NYSE: INR

The Upstream Assets include approximately 42,500 net surface acres in the Ohio Utica Shale across Guernsey, Noble, Belmont, and Monroe Counties, which are highly contiguous with and complementary to our existing Ohio operations. The assets include an estimated 370.1 Bcfe of proved reserves and approximately 110 identified undeveloped drilling locations across multiple phase windows.

The Midstream Assets include approximately 141 miles of natural gas gathering pipelines, with capacity to support up to 600 MMcf/d, and approximately 90 miles of freshwater and produced‑water infrastructure. These assets enhance our vertical integration and are expected to reduce operating costs, improve margins, and enable efficient full‑field development.

Infinity will operate substantially all of the Antero Ohio Assets pursuant to joint development and cooperation agreements entered into with Northern at closing. We funded the transaction with cash on hand, the proceeds of the Preferred Investment and borrowings under our Credit Facility, which was amended and expanded in connection with closing.

Preferred Investment

On February 23, 2026, Infinity issued and sold, pursuant to a Securities Purchase Agreement (“Securities Purchase Agreement”) an aggregate 350,000 shares of Series A Convertible Preferred Stock of the Company, par value $0.01 per share (“Series A Preferred Stock”) to affiliates of Quantum Capital Group (“Quantum”) and affiliates of Carnelian Energy Capital Management, L.P. (“Carnelian”) (each a “Preferred Purchaser” and, collectively, the “Preferred Purchasers”) for consideration of $350 million. After deducting placement agent fees, Infinity received net proceeds of approximately $337.1 million. Quantum acquired 275,000 shares of Series A Preferred Stock and Carnelian acquired 75,000 shares of Series A Preferred Stock (the “Preferred Investment”). The Company used the proceeds of the Preferred Investment to fund a portion of the Antero Acquisitions and will use any remaining proceeds for general corporate purposes.

Initial Public Offering

On February 3, 2025, we completed our IPO of 15,237,500 shares of our Class A common stock, par value $0.01 per share (“Class A common stock”), which includes 1,987,500 shares of Class A common stock issued and sold pursuant to the underwriters’ exercise of their option in full to purchase additional shares of Class A common stock, at a price to the public of $20.00 per share ($18.80 per share net of underwriting discounts and commissions). After deducting underwriting discounts and commissions, we received net proceeds of approximately $286.5 million. We contributed all of the net proceeds from the IPO to INR Holdings. In turn, INR Holdings used all of the net proceeds from the IPO (net of underwriting discounts) after paying certain offering expenses to repay $285.0 million of outstanding borrowings under the Credit Facility.

Corporate Reorganization

In connection with the IPO, we underwent a Corporate Reorganization whereby: (a) the membership interests of the Legacy Owners in INR Holdings (including the Incentive Units, as defined in Item 11. “Executive Compensation—Narrative Disclosure to Summary Compensation Table—Long-Term Equity Incentive Compensation”) were recapitalized into a single class of units (the “INR Units”), and, in exchange for their existing membership interests, the Legacy Owners received INR Units and an equal number of shares of Class B common stock, par value $0.01 per share (“Class B common stock”); and (b) we contributed the net proceeds of the IPO to INR Holdings in exchange for newly issued INR Units and a managing member interest in INR Holdings. Infinity is a holding company whose sole material asset consists of membership interests in INR Holdings. Infinity is the managing member of INR Holdings and controls and is responsible for all operational, management and administrative decisions relating to INR Holdings’ business and consolidates the financial results of INR Holdings and reports non-controlling interests in its consolidated financial statements related to the INR Units that the Legacy Owners own in INR Holdings. As of December 31, 2025, we owned an approximate 25.6% common interest in INR Holdings and the Legacy Owners owned an approximate 74.4% common interest in INR Holdings.

Our Operations and Acreage

Our operations are focused on the Utica Shale in eastern Ohio as well as the Marcellus Shale and the emerging dry gas Utica Shale in southwestern Pennsylvania. As of December 31, 2025, we held approximately 98,400 net surface acres across our core operating areas. The following table provides a summary of our approximate net acreage, net operated producing wells and gross drilling locations separated by shale (including acreage prospective for dual-zone development):

As of December 31, 2025

Net Horizon

Acres(1)

Operated

Producing

Wells (#)

Drilling

Locations (#)

Utica Shale Oil (OH)
64,152 129 129
(3)

Marcellus Shale Dry Gas (PA)(2)
33,925 25 107

Utica Shale Deep Dry Gas (PA)(2)
33,226 — 66

_____________

(1)Does not include 15,677 net acres located in the Marcellus Shale in Ohio that is not part of our development plan.

(2)The acreage in this table reflects net horizon acres. Substantially all of our surface acreage in Pennsylvania is prospective for both the Utica and Marcellus Shales for dual-zone development. As a result, most of our net surface acres represent one horizon acre for the Utica Shale and one horizon acre for the Marcellus Shale. Our total net surface acreage irrespective of dual-zone development was 98,419 net acres and our total horizon acres were 131,303. See “Business—Our Operations—Acreage as of December 31, 2025” for information regarding our undeveloped and developed surface acreage.

(3)Includes 6 PDNP wells and 8 DUCs.

Utica Shale Oil – Ohio

We hold a significant acreage position in Ohio centered in the volatile oil window of the Utica Shale, primarily in Guernsey, Carroll, Noble, Morgan, and Washington Counties. As of December 31, 2025, we held approximately 64,000 net acres in this operating area. Subsequent to year‑end, we completed the Antero Acquisition, which added approximately

42,500 net surface acres attributable to our 60% undivided interest across Guernsey, Belmont, and Harrison Counties. Including the Antero Ohio Assets, our total net acreage position in the Ohio Utica Shale increased to approximately 107,000 net surface acres.

We have 129 producing horizontal wells, six PDNP wells and eight DUCs in this operating area with net daily production of 22.8 MBoe/d in 2025. We intend to operate 100% of our future drilling locations and approximately 82% of our acreage is HBP.

Marcellus Shale Dry Gas and Utica Deep Dry Gas – Pennsylvania

Our Pennsylvania properties, which we initially acquired in March 2018, are predominately located to the northeast of Pittsburgh in Westmoreland, Armstrong and Indiana counties. We have expanded our leasehold position through a series of subsequent acquisitions and have amassed approximately 34,000 net surface acres with exposure to both Marcellus and Utica Shales. Our development of the Marcellus Shale overlies the deep dry gas Utica Shale underneath providing us dual horizon development as well as the opportunity to further leverage our wholly owned midstream system in this area. While early in its development, the deep dry gas Utica continues to emerge and show highly attractive commercial characteristics. As of February 2026, we have one outstanding permit to drill a deep dry gas Utica Shale well in Armstrong County, Pennsylvania. Our contiguous HBP acreage and company-owned midstream infrastructure allow us to maximize the economics of the stacked Marcellus and Utica plays.

We have 25 producing horizontal wells in this operating area with net daily production of 12.5 MBoe/d in 2025. We intend to operate 100% of our future drilling locations and approximately 98% of our acreage is HBP or held-by-storage.

Our Properties

Oil, Natural Gas and NGL Reserves

The information with respect to our estimated reserves has been prepared in accordance with the rules and regulations of the SEC. Our estimated proved reserves as of December 31, 2025 and 2024 are based on valuations prepared by our independent reserve engineer, Wright & Company, Inc. (“Wright”). Copies of the summary reports of our reserve engineers as of December 31, 2025 and 2024 are filed as exhibits to this Annual Report. “—Preparation of Reserve Estimates” below contains additional definitions of proved reserves and the technologies and economic data used in their estimation. The following tables summarize estimated reserves based on reports prepared by Wright. The information in the following tables does not give any effect to or reflect our commodity hedge portfolio.

Summary of Reserves as of December 31, 2025 and 2024 Based on SEC Pricing

The following table provides the estimated reserves of INR Holdings as of December 31, 2025 and 2024 based on SEC pricing:

December 31, 2025(1)
December 31,

2024(2)

Proved developed reserves:

Crude oil (MBbls)
14,717 14,577

Natural Gas (MMcf)
417,362 248,634

NGL (MBbls)
15,958 12,856

Total proved developed reserves (MBoe)(3)
100,235 68,872

Proved undeveloped reserves:

Crude oil (MBbls)
21,954 22,777

Natural Gas (MMcf)
499,262 368,382

NGL (MBbls)
19,589 17,300

Total proved undeveloped reserves (MBoe)(3)
124,753 101,474

Total proved reserves:

Crude oil (MBbls)
36,671 37,354

Natural Gas (MMcf)
916,624 617,016

NGL (MBbls)
35,548 30,156

Total proved reserves (MBoe)(3)(4)
224,989 170,346

Proved developed reserves (%)
45 % 40 %

Proved undeveloped reserves (%)
55 % 60 %

Reserve values (in thousands):

Standardized measure of discounted future net cash flows
$ 1,081,193 $ 972,518

Discounted future income tax expense
$ 251,800 N/A

Total proved pre-tax PV-10(5)
$ 1,332,993 $ 972,518

_____________

(1)Our estimated reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC regulations. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $65.34 per Bbl for oil and $3.39 per MMBtu for natural gas at December 31, 2025. These base prices were adjusted for differentials on a per property basis, including local basis differentials and fuel costs, resulting in $58.61 per Bbl for oil, $2.77 per MMBtu for natural gas, and $23.20 per Bbl for NGLs at December 31, 2025.

(2)Our estimated reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC regulations. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $75.48 per Bbl for oil and $2.13 per MMBtu for natural gas at December 31, 2024. These base prices were adjusted for differentials on a per property basis, including local basis differentials and fuel costs, resulting in $67.98 per Bbl for oil, $1.42 per MMBtu for natural gas, and $25.48 per Bbl for NGLs at December 31, 2024.

(3)Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

(4)All proved reserves as of December 31, 2025 were part of a development plan adopted by management indicating that such locations were scheduled to be drilled within five years of initial classification.

(5)PV-10 is a non-GAAP financial measure and represents the estimated present value of the future cash flows less future development and production costs from our proved reserves before income taxes discounted using a 10% discount rate. PV-10 of proved reserves generally differs from the Standardized Measure (as defined herein), the most directly comparable GAAP financial measure, because it does not include the effects of future income taxes, as is required under GAAP in computing the Standardized Measure.

We believe that the presentation of a pre-tax PV-10 value provides relevant and useful information because it is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and natural gas companies. Because many factors that are unique to each individual company may impact the amount and timing of future income taxes, the use of PV-10 value provides greater comparability when evaluating oil and natural gas companies. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of proved oil and gas reserves. However, the definition of PV-10 value as defined above may differ significantly from the definitions used by other companies to compute similar measures. As a result, the PV-10 value as defined may not be comparable to similar measures provided by other companies.

Investors should be cautioned that neither PV-10 nor Standardized Measure of proved reserves represents an estimate of the fair market value of our proved reserves. We and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities. See Note 19—“Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)” to our consolidated financial statements for additional information about the calculation of Standardized Measure.

Proved Undeveloped Reserves (in MBoe)

Our 2025 proved undeveloped reserves increased by approximately 23.3 MMBoe, or 23%, compared to 2024. The following reconciliation from 2024 to 2025 is presented to meet SEC requirements to provide material changes to our proved undeveloped reserves during the year. All of our PUDs are associated with drilling locations that are scheduled to be drilled within five years of the initial disclosure of proved reserves.

Proved undeveloped reserves at December 31, 2024 101,474

Conversions into proved developed reserves(1)
(30,691)

Revisions(2)
978

Extensions and discoveries(3)
52,992

Proved undeveloped reserves at December 31, 2025 124,753

_____________

(1)Conversions of PUD drilling locations in 2025 included developing 12 wells that were PUDs as of December 31, 2024.

(2)Total positive revisions of 978 MBoe were comprised of 3,930 MBoe of positive revisions related to increases in working interest, improvement in expense assumptions, and improvement in type curve, offset by downward revisions of 2,952 MBoe in PUDs from 2024 to 2025 due to 2 PUD locations that were removed due to changes to our development plan.

(3)Extensions primarily related to the addition of 28 PUD locations to be developed by 2030 (as that year entered the 5-year development window). These locations reside within the 5-year development window, which permits their recognition as PUD reserves based upon their continuing satisfaction of the engineering requirements for recognition as proved reserves. Extensions include the addition of new locations associated with our drilling program and additional Utica drilling in the 5-year development window.

Adjusted Index Prices Used in Reserve Calculations

The following tables show index prices used in our reserve calculations as of the dates indicated under historical SEC pricing:

Pricing Used for Proved Reserves as of December 31, 2025

Based on Historical SEC Pricing:

Oil (per Bbl)
$ 58.61

Natural gas (per Mcf)
$ 2.77

Natural gas liquids (per Bbl)
$ 23.20

Pricing Used for Proved Reserves as of December 31, 2024

Based on Historical SEC Pricing:

Oil (per Bbl)
$ 67.98

Natural gas (per Mcf)
$ 1.42

Natural gas liquids (per Bbl)
$ 25.48

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2025 and December 31, 2024 included in this Annual Report are based on reports prepared by Wright, our independent reserve engineer, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC in effect at such time. Copies of the reports are included as exhibits to this Annual Report. Wright provides a variety of services to the oil and gas industry, including field studies, oil and gas reserve estimations, appraisals of oil and gas properties and reserve report for their clients.

Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. The technical and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, well-test data, production data (including flow rates), well data (including lateral lengths), historical price and cost information and property ownership interests. Our independent reserve engineer uses this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy. The proved developed reserves and EURs are estimated using performance analysis and volumetric analysis. The estimates of the proved developed reserves and EURs are used to estimate the proved undeveloped reserves for each proved undeveloped location (utilizing type curves, statistical analysis, and analogy). Proved undeveloped drilling locations that are more than one offset from a proved developed well utilized reliable technologies to confirm reasonable certainty. The reliable technologies that were utilized in estimating these reserves include log data, performance data, log cross sections, seismic data, core data, and statistical analysis.

Internal Controls

Our internal staff of petroleum engineers works closely with Wright to ensure the integrity, accuracy and timeliness of data furnished to Wright. Periodically, our technical team meets with Wright to review properties and discuss methods and assumptions used by us to prepare reserve estimates. Wright is an independent petroleum engineering and geological services firm.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas 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 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.

For all of our properties, our internally prepared reserve estimates and the reserve report prepared by Wright are reviewed and approved by our SVP of Commercial and Production.

Qualifications of Responsible Technical Persons

Our SVP of Commercial & Production, Ryan Warner, is responsible for overseeing the preparation of the reserves estimates. Mr. Warner is a founding member at Infinity Natural Resources and has over 10 years of relevant experience in reservoir engineering and reserve estimation. He holds a degree in Petroleum Engineering from West Virginia University and is a registered Professional Engineer.

Wright was founded in 1988 by Mr. D. Randall Wright and performs consulting petroleum engineering services including but not limited to annual reserves audits, property evaluation, and reservoir analysis. Mr. Wright is the primary technical person in charge of the estimates of reserves and associated cash flow and economics on behalf of Wright for the results presented. He holds a Master of Science degree in Mechanical Engineering from Tennessee Technological University. He is a registered Professional Engineer in the state of Texas (TBPE #43291), granted in 1978, a member of the Society of Petroleum Engineers (“SPE”) and a member of the Order of the Engineer.

Mr. Adam Null, a registered Professional Engineer in the State of Tennessee (TBAEE #122667), has provided technical assistance in the estimates of reserves and cash flow results presented. Mr. Null is a member of the SPE and has been practicing petroleum engineering for more than 10 years. He currently holds the title of Chief Operating Officer at Wright.

Mr. Wright and Mr. Null are qualified reserves evaluators as set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the SPE. This qualification is based on years of practical experience in the estimation and evaluation of petroleum reserves.

Production, Revenue, Price and Production Costs

The following table sets forth information regarding our production, revenues and realized prices and production costs for the years ended December 31, 2025 and 2024. All of our production is derived from the Appalachian Basin. For additional

information on price calculations, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Year Ended

December 31,

2025 2024

Production data:

Oil (MBbls)
3,074 2,380

Natural gas (MMcf)
45,596 28,291

NGL (MBbls)
2,209 1,723

Total (MBoe)(1)
12,882 8,818

Average daily production (MBoe/d)(1)
35.3 24.1

Average wellhead realized prices (before giving effect to realized derivatives):

Oil (/Bbl)
$ 56.48 $ 67.86

Natural gas (/Mcf)
$ 2.80 $ 1.81

NGL (/Bbl)
$ 22.32 $ 26.14

Average wellhead realized prices (after giving effect to realized derivatives):

Oil (/Bbl)
$ 60.98 $ 66.93

Natural gas (/Mcf)
$ 2.81 $ 2.47

NGL (/Bbl)
$ 22.22 $ 28.66

Operating costs and expenses (per Boe)(1):

Gathering, processing and transportation
$ 4.25 $ 5.59

Lease operating
2.07 3.19

Production and ad valorem taxes
0.46 0.12

Depreciation, depletion, and amortization
8.05 8.36

General and administrative
11.91 1.48

Total
$ 26.74 $ 18.74

_____________

(1)Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

Productive Wells as of December 31, 2025

As of December 31, 2025, we owned interests in the following number of productive wells:

Productive Wells

Gross Net

Oil
152.0 104.7

Natural Gas
30.0 22.1

Total
182.0 126.8

Acreage as of December 31, 2025

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2025:

Surface Acreage

Gross Net

Undeveloped acres
55,989 53,532

Developed acres
48,141 44,887

Total
104,130 98,419

Undeveloped Acreage Expirations as of December 31, 2025

The following table sets forth the gross and net undeveloped acreage, as of December 31, 2025, that will expire over the next five years unless production is established within the spacing units covering the acreage, the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates or pursuant to other terms of the lease agreements. We expect to drill wells on such acreage or make extension payments prior to lease expiration.

Acreage

Gross Net

2026 71 71

2027 6,368 6,338

2028 1,588 1,543

2029 3,058 3,058

2030 and thereafter 1,424 1,423

12,509 12,433

As of December 31, 2025, we had 28.1 MMBoe of proved undeveloped reserves that were associated with potentially expiring acreage.

Drilling Activity

The table below sets forth the results of our operated drilling activities for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.

For the Year Ended December 31,

2025 2024 2023

Gross Net Gross Net Gross Net

Development

Productive
23.0 20.2 14.0 12.0 10.0 9.1

Dry Hole
— — — — — —

Total Development Wells
23.0 20.2 14.0 12.0 10.0 9.1

Exploratory

Productive
— — — — — —

Dry Hole
— — — — — —

Total Exploratory Wells
— — — — — —

As of December 31, 2025, we had 8.0 gross (7.8 net) operated wells in process.

Major Customers

We generally sell our oil, natural gas and NGL production to purchasers at prevailing market prices, which in certain cases are adjusted for contractual differentials, and the majority of our revenue contracts have terms greater than twelve months.

We normally sell production to a relatively small number of customers, as is customary in our business. The table below summarizes the purchasers that accounted for 10% or more of our total net revenues for the periods presented:

For the Year Ended December 31,

2025 2024

Marathon Oil Company
33 % 55 %

BP America
35 % 17 %

Ergon 16 % — %

Blue Racer Midstream
— % 10 %

During these periods, no other purchaser accounted for 10% or more of our net revenues. As of December 31, 2025, the Company’s accounts receivable balance related to oil and gas sales was comprised of amounts due from various purchasers, including amounts due from Marathon Oil Company, BP America and Ergon comprising 24%, 53%, and 18%, respectively, of the total balance. As of December 31, 2024, the Company’s accounts receivable balance related to oil and gas sales was comprised of amounts due from Marathon Oil Company and BP America, which accounted for 49% and 25% respectively, of the total balance. The loss of any of our major purchasers could materially and adversely affect our revenues in the near-term. However, since crude oil and natural gas are fungible products with well-established markets and numerous purchasers and are based on current demand for oil and natural gas, we believe that the loss of any major purchaser would not have a material adverse effect on our financial condition or results of operations.

Title to Properties

We believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we may conduct a more thorough title examination or obtain title opinions and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Seasonality

Generally, demand for oil, natural gas and NGL decreases during the spring and fall months and increases during the summer and winter months. However, certain natural gas and NGL markets utilize storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. In addition, seasonal anomalies such as mild winters or mild summers can have a significant impact on prices. These seasonal anomalies can pose challenges for meeting our well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages, increased costs or delay operations.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in evaluating and bidding for oil and natural gas properties.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Legislative and regulatory environment

Our oil, natural gas and NGL exploration, development, production and related operations and activities are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with such rules and regulations can result in administrative, civil or criminal penalties, compulsory remediation and imposition of natural resource damages or other liabilities. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, we believe these obligations generally do not impact us differently or to any greater or lesser extent than they affect other operators in the natural gas and oil industry with similar operations and types, quantities and locations of production.

Regulation of production

In most states, oil and natural gas companies are generally required to obtain permits for drilling operations, provide drilling bonds, file reports concerning operations and meet other requirements related to the exploration, development and production of oil, natural gas and NGLs. Such states also have statutes and regulations addressing conservation and reclamation matters, including provisions for unitization or pooling of natural gas and oil interests, rights and properties, the surface use and restoration of properties upon which wells are drilled and disposal of water produced or used in the drilling and completion process. These regulations include the establishment of maximum rates of production from natural gas and oil wells, rules as to the spacing, plugging and abandoning of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production, as well as rules governing the surface use and restoration of properties upon which wells are drilled.

These laws and regulations may limit the amount of oil, natural gas and NGLs that can be produced from wells in which we own an interest and may limit the number of wells, the locations in which wells can be drilled or the method of drilling wells. Additionally, the procedures that must be followed under these laws and regulations may result in delays in obtaining permits and approvals necessary for our operations and therefore our expected timing of drilling, completion and production may be negatively impacted. These regulations apply to us directly as the operator of our leasehold. The failure to comply with these rules and regulations can result in substantial penalties.

Regulation of sales and transportation of hydrocarbon liquids

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress has enacted price controls in the past and could reenact such controls in the future.

Our sales of oil and NGLs are affected by the availability, terms and cost of transportation. The transportation of oil, NGLs and other hydrocarbon liquids in common carrier pipelines is subject to rate and access regulation. FERC regulates the rates and terms and conditions of service of interstate transportation of oil, NGL and other liquids by pipeline under the Interstate Commerce Act. Typically, liquids pipelines’ interstate transportation rates are set using a generally applicable annual indexing methodology; however, a pipeline may also use a cost-of-service approach, set rates via settlement with shippers or utilize market-based rates in certain circumstances. The rates we pay for interstate transportation of liquids by pipeline, and the related terms of service, may change as a result of regulatory proceedings.

Rates for intrastate transportation on liquids pipelines are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of liquids transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Regulation of transportation and sales of natural gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by agencies of the U.S. federal government, primarily FERC and its predecessor agency. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act of 1978 (“NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation of natural gas in interstate commerce remains subject to extensive regulation primarily under the Natural Gas Act of 1938 (“NGA”) and NGPA, pursuant to regulations and orders promulgated by FERC. The rates we pay for transportation of natural gas by pipeline, and related terms of service, may change as a result of regulatory proceedings. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected, directly or indirectly, by laws enacted by Congress and by FERC regulations.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical and financial sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the Energy Policy Act of 2005 (the “EPAct of 2005”) and by the Commodity Futures Trading Commission (“CFTC”) under the Commodity Exchange Act (“CEA”) as amended by the Dodd-Frank Act, and regulations promulgated thereunder. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity as well as certain disruptive trading practices. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

The EPAct of 2005 amended the NGA and NGPA to add an anti-market-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC. The EPAct of 2005 also provided FERC with the power to assess civil penalties of up to $1,000,000 per day (adjusted annually for inflation) for violations of the NGA and NGPA. As of 2025, the new adjusted maximum penalty amount is $1,584,648 per violation, per day, in addition to disgorgement of profits associated with any violation. The civil penalty provisions are applicable to entities that engage in the sale and transportation of natural gas for resale in interstate commerce.

On January 19, 2006, FERC issued Order No. 670, implementing the anti-market-manipulation provision of the EPAct of 2005, and subsequently denied rehearing. The resulting rules make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to: (a) use or employ any device, scheme or artifice to defraud; (b) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (c) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-FERC jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services. FERC has also interpreted its authority to reach otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under Order No. 704, described below. However, in October 2022, the Fifth Circuit ruled that FERC’s jurisdiction to regulate market manipulation and assess penalties is limited to interstate natural gas transactions only and does not reach intrastate natural gas transactions.

On December 26, 2007, FERC issued Order No. 704, a final rule on the annual natural gas transaction reporting requirements, as amended and clarified by subsequent orders on rehearing. As a result of these orders, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including oil and natural gas producers, gatherers and marketers, are now required to report, by May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance provided by FERC. Market participants must also indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transportation services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC. Although FERC has set forth a general test for determining whether natural gas facilities perform a non-jurisdictional gathering function or

a jurisdictional transportation function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transportation facilities on which we transport our production as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. We believe that the natural gas pipelines in our own gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transportation services and federally unregulated gathering services could be the subject of litigation, changed regulations or interpretations thereof, and new or amended statutes or interpretations thereof, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

In addition, the pipelines in the gathering systems on which we rely may be subject to safety regulation by the U.S. Department of Transportation through its Pipeline and Hazardous Materials Safety Administration (“PHMSA”). PHMSA has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. Over the past several years, PHMSA has taken steps to expand the regulation of rural gathering lines and impose a number of reporting and inspection requirements on regulated pipelines, and additional requirements are expected in the future. On November 15, 2021, PHMSA released a final rule that expands the definition of regulated gathering pipelines and imposes safety measures on certain previously unregulated gathering pipelines. The final rule also imposes reporting requirements on all gathering pipelines and specifically requires operators to report safety information to PHMSA. We could incur significant costs or liabilities to comply with these PHMSA requirements or similar State safety requirements. Failure to comply with the applicable requirements could result in penalties or fines. As of January 2025, the maximum civil penalties PHMSA can impose are $272,926 per violation per day, with a maximum of $2,729,245 for a related series of violations. Furthermore, the future adoption of laws or regulations that apply more comprehensive or stringent safety standards could increase the expenses we incur.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. As such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC, PHMSA, the CFTC, or state policies and regulations may adversely affect our own operations as well as the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines on which we transport natural gas. We cannot predict what future action FERC, PHMSA, CFTC, or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other oil and natural gas producers and marketers with which we compete.

Regulation of environmental and occupational safety and health matters generally

Our operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing environmental protection, occupational safety and health, and the release, discharge or disposal of materials into the environment, some of which carry substantial costs to maintain compliance and may impose substantial administrative, civil and criminal penalties for failure to comply. Applicable U.S. federal environmental laws include, but are not limited to, the Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”), the Clean Water Act (“CWA”) and the federal Clean Air Act (“CAA”). In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, the prevention and cleanup of pollutants and other matters. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling and production operations; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit construction or drilling activities in sensitive areas such as wilderness, wetlands, frontier or other protected areas; require investigatory or remedial actions to prevent or mitigate

pollution conditions caused by our operations; impose obligations to reclaim and abandon well sites and pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, loss of leases, the imposition of investigatory or remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be feasible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. It is possible that, over time, environmental regulation could evolve to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal or remediation requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot be certain that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our business, there can be no assurance that this will continue in the future.

The following is a summary of some of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous substances and wastes

CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons known as potentially responsible parties, with respect to the release of “hazardous substances” into the environment. Potentially responsible parties include the current and past owners or operators of a disposal site or site where the release occurred and third parties who disposed or arranged for the disposal of the hazardous substances found at such sites. Under CERCLA, such persons may be subject to strict, joint and several and retroactive liability for the remediation of hazardous substances that have been released into the environment and for damages to natural resources. Neighboring landowners, governmental agencies, citizen organizations and other third parties may file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. We are only able to directly control the operation of those wells that we operate. The failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances under CERCLA and other environmental laws but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect our business operations. While petroleum and crude oil fractions are generally not considered hazardous substances under CERCLA and its analogues because of the so-called “petroleum exclusion,” adulterated petroleum products containing other hazardous substances have been treated as hazardous substances in the past.

We also generate, handle, transport, store and dispose of solid and hazardous wastes that may be subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and analogous state laws. RCRA regulates the generation, handling, storage, treatment, transport and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes “drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy” from regulation as hazardous wastes. With the approval of the Environmental Protection Agency (the “EPA”), individual states can administer some or all of the provisions of RCRA, and some states have adopted their own, more stringent requirements. However, legislation has been proposed from time to time and various environmental groups have filed lawsuits that, if successful, could result in the reclassification of certain natural gas and oil exploration and production wastes as “hazardous wastes,” and potentially subject such wastes to much more stringent handling, disposal and clean-up requirements. Any future loss of the RCRA exclusion for drilling fluids,

produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes are determined to have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently own, lease or operate numerous properties that may have been used by prior owners or operators for oil and natural gas development and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations where such substances have been taken for recycling or disposal. In addition, some of our properties may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons were not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and/or analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water discharges

The CWA, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including spills and leaks of oil and other natural gas wastes, into or near waters of the United States or state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The discharge of dredge and fill material into regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). In April 2020 the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit. Further, the U.S. Supreme Court’s decision issued in May 2023 in Sackett v. EPA, held that the jurisdiction of the CWA to regulate the waters of the United States (“WOTUS”) extends only to those adjacent wetlands that are indistinguishable from traditional navigable bodies of water due to a continuous surface connection. In September 2023, the EPA and the Corps published a direct-to-final rule redefining WOTUS to align with the decision in Sackett. However, roughly half of the states and other plaintiffs are continuing to challenge the rule, and the EPA and the Corps are using the pre-2015 definition of WOTUS in these states while litigation continues. In November 2025, the Corps and the EPA issued a proposed rule revising the definition of WOTUS with the stated aim of conforming to the U.S. Supreme Court’s decision in Sackett and revising certain regulatory terms, such as “relatively permanent,” “tributary,” and “continuous surface connection;” a final rule is expected in early 2026, and litigation is likely to follow issuance of the final rule. In addition, in an April 2020 decision further defining the scope of the CWA, the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit. The Court rejected the EPA and the Corps’ assertion that groundwater should be totally excluded from the CWA. In November 2023, the EPA issued draft guidance describing the information that should be used to determine which discharges through groundwater may require a permit. However, in January 2025, President Trump issued executive orders directing (i) the EPA and the Corps to identify planned or potential actions that could be subject to emergency treatment under Section 404 of the CWA and (ii) the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions, including all existing regulations and guidance documents, that are unduly burdensome on the identification, development, or use of domestic energy resources. Accordingly, on January 13, 2026, the EPA announced a proposed rule to revise the Section 401 state and tribal water quality certification regulations. The proposed rule aims to narrow the “activity”-based scope of state and tribal certification to point source discharges into waters of the United States. To the extent a stay of recent rules or the implementation of a revised rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits, including for dredge and fill activities in wetland areas. Additionally, many states have similar requirements that apply to state waters where federal jurisdiction ends.

The process for obtaining permits also has the potential to delay our operations. For example, in January 2021, the Corps released the final version of a rule renewing twelve of its Nationwide Permits (“NWPs”), including NWP 12, the general permit issued by the Corps for pipelines and utility projects. The new rule, which took effect in March 2021, splits NWP 12 into three parts; NWP 12 will continue to be available to oil and gas pipelines. In March 2022, the Corps initiated an early review of NWP 12 to determine whether any future actions may be appropriate to modify NWP 12 prior to its expiration in 2026. However, in January 2025, President Trump issued an executive order instructing the Corps to use emergency authorities and NWPs to grant approvals for energy projects under Section 404 of the CWA, and on June 18, 2025, the Corps and the Department of Defense issued a proposed rule titled “Proposal to Reissue and Modify Nationwide Permits”

to modify and clarify existing NWPs in order to authorize activities with no more and minimal adverse environmental effects. Any further changes to NWP 12 could have an impact on our business. We cannot predict at this time how the new Corps rule will be implemented because permits are issued by the local Corps district offices. If new oil and gas pipeline projects are unable to utilize NWP 12 or identify an alternate means of CWA compliance, such projects could be significantly delayed.

Additionally, spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” are required by federal law in connection with on-site storage of significant quantities of oil. Compliance may require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak.

Safe Drinking Water Act

The U.S. Safe Drinking Water Act (“SDWA”) grants the EPA broad authority to take action to protect public health when an underground source of drinking water is threatened with pollution that presents an imminent and substantial endangerment to humans. The SDWA also regulates saltwater disposal wells under the Underground Injection Control Program. The federal EPAct of 2005 amended the Underground Injection Control provisions of the SDWA to expressly exclude certain hydraulic fracturing from the definition of “underground injection,” but disposal of hydraulic fracturing fluids and produced water or their injection for enhanced oil recovery is not excluded. In 2014, the EPA issued permitting guidance governing hydraulic fracturing with diesel fuels. While we do not currently use diesel fuels in our hydraulic fracturing fluids, we may become subject to federal permitting under SDWA if our fracturing formula changes or if there are other changes to the applicable provisions of the SDWA.

Air emissions

The CAA and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and other requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. In December 2020, the EPA announced its intention to leave the ozone NAAQS unchanged at 70 parts per billion. Further, in June 2016, the EPA also finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. These rules could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These and other laws and regulations concerning air emissions may increase the costs of compliance for some facilities where we operate.

State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In March 2024, the EPA adopted new rules under the CAA that require the reduction of volatile organic compound (“VOC”) and methane emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. In addition, the regulations place new requirements to detect and repair volatile organic compound and methane at certain well sites and compressor stations. In December 2023, the EPA announced a final rule targeting methane emissions from new and existing oil and gas sources, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for certain requirements to a construction date of December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans. The final rule gives states, along with federal tribes, until March 2026 to develop and submit their plans for reducing methane emissions from existing sources, and those existing sources themselves have until 2029 from the plan submission deadline to comply. Fines and penalties for violation of the final rule could be substantial. The final rule is subject to ongoing litigation but remains in effect. However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise or rescind all agency actions that are unduly burdensome on the identification, development or use of domestic energy resources. Further, in March 2025, the

EPA announced its intention to reconsider the March 2024 rule, with a final rule expected in or around July 2026. A subsequent rule finalized on November 26, 2025 also gives states, along with federal tribes that wish to regulate existing sources, until January 2027 to develop and submit their plans for reducing methane emissions from existing sources. Consequently, future implementation and enforcement of the final rule remains uncertain at this time. Several states, including West Virginia and Ohio, are considering their own regulations related to methane emissions from oil and gas operations. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of natural gas projects and increase our costs of development, which costs could be significant. Further, compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment and increased frequency of maintenance and repair activities to address emissions leakage at certain well sites and compressor stations, and also may require hiring additional personnel to support these activities or the engagement of third-party contractors to assist with and verify compliance.

Climate change

More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted and could cause us to incur material expenses to comply with such laws and regulations. These requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. The EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations.

At the international level, the Biden Administration signed the instrument recommitting the U.S. to the United Nations-sponsored Paris Agreement (the “Paris Agreement”) in January 2021. However, in January 2025, President Trump issued executive orders directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. The withdrawal became effective in January 2026. On January 7, 2026, President Trump announced the formal withdrawal of the United States from the United Nations Framework Convention on Climate Change in a presidential memorandum. The full impact of these actions remains uncertain at this time. At the same time, various state and local governments have committed to continue furthering the goals of the Paris Agreement and many of these initiatives are expected to continue.

Additionally, in 2022, the Inflation Reduction Act (the “IRA”) was signed into law, which could accelerate the transition to a lower carbon economy. The IRA provides incentives for the development of renewable energy, clean hydrogen, clean fuels and supporting infrastructure and carbon capture and sequestration. In addition, the IRA includes a methane emissions reduction program that amends the Clean Air Act to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems. This program requires the EPA to impose a “Waste Emissions Charge” on certain natural gas and oil sources that are already required to report under the EPA’s Greenhouse Gas Reporting Program. To implement the program, in May 2024, EPA finalized revisions to the Greenhouse Gas Reporting Program for the oil and natural gas sector. The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions Reduction Program. However, in March 2025, President Trump signed Congress’ Joint Resolution of Disapproval of the Waste Emissions Charge, and in May 2025 the EPA issued a final rule to remove the Waste Emissions Charge Regulations from the Code of Federal Regulations. In addition, in September 2025, the EPA proposed to permanently remove program obligations from the Greenhouse Gas Reporting Program for most source categories and suspect program obligations for some sources subject to subpart W (which applies to emissions sources in certain segments of the oil and natural gas industry) until 2034. The Inflation Reduction Act may also be subject to amendment or repeal through Congressional budget reconciliation. Consequently, future implementation and enforcement of these rules remains uncertain at this time. Additionally, some states have issued mandates to reduce emissions of GHGs, primarily through planned development of GHG emission inventories and potential cap-and-trade programs. Most of these types of programs require major sources of emissions or major producers of fuels to acquire and subsequently surrender emission allowances, with the number of allowances available being reduced each year until a target goal is achieved.

Further, in January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of LNG to non-free trade agreement countries until the Department of Energy could update the underlying analyses for authorizations, including an assessment of the impact of GHG emissions. However, in January 2025, President Trump issued an executive order directing the Department of Energy to restart reviews of applications for approvals of LNG export projects as expeditiously as possible, and in April 2025 the Department of Energy rescinded its Policy Statement on Export Commencement Deadlines in Authorizations to Export Natural Gas to Non-Free Trade Agreement Countries, effectively ending the temporary pause on new exports of LNG. Separately, in April 2024, the European Union adopted a regulation to track and reduce methane emissions in the energy sector, including requiring new monitoring, reporting and verification measures to be applied by importers of oil, natural gas and coal into the European Union by January 1, 2027, and “maximum methane intensity values” must be met by 2030 and every year thereafter. Each member state will have the

power to impose administrative penalties for failure to comply and the standard will be mandatory for supply contracts signed after the law takes effect. This and other changes in law and governmental policy may have impacts on our business that are difficult to anticipate.

The adoption and implementation of new or more stringent international, federal, state, or local legislation, regulations or other regulatory initiatives related to climate change or GHG emissions from oil and natural gas facilities could result in increased costs of compliance or costs of consumption, thereby reducing demand for our products, and could require us to incur increased operating costs or otherwise have an adverse effect on our business, financial condition and results of operations.

Hydraulic fracturing

Hydraulic fracturing is a common practice that is used to stimulate production of oil and/or natural gas from low permeability subsurface rock formations and is important to our business. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the hydrocarbon-bearing rock formation and stimulate production of hydrocarbons. We regularly use hydraulic fracturing as part of our operations. Presently, hydraulic fracturing is primarily regulated at the state level, but the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels.

In addition, there are heightened concerns by the public about hydraulic fracturing causing damage to aquifers, and there is potential for future regulation to address those concerns. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under some circumstances. To date, the EPA has taken no further action in response to the 2016 report.

At the state level, several states have adopted or are considering legal requirements that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. Local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Oil Pollution Act

The Oil Pollution Act of 1990 (the “OPA”) establishes strict liability for owners and operators of facilities that are the source of a release of oil into WOTUS. The OPA and its associated regulations impose a variety of requirements on responsible parties, including owners and operators of certain facilities from which oil is released, related to the prevention of oil spills and liability for damages resulting from such spills. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct, resulted from violation of a federal safety, construction or operating regulation or if the party fails to report a spill or to cooperate fully in the cleanup. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies to evaluate major federal actions having the potential to significantly impact the environment. The process involves the preparation of an environmental assessment and, if necessary, an environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action have the potential to significantly impact the environment. The NEPA process involves public input through comments, which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in

delaying the permitting and development of projects, may increase the costs of permitting and developing some facilities and could result, in certain instances, in the cancellation of existing leases. In July 2020, the Council on Environmental Quality (“CEQ”) revised NEPA’s implementing regulations to make the NEPA process more efficient, effective and timely. The rule required federal agencies to develop procedures consistent with the new rule within one year of the rule’s effective date (which was extended to two years in June 2021). In October 2021, CEQ issued a notice of proposed rulemaking to amend the NEPA regulatory changes adopted in 2020 in two phases. Phase I of the CEQ’s rulemaking process was finalized on April 20, 2022, and generally restored provisions that were in effect prior to 2020. In May 2024, the CEQ finalized the Phase II rule that streamlined and clarified NEPA reviews while maintaining consideration of relevant environmental, climate change and environmental justice effects. The final rule took effect in July 2024. The Infrastructure and Investment Jobs Act, signed into law in November 2021, codified some of the July 2020 amendments. These amendments must be implemented into each agency’s implementing regulations, and each of those individual rulemakings could be subject to legal challenge. Additionally, in June 2023, the Fiscal Responsibility Act of 2023 was signed into law, which includes important changes to NEPA to streamline the environmental review process. However, in February 2025, the U.S. District Court for the District of North Dakota vacated the Phase II rule, finding that NEPA does not authorize the CEQ to issue binding regulations. Also in February 2025, CEQ issued an interim final rule revoking the NEPA implementing regulations, and issued guidance recommending federal agencies revise their NEPA rules within one year, using CEQ’s 2020 NEPA rules as a model and incorporating specific policy priorities. In January 2026, CEQ formally repealed its NEPA implementing regulations on the basis of the U.S. Supreme Court’s decision in Seven County Infrastructure Coalition v. Eagle County, Colorado. In Seven County, the U.S. Supreme Court directed lower courts to give “substantial deference” to reasonable agency conclusions underlying its NEPA process. Accordingly, the January 2026 rule is meant to streamline NEPA review, and has left the July 2020, Phase I, and Phase 2 rules in place. The January 2026 rule may be subject to litigation. Congress is also considering legislation designed to streamline NEPA through the Standardizing Permitting and Expediting Economic Development Act (“SPEED Act”). The SPEED Act aims to redefine what qualifies as a “major Federal action” and impose stricter deadlines for NEPA review. The SPEED Act has passed the House of Representatives and passage remains pending and uncertain. The full impact of these changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our operations and our ability to obtain governmental permits.

Endangered Species Act and Migratory Bird Treaty Act

The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”). We may conduct operations on natural gas leases in areas where certain species that are or could be listed as threatened or endangered are known to exist. In February 2016, the U.S. Fish and Wildlife Service (“FWS”) published a final policy which alters how it may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for natural gas development. The Trump Administration issued rules that narrowed the definition of “habitat” and altered a policy in a way that made it easier to exclude territory from critical habitat. In October 2021, the Biden Administration published two rules that reversed those changes, and in June and July 2022, the FWS issued final rules rescinding former Trump-era regulations concerning the definition of “habitat” and critical habitat exclusions. In June 2023, the FWS issued three proposed rules governing critical habitat designation and expanding protection options for species listed as threatened pursuant to the ESA. Final rules were published in April 2024, and took effect in May 2024. However, in January 2025, President Trump issued an executive order directing agencies to use, to the maximum extent permissible, the ESA regulation on consultations in emergencies to facilitate the domestic energy supply. The executive order also requires the quarterly convening of the Endangered Species Act Committee to ensure prompt and efficient review of all submissions for potential actions that could facilitate energy development. Further, in April 2024, the FWS and National Marine Fisheries Service proposed to redefine “harm” under the ESA to mean affirmative acts that are directed immediately and intentionally against a particular animal, excluding acts or omissions that indirectly cause injury. In addition, in November 2025, the Trump Administration proposed several rules that would significantly alter protections for plants and animals. One such proposed rule would rescind a rule that automatically extends protections for endangered species to threatened species. Another such proposed rule would change regulations for listing species as endangered or threatened as well as for designating critical habitats. A third such proposed rule would reinstate the framework for evaluating the benefits and costs of designating a critical habitat by considering factors such as economic impact, impact on national security, and other relevant impacts. The FWS is expected to issue final rules in 2026. As a result, future implementation and enforcement of these rules remains uncertain at this time. The designation of previously unprotected species as threatened or endangered or new critical or suitable habitat designations in areas where we conduct operations could result in limitations or prohibitions on our operations and could adversely impact our business. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

The Department of the Interior issued an opinion in December 2017, followed by a rule in January 2021 that narrows certain protections afforded to migratory birds pursuant to the MBTA. The MBTA makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests or eggs without a permit. The Department of the Interior revoked the rule in October 2021 and issued an advance notice of proposed rulemaking seeking comment to the Department of the Interior’s plan to develop regulations that authorize incidental take under certain prescribed conditions. However, in April 2024, the U.S. Department of the Interior issued a memo, M-37085, which clarified that the MBTA only prohibits the intentional “take” of migratory birds. As a result, future implementation and enforcement of these rules under the MBTA remains uncertain at this time. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

Worker health and safety

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, the purpose of which is to protect the health and safety of workers. For example, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we maintain, organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

Related permits and authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for ongoing operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

Related insurance

We maintain insurance against some contamination risks associated with our development activities, including a coverage policy for gradual pollution events. However, this insurance is limited to activities at the well site, and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

Human Capital Resources

We aim to attract and retain top-tier talent in the oil and gas sector. As of December 31, 2025, we had 101 employees, none of whom were subject to a collective bargaining agreement.

We believe that our employees give us a sustainable competitive advantage, and we understand the need to attract, retain and develop the best team possible. We offer a variety of programs that are designed to retain our employees and also provide opportunities to grow their professional careers while continuing to deliver value to the Company. Additionally, we maintain a comprehensive suite of benefits that provide our employees with various options including retirement, health and wellness, and life and disability plans.

We are committed to a highly-qualified workforce, and we believe employees with different skill sets, experiences and interests drive superior results. We strive to promote a safe and healthy working environment, prioritizing the safety and well-being of our employees, contractors, the public and the environment in the communities where we operate.

Available Information

Our internet website address is www.infinitynaturalresources.com. We routinely post important information for investors on our website. Within our website’s investor relations section, we make available free of charge our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and related amendments, exhibits and other

information, as soon as reasonably practicable after such materials are electronically filed with or furnished to the Securities and Exchange Commission (the “SEC”). You may also access and read our filings without charge through the SEC’s website at www.sec.gov. Information contained on, or accessible through, our website shall not be deemed incorporated into and is not a part of this Annual Report.