335 million to $355 million. Also, we currently expect to spend approximately $35 million to $40 million in 2025 for maintenance leasehold and land investment, which is focused on near-term drilling programs and facilitating increases in our working interests and lateral footage in units we plan to drill in 2025, 2026 and 2027. We expect this capital program to result in approximately 1,040 to 1,065 MMcfe per day of production in 2025.
Commodity Price Risk. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2024, WTI prices ranged from $66.73 to $87.69 per barrel and the Henry Hub spot market price of natural gas ranged from $1.21 to $13.20 per MMBtu. During 2023, WTI prices ranged from $66.61 to $93.67 per barrel and the Henry Hub spot market price of natural gas ranged from $1.74 to $3.78 per MMBtu. If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities.
See Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” for further information regarding our open derivative instruments at December 31, 2024.
Sources and Uses of Cash
The following table presents the major changes in cash and cash equivalents for the year ended December 31, 2024 and 2023 (in thousands):
Year Ended December 31, 2024 Year Ended December 31, 2023
Net cash provided by operating activities $ 650,033 $ 723,181
Additions to oil and natural gas properties (454,098) (537,360)
Debt activity, net 32,761 (27,000)
Debt issuance and loan commitment fees (14,933) (7,068)
Repurchases of common stock (184,477) (149,165)
Dividends on preferred stock (4,230) (4,840)
Shares exchanged for tax withholdings (23,614) (3,207)
Other (1,898) 129
Net change in cash and cash equivalents $ (456) $ (5,330)
Cash and cash equivalents at end of period $ 1,473 $ 1,929
Net cash provided by operating activities. Net cash provided by operating activities was $650.0 million for the year ended December 31, 2024, compared to $723.2 million for the year ended December 31, 2023. The decrease was primarily the result of a decrease in our natural gas revenues.
Additions to oil and natural gas properties. During the year ended December 31, 2024, we spud 20 gross (19.7 net) operated wells and commenced sales from 16 gross (15.4 net) operated wells targeting the Utica formation for a total cost incurred of approximately $259.8 million. During the year ended December 31, 2024, we spud 2 gross (1.8 net) operated wells and commenced sales from 3 gross (2.4 net) operated wells in the SCOOP for a total incurred cost of approximately $63.8 million. Additionally, the Company incurred $57.9 million related to maintenance leasehold and land investment and $44.8 million related to discretionary acreage acquisitions.
Drilling and completion costs discussed above reflect incurred costs while drilling and completion costs presented in the table below reflect cash payments for drilling and completions. Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle. Cash capital expenditures for the year ended December 31, 2024 and 2023, were as follows (in thousands):
Year Ended December 31, 2024 Year Ended December 31, 2023
Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costs $ 325,129 $ 413,258
Leasehold acquisitions 102,630 101,191
Other 26,339 22,911
Total oil and natural gas property expenditures $ 454,098 $ 537,360
Debt activity, net. During the year ended December 31, 2024, the Company had $956.0 million and $1.0 billion in borrowings and repayments, respectively, on its Credit Facility. In September 2024, the Company purchased $524.3 million of the 2026 Senior Notes in a tender offer. The retirement of the 2026 Senior Notes resulted in a loss on debt extinguishment of $13.4 million, which included cash costs of $12.9 million. The Company also issued $650.0 million aggregate principal amount of its 6.750% senior notes due 2029. As of February 20, 2025, the Company had $10.0 million in borrowings outstanding on its Credit Facility.
Debt issuance and loan commitment fees. During the year ended December 31, 2024, the Company incurred debt issuance and loan commitment fees of $14.9 million, as compared to $7.1 million during the year ended December 31, 2023. The increase was primarily related to the issuance of the 2029 Senior Notes and the Fourth Amendment to the Credit Facility. See Note 4 of our consolidated financial statements for further discussion of the long-term debt activity.
Repurchases of common stock. During the year ended December 31, 2024, the Company repurchased 1.2 million shares for approximately $184.5 million under the Repurchase Program at a weighted average price of $153.35 per share. For the same period in 2023, the Company repurchased 1.5 million shares for $148.9 million at a weighted average price of $101.53 per share. As of February 20, 2025, we repurchased 5.6 million shares for approximately $593.2 million under the Repurchase Program at a weighted average price of $105.57 per share.
Dividends on preferred stock. During the year ended December 31, 2024, the Company paid $4.2 million of cash dividends to holders of our preferred stock compared to $4.8 million in the year ended December 31, 2023.
Shares exchanged for tax withholdings. During the year ended December 31, 2024, the Company paid $23.6 million of shares exchanged for tax withholdings compared to $3.2 million in the year ended December 31, 2023. The increase in shares traded for taxes was primarily due to the vesting of certain PSU awards as discussed in Note 7 of our consolidated financial statements.
Other. During the year ended December 31, 2024, the Company incurred other expenses of $1.9 million, as compared to other income of $0.1 million paid during the year ended December 31, 2023. The change was primarily related to proceeds from sales of oil and gas properties of $2.6 million during the year ended December 31, 2023.
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions we consider to be most significant to our financial statements are discussed below. Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors.
Oil and Natural Gas Properties. We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized.
Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.
We review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test.
Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2024. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. During 2024, the Company recognized ceiling test impairments of $373.2 million and did not record an impairment of its oil and natural gas properties for the year ended December 31, 2023. See Oil and Natural Gas Properties in Note 1 of our consolidated financial statements for further information on the full cost method of accounting.
Oil, Natural Gas and NGL Reserves. Estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Note 20 of our consolidated financial statements for further information.
Income Taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. At each reporting period, the Company weighs all available positive and negative evidence to determine whether its deferred tax assets are more likely than not to be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry. Based upon the Company’s analysis, the Company currently believes that it is more likely than not that a portion of the Company's federal and state deferred tax assets will be utilized.
Revenue Recognition. We derive almost all of our revenue from the sale of natural gas, crude oil and NGL produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. Historically, our actual payments received have not significantly deviated from our accruals.
Derivative Instruments. We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. All derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures.
The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Our current commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Natural Gas, Oil and Natural Gas Liquids Derivative Instruments. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.
Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse natural gas, oil and NGL price changes is to hedge into strengthening natural gas, oil and NGL futures markets when prices reach levels that management believes provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas storage inventory levels, industry decline rates for base production and weather trends. Executive management is involved in all risk management activities and the Board of Directors reviews our derivative program at its quarterly board meetings.
We use derivative instruments to achieve our risk management objectives, including swaps, options and costless collars. All of these are described in more detail below. We typically use swaps for a large portion of the oil and natural gas price risk we hedge. We have also sold calls in the past to take advantage of premiums associated with market price volatility.
We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of estimated production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions are typically reversed. The actual fixed prices on our derivative instruments is derived from the reference prices from third-party indices such as NYMEX. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.
We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter the original derivative position.
We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves, discount factors and option pricing models. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 15 of our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.
As of December 31, 2024, our natural gas, oil, and NGL derivative instruments consisted of the following types of instruments:
•Swaps: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options.
•Basis Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.
•Costless Collars: Each two-way price collar has a set floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, the Company will cash-settle the difference with the counterparty.
•Call Options: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we would receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
Our hedge arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or commodity prices increase. At December 31, 2024, we had a net liability derivative position of $12.9 million, compared to a net asset derivative position of $240.2 million as of December 31, 2023. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have increased our liability by approximately $82.3 million, while a 10% decrease in underlying commodity prices would have decreased our liability by approximately $81.8 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument. For more information regarding the Company's commodity derivative transactions, refer to Note 12 of our consolidated financial statements.
Counterparty Credit Risk. The Company routinely monitors and manages its exposure to counterparty risk related to derivative contracts by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties public credit ratings, and avoiding concentration of credit exposure by transacting with multiple counterparties. The Company's commodity derivative contract counterparties are typically financial institutions with investment-grade credit ratings. The Company enters into International Swap Dealers Association Master Agreements (“ISDA”) with each of its derivative counterparties prior to executing derivative contracts. The terms of the ISDA provide, among other things, the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or counterparty to a derivative contract.
Interest Rate Risk. Our Credit Facility is structured under floating rate terms, as advances under these facilities may be in the form of either base rate loans or term benchmark loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the United States or, if the term benchmark rates are elected, the term benchmark rates. At December 31, 2024, we had $38.0 million in borrowings outstanding under our Credit Facility which bore interest at the weighted average rate of 8.23% for the year ended December 31, 2024. A 1% increase in the average interest rate would increase interest expense by approximately $0.4 million based on outstanding borrowings under our Credit Facility at December 31, 2024. As of December 31, 2024, we did not have any interest rate swaps to hedge our interest risks.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders' Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
2. Segment Information
3. Property and Equipment
4. Long-Term Debt
5. Mezzanine Equity
6. Equity
7. Stock-Based Compensation
8. Revenue From Contracts With Customers
9. Leases
10. Income Taxes
11. Earnings Per Share
12. Derivative Instruments
13. Restructuring Costs
14. Investments
15. Fair Value Measurements
16. Related Party Transactions
17. Commitments
18. Contingencies
19. Subsequent Events
20. Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Gulfport Energy Corporation
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2024 and 2023, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 26, 2025 expressed an unqualified opinion.
Basis for opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Depletion, depreciation and amortization expense and impairment of oil and gas properties impacted by the Company’s estimation of proved reserves
As described further in Note 1 and Note 3 to the consolidated financial statements, the Company uses the full cost method of accounting for oil and gas operations. This accounting method requires management to make estimates of proved reserves and related future net cash flows to compute and record depletion, depreciation and amortization, as well as to assess potential impairment of oil and gas properties (the full cost ceiling test). To estimate the volume of proved oil and gas reserve quantities, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with those proved reserves to determine if wells are expected to be economical under the appropriate pricing assumptions that are required in the estimation of depletion, depreciation and amortization expense and assessment of potential impairment. We identified the estimation of proved reserves as it relates to the
recognition of depletion, depreciation and amortization expense and the assessment of potential impairment as a critical audit matter.
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that relatively minor changes in certain inputs and assumptions that are necessary to estimate the volume and future cash flows of the Company’s proved reserves could have a significant impact on the measurement of depletion, depreciation and amortization expense and the assessment of potential impairment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.
Our audit procedures related to the estimation of proved reserves included the following, among others:
•Tested the design and operating effectiveness of internal controls relating to management’s estimation of proved reserves for the purpose of estimating depletion, depreciation and amortization expense and assessment of potential impairment for the Company’s oil and gas properties.
•Evaluated the independence, objectivity, and professional qualifications of the Company’s reserves specialist, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes and read the report prepared by the Company’s reserve specialist.
•Evaluated sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions that are derived from the Company’s accounting records, such as historical pricing differentials, operating costs, estimated future development costs, and ownership interest. We tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis where applicable. Specifically, our audit procedures involved testing management’s assumptions as follows:
◦Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year;
◦Tested the model used to estimate the operating costs at year end and compared to historical operating costs;
◦Tested the model used to determine the future development costs and compared estimated future development costs used in the reserve report to amounts expended for recently drilled and completed wells, where applicable;
◦Tested the working and net revenue interests used in the reserve report by inspecting land and division order records;
◦Evaluated the Company’s evidence supporting the proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties; and
◦Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year’s reserve report.
/s/ GRANT THORNTON LLP
We have served as the Company's auditor since 2005.
Oklahoma City, Oklahoma
February 26, 2025
GULFPORT ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31, 2024 December 31, 2023
Assets
Current assets:
Cash and cash equivalents $ 1,473 $ 1,929
Accounts receivable-oil, natural gas, and natural gas liquids sales 155,942 122,479
Accounts receivable-joint interest and other 8,727 22,221
Prepaid expenses and other current assets 7,086 16,951
Short-term derivative instruments 58,085 233,226
Total current assets 231,313 396,806
Property and equipment:
Oil and natural gas properties, full-cost method
Proved oil and natural gas properties 3,349,805 2,904,519
Unproved properties 221,650 204,233
Other property and equipment 11,291 9,165
Total property and equipment 3,582,746 3,117,917
Less: accumulated depletion, depreciation, amortization and impairment (1,564,475) (865,618)
Total property and equipment, net 2,018,271 2,252,299
Other assets:
Long-term derivative instruments 6,003 47,566
Deferred tax asset 581,233 525,156
Operating lease assets 6,099 14,299
Other assets 22,778 31,487
Total other assets 616,113 618,508
Total assets $ 2,865,697 $ 3,267,613
Liabilities, Mezzanine Equity and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities $ 298,081 $ 309,532
Short-term derivative instruments 41,889 21,963
Current portion of operating lease liabilities 5,538 12,959
Total current liabilities 345,508 344,454
Non-current liabilities:
Long-term derivative instruments 35,081 18,602
Asset retirement obligation 32,949 29,941
Non-current operating lease liabilities 561 1,340
Long-term debt 702,857 667,382
Total non-current liabilities 771,448 717,265
Total liabilities 1,116,956 1,061,719
Commitments and contingencies (Notes 17 and 18)
Mezzanine equity:
Preferred stock - $0.0001 par value, 110.0 thousand shares authorized, 37.3 thousand issued and outstanding at December 31, 2024, and 44.2 thousand issued and outstanding at December 31, 2023
37,348 44,214
Stockholders’ equity:
Common stock - $0.0001 par value, 42.0 million shares authorized, 17.8 million issued and outstanding at December 31, 2024, and 18.3 million issued and outstanding at December 31, 2023
2 2
Additional paid-in capital 129,059 315,726
Common stock held in reserve, 0 shares at December 31, 2024, and 62.0 thousand shares at December 31, 2023
- (1,996)
Retained earnings 1,582,332 1,847,948
Total stockholders’ equity 1,711,393 2,161,680
Total liabilities, mezzanine equity and stockholders’ equity $ 2,865,697 $ 3,267,613
See accompanying notes to consolidated financial statements.
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands)
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
REVENUES:
Natural gas sales $ 714,160 $ 831,812 $ 1,998,452
Oil and condensate sales 101,589 99,854 147,444
Natural gas liquid sales 112,855 119,717 184,963
Net gain (loss) on natural gas, oil and NGL derivatives 29,527 740,319 (999,747)
Total revenues 958,131 1,791,702 1,331,112
OPERATING EXPENSES:
Lease operating expenses 70,112 68,648 64,790
Taxes other than income 29,737 33,717 60,139
Transportation, gathering, processing and compression 351,237 348,631 357,246
Depreciation, depletion and amortization 325,723 319,715 267,761
Impairment of oil and natural gas properties 373,214 - -
General and administrative expenses 42,558 38,600 35,304
Restructuring costs - 4,762 -
Accretion expense 2,307 2,782 2,746
Total operating expenses 1,194,888 816,855 787,986
(LOSS) INCOME FROM OPERATIONS (236,757) 974,847 543,126
OTHER EXPENSE (INCOME):
Interest expense 59,982 57,069 59,773
Loss on debt extinguishment 13,388 - -
Other, net 7,336 (27,982) (11,348)
Total other expense 80,706 29,087 48,425
(LOSS) INCOME BEFORE INCOME TAXES (317,463) 945,760 494,701
INCOME TAX BENEFIT:
Current - - -
Deferred (56,077) (525,156) -
Total income tax benefit (56,077) (525,156) -
NET (LOSS) INCOME (261,386) 1,470,916 494,701
Dividends on preferred stock (4,230) (4,840) (5,444)
Participating securities - preferred stock - (212,360) (76,401)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS $ (265,616) $ 1,253,716 $ 412,856
NET (LOSS) INCOME PER COMMON SHARE:
Basic $ (14.72) $ 67.24 $ 20.45
Diluted $ (14.72) $ 66.46 $ 20.32
Weighted average common shares outstanding-Basic 18,050 18,645 20,185
Weighted average common shares outstanding-Diluted 18,050 18,902 20,347
See accompanying notes to consolidated financial statements.
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
Common Stock Common Stock Held in Reserve Treasury Stock Paid-in
Capital Retained Earnings (Accumulated
Deficit) Total Stockholders’
Equity
Shares Amount Shares Amount
Balance at January 1, 2022 21,537 $ 2 (938) $ (30,216) $ - $ 692,521 $ (112,829) 549,478
Net income - - - - - - 494,701 494,701
Conversion of preferred stock 407 - - - - 5,601 - 5,601
Stock compensation - - - - - 8,670 - 8,670
Repurchase of common stock under Repurchase Program (2,896) - - - (286) (250,482) - (250,768)
Issuance of common stock held in reserve - - 876 28,220 - - - 28,220
Issuance of common stock upon vesting of share-based awards 68 - - - - - - -
Common stock withheld for income taxes on share-based awards (19) - - - - (1,623) - (1,623)
Dividends on preferred stock - - - - - (5,444) - (5,444)
Balance at December 31, 2022 19,097 $ 2 (62) $ (1,996) $ (286) $ 449,243 $ 381,872 $ 828,835
Net income - - - - - - 1,470,916 1,470,916
Conversion of preferred stock 593 - - - - 8,081 - 8,081
Stock compensation - - - - - 13,525 - 13,525
Repurchase of common stock under Repurchase Program (1,470) - - - 286 (151,912) - (151,626)
Issuance of common stock upon vesting of share-based awards 102 - - - - - - -
Common stock withheld for income taxes on share-based awards (34) - - - - (3,207) - (3,207)
Dividends on preferred stock - - - - - (4) (4,840) (4,844)
Balance at December 31, 2023 18,288 $ 2 (62) $ (1,996) $ - $ 315,726 $ 1,847,948 $ 2,161,680
Net loss - - - - - - (261,386) (261,386)
Conversion of preferred stock 500 - - - - 6,866 - 6,866
Stock compensation - - - - - 16,355 - 16,355
Repurchase of common stock under Repurchase Program (1,203) - - - - (186,271) - (186,271)
Issuance of common stock held in reserve - - 62 1,996 - - - 1,996
Issuance of common stock upon vesting of share-based awards 363 - - - - - - -
Common stock withheld for income taxes on share-based awards (150) - - - - (23,614) - (23,614)
Dividends on preferred stock - - - - - (3) (4,230) (4,233)
Balance at December 31, 2024 17,798 $ 2 - $ - $ - $ 129,059 $ 1,582,332 $ 1,711,393
See accompanying notes to consolidated financial statements.
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Cash flows from operating activities:
Net (loss) income $ (261,386) $ 1,470,916 $ 494,701
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and amortization 325,723 319,715 267,761
Impairment of oil and natural gas properties 373,214 - -
Loss on debt extinguishment 13,388 - -
Net (gain) loss on derivative instruments (29,527) (740,319) 999,747
Net cash receipts (payments) on settled derivative instruments 282,637 152,199 (1,053,810)
Deferred income tax benefit (56,077) (525,156) -
Stock-based compensation expense 10,958 9,480 5,723
Other, net 6,315 7,645 5,528
Changes in operating assets and liabilities, net (15,212) 28,701 19,427
Net cash provided by operating activities 650,033 723,181 739,077
Cash flows from investing activities:
Additions to oil and natural gas properties (454,098) (537,360) (460,780)
Proceeds from sale of oil and natural gas properties 225 2,659 3,360
Other, net (2,120) (2,526) (875)
Net cash used in investing activities (455,993) (537,227) (458,295)
Cash flows from financing activities:
Principal payments on Credit Facility (1,036,000) (998,000) (2,082,000)
Borrowings on Credit Facility 956,000 971,000 2,063,000
Issuance of 2029 Senior Notes 650,000 - -
Early retirement of 2026 Senior Notes (524,298) - -
Premium paid on 2026 Senior Notes (12,941) - -
Debt issuance costs and loan commitment fees (14,933) (7,068) (234)
Dividends on preferred stock (4,230) (4,840) (5,444)
Repurchase of common stock under Repurchase Program (105,344) (108,735) (250,482)
Repurchase of common stock under Repurchase Program - related party (79,133) (40,430) -
Shares exchanged for tax withholdings (23,614) (3,207) (1,623)
Other, net (3) (4) -
Net cash used in financing activities (194,496) (191,284) (276,783)
Net change in cash and cash equivalents (456) (5,330) 3,999
Cash and cash equivalents at beginning of period 1,929 7,259 3,260
Cash and cash equivalents at end of period $ 1,473 $ 1,929 $ 7,259
See accompanying notes to consolidated financial statements.
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Company
Gulfport Energy Corporation 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. The Company's principal properties are located in eastern Ohio targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and Springer formations.
Basis of Presentation
The consolidated financial statements included in this Annual Report are prepared in accordance with GAAP and the rules and regulations of the SEC.
Risks and Uncertainties
The Company's revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil, gas and NGL, which are affected by many factors outside of Gulfport’s control, including changes in market supply and demand. Field-level prices received for Gulfport’s production have historically been volatile and may be subject to significant fluctuations in the future. The Company's derivative contracts serve to mitigate in part the effect of this price volatility on the Company's cash flows, and the Company has derivative contracts in place for a portion of its expected future natural gas, crude oil and NGL production. See Note 12 for further discussion of the Company's commodity derivative contracts.
Principles of Consolidation
The consolidated financial statements include the Company and its wholly-owned subsidiaries, Gulfport Energy Operating Corporation, Grizzly Holdings Inc., Jaguar Resources LLC, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Westhawk Minerals LLC, Puma Resources, Inc., Gulfport Appalachia LLC, Gulfport Midstream Holdings, LLC, Gulfport MidCon, LLC and Mule Sky LLC. All intercompany balances and transactions are eliminated in consolidation.
Segments
The Company's assets and operations consist of one reportable segment. The Company has a single management team that administers all properties as a whole rather than by geographic operating area. See Note 2, Segment Information, for further detail.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the consolidated financial statements.
Accounts Receivable
The Company sells oil and natural gas to various purchasers and participates in drilling, completion and operation of oil and natural gas wells with joint interest owners on properties the Company operates. The related receivables are classified as accounts receivable-oil and natural gas sales and accounts receivable-joint interest and other, respectively. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and the industry as a whole. No material allowance was deemed necessary at December 31, 2024 and December 31, 2023.
Oil and Gas Properties
The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are capitalized. Additionally, interest is capitalized on the cost of unproved oil and natural gas properties that are excluded from amortization for which exploration and development activities are in process or expected within the next 12 to 18 months.
Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue (only to the extent that the derivative instruments are treated as cash flow hedges for accounting purposes), and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of unproved properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash write-down is required. Ceiling test impairment can result in a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. The Company recognized ceiling test impairments of $373.2 million during the year ended December 31, 2024. There were no impairments recognized in 2023 or 2022.
Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties, are depleted by an equivalent units-of-production method, converting barrels to gas at the ratio of one barrel of oil to six Mcf of gas. No gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proved oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled approximately $221.7 million and $204.2 million at December 31, 2024 and December 31, 2023, respectively. These costs are reviewed quarterly by management for impairment. If impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for exploration and development.
The Company accounts for its abandonment and restoration liabilities by recording a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.
Other Property and Equipment
Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Depreciation of other property and equipment is provided on a straight-line basis over the estimated useful lives of the related assets, which range from 3 to 30 years.
Net Income (Loss) per Common Share
Basic net income (loss) per common share is computed by dividing income attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock. Potential common shares are not included if their effect would be anti-dilutive. Calculations of basic and diluted net income (loss) per common share are illustrated in Note 11.
Income Taxes
The amount of income taxes recorded by Gulfport requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which realization becomes determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.
The Company is subject to U.S. federal income tax as well as income tax of multiple state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years prior to 2021. As of December 31, 2024, the Company has no unrecognized tax benefits that would have a material impact on the effective rate. The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. See Note 10 for further discussion of the Company's income taxes.
Revenue Recognition
The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGL. Sales of natural gas, oil and condensate and NGL are recognized in the period that the performance obligations are satisfied. The Company generally considers the delivery of each unit (MMBtu or Bbl) to be separately identifiable and represents a distinct performance obligation that is satisfied at a point-in-time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to (i) whether the purchaser can direct the use of the product, (ii) the transfer of significant risks, (iii) the Company’s right to payment and (iv) transfer of legal title.
Gathering, processing and compression fees attributable to gas processing, as well as any transportation fees, including firm transportation fees, incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression in the accompanying consolidated statements of operations.
Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered.
The recognition of gains or losses on derivative instruments is outside the scope of ASC 606, Revenue from Contracts with Customers and is not considered revenue from contracts with customers subject to ASC 606. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales.
The Company has elected to exclude from the measurement of the transaction price all taxes assessed by governmental authorities that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Company from a customer, such as sales tax, use tax, value-added tax and similar taxes.
See Note 8 for additional discussion of revenue from contracts with customers.
Accounting for Stock-based Compensation
Share-based payments to employees and members of its Board of Directors, including grants of restricted stock units and performance vesting restricted stock units, are recognized as equity at the fair value on the date of grant and to be expensed over the applicable vesting period. The vesting periods for restricted shares generally range between one year to three years with annual vesting installments. The Company does not recognize expense based on an estimate of forfeitures, but rather recognizes the impact of forfeitures only as they occur.
Derivative Instruments
The Company utilizes commodity derivatives to manage the price risk associated with forecasted sale of its natural gas, crude oil and NGL production. All derivative instruments are recognized as assets or liabilities in the consolidated balance sheets, measured at fair value. The Company does not apply hedge accounting to derivative instruments. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount and timing of asset retirement obligations, the realization of deferred tax assets, the fair value determination of acquired assets and liabilities and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves is used to compute depletion, depreciation, amortization and impairment of oil and gas properties. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Reclassification
Certain reclassifications have been made to prior period financial statements and related disclosures to conform to current period presentation. These reclassifications have no impact on previous reported total assets, total liabilities, net income (loss) or total operating cash flows.
Supplemental Cash Flow and Non-Cash Information (in thousands)
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Supplemental disclosure of cash flow information:
Interest payments, net of amounts capitalized $ 46,406 $ 53,820 $ 57,685
Changes in operating assets and liabilities, net:
Accounts receivable - oil, natural gas, and natural gas liquids sales (33,463) 155,925 (45,550)
Accounts receivable - joint interest and other 13,494 (743) (1,095)
Accounts payable and accrued liabilities 4,067 (126,329) 59,879
Prepaid expenses 667 (215) 4,863
Other assets 23 63 1,330
Total changes in operating assets and liabilities, net $ (15,212) $ 28,701 $ 19,427
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation $ 5,397 $ 4,046 $ 2,948
Asset retirement obligation capitalized 682 588 2,169
Asset retirement obligation removed due to divestiture and settlements - (1,267) (7)
Asset retirement obligation revisions 19 (5,077) 2,072
Release of common stock held in reserve 1,996 - 28,220
Unamortized 2026 Senior Notes debt issuance costs 447 - -
Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities consisted of the following (in thousands):
December 31, 2024 December 31, 2023
Revenue payable and suspense $ 139,703 $ 148,598
Accounts payable 34,668 43,517
Accrued capital expenditures 20,229 38,322
Accrued transportation, gathering, processing, and compression 36,170 32,849
Accrued contract rejection damages and shares held in reserve - 1,996
Other accrued liabilities 67,311 44,250
Total accounts payable and accrued liabilities $ 298,081 $ 309,532
Other, net
Other, net in the Company's consolidated statements of operations for the year ended December 31, 2024, included approximately $4.9 million related to changes in the Company's legal reserves for certain litigation and regulatory proceedings. Additionally, Other, net included approximately $1.9 million as a result of a write-down of certain of its pipe inventory that the Company does not expect to utilize in its drilling and completion activities.
As part of its Chapter 11 Cases and restructuring efforts, the Company filed motions to reject certain firm transportation agreements between the Company and affiliates of TC Energy Corporation (“TC”) and Rover Pipeline LLC (“Rover”). During the first quarter of 2023, Gulfport finalized a settlement agreement with Rover that was approved by the Bankruptcy Court on February 21, 2023. Pursuant to the settlement agreement, Gulfport and Rover agreed that the firm transportation contracts between them would be rejected. As part of the settlement, Gulfport paid a $1.0 million administrative claim, which is included in Other, net. On February 24, 2023, Gulfport received an additional $17.8 million interim distribution for its TC claim, which is also included in Other, net. Other, net in the second quarter of 2023 included a $5.0 million recoupment of previously placed collateral for certain firm transportation commitments during the Company's Chapter 11 Cases. Additionally, in the fourth quarter of 2023, Gulfport received an additional $8.3 million distribution related to its TC claim.
Recent Accounting Pronouncements
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (Topic 280). The amendments require disclosure for each reportable segment, the significant expense categories and amounts that are regularly provided to the CODM and included in each reported measure of a segment’s profit or loss. Additionally, this ASU enhances interim disclosure requirements and provides new segment disclosure requirements for entities with a single reportable segment. The Company adopted ASU 2023-07 during the year ended December 31, 2024. See Note 2, Segment Information, for further detail.
In December 2023, the FASB issued ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures (Topic 740). The amendment requires annual disclosure of additional categories of information about federal, state, and foreign income taxes in the rate reconciliation table and to provide more details about the reconciling items in some categories if the items meet a quantitative threshold. Additionally, the amendment requires disclosure of annual income taxes paid (net of refunds received) disaggregated by federal, state, and foreign taxes and to disaggregate the information by jurisdiction based on a quantitative threshold. ASU 2023-09 is effective for the Company’s annual reporting periods beginning after December 15, 2024, with early adoption permitted, and should be applied on a prospective basis, with a retrospective option. The Company is currently evaluating the effect the adoption of ASU 2023-09 will have on its disclosures and does not expect it to have a material impact on its consolidated financial statements.
In November 2024, the FASB issued ASU 2024-03, Disaggregation of Income Statement Expenses, which requires disclosures about specific types of expenses included in the expense captions presented on the face of the income statement as well as disclosures about selling expenses. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The requirements will be applied prospectively with the option for retrospective application. The Company is currently evaluating the impact that the adoption of this accounting standard will have on its financial disclosures.
2.SEGMENT INFORMATION
The Company's assets and operations consist of one reportable segment with all revenues, operating expenses and assets attributable to this segment reflected in the consolidated financial statements. The Company derives its revenue from the sale of natural gas, oil and condensate and NGL produced from its oil and natural gas properties located in the United States.
The CODM of the Company is its Chief Executive Officer. The CODM assesses entity-wide operating results and performance and decides how to allocate resources based on net (loss) income, which is reported on the consolidated statement of operations.
The measure of segment assets is reported on the consolidated balance sheets as “total assets”.
The following table presents selected financial information with respect to the Company's one operating segment for the years ended December 31, 2024, 2023 and 2022 (in thousands):
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Total revenues $ 958,131 $ 1,791,702 $ 1,331,112
Significant segment expenses
Lease operating expenses 70,112 68,648 64,790
Taxes other than income 29,737 33,717 60,139
Transportation, gathering, processing and compression 351,237 348,631 357,246
Depreciation, depletion, and amortization 325,723 319,715 267,761
Impairment of oil and gas properties 373,214 - -
General and administrative 42,558 38,600 35,304
Interest expense 59,982 57,069 59,773
Other segment expenses(1)
23,031 (20,438) (8,602)
Income tax benefit (56,077) (525,156) -
Total significant segment expenses 1,219,517 320,786 836,411
Net (loss) income $ (261,386) $ 1,470,916 $ 494,701
Capital expenditures(2)
$ 464,492 $ 521,187 $ 470,396
_____________________
(1) Other segment expenses include “Restructuring costs”, “Accretion expense”, “Loss on debt extinguishment”, and “Other, net” from the consolidated statements of operations.
(2) Capital expenditures include capitalized general and administrative costs and capitalized interest expense.
3.PROPERTY AND EQUIPMENT
The major categories of property and equipment and related accumulated DD&A are as follows (in thousands):
December 31, 2024 December 31, 2023
Proved oil and natural gas properties $ 3,349,805 $ 2,904,519
Unproved properties 221,650 204,233
Other depreciable property and equipment 10,905 8,779
Land 386 386
Total property and equipment 3,582,746 3,117,917
Accumulated DD&A and impairment (1,564,475) (865,618)
Property and equipment, net $ 2,018,271 $ 2,252,299
Oil and Natural Gas Properties
Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the Company's oil and natural gas properties. During the year ended December 31, 2024, the net book value of the Company's oil and gas properties exceeded the calculated ceiling. As a result, the Company recorded a non-cash ceiling test impairment of its oil and natural gas properties of $30.5 million in the third quarter of 2024 and $342.7 million in the fourth quarter of 2024. The impairments resulted from declines in the full cost ceiling, which primarily resulted from the significant decrease in the 12-month average trailing price for natural gas. The Company did not record an impairment of its oil and natural gas properties during 2023 or 2022.
Lower natural gas, oil and NGL prices can reduce the value of the Company’s assets. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine the actual ceiling test calculation and impairment analysis in future periods. Given the decline of natural gas prices through December 2024, we may have additional ceiling test impairments of our oil and natural gas properties in subsequent quarters if the 12-month average trailing price does not improve from the $2.13 per MMBtu utilized in the fourth quarter 2024 ceiling test. Any such ceiling test impairment could be material to our net earnings; however, given the inter-relationship of the various judgements made to estimate proved reserves, it is impractical to estimate the potential changes in these estimates and their impact on the impairment.
General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $25.3 million, $22.8 million and $20.2 million for the years ended December 31, 2024, 2023 and 2022, respectively. The average depletion rate per Mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $0.84, $0.83 and $0.74 per Mcfe for the years ended December 31, 2024, 2023 and 2022, respectively.
The following table summarizes the Company’s non-producing properties excluded from amortization by area (in thousands):
December 31, 2024 December 31, 2023
Utica & Marcellus $ 197,513 $ 177,888
SCOOP 24,137 26,345
Total unproved properties $ 221,650 $ 204,233
The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of December 31, 2024 (in thousands):
Costs Incurred in
2024 2023 2022 Prior to 2022 Total
Acquisition costs $ 58,742 $ 58,002 $ 17,288 $ 82,695 $ 216,727
Exploration costs - - - - -
Development costs 1,472 556 - - 2,028
Capitalized interest 2,895 - - - 2,895
Total oil and natural gas properties not subject to amortization $ 63,109 $ 58,558 $ 17,288 $ 82,695 $ 221,650
The Company evaluates the costs excluded from its amortization calculation at least annually. Subject to industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation typically occurs within three years to five years. However, the majority of the Company's non-producing leases in the Utica/Marcellus have five-year extension terms, which could extend this time frame beyond five years.
Asset Retirement Obligation
The following table provides a reconciliation of the Company's asset retirement obligation for the years ended December 31, 2024 and 2023 (in thousands):
Year Ended December 31, 2024 Year Ended December 31, 2023
Asset retirement obligation, beginning of period $ 29,941 $ 33,171
Liabilities incurred 682 588
Liabilities settled - (604)
Liabilities removed due to divestitures - (919)
Accretion expense 2,307 2,782
Revisions in estimated cash flows(1)
19 (5,077)
Asset retirement obligation, end of period $ 32,949 $ 29,941
_____________________
(1) Revisions represent changes in the present value of liabilities resulting from changes in estimated costs.
4.LONG-TERM DEBT
Long-term debt consisted of the following items as of December 31, 2024 and 2023 (in thousands):
December 31, 2024 December 31, 2023
6.750% senior unsecured notes due 2029
$ 650,000 $ -
8.0% senior unsecured notes due 2026
25,702 550,000
Credit Facility due 2028 38,000 -
Credit Facility due 2027 - 118,000
Net unamortized debt issuance costs (10,845) (618)
Total debt, net 702,857 667,382
Less: current maturities of long-term debt - -
Total long-term debt, net $ 702,857 $ 667,382
2029 Senior Notes
In September 2024, Gulfport Operating completed a private offering of $650.0 million aggregate principal amount of 6.750% senior notes due September 1, 2029. The 2029 Senior Notes are guaranteed on a senior unsecured basis by the Company and each of the Company's subsidiaries that guarantee the Credit Facility. Interest on the 2029 Senior Notes is payable semi-annually, on March 1 and September 1 of each year, beginning on March 1, 2025.
The net proceeds from the offering, together with cash on hand were used to purchase $524.3 million of the 2026 Senior Notes in a tender offer and repay a portion of its outstanding borrowings under the Credit Facility. The 2029 Senior Notes were issued under the 2029 Senior Notes Indenture, dated as of September 13, 2024, by and among Gulfport Operating, UMB Bank, National Association, as trustee, and the Guarantors. The 2029 Senior Notes will mature on September 1, 2029.
The 2029 Senior Notes Indenture contains covenants limiting Gulfport Operating’s and its restricted subsidiaries’ ability to (i) incur additional debt, (ii) make certain restricted payments, (iii) make certain investments (iv) create restrictions on distributions from restricted subsidiaries, (v) engage in specified sales of assets, (vi) enter into certain transactions among affiliates, (vii) engage in consolidations, mergers and acquisitions, (viii) create unrestricted subsidiaries (ix) incur or create liens. These covenants contain important exceptions, limitations and qualifications. At any time that the 2029 Senior Notes are rated investment grade, certain covenants will be terminated and cease to apply.
2026 Senior Notes
In May 2021, Gulfport Operating issued $550 million aggregate principal amount of its 8.0% senior notes due 2026. The notes are guaranteed on a senior unsecured basis by the Company and each of the Company's subsidiaries that guarantee the Credit Facility. Interest on the 2026 Senior Notes is payable semi-annually, on June 1 and December 1 of each year. The 2026 Senior Notes were issued under the 2026 Senior Notes Indentures, dated as of May 17, 2021, by and among the Issuer, UMB Bank, National Association, as trustee, and the Guarantors and mature on May 17, 2026.
The covenants of the 1145 Indenture (other than the payment covenant) require that the Company comply with the covenants of the 4(a)(2) Indenture, as amended. The 4(a)(2) Indenture contains covenants limiting the Issuer’s and its restricted subsidiaries’ ability to (i) incur additional debt, (ii) pay dividends or distributions in respect of certain equity interests or redeem, repurchase or retire certain equity interests or subordinated indebtedness, (iii) make certain investments, (iv) create restrictions on distributions from restricted subsidiaries, (v) engage in specified sales of assets, (vi) enter into certain transactions among affiliates, (vii) engage in certain lines of business, (viii) engage in consolidations, mergers and acquisitions, (ix) create unrestricted subsidiaries and (x) incur or create liens. These covenants contain important exceptions, limitations and qualifications. At any time that the 2026 Senior Notes are rated investment grade, certain covenants will be terminated and cease to apply.
As noted above, in September 2024, Gulfport Operating purchased and retired $524.3 million of its 2026 Senior Notes in a tender offer using net proceeds from the 2029 Senior Notes offering. The 2026 Senior Notes were tendered at an average price equal to 102.3% of the principal amount. The retirement of the 2026 Senior Notes resulted in a loss on debt extinguishment of $13.4 million, which included cash costs of $12.9 million.
Credit Facility
On May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Credit Facility. The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility from $700 million to $900 million, (b) increased the borrowing base under the Credit Facility from $1 billion to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility from $45 million to $75 million, and (d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not been refinanced, redeemed or repaid in full on or prior to such 91st day.
On April 18, 2024, Gulfport completed its semi-annual borrowing base redetermination during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million.
Prior to the Fourth Amendment (as defined below), the Credit Facility bore interest at a rate equal to, at the Company’s election, either (a) SOFR benchmark plus an applicable margin that varies from 2.75% to 3.75% per annum or (b) a base rate plus an applicable margin that varies from 1.75% to 2.75% per annum, based on borrowing base utilization. Prior to the Fourth Amendment, the Company was required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Credit Facility. The Company was also required to pay customary letter of credit and fronting fees.
Prior to the Fourth Amendment, the Credit Facility required the Company to maintain as of the last day of each fiscal quarter (i) a net funded leverage ratio of less than or equal to 3.25 to 1.00, and (ii) a current ratio of greater than or equal to 1.00 to 1.00.
On September 12, 2024, the Company entered into the Commitment Increase, Borrowing Base Reaffirmation Agreement, and Fourth Amendment to Credit Agreement (the “Fourth Amendment”), which amended the Company’s Third Amended and Restated Credit Agreement. The Fourth Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $1.0 billion, (b) reaffirmed the borrowing base under the Credit Facility at $1.1 billion, (c) extended the maturity date under the Credit Facility to September 12, 2028, and (d) reduced the pricing grid 50 bps.
The Credit Facility bears interest at a rate equal to, at the Company’s election, either (a) SOFR benchmark plus an applicable margin that varies from 2.25% to 3.25% per annum or (b) a base rate plus an applicable margin that varies from 1.25% to 2.25% per annum, based on borrowing base utilization. The Company is required to pay a commitment fee that varies from 0.375% to 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Credit Facility. The Company is also required to pay customary letter of credit and fronting fees.
The Credit Facility requires the Company to maintain as of the last day of each fiscal quarter (i) a net funded leverage ratio of less than or equal to 3.50 to 1.00, and (ii) a current ratio of greater than or equal to 1.00 to 1.00.
The obligations under the Credit Facility, certain swap obligations and certain cash management obligations, are guaranteed by the Company and the wholly-owned domestic material subsidiaries of the Borrower (collectively, the “Guarantors” and, together with the Borrower, the “Loan Parties”) and secured by substantially all of the Loan Parties’ assets (subject to customary exceptions).
The Credit Facility also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, entry into certain derivatives contracts, restrictions on the incurrence of liens, indebtedness, asset dispositions, restricted payments, and other customary covenants. These covenants are subject to a number of limitations and exceptions.
As of December 31, 2024, the Company had $38.0 million outstanding borrowings under the Credit Facility, $63.8 million in letters of credit outstanding and was in compliance with all covenants under the credit agreement.
For the years ended December 31, 2024 and 2023, the Credit Facility bore interest at a weighted average rate of 8.23% and 8.15%, respectively.
Interest Expense
The following schedule shows the components of interest expense for the years ended December 31, 2024, 2023 and 2022 (in thousands):
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Cash paid for interest $ 51,177 $ 57,967 $ 57,685
Change in accrued interest 9,368 (7) (826)
Capitalized interest (4,771) (4,147) -
Amortization of loan costs 4,208 3,256 2,914
Other - - -
Total interest expense $ 59,982 $ 57,069 $ 59,773
The Company capitalized $4.8 million and $4.1 million in interest expense for the years ended December 31, 2024 and 2023, respectively, to undeveloped oil and natural gas properties. The Company did not capitalize interest expense for the year ended December 31, 2022.
Fair Value of Debt
At December 31, 2024, the carrying value of the outstanding debt represented by the 2026 Senior Notes and 2029 Senior Notes were approximately $25.7 million and $639.2 million, respectively. Based on the quoted market prices (Level 1), the fair value of the 2026 Senior Notes and 2029 Senior Notes was determined to be approximately $26.0 million and $655.0 million, respectively, at December 31, 2024.
5.MEZZANINE EQUITY
The Company's amended and restated certificate of incorporation provides for, among other things, (i) the authority to issue 42 million shares of common stock with a par value of $0.0001 per share and (ii) the designation of 110,000 shares of preferred stock, with a par value of $0.0001 per share and a liquidation preference of $1,000 per share (the “Liquidation Preference”).
Preferred Stock
In May 2021, the Company issued 55,000 shares of preferred stock.
Holders of preferred stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of preferred stock (“PIK Dividends”). Gulfport currently has the option to pay either cash dividends or PIK Dividends on a quarterly basis.
Each holder of shares of preferred stock has the right (the “Conversion Right”), at its option and at any time, to convert all or a portion of the shares of preferred stock that it holds into a number of shares of common stock equal to the quotient obtained by dividing (x) the product obtained by multiplying (i) the Liquidation Preference times (ii) an amount equal to one (1) plus the Per Share Makewhole Amount (as defined in the Preferred Terms) on the date of conversion, by (y) $14.00 per share (as may be adjusted under the Preferred Terms). The shares of preferred stock outstanding at December 31, 2024 would convert to 2.7 million shares of common stock if all holders of preferred stock exercised their Conversion Right.
Gulfport may redeem all, but not less than all, of the outstanding shares of preferred stock by notice to the holders of preferred stock, at the greater of (i) the aggregate value of the preferred stock, calculated by the Current Market Price (as defined in the Preferred Terms) of the number of shares of common stock into which, subject to redemption, such preferred stock would have been converted if such shares were converted pursuant to the Conversion Right at the time of such redemption and (ii) the Liquidation Preference (the “Redemption Price”).
Following the Emergence Date, if there is a Fundamental Change (as defined in the Preferred Terms), Gulfport is required to redeem all, but not less than all, of the outstanding shares of preferred stock by cash payment of the Redemption Price per share of preferred stock within three (3) business days of the occurrence of such Fundamental Change. Notwithstanding the foregoing, in the event of a redemption pursuant to the preceding sentence, if Gulfport lacks sufficient cash to redeem all outstanding shares of preferred stock, the Company is required to redeem a pro rata portion of each holder’s shares of preferred stock.
The preferred stock has no stated maturity and will remain outstanding indefinitely unless repurchased or redeemed by Gulfport or converted into common stock.
The preferred stock has been classified as mezzanine equity in the accompanying consolidated balance sheets due to the redemption features noted above.
Dividends and Conversions
During the years ended December 31, 2024, 2023 and 2022 the Company paid $4.2 million, $4.8 million and $5.4 million, respectively, of cash dividends to holders of our preferred stock.
The following table summarizes activity of the Company’s preferred stock for the years ended December 31, 2024 and 2023:
Year Ended December 31, 2024 Year Ended December 31, 2023
Preferred stock, beginning of period 44,214 52,295
Issuance of preferred stock - -
Conversion of preferred stock (6,866) (8,081)
Preferred stock, end of period 37,348 44,214
6.EQUITY
In May 2021, the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for, among other things, (i) the authority to issue 42 million shares of common stock with a par value of $0.0001 per share and (ii) the designation of 110,000 shares of preferred stock, with a par value of $0.0001 per share and a Liquidation Preference of $1,000 per share.
Common Stock
In May 2021, Gulfport issued approximately 19.8 million shares of common stock and 1.7 million shares of common stock were issued to the Disputed Claims Reserve.
In January 2024, the remaining 62,000 shares in the Disputed Claims Reserve were issued to certain claimants. There are no remaining shares in the Disputed Claims Reserve subsequent to the January 2024 issuance.
Common Stock Offering
On June 26, 2023, Gulfport completed an underwritten public offering of 1.5 million shares of its common stock by certain stockholders at a price to the public of $95.00 per share. Gulfport did not sell any of its common stock as part of this offering and did not receive any proceeds from the sale of the shares sold by the selling stockholders.
Concurrent with the closing of the offering, Gulfport purchased 263,158 shares of its common stock at $95.00 per share. The repurchase was part of the Company's existing Repurchase Program discussed below.
On December 14, 2023, Gulfport completed an underwritten public offering of 653,464 shares of its common stock by certain stockholders at a price to the public of $128.21 per share. Gulfport did not sell any of its common stock as part of this offering and did not receive any proceeds from the sale of the shares sold by the selling stockholders.
Stock Repurchase Program
In November 2021 the Company's Board of Directors approved the Repurchase Program to acquire up to $100 million of common stock, which has subsequently been increased up to $1 billion and extended through December 31, 2025. Purchases under the Repurchase Program may be made from time to time in open market or privately negotiated transactions, and will be subject to available liquidity, market conditions, credit agreement restrictions, applicable legal requirements, contractual obligations and other factors. The Repurchase Program does not require the Company to acquire any specific number of shares of common stock. The Company intends to purchase shares under the Repurchase Program with available funds while maintaining sufficient liquidity to fund its capital development program. The Repurchase Program may be suspended from time to time, modified, extended or discontinued by the Board of Directors at any time.
The following table summarizes activity under the Repurchase Program for the year ended December 31, 2024 (number of shares and dollar value of shares purchased shown in thousands):
Total Number of Shares Purchased Dollar Value of Shares Purchased Average Price Paid Per Share
First quarter 2024 210 $ 29,492 $ 140.39
Second quarter 2024 161 25,000 155.65
Third quarter 2024 341 49,862 146.17
Fourth quarter 2024 491 80,123 163.13
Total 1,203 $ 184,477 $ 153.35
As of December 31, 2024, the Company has repurchased 5.6 million shares for $584.1 million at a weighted average price of $104.88 per share since the inception of the Repurchase Program.
7.STOCK-BASED COMPENSATION
In May 2021, the Board of Directors adopted the Incentive Plan with a share reserve of 2.8 million shares of common stock. The Incentive Plan provides for the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents and performance awards or any combination of the foregoing.
The Company has granted both restricted stock units and performance vesting restricted stock units to employees and directors pursuant to the Incentive Plan, as discussed below. During the years ended December 31, 2024 and 2023, the Company's stock-based compensation expense was $16.4 million and $12.3 million of which the Company capitalized $5.4 million and $4.0 million, respectively, relating to its exploration and development efforts. Stock compensation expense, net of the amounts capitalized, is included in general and administrative expenses in the accompanying consolidated statements of operations. As of December 31, 2024, the Company has awarded an aggregate of approximately 444,493 restricted stock units and approximately 462,982 performance vesting restricted stock units under the Incentive Plan.
The vesting for certain share-based awards was accelerated in the first three months of 2023 in conjunction with the restructuring activities described in Note 13 and is included in restructuring costs in the accompanying consolidated statement of operations.
The following table summarizes activity for the years ended December 31, 2022, 2023 and 2024:
Number of
Unvested
Restricted Stock Units Weighted
Average
Grant Date
Fair Value Number of
Unvested
Performance Vesting Restricted Stock Units Weighted
Average
Grant Date
Fair Value
Unvested shares as of December 31, 2021 198,413 $ 66.04 153,138 $ 48.54
Granted 78,192 96.90 37,666 66.82
Vested (67,564) 65.91 - -
Forfeited/canceled (11,269) 80.11 - -
Unvested shares as of December 31, 2022 197,772 $ 77.49 190,804 $ 52.15
Granted 104,901 88.59 83,820 58.39
Vested (101,804) 75.75 - -
Forfeited/canceled (7,267) 91.61 (19,046) 49.37
Unvested shares as of December 31, 2023 193,602 $ 83.89 255,578 $ 54.40
Granted(1)
75,476 152.79 188,358 81.90
Vested (96,942) 81.14 (265,797) 48.65
Forfeited/canceled (5,122) 114.91 - -
Unvested shares as of December 31, 2024 167,014 $ 115.67 178,139 $ 92.06
_____________________
(1) The table includes the impacts of performance share units granted in a prior year that vested higher than 100% of target due to the Company's TSR performance compared to peers.
The aggregate fair value of share-based awards that vested during the years ended December 31, 2024, 2023 and 2022, was approximately $56.8 million, $9.9 million and $5.9 million, respectively, based on the stock price at the time of vesting.
Restricted Stock Units
Restricted stock units awarded under the Incentive Plan generally vest over a period of 3 years in the case of employees and 1 or 4 years in the case of directors upon the recipient meeting applicable service requirements. Stock-based compensation expense is recorded ratably over the service period. The grant date fair value of restricted stock units represents the closing market price of the Company's common stock on the date of the grant. Unrecognized compensation expense as of December 31, 2024, was $12.1 million. The expense is expected to be recognized over a weighted average period of 1.72 years.
Performance Vesting Restricted Stock Units
The Company has awarded performance vesting restricted stock units to certain of its executive officers under the Incentive Plan. The number of shares of common stock issued pursuant to the award will be based on a combination of (i) the Company's TSR and (ii) the Company's RTSR for the performance period. Participants will earn from 0% to 200% of the target award based on the Company's TSR and RTSR ranking compared to the TSR of the companies in the Company's designated peer group at the end of the performance period. Awards will be earned and vested at the end of a three-year performance period, subject to earlier termination of the performance period in the event of a change in control. The grant date fair values were determined using the Monte Carlo simulation method and are being recorded ratably over the performance period.
The table below summarizes the assumptions used in the Monte Carlo simulation to determine the grant date fair value of awards granted during the years ended December 31, 2022, 2023 and 2024:
Grant date April 29, 2022 January 24, 2023 March 3, 2023 April 3, 2023 March 1, 2024
Forecast period (years) 3 3 3 3 3
Risk-free interest rates 2.87% 3.88% 4.64% 3.79% 4.36%
Implied equity volatility 88.4% 87.2% 86.4% 70.8% 46.7%
Stock price on the date of grant $93.98 $72.99 $82.20 $79.50 $142.00
Unrecognized compensation expense as of December 31, 2024, related to performance vesting restricted shares was $8.0 million. The expense is expected to be recognized over a weighted average period of 1.73 years.
8.REVENUE FROM CONTRACTS WITH CUSTOMERS
Revenue Recognition
The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGL. These sales are recognized in the period that the performance obligations are satisfied. The Company generally considers the delivery of each unit (MMBtu or Bbl) to be separately identifiable and represents a distinct performance obligation that is satisfied at the time control of the product is transferred to the customer. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered.
Gathering, processing and compression fees attributable to gas processing, as well as any transportation fees, including firm transportation fees, incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression expense in the accompanying consolidated statements of operations.
Transaction Price Allocated to Remaining Performance Obligations
A significant number of the Company's product sales are short-term in nature generally through evergreen contracts with contract terms of one year or less. These contracts typically automatically renew under the same provisions. For those contracts, the Company has utilized the practical expedient allowed in the revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
For product sales that have a contract term greater than one year, the Company has utilized the practical expedient that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, the Company's product sales that have a contractual term greater than one year have no long-term fixed consideration.
Contract Balances
Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $155.9 million and $122.5 million as of December 31, 2024 and December 31, 2023, respectively, and are reported in accounts receivable - oil, natural gas, and natural gas liquids sales in the accompanying consolidated balance sheets. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.
Prior-Period Performance Obligations
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain sales may be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The differences between the estimates and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. For each of the periods presented, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
9.LEASES
Nature of Leases
The Company has operating leases on certain equipment with remaining lease durations in excess of one year. The Company recognizes a right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year. Short-term leases that have an initial term of one year or less are not capitalized.
The Company has entered into contracts for drilling rigs with varying terms with third parties to ensure operational continuity, cost control and rig availability in its operations. The Company has concluded its drilling rig contracts are operating leases as the assets are identifiable and the Company has the right to control the identified assets. The Company's drilling rig commitments are typically structured with an initial term of less than one year. At December 31, 2024, the Company had one active long-term drilling rig contract. These agreements typically include renewal options at the end of the initial term. Due to the nature of the Company's drilling schedules and potential volatility in commodity prices, the Company is unable to determine at contract commencement with reasonable certainty if the renewal options will be exercised; therefore, renewal options are not considered in the lease term for drilling contracts. The operating lease liabilities associated with these rig commitments, when applicable, are based on the minimum contractual obligations, primarily standby rates, and do not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of drilling costs are borne by other interest owners in our wells.
The Company rents office space for its corporate headquarters, field locations and certain other equipment from third parties, which expire at various dates through 2027. These agreements are typically structured with non-cancelable terms of one year to five years. The Company has determined these agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. The Company has included any renewal options that it has determined are reasonably certain of exercise in the determination of the lease terms.
Discount Rate
As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company's incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.
Future amounts due under operating lease liabilities as of December 31, 2024, were as follows (in thousands):
2025 $ 5,657
2026 561
2027 10
2028 -
2029 -
Total lease payments $ 6,228
Less: imputed interest (129)
Total $ 6,099
Lease costs incurred for the years ended December 31, 2024 and 2023 consisted of the following (in thousands):
Year Ended December 31, 2024 Year Ended December 31, 2023
Operating lease cost $ 12,828 $ 13,752
Variable lease cost - -
Short-term lease cost 26,817 28,691
Total lease cost(1)
$ 39,645 $ 42,443
_____________________
(1) The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in either lease operating expenses or general and administrative expenses in the accompanying consolidated statements of operations.
The weighted-average remaining lease term as of December 31, 2024, was 0.76 years. The weighted-average discount rate used to determine the operating lease liability as of December 31, 2024, was 6.25%.
10.INCOME TAXES
Details of income tax provisions and deferred income taxes from continuing operations are provided in the following tables.
The components of income tax benefits were as follows (in thousands):
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Current:
State $ - $ - $ -
Federal - - -
Deferred:
State 11,747 (26,704) -
Federal (67,824) (498,452) -
Total income tax benefit provision $ (56,077) $ (525,156) $ -
A reconciliation of the statutory federal income tax amount to the recorded benefit follows (in thousands):
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Income (loss) before federal income taxes $ (317,463) $ 945,760 $ 494,701
Expected income tax at statutory rate (66,668) 198,610 103,887
State income taxes 4,765 (2,581) 2,227
Remeasurement of state deferred tax asset 54 - 13,869
Return to provision 5,800 (5,592) (17,075)
Other differences 1,857 1,982 1,117
Change in valuation allowance due to current year activity (1,885) (717,575) (104,025)
Income tax benefit recorded $ (56,077) $ (525,156) $ -
For the year ended December 31, 2024, the Company's effective tax rate was 18% and an income tax benefit of $56.1 million. For the year ended December 31, 2023, the Company's effective tax rate was (56)% and an income tax benefit of $525.2 million. For the year ended December 31, 2022, the Company's effective tax rate was 0%. The higher effective income tax rate for the year ended December 31, 2024, is primarily related to the valuation allowance the Company released during the year ended December 31, 2023.
The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2024 and December 31, 2023 are estimated as follows (in thousands):
Year Ended December 31, 2024 Year Ended December 31, 2023
Deferred tax assets:
Net operating loss carryforward and tax credits $ 345,770 $ 399,017
Oil and gas property basis difference 194,412 143,769
Investment in pass through entities 65,210 68,114
Stock-based compensation expense 1,821 1,262
Change in fair value of derivative instruments 6,106 -
Other assets 56,849 52,730
Total deferred tax assets 670,168 664,892
Valuation allowance for deferred tax assets (83,695) (85,757)
Deferred tax assets, net of valuation allowance 586,473 579,135
Deferred tax liabilities:
Change in fair value of derivative instruments 3,401 50,448
Right of use asset 1,281 3,003
Other 558 528
Total deferred tax liabilities 5,240 53,979
Net deferred tax asset $ 581,233 $ 525,156
At each reporting period, the Company weighs all available positive and negative evidence to determine whether its deferred tax assets are more likely than not to be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess the likelihood, the Company uses estimates and judgment regarding future taxable income and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry. Based upon the Company’s analysis, the Company currently believes it is more-likely-than-not that a portion of the Company's federal and state deferred tax assets will be utilized. The Company has maintained a $83.7 million valuation allowance associated with its federal and state deferred tax assets.
The Company will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to the deferred tax assets. Changes in positive and negative evidence, including differences between estimated and actual results, could result in changes in the valuation of the deferred tax assets that could have a material impact on the consolidated financial statements. Changes in existing tax laws could also affect actual tax results and the realization of deferred tax assets over time.
The Company has an available federal tax net operating loss carryforward estimated at approximately $1.6 billion as of December 31, 2024. These federal net operating loss carryforwards of approximately $264.5 million generated in tax years prior to 2018 will begin to expire in 2036. As a result of the Tax Cuts and Jobs Act, the 2018 through 2024 federal NOL carryforwards of $1.3 billion have no expiration. The Company also has state net operating loss carryovers of approximately $394.5 million that will begin to expire in 2025.
As of December 31, 2024, we had no liability for uncertain tax positions.
11.EARNINGS (LOSS) PER SHARE
Basic income or loss per share attributable to common stockholders is computed as (i) net income or loss less (ii) dividends paid to holders of preferred stock less (iii) net income or loss attributable to participating securities divided by (iv) weighted average basic shares outstanding. Diluted net income or loss per share attributable to common stockholders is computed as (i) basic net income or loss attributable to common stockholders plus (ii) diluted adjustments to income allocable to participating securities divided by (iii) weighted average diluted shares outstanding. The “if-converted” method is used to determine the dilutive impact for the Company's convertible preferred stock and the treasury stock method is used to determine the dilutive impact of unvested restricted stock.
There were 0.3 million shares of restricted stock that were considered anti-dilutive for the year ended December 31, 2024. There were 0.3 million and 0.2 million shares of restricted stock that were considered dilutive for the years ended December 31, 2023 and 2022, respectively. There were 2.7 million, 3.2 million and 3.7 million potential shares of common stock issuable due to the Company's convertible preferred stock for the years ended December 31, 2024, 2023 and 2022, respectively.
Reconciliations of the components of basic and diluted net (loss) income per common share are presented in the table below (in thousands):
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Net (loss) income $ (261,386) $ 1,470,916 $ 494,701
Dividends on preferred stock (4,230) (4,840) (5,444)
Participating securities - preferred stock(1)
- (212,360) (76,401)
Net (loss) income attributable to common stockholders $ (265,616) $ 1,253,716 $ 412,856
Re-allocation of participating securities - 2,475 512
Diluted net (loss) income attributable to common stockholders $ (265,616) $ 1,256,191 $ 413,368
Basic Shares 18,050 18,645 20,185
Dilutive Shares 18,050 18,902 20,347
Basic EPS $ (14.72) $ 67.24 $ 20.45
Dilutive EPS $ (14.72) $ 66.46 $ 20.32
_____________________
(1) Preferred stock represents participating securities because it participates in any dividends on shares of common stock on a pari passu, pro rata basis. However, preferred stock does not participate in undistributed net losses.
12.DERIVATIVE INSTRUMENTS
Natural Gas, Oil and NGL Derivative Instruments
The Company seeks to mitigate risks related to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. These contracts allow the Company to mitigate the impact of declines in future natural gas, oil and NGL prices by effectively locking in a floor price for a certain level of the Company’s production. However, these hedge contracts also limit the benefit to the Company in periods of favorable price movements.
The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. Gulfport may enter into commodity derivative contracts up to limitations set forth in its Credit Facility. The Company generally enters into commodity derivative contracts for approximately 30% to 70% of its forecasted current year annual production by the end of the first quarter of each fiscal year. The Company typically enters into commodity derivative contracts for the next 12 to 36 months. Gulfport does not enter into commodity derivative contracts for speculative purposes.
The Company does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. The Company's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. Gulfport routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties' public credit ratings and avoiding the concentration of credit exposure by transacting with multiple counterparties. The Company has master netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation. As of December 31, 2024, our commodity derivative contracts were spread among 12 counterparties.
Fixed price swaps require that the Company receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. They are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume.
The Company has entered into natural gas, crude oil and NGL fixed price swap contracts based off the NYMEX Henry Hub, NYMEX WTI and Mont Belvieu C3 indices. Below is a summary of the Company's open fixed price swap positions as of December 31, 2024:
Index Daily Volume Weighted
Average Price
Natural Gas (MMBtu/d) ($/MMBtu)
2025 NYMEX Henry Hub 250,000 $ 3.82
2026 NYMEX Henry Hub 200,000 $ 3.64
Oil (Bbl/d) ($/Bbl)
2025 NYMEX WTI 2,000 $ 74.50
NGL (Bbl/d) ($/Bbl)
2025 Mont Belvieu C3 2,504 $ 29.97
2026 Mont Belvieu C3 496 $ 29.51
Each two-way costless collar has a set floor and ceiling price for the hedged production. They are settled monthly based on differences between the floor and ceiling prices specified in the contract and the referenced settlement price. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the collar contracts, the Company will cash-settle the difference with the hedge counterparty. When the referenced settlement price is less than the floor price in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the hedged contract volume. Similarly, when the referenced settlement price exceeds the ceiling price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the hedged contract volume. No payment is due from either party if the referenced settlement price is within the range set by the floor and ceiling prices.
The Company has entered into natural gas costless collars based off the NYMEX Henry Hub index. Below is a summary of the Company's costless collar positions as of December 31, 2024:
Index Daily Volume Weighted Average Floor Price Weighted Average Ceiling Price
Natural Gas (MMBtu/d) ($/MMBtu) ($/MMBtu)
2025 NYMEX Henry Hub 220,000 $ 3.37 $ 4.23
2026 NYMEX Henry Hub 90,000 $ 3.35 $ 4.10
From time to time the Company has sold natural gas call options in exchange for a premium, and used the associated premiums received to enhance the fixed price for a portion of the fixed price natural gas swaps. Each sold call option has an established ceiling price. If at the time of settlement the referenced settlement price exceeds the ceiling price, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes. No payment is due from either party if the referenced settlement price is below the price ceiling. Below is a summary of the Company's open sold call option positions as of December 31, 2024:
Index Daily Volume Weighted Average Ceiling Price
Natural Gas (MMBtu/d) ($/MMBtu)
2025 NYMEX Henry Hub 193,315 $ 5.80
In addition, the Company has entered into natural gas basis swap positions. These instruments are arrangements that guarantee a fixed price differential to NYMEX Henry Hub from a specified delivery point. The Company receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity. As of December 31, 2024, the Company had the following natural gas basis swap positions open:
Gulfport Pays Gulfport Receives Daily Volume Weighted Average Fixed Spread
Natural Gas (MMBtu/d) ($/MMBtu)
2025 Rex Zone 3 NYMEX Plus Fixed Spread 110,000 $ (0.20)
2025 NGPL TXOK NYMEX Plus Fixed Spread 40,000 $ (0.29)
2025 TETCO M2 NYMEX Plus Fixed Spread 230,000 $ (0.96)
2025 Transco Station 85 NYMEX Plus Fixed Spread 5,000 $ 0.38
2025 TGP 500 NYMEX Plus Fixed Spread 10,000 $ 0.31
2026 Rex Zone 3 NYMEX Plus Fixed Spread 40,000 $ (0.19)
2026 NGPL TXOK NYMEX Plus Fixed Spread 30,000 $ (0.30)
2026 TETCO M2 NYMEX Plus Fixed Spread 130,000 $ (0.98)
2026 Transco Station 85 NYMEX Plus Fixed Spread 5,000 $ 0.52
2026 TGP 500 NYMEX Plus Fixed Spread 10,000 $ 0.54
Balance Sheet Presentation
The Company reports the fair value of derivative instruments on the consolidated balance sheets as derivative instruments under current assets, noncurrent assets, current liabilities, and noncurrent liabilities on a gross basis. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The following table presents the fair value of the Company's derivative instruments on a gross basis at December 31, 2024 and December 31, 2023 (in thousands):
December 31, 2024 December 31, 2023
Short-term derivative asset $ 58,085 $ 233,226
Long-term derivative asset 6,003 47,566
Short-term derivative liability (41,889) (21,963)
Long-term derivative liability (35,081) (18,602)
Total commodity derivative position $ (12,882) $ 240,227
Gains and Losses
The following table presents the gain and loss recognized in net gain (loss) on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the years ended December 31, 2024, 2023 and 2022 (in thousands):
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Natural gas derivatives - fair value (losses) gains
$ (251,019) $ 584,563 $ 32,797
Natural gas derivatives - settlement gains (losses)
284,626 146,381 (1,002,098)
Total gains (losses) on natural gas derivatives
33,607 730,944 (969,301)
Oil and condensate derivatives - fair value gains
2,351 5,971 6,618
Oil and condensate derivatives - settlement gains (losses) 166 (3,272) (39,163)
Total gains (losses) on oil and condensate derivatives
2,517 2,699 (32,545)
NGL derivatives - fair value (losses) gains
(4,442) (2,414) 14,648
NGL derivatives - settlement (losses) gains (2,155) 9,090 (12,549)
Total (losses) gains on NGL derivatives
(6,597) 6,676 2,099
Total gains (losses) on natural gas, oil and NGL derivatives
$ 29,527 $ 740,319 $ (999,747)
Offsetting of Derivative Assets and Liabilities
As noted above, the Company records the fair value of derivative instruments on a gross basis. The following table presents the gross amounts of recognized derivative assets and liabilities in the consolidated balance sheets and the amounts that are subject to offsetting under master netting arrangements with counterparties, all at fair value (in thousands):
As of December 31, 2024
Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets Gross Amounts Subject to Master Netting Agreements Net Amount
Derivative assets $ 64,088 $ (49,343) $ 14,745
Derivative liabilities $ (76,970) $ 49,343 $ (27,627)
As of December 31, 2023
Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets Gross Amounts Subject to Master Netting Agreements Net Amount
Derivative assets $ 280,792 $ (30,866) $ 249,926
Derivative liabilities $ (40,565) $ 30,866 $ (9,699)
Concentration of Credit Risk
By using derivative instruments that are not traded on an exchange, the Company is exposed to the credit risk of its counterparties. Credit risk is the risk of loss from counterparties not performing under the terms of the derivative instrument. When the fair value of a derivative instrument is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The Company’s derivative contracts are spread between multiple counterparties to lessen its exposure to any individual counterparty. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. None of the Company’s derivative instrument contracts contain credit-risk related contingent features. Other than as provided by the Company’s revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under its derivative instruments, nor are the counterparties required to provide credit support to the Company.
13.RESTRUCTURING COSTS
During the year ended December 31, 2023, Gulfport recognized $4.8 million in personnel-related restructuring expenses associated with changes in the organizational structure and leadership team resulting from the appointment of Gulfport's new CEO in January 2023. Of these expenses, $1.3 million resulted from accelerated vesting of certain share-based grants, which are non-cash charges. The organizational changes were completed in the second quarter of 2023 and there are no remaining employee termination liabilities associated with these changes.
14.INVESTMENTS
Grizzly Oil Sands ULC
The Company, through its wholly owned subsidiary Grizzly Holdings, owns an approximate 24.5% interest in Grizzly, a Canadian unlimited liability company. As of December 31, 2024, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. The Company has not paid any cash calls since its decision to cease funding further capital calls in 2019. Grizzly’s functional currency is the Canadian dollar.
The Company reduced the carrying value of its investment in Grizzly to zero upon the Emergence Date. The reduction in valuation was based upon the Company's new management's assessment of the investment and its priority for future funding in its portfolio. In particular, Grizzly’s operations remained suspended, even with improvements in the pricing environment since its initial suspension in 2015. Additionally, the Company does not anticipate funding future capital calls, which will lead to further dilution of its equity ownership interest.
15.FAIR VALUE MEASUREMENTS
The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. Fair value measurements are classified and disclosed in one of the following categories:
Level 1 - Quoted prices (unadjusted) in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.
Level 2 - Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.
Level 3 - Significant inputs to the valuation model are unobservable.
Valuation techniques that maximize the use of observable inputs are favored. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter.
Financial assets and liabilities
The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of December 31, 2024 and December 31, 2023 (in thousands):
December 31, 2024
Level 1 Level 2 Level 3
Assets:
Derivative instruments $ - $ 64,088 $ -
Contingent consideration arrangement $ - $ - $ 2,700
Total assets $ - $ 64,088 $ 2,700
Liabilities:
Derivative instruments $ - $ 76,970 $ -
December 31, 2023
Level 1 Level 2 Level 3
Assets:
Derivative instruments $ - $ 280,792 $ -
Contingent consideration arrangement $ - $ - $ 2,900
Total assets $ - $ 280,792 $ 2,900
Liabilities:
Derivative instruments $ - $ 40,565 $ -
The Company estimates the fair value of all derivative instruments using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.
The Company's SCOOP water infrastructure sale, which closed in the first quarter of 2020, included a contingent consideration arrangement. As of December 31, 2024, the fair value of the contingent consideration was $2.7 million, of which $0.5 million is included in prepaid expenses and other current assets and $2.2 million is included in other assets in the accompanying consolidated balance sheets. The fair value of the contingent consideration arrangement is calculated using discounted cash flow techniques and is based on internal estimates of the Company's future development program and water production levels. Given the unobservable nature of the inputs, the fair value measurement of the contingent consideration arrangement is deemed to use Level 3 inputs. The Company has elected the fair value option for this contingent consideration arrangement and, therefore, records changes in fair value in earnings. The Company recognized an immaterial gain for the year ended December 31, 2024 and a loss of $1.4 million for the year ended December 31, 2023, with respect to this contingent consideration arrangement. These fair value changes are included in Other, net in the accompanying consolidated statements of operations.
Non-financial assets and liabilities
The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 3 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred were $0.7 million and $0.6 million for the years ended December 31, 2024 and 2023, respectively.
Fair value of other financial instruments
The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable and accounts payable and accrued liabilities are carried at cost, which approximates market value due to their short-term nature. Long-term debt related to the Company's Credit Facility is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities.
16.RELATED PARTY TRANSACTIONS
Stock Repurchase Program
The following table summarizes the Company's purchases of its common stock from Silver Point Capital, L.P. for the years ended December 31, 2023 and 2024 (dollar value of shares purchased shown in thousands):
Date of Transaction Shares Repurchased Repurchase Amount Closing Date
June 22, 2023(1)
215,060 $ 20,430 June 26, 2023
December 07, 2023 146,455 $ 20,000 December 11, 2023
March 19, 2024 97,219 $ 15,002 March 19, 2024
September 19, 2024 170,000 $ 24,863 September 25, 2024
November 21, 2024 150,000 $ 26,340 December 03, 2024
December 19, 2024 79,410 $ 12,929 December 26, 2024
_____________________
(1) Concurrent with the closing of the June 2023 offering transaction discussed in Note 6.
The repurchases are part of the Company's existing Repurchase Program. Upon closing of the transactions, the repurchased common stock was canceled.
17.COMMITMENTS
Firm Transportation and Gathering Agreements
The Company has contractual commitments with midstream and pipeline companies for future gathering and transportation of natural gas from the Company's producing wells to downstream markets. Under certain of these agreements, the Company has minimum daily volume commitments. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it often can release it to other counterparties, thus reducing the cost of these commitments. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to future firm transportation and gathering agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, costs associated with utilized future firm transportation and gathering agreements are reflected in the Company's estimates of proved reserves.
A summary of these commitments at December 31, 2024, are set forth in the table below (in thousands):
2025 $ 140,434
2026 134,281
2027 136,448
2028 136,604
2029 136,762
Thereafter 463,417
Total $ 1,147,946
Future Firm Sales Commitments
The Company has entered into various firm sales contracts to deliver and sell natural gas. The Company expects to fulfill its delivery commitments primarily with production from proved developed reserves. The Company's operated production has generally been sufficient to satisfy its delivery commitments during the periods presented, and it expects its operated production will continue to be the primary means of fulfilling its future commitments. However, where the Company's operated production is not sufficient to satisfy its delivery commitments, it can and may use spot market purchases to satisfy the commitments.
A summary of these volume commitments at December 31, 2024, are set forth in the table below (MMBtu per day):
2025 68,000
2026 75,000
2027 12,000
2028 -
Thereafter -
Total 155,000
Other Operational Commitments
The Company entered into various contractual commitments to purchase inventory and other material to be used in future activities. The Company's commitment to purchase these materials exists through 2025, with approximately $13.8 million remaining.
Contributions to 401(k) Plan
Gulfport sponsors a 401(k) plan under which eligible employees may contribute a portion of their total compensation up to the maximum threshold through salary deferrals. The plan is considered a Safe Harbor 401(k) and provides a company match on 100% of salary deferrals that do not exceed 6% of compensation. The Company may also make discretionary elective contributions to the plan. The following table summarizes the contributions expenses related to this plan for the years ended December 31, 2024, 2023 and 2022 (in thousands):
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Contributions expense $ 1,749 $ 1,549 $ 1,386
18.CONTINGENCIES
The Company is involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. The Company's total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, its experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and their final liabilities may ultimately be materially different. In accordance with ASC Topic 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.
Litigation and Regulatory Proceedings
The Company, along with other oil and gas companies, have been named as a defendant in a number of lawsuits where Plaintiffs assert their respective leases are limited to the Utica/Marcellus shale geological formations and allege that Defendants have willfully trespassed and illegally produced oil, natural gas, and other hydrocarbon products beyond these respective formations. They also allege that Defendants engaged in conversion and were unjustly enriched. Plaintiffs seek the full value of any production from below the Utica/Marcellus shale formations, unspecified damages from the diminution of value to their mineral estate, unspecified punitive damages, and the payment of reasonable attorney fees, legal expenses, and interest. On April 27, 2021, the Bankruptcy Court for the Southern District of Texas approved a settlement agreement in which the plaintiffs fully released the Company from all claims that accrued and any damages related to the period before the effective date of the Company’s Chapter 11 plan, which occurred on May 17, 2021. The plaintiffs are continuing to pursue alleged damages after May 17, 2021.
The Company received Notice and Finding of Violations (“NOV/FOVs”) from the USEPA alleging violations of the Clean Air Act at 17 locations in Ohio between 2013 and 2019. On January 22, 2020, the Company entered a Consent Decree with the Department of Justice and USEPA addressing Gulfport's failure to capture and control air emissions from storage vessels and to comply with associated inspection, recordkeeping, and reporting requirements. During the process of terminating the Consent Decree, the Company was informed that there were untimely repairs on a number of locations subject to the Company's Consent Decree that failed to comply with Subpart OOOO or Permit to Install and Operate Applications. On July 31, 2024, the Company received a NOV/FOV from USEPA related to the alleged untimely repairs. While these repairs have been completed, resolution of the matter may result in monetary sanctions exceeding $300,000. The Company also received a Demand for Stipulated Penalties for Certain Instances of Alleged Non-Compliance with Consent Decree Requirements from the United States Department of Justice (“USDOJ”) on September 5, 2024. The Company paid a $97,500 penalty to resolve the USDOJ demand for stipulated penalties.
In November 2020, Robert T. Stephenson and Sandra J. Bass, as the Successor Co-Trustees of the Robert L. Stephenson Living Trust, dated January 28, 2004, and express trust; and Norma E. Stephenson, Trustee of the Norma E. Stephenson Living Trust, dated July 29, 1991, and express trust filed an action against the Company in the District Court of Grady County in the State of Oklahoma. In June 2021 the case was removed to the United States District Court for the Western District of Oklahoma. The parties have engaged in discovery and a trial has been set for Summer 2025. The complaint alleges that the Company has failed to comply with a Letter Agreement from April 1979 granting an overriding royalty interest covering 16 sections (approximately 10,240 acres). The plaintiffs seek quiet title, declaratory judgment, breach of contract, specific performance, and damages under the Oklahoma Production Revenue Standards Act. Given the nature of this matter, the Company is unable to reasonably estimate the total possible loss or ranges of loss. The Company believes it has strong defenses to these claims and intends to vigorously defend this matter; however, an adverse decision could have a material effect on the Company, its financial condition, results of operations, and cash flows.
In January 2025, Grace E. Moore Great Grandchildren Trust of 2006, Joseph Gorsha, Damon Faldowski, Damon Faldowski II, and Mark Faldowski, individually and on behalf of all others similarly situated, filed a class action against Gulfport and another natural gas producer in the United States District Court, Southern District of Ohio, Eastern Division. The lawsuit alleges, among other things, that defendants underpaid royalties to the plaintiffs in connection with the production and sale of natural gas and NGL. The lawsuit seeks compensatory damages, injunctive relief regarding royalty payment practices, restitution, disgorgement of profits, prejudgment interest, post-judgment interest, attorney’s fees, and costs. Given the preliminary nature of this action, we are currently unable to estimate what, if any, liability may result from this matter.
Business Operations
The Company is involved in various lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Environmental Contingencies
The nature of the oil and gas business carries with it certain environmental risks for Gulfport and its subsidiaries. Gulfport and its subsidiaries have implemented various policies, programs, procedures, training and audits to reduce and mitigate environmental risks. The Company conducts periodic reviews, on a company-wide basis, to assess changes in its environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. The Company manages its exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, it may, among other things, exclude a property from the transaction, require the seller to remediate the property to its satisfaction in an acquisition or agree to assume liability for the remediation of the property.
Other Matters
Based on management’s current assessment, they are of the opinion that no pending or threatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on their future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
Concentration of Credit Risk
Gulfport operates in the oil and natural gas industry principally in the states of Ohio and Oklahoma with sales to refineries, re-sellers such as marketers, and other end users. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and will continue to be immaterial to the Company’s results of operations in the long term.
The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation. At December 31, 2024, Gulfport held no cash in excess of insured limits in these banks.
During the years ended December 31, 2024 and 2023, one customer accounted for approximately 15% and 12%, respectively, of the Company's total sales. During the year ended December 31, 2022, two customers accounted for approximately 31% of the Company's total sales. The Company does not believe that the loss of any of these customers would have a material adverse effect on its natural gas, oil and condensate and NGL sales as alternative customers are readily available.
19.SUBSEQUENT EVENTS
Natural gas, Oil and NGL Derivative Instruments
Subsequent to December 31, 2024 and as of February 20, 2025, the Company entered into the following derivative contracts:
Period Type of Derivative Instrument Index Daily Volume
Weighted
Average Price
Natural Gas
(MMBtu/d) ($/MMBtu)
Swaps
NYMEX Henry Hub
18,301 $3.85
Basis Swaps
Rex Zone 3
40,000 $(0.17)
Oil
(Bbl/d) ($/Bbl)
Swaps
NYMEX WTI
1,000 $70.87
20.SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)
The Company is making the following supplemental disclosures of oil and gas activities, in accordance with the full cost method of accounting for its oil and gas exploration and development activities. The Company owns a 24.5% interest in Grizzly. However, Grizzly did not have any material activity or proved reserves in the years presented below. As such, amounts related to Grizzly have been omitted below.
The following table provides historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the United States:
Capitalized Costs Related to Oil and Gas Producing Activities (in thousands)
Year Ended December 31, 2024 Year Ended December 31, 2023
Proved properties $ 3,349,805 $ 2,904,519
Unproved properties 221,650 204,233
Total oil and natural gas properties 3,571,455 3,108,752
Accumulated depletion and amortization (1,559,546) (862,253)
Net capitalized costs $ 2,011,909 $ 2,246,499
Costs Incurred in Oil and Gas Property Acquisition, Development and Exploratory Activities (in thousands)
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Acquisition $ 89,646 $ 93,905 $ 29,675
Development 373,284 419,431 441,458
Exploratory - - -
Total $ 462,930 $ 513,336 $ 471,133
Capitalized interest is included as part of the cost of oil and natural gas properties. The Company capitalized $4.8 million and $4.1 million for the years ended December 31, 2024 and 2023, respectively, based on the Company's weighted average cost of borrowings used to finance expenditures. The Company did not capitalize interest expense for the year ended December 31, 2022.
In addition to capitalized interest, the Company capitalized internal costs totaling $25.3 million, $22.8 million and $20.2 million during the years ended December 31, 2024, 2023, and 2022, respectively, which were directly related to the acquisition, exploration and development of the Company's oil and natural gas properties.
Results of Operations for Producing Activities (in thousands)
The following table sets forth the revenues and expenses related to the production and sale of oil and natural gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas production.
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Revenues $ 928,604 $ 1,051,383 $ 2,330,859
Production costs (451,086) (450,996) (482,175)
Depletion (324,078) (318,473) (266,449)
Impairment (373,214) - -
Income tax benefit 56,077 525,156 -
Results of operations from producing activities $ (163,697) $ 807,070 $ 1,582,235
Depletion per Mcf of gas equivalent (Mcfe) $ 0.84 $ 0.83 $ 0.74
Oil and Natural Gas Reserves
The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2024, 2023 and 2022 and changes in proved reserves during the last three years. The reserve reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2024, 2023 and 2022, in accordance with guidelines of the SEC applicable to reserves estimates. The prices used for the 2024 reserve report are $76.32 per barrel of oil, $2.13 per MMbtu and $31.30 per barrel for NGL, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, 2023 and 2022 for reserve report purposes are $78.21 per barrel, $2.64 per MMbtu and $31.42 per barrel for NGL and $94.14 per barrel, $6.36 per MMbtu and $47.86 per barrel for NGL, respectively.
Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data.
Oil (MMBbl) Natural Gas (Bcf) NGL (MMBbl) Natural Gas Equivalent (Bcfe)
Proved Reserves
December 31, 2021 16 3,478 54 3,898
Purchases of reserves - - - -
Extensions and discoveries 3 391 5 439
Sales of reserves - - - -
Revisions of prior reserve estimates - 66 - 70
Current production (2) (322) (4) (359)
December 31, 2022 18 3,612 54 4,048
Purchases of reserves - - - -
Extensions and discoveries 6 875 14 996
Sales of reserves - - - -
Revisions of prior reserve estimates (4) (411) (1) (445)
Current production (1) (350) (4) (385)
December 31, 2023 19 3,725 63 4,214
Purchases of reserves - - - -
Extensions and discoveries 5 398 20 547
Sales of reserves - - - -
Revisions of prior reserve estimates - (413) 1 (406)
Current production (1) (354) (4) (386)
December 31, 2024 22 3,356 80 3,969
Proved developed reserves
December 31, 2021 8 1,928 31 2,165
December 31, 2022 9 2,034 34 2,295
December 31, 2023 6 1,980 31 2,203
December 31, 2024 7 1,879 31 2,109
Proved undeveloped reserves
December 31, 2021 8 1,550 22 1,733
December 31, 2022 9 1,578 20 1,752
December 31, 2023 12 1,746 32 2,011
December 31, 2024 15 1,478 49 1,861
Totals may not sum or recalculate due to rounding.
In 2024, the Company experienced extensions of 547.5 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica/Marcellus and SCOOP acreages. Of the total extensions, 340.7 Bcfe was attributable to the addition of 33 Utica PUD locations, 92.4 Bcfe was attributable to the addition of 13 Marcellus PUD locations, and 114.4 Bcfe was attributable to the addition of 16 SCOOP PUD locations. The Company experienced total downward revisions of 406.0 Bcfe in estimated proved reserves. These consisted of upward revisions of 16.2 Bcfe as a result of positive well performance and 171.2 Bcfe due to an increase in working interest and net revenue interest as a result of our successful leasing efforts through 2024. These were offset by downward revisions of 487.9 Bcfe which were due to commodity price changes. Commodity prices experienced volatility throughout 2024 and the 12-month average price for natural gas decreased from $2.64 per MMBtu for 2023 to $2.13 per MMBtu for 2024, the 12-month average price for NGL decreased from $31.42 per barrel for 2023 to $31.30 per barrel for 2024, and the 12-month average price for crude oil decreased from $78.21 per barrel for 2023 to $76.32 per barrel for 2024. Additionally, downward revisions of 172.4 Bcfe were primarily a result of development schedule changes with some PUD well design changes. The schedule changes moved the development of 11 Utica/Marcellus PUD locations and 6 SCOOP PUD locations beyond the SEC requirement of developing these wells five years from initial booking. The development schedule changes reflect our ongoing commitment to optimizing the long-term plan to best develop our asset and maximize cash flow and overall economic returns. These locations excluded from our SEC reserves report remain in Gulfport's development plan. Finally, upward revisions of 66.9 Bcfe were a result of a combination of various economic assumption updates.
In 2023, the Company experienced extensions of 995.7 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica/Marcellus and SCOOP acreages. Of the total extensions, 789.2 Bcfe was attributable to the addition of 67 Utica PUD locations, 88.6 Bcfe was attributable to the addition of 12 Marcellus PUD locations, and 110.4 Bcfe was attributable to the addition of 14 SCOOP PUD locations. The Company experienced total downward revisions of 444.9 Bcfe in estimated proved reserves. These consisted of upward revisions of 24.9 Bcfe as a result of positive well performance and 293.9 Bcfe due to an increase in working interest and net revenue interest as a result of our successful leasing efforts through 2023. These were offset by downward revisions of 554.9 Bcfe which were primarily a result of development schedule changes with some PUD well design changes. The schedule changes moved the development of 36 Utica/Marcellus PUD locations and 8 SCOOP PUD locations beyond the SEC requirement of developing these wells five years from initial booking. The development schedule changes reflect our ongoing commitment to optimizing the long-term plan to best develop our asset and maximize cash flow and overall economic returns. These locations excluded from our SEC reserves report remain in Gulfport's development plan. Additionally, downward revisions of 159.7 Bcfe due to commodity price changes. Commodity prices experienced volatility throughout 2023 and the 12-month average price for natural gas decreased from $6.36 per MMBtu for 2022 to $2.64 per MMBtu for 2023, the 12-month average price for NGL increased from $47.86 per barrel for 2022 to $31.42 per barrel for 2023, and the 12-month average price for crude oil decreased from $94.14 per barrel for 2022 to $78.21 per barrel for 2023. Finally, downward revisions of 49.1 Bcfe were a result of a combination of various economic assumption updates.
In 2022, the Company experienced extensions of 438.9 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica/Marcellus and SCOOP acreages. Of the total extensions, 295.9 Bcfe was attributable to the addition of 36 PUD locations in the Utica, 72.1 Bcfe was attributable to the addition of 8 PUD locations in the Marcellus and 65.4 Bcfe was attributable to the addition of 5 PUD locations in the SCOOP. The Company experienced total upward revisions of approximately 69.7 Bcfe in estimated proved reserves, of which 47.7 Bcfe was the result of improved commodity prices. The 12-month average price for natural gas increased from $3.60 per MMBtu for 2021 to $6.36 per MMBtu for 2022, the 12-month average price for NGL increased from $31.90 per barrel for 2021 to $47.86 per barrel for 2022, and the 12-month average price for crude oil increased from $66.55 per barrel for 2021 to $94.14 per barrel for 2022. Upward revisions of 144.5 Bcfe were a result of an increase in working interest and net revenue interests as a result of our successful leasing efforts through 2022. Downward revisions of 95.6 Bcfe were experienced as a result of the SEC five-year development window, which removed 4 PUD locations in the Utica and 5 PUD locations in the SCOOP. The development plan changes reflect our commitment to optimizing the long-term development schedule to maximize cash flow and overall economic returns. A small downward revision of 26.9 Bcfe was primarily a result of performance changes to several wells and changes in PUD location forecasts.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2024, 2023 and 2022 using an unweighted average first-of-the-month price for the year January through December 31, 2024, 2023 and 2022. The average gas prices used were $2.13, $2.64 and $6.36 per MMbtu, for the years ended December 31, 2024, 2023 and 2022, respectively. The average oil prices used were $76.32, $78.21 and $94.14 per Bbl, for the years ended December 31, 2024, 2023 and 2022, respectively. The average NGL prices used were $31.30, $31.42 and $47.86 per Bbl, for the years ended December 31, 2024, 2023 and 2022, respectively.
Year ended operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop proved developed non-producing and proved undeveloped reserves are approximately $280.2 million in 2025, $318.8 million in 2026 and $259.2 million in 2027. Estimated future development costs include capital spending on major development projects. Gulfport believes cash flow from its operating activities, cash on hand and borrowings under its Credit Facility will be sufficient to cover these estimated future development costs.
The assumptions used to derive the standardized measure of discounted future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes but should not be solely relied upon in evaluating Gulfport or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company's reserves. Management believes that the following factors should be considered when reviewing the information below:
•Future commodity prices received for selling the Company's net production will likely differ from those required to be used in these calculations.
•Future operating and capital costs will likely differ from those required to be used in these calculations and do not reflect cost savings of Company owned midstream operations on future operating expenses.
•Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and condensate and gas may cause production rates in future years to vary significantly from those rates used in the calculations.
•Future revenues may be subject to different production, severance and property taxation rates.
•The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves.
The following table summarizes estimated future net cash flows from natural gas and crude oil reserves (in millions):
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Future cash flows $ 10,474 $ 12,338 $ 26,677
Future development and abandonment costs (1,498) (1,625) (1,588)
Future production costs (5,268) (5,641) (5,872)
Future production taxes (212) (303) (553)
Future income taxes (23) (63) (2,609)
Future net cash flows 3,473 4,706 16,055
10% discount to reflect timing of cash flows (1,726) (2,323) (7,776)
Standardized measure of discounted future net cash flows $ 1,747 $ 2,383 $ 8,279
Totals may not sum or recalculate due to rounding.
Future development and abandonment costs include not only development costs but also all future costs to settle asset retirement obligations. The following table summarizes the total of all future costs to settle asset retirement obligations that are included in future development and abandonment costs above (in millions):
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Future asset retirement obligations $ 240 $ 229 $ 222
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The principal source of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below (in millions):
Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022
Sales and transfers of oil and gas produced, net of production costs $ (478) $ (600) $ (1,849)
Net changes in prices, production costs, and development costs (910) (7,181) 5,130
Acquisition of oil and gas reserves in place - - -
Extensions and discoveries 368 581 941
Previously estimated development costs incurred during the period 211 263 204
Revisions of previous quantity estimates, less related production costs (21) (278) 154
Sales of oil and gas reserves in place - - (1)
Accretion of discount 238 828 414
Net changes in income taxes 16 1,219 (1,067)
Change in production rates and other (60) (728) 215
Total change in standardized measure of discounted future net cash flows $ (636) $ (5,896) $ 4,141

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Control and Procedures
Under the direction of our Chief Executive Officer and our Chief Financial Officer, and with participation of management, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.
As of December 31, 2024, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and our Chief Financial Officer have concluded that, as of December 31, 2024, our disclosure controls and procedures are effective.
In designing and evaluating the Company's disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company's controls will succeed in achieving their goals under all potential future conditions.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter ended December 31, 2024, which materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of adequate internal control over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act of 1934. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting financial information.
Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2024.
Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2024 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2024, as stated in their accompanying report.
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Gulfport Energy Corporation
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Gulfport Energy Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2024, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2024, and our report dated February 26, 2025 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
February 26, 2025

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
The disclosures set forth below are provided in this Part II, Item 9B in lieu of separate disclosure under Items 5.02(b)-(c) and (e) of Form 8-K.
Trading Arrangements
During the year ended December 31, 2024, none of our officers (as defined in Rule 16a-1(f) of the Exchange Act) or directors adopted or terminated any contract, instruction or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any “non-Rule 10b5-1 trading arrangement” (as defined in Item 408 of Regulation S-K).
Appointment of Chief Operating Officer
On February 24, 2025, Matthew Rucker was promoted to Executive Vice President, Chief Operating Officer, with a $500,000 base salary, 100% short-term incentive bonus target, and 400% long-term incentive award.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The names of executive officers and certain other senior officers of the Company and their ages, titles and biographies as of the date hereof are incorporated by reference from Item 1 of Part I of this report. The other information called for by this Item 10 is incorporated herein by reference to the definitive proxy statement to be filed by Gulfport pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than 120 days after the close of our fiscal year ended December 31, 2024 (the 2025 Proxy Statement).

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The information called for by this Item 11 is incorporated herein by reference to the 2025 Proxy Statement.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information called for by this Item 12 is incorporated herein by reference to the 2025 Proxy Statement.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information called for by this Item 13 is incorporated herein by reference to the 2025 Proxy Statement.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information called for by this Item 14 is incorporated herein by reference to the 2025 Proxy Statement.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following financial statements, financial statement schedules and exhibits are filed as part of this report:
1.Financial Statements. Gulfport's consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements.
2.Financial Statement Schedules. No financial statement schedules are applicable or required.
3.Exhibits. The exhibits listed below in the Index of Exhibits are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.
INDEX OF EXHIBITS
Incorporated by Reference
Exhibit Number Description Form SEC File Number Exhibit Filing Date Filed or Furnished Herewith
2.1 Amended Joint Chapter 11 Plan of Reorganization of Gulfport Energy Corporation and its Debtor Subsidiaries.
8-K 001-19514 2.2 4/29/2021
3.1 Amended and Restated Certificate of Incorporation of Gulfport Energy Corporation.
8-K 001-19514 3.1 5/17/2021
3.2 Amended and Restated Bylaws of Gulfport Energy Corporation.
8-K 001-19514 3.2 5/17/2021
4.1 1145 Indenture, dated as of May 17, 2021, by and among Gulfport Energy Corporation, UMB Bank, National Association, as trustee, and the guarantors party thereto (including the form of note attached thereto).
8-K 001-19514 4.1 5/17/2021
4.2 4(a)(2) Indenture, dated as of May 17, 2021, by and among Gulfport Energy Corporation, UMB Bank, National Association, as trustee, and the guarantors party thereto (including the form of note attached thereto).
8-K 001-19514 4.2 5/17/2021
4.3 Indenture, dated September 13, 2024, among Gulfport Energy Operating Corporation, Gulfport Energy Corporation, the subsidiary guarantors party thereto and UMB Bank, National Association, as trustee.
8-K 001-19514 4.1 9/16/2024
4.4 Description of Securities Registered Pursuant to Section 12 of the Exchange Act.
10-K 001-19514 4.3 3/1/2023
10.1+ Gulfport Energy Corporation 2021 Stock Incentive Plan.
8-K 001-19514 10.6 5/17/2021
10.2+ Form of Employee Restricted Stock Unit Award Agreement, dated as of July 21, 2021.
10-Q 001-19514 10.7 8/9/2021
10.3+ Form of Director Restricted Stock Unit Award Agreement, dated as of July 21, 2021.
10-Q 001-19514 10.8 8/9/2021
10.4+ Form of Performance-Based Restricted Stock Unit Award Agreement, dated as of July 21, 2021.
10-Q 001-19514 10.9 8/9/2021
10.5+ Form of Indemnification Agreement.
S-4 333-199905 10.1 11/6/2014
10.6+ CEO Agreement Amendment by and among Timothy Cutt and Gulfport, effective as of September 2, 2021.
8-K 001-19514 10.1 9/7/2021
10.7+ Employment Agreement by and among William Buese and Gulfport, effective as of May 17, 2021.
8-K 001-19514 10.5 5/17/2021
10.8+ Employment Agreement between Gulfport Energy Corporation and Timothy Cutt, effective April 29, 2022.
10-Q 001-19514 10.2 5/4/2022
10.9+ Employment Agreement, by and between Gulfport Energy Corporation and John Reinhart, effective January 24, 2023.
8-K 001-19514 10.1 1/24/2023
10.10+ Indemnification Agreement, by and between Gulfport Energy Corporation and John Reinhart, effective January 24, 2023.
8-K 001-19514 10.2 1/24/2023
10.11+ Transition and Services Agreement, by and between Gulfport Energy Corporation and Timothy Cutt, effective February 1, 2023.
8-K 001-19514 10.3 1/24/2023
10.12 Cooperation Agreement, dated as of May 17, 2021, by and among Gulfport Energy Corporation and Silver Point Capital, L.P.
8-K 001-19514 10.3 5/17/2021
10.13 Registration Rights Agreement, dated as of May 17, 2021, by and among Gulfport Energy Corporation and the holders party thereto.
8-K 001-19514 10.2 5/17/2021
10.14* Third Amended and Restated Credit Agreement, dated as of October 14, 2021, by and among Gulfport Energy Corporation, as holdings, Gulfport Energy Operating Corporation, as the borrower, JPMorgan Chase Bank, N.A., the lenders party thereto, and the guarantors party thereto.
8-K 001-19514 10.1 10/14/2021
10.15 Borrowing Base Redetermination Agreement and First Amendment to Credit Agreement, dated as of May 2, 2022.
10-Q 001-19514 10.1 5/4/2022
10.16 Borrowing Base Reaffirmation Agreement and Second Amendment to Credit Agreement, dated as of October 31, 2022.
10-Q 001-19514 10.1 11/2/2022
10.17+ Form of Employment Agreement.
10-K 001-19514 10.19 3/1/2023
10.18 Borrowing Base Reaffirmation Agreement and Third Amendment to Credit Agreement, dated as of May 1, 2023.
10-Q 001-19514 10.3 5/3/2023
10.19+ Change in Control Severance Agreement.
10-Q 001-19514 10.2 8/2/2023
10.20+ Employment Agreement between Gulfport Energy Corporation and Michael Hodges, effective April 3, 2023.
8-K 001-19514 10.1 4/3/2023
10.21+ Indemnification Agreement, by and between Gulfport Energy Corporation and Michael Hodges, effective April 3, 2023.
8-K 001-19514 10.2 4/3/2023
10.22
Commitment Increase, Borrowing Base Reaffirmation Agreement and Fourth Amendment to Credit Agreement dated September 12, 2024.
8-K 001-19514 10.1 9/16/2024
10.23+
Employment Agreement between Gulfport Energy Corporation and Patrick Craine, effective March 1, 2023.
X
10.24+ Employment Agreement between Gulfport Energy Corporation and Matthew Rucker, effective March 1, 2023.
X
10.25+
Employment Agreement between Gulfport Energy Corporation and Michael Sluiter, effective March 1, 2023.
X
10.26+
Form of Performance-Based Restricted Stock Unit Award Agreement, dated as of April 29, 2022.
X
10.27+
Form of Performance-Based Restricted Stock Unit Award Agreement, dated as of January 1, 2023.
X
10.28+
Form of Non-Executive Restricted Stock Unit Award Agreement, dated as of May 24, 2023.
X
10.29+
Form of Director Restricted Stock Unit Award Agreement, dated as of May 24, 2023.
X
10.30+
Form of Performance-Based Restricted Stock Unit Award Agreement, dated as of January 1, 2024.
X
10.31+
Form of Executive Restricted Stock Unit Award Agreement, dated as of February 29, 2024.
X
10.32+
Form of Non-Executive Restricted Stock Unit Award Agreement, dated as of February 29, 2024.
X
10.33+
Form of Director Restricted Stock Unit Award Agreement, dated as of May 23, 2024.
X
10.34+
Form of Performance-Based Restricted Stock Unit Award Agreement, dated as of January 1, 2025.
X
10.35+
Form of Executive Restricted Stock Unit Award Agreement, dated as of February 24, 2025.
X
10.36+
Form of Non-Executive Restricted Stock Unit Award Agreement, dated as of February 24, 2025.
X
19 Insider Trading Policy.
X
21 Subsidiaries of the Registrant.
X
23.1 Consent of Netherland, Sewell & Associates, Inc.
X
23.2 Consent of Grant Thornton LLP.
X
31.1 Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
X
31.2 Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
X
32.1 Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
X
32.2 Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
X
97.1 Clawback Policy.
10-K 001-19514 97.1 2/28/2024
99.1 Report of Netherland, Sewell & Associates, Inc.
X
101.INS Inline XBRL Instance Document. X
101.SCH Inline XBRL Taxonomy Extension Schema Document. X
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document. X
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document. X
101.LAB Inline XBRL Taxonomy Extension Labels Linkbase Document. X
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document. X
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) X
* Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The registrant undertakes to furnish supplemental copies of any of the omitted schedules upon request by the SEC.
+ Management contract, compensatory plan or arrangement.