INR 10-K & 10-Q changes, risk factors and insider trading
Infinity Natural Resources, Inc. · NYSE · Crude Petroleum & Natural Gas · CIK 2029118 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Risk Factors
New heading “We may be unable to integrate the recently acquired Antero Ohio Assets successfully, or realize the anticipated benefits of the acquisition.”
New heading “We and Northern jointly own the Antero Ohio Assets pursuant to an undivided interest acquisition structure and are subject to a cooperation agreement, infrastructure joint ownership agreement and joint operating agreement with Northern. Disagreements or misalignment with our partner could adversely affect development plans, capital allocation, or timing of returns.”
New heading “Notwithstanding the due diligence investigation that we performed in connection with our entry into the definitive agreement to purchase the Antero Ohio Assets, the Antero Ohio Assets may have liabilities, losses or other exposures for which we do not have adequate insurance coverage or other protection.”
New heading “Our Series A Preferred Stock has rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our Class A common stock.”
New heading “The Certificate of Designation governing our Series A Preferred Stock contains covenants that may limit our business flexibility.”
New heading “We may issue additional preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.”
New heading “We cannot guarantee that our Share Repurchase Program will be fully consummated or that it will enhance long-term stockholder value. Share repurchases could also increase the volatility of the trading price of our Class A common stock and could diminish our cash reserves.”
Removed heading “We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.”
Largest changes
“•armed conflict, political instability or civil unrest in oil and gas producing regions, including armed conflict and instability in the Middle East, Venezuela, Mexico and the conflict between Russia and Ukraine, and the related potential effects on laws and regulations or the imposition of economic or trade sanctions;”see in full comparison
Internationally, the Unitedsee in full comparisonNations-sponsoredStates joined the international community and the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change in Paris, France in 2015, which resulted in the ParisAgreementAgreement,(the “Paris Agreement”) requiresrequiring member states to individually determine and submit non-binding emissions reductiontargets every five years after 2020. In 2021, the Biden Administration recommitted the U.S. to the Paris Agreement and announced a goal of reducing U.S. emissions by 50-52% below 2005 levels by 2030. In September 2021, the Biden Administration publicly announced the “Global Methane Pledge,” an international pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030, including “all feasible reductions” in the energy sector. Further, at the 28th Conference of the Parties (“COP28”) in December 2023, member countries entered into an agreement that calls for actions toward achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. The goals of the agreement, among other things, are to accelerate efforts toward the phase-down of unabated coal power, phase out inefficient fossil fuel subsidies and take other measures that drive the transition away from fossil fuels in energy systems. Most recently, at COP29 participants representing 159 countries met and, among other things, agreed on rules to operationalize international carbon markets under Article 6 of the Paris Agreement. Various state and local governments have also vowed to continue to enact regulations to satisfy their proportionate obligations under the Paris Agreement.targets. However, in January 2025, the Trump Administration 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. We may also be subject to risks related to more restrictive requirements for the development of pipeline infrastructure or LNG export facilities, as well as more restrictive GHG emissions limitations for oil and gas facilities. For example, in January 2024, the Biden Administration announced a temporary pause on pending decisions on new exports of LNG to countries that the U.S. does not have free trade agreements with, pending Department of Energy review of the underlying analyses for authorization, including an assessment of the impact of GHG emissions.In a July 2024 ruling, the Western District of Louisiana stayed this temporary pause on LNG exports to non-free trade agreement countries. The Biden Administration appealed the ruling in August 2024 and the litigation remains ongoing. In December 2024, the Department of Energy released its report on LNG exports.However, in January 2025, the Trump Administration issued an executive order directing the Department of Energy to restart reviews of applications for approvals of LNG export projects as expeditiously aspossible.possible,Further,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.
“Notwithstanding the due diligence investigation that we performed in connection with our entry into the definitive agreement to purchase the Antero Ohio Assets, the Antero Ohio Assets may have liabilities, losses or other exposures for which we do not have adequate insurance coverage or other protection.”see in full comparison
Additionally, in 2022, 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,see in full comparisonpetitions for reconsideration to EPA are pending and litigationinthe D.C. Circuit has commenced. In November 2024, EPA finalized a regulation to implement the Inflation Reduction Act’s Waste Emissions Charge. The fee imposed under the Methane Emissions Reduction Program for 2024 is $900 per ton emitted over annual methane emissions thresholds, and increases to $1,200 inMarch 2025,andPresident$1,500Trumpinsigned2026.Congress’InJointJanuaryResolution2025,ofindustryDisapprovalassociations challengedof the Waste EmissionsChargeCharge, and in May 2025 the EPA issued a final ruleinto remove theD.C.WECCircuit.regulationsHowever,from the Code of Federal Regulations. In addition, inFebruarySeptember 2025,CongressthevotedEPA proposed torepealpermanently remove program obligations from theWasteGreenhouseEmissionsGasCharge ruleReportingpursuantProgramtoforthemostCongressionalsourceReviewcategoriesAct,andwhichsuspendmeasureprogramisobligationsexpectedfortosomebe signed by President Trump. The Inflation Reduction Act may also besources subject toamendmentsubpartorWrepeal(whichthroughappliesCongressionaltobudgetemissionreconciliation.sources in certain segments of the oil and natural gas industry) until 2034. 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.
“The Certificate of Designation governing our Series A Preferred Stock contains covenants that may limit our business flexibility.”see in full comparison
“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. …”see in full comparison
Full comparison: every changed paragraph (151)
•worldwide and regional economic conditions impacting the supply and demand for oil, natural gas and NGLs, including inflationary pressures;
•changes in seasonal temperatures, including the number of heating degree days during winter months and cooling degree days during summer months;
•the level of oil, natural gas and NGL exploration, development and production;
•the level of U.S. LNG exports;
•prevailing prices on local price indexes in the areas in which we operate;
•the proximity, capacity, cost and availability of gathering and transportation facilities;
•localized and global supply and demand fundamentals and transportation availability;
•the cost of exploring for, developing, producing and transporting reserves;
•the spot price of LNG on world markets;
•weather conditions and natural disasters;
•technological advances affecting energy consumption;
•the price and availability of alternative fuels;
•speculative trading in natural gas derivative contracts;
•armed conflict, political instability or civil unrest in oil and gas producing regions, including armed conflict and instability in the Middle East, Venezuela, Mexico and the conflict between Russia and Ukraine, and the related potential effects on laws and regulations or the imposition of economic or trade sanctions;
•the occurrence or threat of epidemic or pandemic diseases, or any government response to such occurrence or threat;
•political and economic conditions in or affecting major LNG consumption regions or countries, particularly Asia and Europe;
•actions of the Organization of the Petroleum Exporting Countries (“OPEC”), including the ability and willingness of the members of OPEC and other exporting nations to agree to and maintain oil price and production controls, including the anticipated increases in supply from Russia and OPEC, particularly Saudi Arabia;
•U.S. trade policies and their effect on U.S. oil, natural gas and NGL exports;
•expectations about future commodity prices; and
•U.S. federal, state and local and non-U.S. governmental regulation and taxes.
We may be unable to integrate the recently acquired Antero Ohio Assets successfully, or realize the anticipated benefits of the acquisition.
Our ability to achieve the anticipated benefits of the recently completed acquisition of the Antero Ohio Assets will depend in part upon whether we can integrate the assets into our existing business in an efficient and effective manner, including aligning development plans, operating practices, cost structures, data systems, and regulatory compliance processes. We may not be able to accomplish this integration process successfully. The integration process may be subject to delays or changed circumstances, and we can give no assurance that our expectations with respect to integration or cost savings as a result of the acquisition will materialize or that the Antero Ohio Assets will perform in accordance with our expectations. The success of the acquisition will depend, in significant part, on the Company’s ability to successfully integrate the acquired business, grow the revenue of the Company and realize the anticipated strategic benefits from the acquisition. Additionally, the integration process may result in the disruption of ongoing business and there could be potential unknown liabilities and unforeseen expenses associated with the acquisition that were not discovered in the course of performing customary due diligence. The integration may also require significant time and focus from management following the acquisition which may disrupt the Company’s business and results of operations. Our failure to achieve consolidation savings, to successfully integrate the Antero Ohio Assets into our existing operations or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
We and Northern jointly own the Antero Ohio Assets pursuant to an undivided interest acquisition structure and are subject to a cooperation agreement, infrastructure joint ownership agreement and joint operating agreement with Northern. Disagreements or misalignment with our partner could adversely affect development plans, capital allocation, or timing of returns.
Pursuant to a cooperation agreement, infrastructure joint ownership agreement and joint operating agreement, we co-won an undivided interest in the Antero Ohio Assets with Northern, but we operate the assets. Conflicts of interest are not anticipated but may arise in the future with Northern, where its business interests are inconsistent with our and our stockholders’ interests. Further, disagreements or disputes with Northern, while not expected, could result in litigation, resulting in increase of expenses incurred and potentially limit the time and effort our officers and directors are able to devote to remaining aspects of our business, all of which could have a material adverse effect on our business, financial condition and results of operations, including our development plans, capital allocation, or timing of returns. This arrangement may also limit the price or interest level for our interests in the Antero Ohio Assets, in the event we want to sell such interests.
Notwithstanding the due diligence investigation that we performed in connection with our entry into the definitive agreement to purchase the Antero Ohio Assets, the Antero Ohio Assets may have liabilities, losses or other exposures for which we do not have adequate insurance coverage or other protection.
While we performed due diligence on the Antero Ohio Assets prior to our entry into the definitive agreement to purchase the Antero Ohio Assets, we are dependent on the accuracy and completeness of statements and disclosures made or actions taken by the Upstream Sellers and Midstream Sellers and their representatives when conducting due diligence and evaluating the results of such due diligence. We do not control and may be unaware of activities of the Upstream Sellers and Midstream Sellers prior to the completion of the Antero Acquisition, including intellectual property and other litigation, claims or disputes, information security vulnerabilities, violations of laws, policies, rules and regulations, commercial disputes, tax liabilities and other known and unknown liabilities.
With the consummation of the Antero Acquisition, certain of the liabilities of the Antero Ohio Assets, including contingent liabilities, will be consolidated with our liabilities for purposes of financial reporting. The Antero Ohio Assets may have unknown liabilities that we will be responsible for following the consummation of the Antero Acquisition. If those liabilities are greater than expected, or if there are obligations of the Antero Ohio Assets of which we are not aware, our business could be materially and adversely affected. We do not have indemnification rights from the Upstream Sellers and Midstream Sellers for defects and liabilities associated with the acquired assets and instead will rely on a limited representation and warranty insurance policy, which we have obtained. Such insurance is subject to exclusions, policy limits and certain other customary terms and conditions. If we are responsible for liabilities not covered by our representation and warranty insurance policy, we could suffer consequences that could have a material adverse effect on our financial condition and results of operations.
•the prices at which our production is sold;
•the amount of our proved reserves;
•the amount of hydrocarbons we are able to produce from existing wells;
•our ability to acquire, locate and produce new reserves;
•the amount of our operating expenses;
•cash settlements from our derivative activities;
•our ability to borrow under our Credit Facility; and
•our ability to access the capital markets or sell non-core assets.
•declines in oil, natural gas and NGL prices;
•increases in the cost of, and shortages or delays in the availability of, proppant, equipment, services and qualified personnel or in obtaining water for hydraulic fracturing activities;
•equipment failures, accidents or other unexpected operational events;
•capacity or pressure limitations on gathering systems, processing and treating facilities or other related midstream infrastructure;
•coal and other mineral ownership permitting issues may impact our ability to develop on our current timeline;
•drilling in the vicinity of coal mining operations and certain other structures;
•any future lack of available capacity on interconnecting transmission pipelines;
•complying with regulatory requirements, including limitations on freshwater sourcing, wastewater disposal, emission of GHGs and hydraulic fracturing;
•pressure or irregularities in geological formations;
•limited availability of financing on acceptable terms;
•compliance with or liability arising under environmental laws and regulations;
•environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the environment;
•compliance with contractual requirements;
•competition for surface locations from other operators that may own rights to drill at certain depths across portions of our leasehold;
•adverse weather conditions;
•title issues or legal disputes regarding leasehold rights; and
•other market limitations in our industry.
•landing our wellbores in the desired drilling zone;
•staying in the desired drilling zone while drilling horizontally through the formation;
•running casing the entire length of the wellbore;
•potentials for casing failures; and
•being able to run and remove tools and other equipment consistently through the entire length of the wellbore.
•the ability to fracture stimulate the planned number of stages with the planned amount of fluid and proppant;
•the ability to run tools through the entire length of the wellbore during completion operations; and
•the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
Management's Discussion & Analysis (MD&A)
New heading “Antero Acquisition”
New heading “Chase Acquisition”
New heading “Share Repurchase Program”
New heading “Amendments to Credit Agreement”
New heading “Preferred Investment”
Removed heading “Initial Public Offering”
Removed heading “Corporate Reorganization”
Removed heading “Muskingum Watershed Lease”
Removed heading “Principal Components of Our Cost Structure”
Removed heading “Accounting Standards Not Yet Adopted”
Largest changes
“In connection with the closing of the Antero Acquisition, we also completed a private placement of Series A Convertible Preferred Stock, which generated gross proceeds of $350 million and net proceeds of $337.1 million after deducting placement agent fees. The proceeds from the Preferred Investment were used to fund a portion of the acquisition. …”see in full comparison
“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. …”see in full comparison
We are a growth oriented independent energy company focused on the acquisition, development, and production of hydrocarbons in the Appalachian Basin. We are focused on creating shareholder value through the identification and disciplined development of low-risk, highly economic oil and natural gas assets while maintaining a strong and flexible balance sheet.see in full comparisonWeOur operations areanfocusedearly mover into the core ofon the UticaShale’s volatile oil windowShale in eastern Ohio as well asthe emergingour dry gas assets in both the Marcellus and UticaShaleShales in southwesternPennsylvania. Our Marcellus Shale development overlays our deep dry gas Utica assets inPennsylvania, providing highly economic stacked development inventory that leveragesthesharedsame company-owned midstream infrastructure. We have amassed approximately 93,000 net surface acres with exposure to the core of these plays providing us a uniqueinfrastructure andbalancedoperational efficiencies. Our portfolioofishigh-returnbalanced across oil and natural gasdrillingassets,locations. This balance allowsallowing us to optimize our development planacrosstoour portfoliorespond tocapitalize onchanges in commoditypricingprices over time. Unless expressly stated otherwise, the operating and financial information presented in this Annual Report does not give effect to the completion of the Antero Acquisition or the Preferred Investment (each as defined herein).
On September 25, 2024, we entered into a new credit facility led by Citibank, N.A. (the “Credit Facility”). The Credit Facility has a total facility size of $1.5 billion,see in full comparisonansubjectinitialto lender commitments and borrowing baseof $325.0 million and available capacity of $65.7 million as of December 31, 2024. The Credit Facility replaced our prior credit facility (as defined below), which was terminated in connection with entry into the Credit Facility.limitations. As of December 31,2024,2025, ourreserveselectedsupportedcommitmentsaand$325.0borrowing base were $375.0 millionfacilityof which$259.3$150.9 million wasoutstandingoutstanding.leavingOn$65.7February 23, 2026, in connection with the closing of the Antero Acquisition, we amended our Credit Facility to, among other things, increase the aggregate elected commitment amount from $375.0 millionoftounused$875.0capacity.million and increase the borrowing base from $375.0 million to $875.0 million.
Full comparison: every changed paragraph (82)
The following should be read in conjunction with our financial statements and related notes in “Item 8. Financial Statements and
Supplementary Data” in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon
events, risks, and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not
limited to, future market prices for oil, natural gas and NGLs, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, inflation, regulatory changes, and other uncertainties, as well as
those factors discussed in “Cautionary Statement Regarding Forward-Looking Statements” and “Item 1A. Risk Factors” in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and
assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. Unless otherwise indicated, the historical
financial information presented in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” speaks only with respect to our predecessor, INR Holdings, and does not give pro forma effect to our corporate
reorganization described in “Item 1. Business—Corporate Reorganization.”
We are a growth oriented independent energy company focused on the acquisition, development, and production of hydrocarbons in the Appalachian
Basin. We are focused on creating shareholder value through the identification and disciplined development of low-risk, highly economic oil and natural gas assets while maintaining a strong and flexible
balance sheet. WeOur operations are anfocused early mover into the core ofon the Utica Shale’s volatile oil windowShale in eastern Ohio as well as the emergingour dry gas assets in both the Marcellus and Utica ShaleShales in southwestern Pennsylvania. Our Marcellus Shale development overlays our deep dry gas
Utica assets in Pennsylvania, providing highly economic stacked development inventory that leverages theshared same company-owned midstream infrastructure. We have amassed approximately 93,000 net surface acres with exposure to the core of these plays
providing us a uniqueinfrastructure and balancedoperational efficiencies. Our portfolio ofis high-returnbalanced across oil and natural gas drillingassets, locations. This balance allowsallowing us to optimize our development plan acrossto our portfoliorespond to capitalize on changes in commodity pricingprices over time. Unless expressly stated otherwise, the operating and financial information presented in this Annual Report does not give effect to the completion of the Antero Acquisition or the Preferred Investment (each as defined herein).
Antero Acquisition
On February 23, 2026, we and Northern completed the Antero Acquisition of the Upstream Assets from the Upstream Sellers and the Midstream Assets from the Midstream Sellers. 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.
Chase Acquisition
On January 20, 2026, the Company and INR Holdings entered into a purchase and sale agreement (the “Chase Purchase Agreement”) with Chase Oil Corporation, a New Mexico corporation, and certain other sellers (each a “Chase Seller” and, collectively, “Chase Sellers”) for the acquisition of certain non-operated rights, title and interests in oil and gas properties, rights and related assets located in the State of Pennsylvania from the Chase Sellers (the “Chase Acquisition”), for consideration of 2,517,194 shares of the Company’s Class A common stock. The Chase Acquisition closed on January 20, 2026, simultaneously with the execution of the Chase Purchase Agreement.
Share Repurchase Program
On November 10, 2025, our board of directors authorized the Share Repurchase Program, whereby we may purchase up to an aggregate of $75 million of our Class A common stock. The Company repurchased 87,132 shares for a total of $1.2 million during the quarter ended December 31, 2025. As of December 31, 2025, we had $73.8 million remaining under the Share Repurchase Program. Repurchases under the Share Repurchase Program may be made from time to time in the open market, in privately negotiated transactions, through purchases made in accordance with Rule 10b5-1 of the Exchange Act, or by such other means as will comply with applicable state and federal securities laws.The timing of any such repurchases will depend on market conditions, contractual limitations and other considerations. The Share Repurchase Program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.
Amendments to Credit Agreement
On December 5, 2025, INR Holdings entered into that certain Third Amendment to Credit Agreement (the “Third Credit Agreement Amendment”). The Third Credit Agreement Amendment, among other things, amended certain provisions relating to hedging requirements and restrictions, debt incurrences and permitted acquisitions in the Credit Agreement.
On February 23, 2026, INR Holdings entered into that certain Fourth Amendment to Credit Agreement (the “Fourth Credit Agreement Amendment”). The Fourth Credit Agreement Amendment, among other things, amends certain provisions to (i) increase the aggregate elected commitment amount from $375.0 million to $875.0 million, (ii) increase the borrowing base from $375.0 million to $875.0 million and (iii) remove the credit spread adjustment that was previously applicable to all Secured Overnight Financing Rate (“SOFR”) borrowings under the Credit Agreement.
Preferred Investment
On February 23, 2026, we issued and sold, pursuant to the Securities Purchase Agreement an aggregate 350,000 shares of Series A Preferred Stock to affiliates of Quantum and affiliates of Carnelian 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 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
In
February 2025, Infinity completed its IPO of 15,237,500 shares of its Class A common stock (including 1,987,500 shares pursuant to an over-allotment option) at a price to the public of $20.00 per share. The aggregate gross proceeds of the IPO
were $304.8 million. After subtracting underwriting discounts and commissions, we received net proceeds of $286.5 million. We contributed all of the net proceeds from the IPO to INR Holdings in exchange for 15,237,500 INR Units. 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. After giving effect to the IPO and the
transactions related thereto, we had 15,237,500 shares of Class A common stock and 45,638,889 shares of Class B common stock issued and outstanding. In connection with the closing of the IPO, all outstanding performance-based incentive
units of INR Holdings vested. Consequently, INR Holdings will recognize $126.1 million of non-recurring, non-cash compensation expense related to these awards in
the first quarter of 2025, in accordance with the guidance provided by ASC 710.
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; 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. After giving effect to the Corporate Reorganization and the IPO, we own an approximate 25.0% interest in INR Holdings and the Legacy Owners own an
approximate 75.0% 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. In connection with the Corporate Reorganization, INR Holdings
and Infinity entered into the INR Holdings LLC Agreement and a Tax Receivable Agreement. For additional information on the INR Holdings LLC Agreement and Tax Receivable Agreement, see “Item 13. Certain Relationships and Related Transactions,
and Director Independence.”
Muskingum Watershed Lease
In December 2024, we closed on a lease with Muskingum Watershed Conservancy District for approximately 1,900 acres in Guernsey and Noble
Counties, Ohio.
We utilize unaffiliated third parties to market a portion of our oil, natural gas, and NGL production to various purchasers, which consist of
credit-worthy counterparties, including utilities, LNG producers, industrial consumers, major corporations and super majors in our industry. The third parties collect proceeds directly from these purchasers and remit to us the total of all amounts
collected on our behalf less the third party’s fee for making such sales. We do not believe the loss of any purchaser would have a material adverse effect on our business, as other purchasers or markets are currently accessible to us.
Principal Components of Our Cost Structure
Lease operating. LOE are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water
disposal, materials, and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor, materials, and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on
activities performed during a specific period. For instance, repairs to our well equipment or surface facilities result in increased LOE in periods during which they are performed. Certain operating cost components are variable and fluctuate based
on production levels. For example, the disposal of produced water usually increases in conjunction with increased production. Also, we monitor our LOE in absolute dollar terms and on a per Boe and/or Mcfe basis to assess our performance and to
determine if any wells or properties should be shut in, repaired or recompleted.
Gathering, processing, and transportation.
Gathering, processing, and transportation expense includes fees paid to third parties who operate low- and high-pressure gathering systems that transport our gas. It also includes costs to process, extract,
and fractionate NGLs from our liquids-rich gas and transport our natural gas and NGLs to market.
Production and ad valorem
taxes. Pennsylvania imposes an annual impact fee on each producing shale well for a period of 15 years beginning in the year the well is spud. Ohio imposes a production tax which is based upon annual production. The proportion of our
production and producing wells from each state may change over time and, as a result, the proportion of our production taxes and impact fees will vary depending on volumes produced from the Utica Shale, the number of producing shale wells in
Pennsylvania, and the applicable production tax rates and impact fees then in effect. In addition, we are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our
oil and gas properties as well as the value of property and equipment.
Depreciation, depletion, and amortization.
Depreciation, depletion, and amortization includes the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas. Under the full- cost method of accounting, we capitalize costs within a cost center and then
systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on all capitalized costs, other than the cost of investments in unproved properties and major
development projects for which proved reserves cannot yet be assigned, less accumulated amortization. Accretion expense related to our asset retirement obligations is also included within this balance.
General and administrative. General and administrative (“G&A”) expenses are costs incurred for overhead, including
payroll and benefits for our corporate staff, costs of maintaining our headquarters, IT expenses, legal, audit and other fees for professional services. G&A expenses are offset by recoveries for overhead that are billed to our joint-interest
partners as outlined in a joint operating agreement or other similar documents.
Interest expense. We have financed a
portion of our working capital requirements and property acquisitions with borrowings under our prior credit facility and Credit Facility. As a result, we incur interest expense that is affected by fluctuations in interest rates and, in the case of
the prior credit facility and Credit Facility based on outstanding borrowings. We expect to see a reduction in cash interest expense following the completion of the IPO in February 2025 as we repaid substantially all of our outstanding borrowings
under the Credit Facility with the net proceeds of the IPO.
Gains and losses on derivatives. We utilize commodity
derivative contracts to reduce our exposure to fluctuations in the price of oil, natural gas, and NGLs. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes.
Consequently, these commodity derivative contracts are recorded at fair value as of the balance sheet date with changes in fair value recognized as a gain or loss in our results of operations. Our operating cash flows are impacted to the extent the
actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.
Public
Company Expenses. We expect to incur direct, incremental G&A expenses as a result of being a public company, including costs associated with Exchange Act compliance, tax compliance, PCAOB support fees, SOX compliance costs, investor
relations activities, listing fees, registrar and transfer agent fees, stock-based compensation, incremental director and officer liability insurance costs, and independent director compensation. We estimate these direct, incremental G&A
expenses could total approximately $4 million to $6 million per year, which are not included in our historical results of operations.
Corporate Reorganization. The historical2023 and 2024 consolidated financial statements included in this Annual Report are based on the
financial statements of our predecessor, INR Holdings, prior to our reorganizationCorporate Reorganization in connection with the IPO as described in “Item 1. Business—Corporate Reorganization.” Our historical financial data may not yield an accurate
indication of what our actual results would have been if those transactions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. In connection with the closing of the IPO, all
outstanding performance-based incentive units of INR Holdings vested. Consequently, INR Holdings will recognize $126.1 million of non-recurring, non-cash
compensation expense related to these awards in the first quarter of 2025, in accordance with the guidance provided by ASC 710.
Interest Expense. In connection with the IPO, we materially reduced our indebtedness through the repayment of substantially all
of our outstanding borrowings under the Credit Facility with net proceeds of the IPO. As a result, we expect an immediate reduction inour cash interest expense.expense was lower in 2025 than 2024.
Income Taxes. Our predecessor, INR Holdings, was organized as a limited liability company not subject to federal income taxes.
Accordingly, no provision for federal income taxes has beenwas provided for in our historical results of operations for 2024 because taxable income was passed through to our members. AlthoughFollowing the Corporate Reorganization, we are a corporation under the Internal Revenue Code of 1986, as
amended (the “Code”), and we do not expect towill report any income tax benefit or expense priorfor to2025 theand consummationgoing of the IPO.forward.
Non-Cash Compensation Expense. In connection with the closing of the IPO, all outstanding incentive units of INR Holdings vested. Consequently, the Company recognized $126.1 million of non-recurring, non-cash stock compensation expense related to these awards, in accordance with the guidance provided by ASC 710.
(1)Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
(2)Based on Netherland, Sewell and Associates Inc. (“NSAI”) found at https://netherlandsewell.com/resources/pricing-data/ and U.S. Energy Information Administration commodity pricing.
(3)Weighted average is based on INR’s production in a given month during the course of the calendar year.
Oil, natural gas, and NGL sales. TotalDuring 2025 and 2024, our oil, natural gasgas, and NGL netrevenues were comprised of 50% and 63%, respectively, from the sale of oil, 36% and 20%, respectively, from the sale of natural gas, and 14% and 17%, respectively, from the sale of NGLs. Net revenues for the year ended December 31, 20242025 increased by
$98.2 $92.7 million, or 62%,36%, compared to the year ended December 31, 2023.2024. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Net production volumes for oil,oil increased 29%, natural gas,gas increased 61% and NGLs increased 98%, 3% and 55%,28%, respectively, between periods. The oiloil, natural gas and NGL production
volume increase resulted from placing fourteen (14)23 wells on production fromacross our oil weighted assets in the Ohio Utica’s Volatilevolatile Oiloil Windowwindow sinceand December 31, 2023. The higher increase inour natural gas volumesweighted betweenassets periods was due toin the fourteen
(14)Marcellus wellsShale thatin were placed on productionPennsylvania during the yearfourth 2024,quarter offsetof from2024 theand normal production decline across existing wells.2025. The combinationaddition of a full year of production from thethese wells acquired from Utica Resource Ventures and PEO Ohio and
wells placed into production throughout 2024 contributed to the overall increase of 1.911.2 MMBoeMBoe/d, or 46%, in production, or of 28%production relative to the prior year.period.
Average realized natural gas prices rose 54% during the period driven by higher NYMEX prices and improved differentials. Oil prices fell 17%, reflecting lower NYMEX WTI prices. NGL prices decreased 15% due to lower Mont Belvieu spot prices and changes in product mix.
Average realized sales prices for NGLs increased 18% during the period while average realized oil and natural gas sales prices decreased 4%
and 2%, respectively, for the year ended December 31, 2024 compared to the prior year. Average realized natural gas prices remained consistent when compared to the same period a year earlier. The 4% decrease in the average realized oil price
was mainly driven by lower NYMEX WTI oil prices during the period along with higher regional differentials compared to the same period a year earlier. The average realized natural gas price decreased 2% due to 19% lower average NYMEX gas prices
between periods offset by lower natural gas differentials. The 18% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in 2024 compared to 2023 and changes in
product composition between periods.
Gathering, processing, and transportation. Gathering, processing, and transportation
(“GP&T”) for the year ended December 31, 2024,2025, increased $18.2$5.5 million compared to the year ended December 31, 2023.2024. This increase iswas attributed to additional wells brought online in Ohio between periods. GP&T per
Boe was $5.59$4.25 for the year ended December 31, 2024,2025, which represents ana increasedecrease of $1.08$1.34 per BoeBoe, or 24%24%, from the prior year.period. ThisThe increasedecrease in per-unit GP&T rate was primarily relatedattributable to increased gasproduction volumes in Ohioour thatnatural gas-weighted areas of Pennsylvania, which are subject to lower GP&T rates on thirdour partyinternal gathering systemssystems. and
lowerThis volumes on INR’s owned gathering systemshift in Pennsylvania.volume mix reduced our overall average GP&T rate, as these areas incur fewer processing charges compared to our wet gas-weighted areas in Ohio, where the NGLs require additional processing.
Lease operating. Lease operating expense
(“LOE”) for the year ended December 31, 2024,2025, increaseddecreased $9.8$1.5 million compared to the prior year.period. LOE per Boe was $3.19$2.07 for the year ended December 31, 2024,2025, which represents ana increasedecrease of $0.53$1.12 per Boe, or 20%,35%, from the
prior year.period. This increasedecrease in LOE was primarily related to highera combination of (a) lower fixed and semi-variable well costs, such as water disposal, equipment rentals, repair work, wellhead chemicals, labor and electricity, associated with a higher well count from new
producing wells drilled or acquired. The higher well count as of December 31, 2024 was primarily due to the acquisition of 50 gross operated horizontal wells from Utica Resources Venturesacquired and PEO(b) Ohio that INR operated for the fourth quarter
2023 and 14 wells INR placed on production since December 31, 2023. In addition, lower natural gashigher volumes from our assets located in Pennsylvania contributedMarcellus to the per unit increase.development.
Depreciation, Depletion and Amortization. For the year ended December 31,
2024, 2025, depreciation, depletion and amortization (“DD&A”) expense was to $73.7$103.8 million, an increase of $19.9$30.0 million over the prior year.period. The primary factor contributing to higher DD&A expense in 20242025 was the increase in our overall production volumes between periods, which
increased DD&Aresulted expensein byan $13.7 million, while our higheraverage DD&A rate of $8.10$7.81 per Boe increased total DD&A expense by $6.5 million between periods. Our DD&A rate can fluctuate as a result of finding and development costs
incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves.Boe.
General and
Administrative Expenses. General and administrative (“G&A”) expenses for the year ended December 31, 20242025 were $13.0$153.4 million compared to $4.9$13.0 million for the prior year. This increase was primarily due to fees related to legal, accounting and
auditing services. We also had higher payroll and employee-relatedemployee costscosts, dueincluding toa higherone-time headcount,non-cash whichstock increasedcompensation from 49 asexpense of December$126.1 31,million 2023expense torecognized 80at as of December 31, 2024.IPO.
Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations” in the Company’s2024 finalAnnual prospectusReport on Form 10-K filed with the SEC on February 3, 2025 pursuant to Rule 424(b)(4) for a discussion of the results of operations for the year ended December 31, 20232024 compared to the
year ended December 31, 2022.2023.
Historically, our primary sources of liquidity have been cash flows from operations, borrowings incurred under our Credit Facility and proceeds from sales of equity securities. Going forward, we expect our primary sources of liquidity to be cash flows from operations, borrowings incurred under our Credit Facility, proceeds from offerings of debt or equity securities, such as the Preferred Investment, or proceeds from the sale of oil and gas properties. Our future cash flows are subject to a number of variables, including oil and natural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary uses of capital have been for drilling and development capital expenditures and the acquisition of oil and natural gas properties.
We continually evaluate our capital needs and compare them to our
capital resources. Our total cash capital expenditures incurred for development during the year ended December 31, 20242025 were $279.7$326.2 million, which includes $165.8$274.7 million on drilling and completion activities, $5.5$16.1 million on
midstream and $108.3$35.5 million on maintenance leasehold and land investment.activities. We funded our capital expenditures for the year ended December 31, 20242025 from cash flows from operations and borrowings incurred under our Credit Facility. Our drilling and
completiondevelopment capital budget for 20252026 is $240$450 million to $280$500 million, alongwhich withincludes $9drilling millionand tocompletions $12 million ofand midstream capital expenditures. We expect to fund our 20252026 capital expenditures budget through a combination of cash
flows from operations and additional borrowings under our Credit Facility.Facility, as well as the proceeds of the Preferred Investment. Our ability to utilize cash flows from operations to fund our development program is driven by our oil and gas production, current commodity prices and our commodity hedge
positions in place.
On February 23, 2026, we closed the Antero Acquisition for consideration of approximately $720 million net to Infinity. See “Item 1. Business—Recent Acquisition—Antero Acquisition.” We funded the transaction with cash on hand, the proceeds of the Preferred Investment and borrowings under our Credit Facility, the borrowing base and aggregate elected commitment amount of which increased from $375.0 million to $875.0 million in connection with closing.
In connection with the closing of the Antero Acquisition, we also completed a private placement of Series A Convertible Preferred Stock, which generated gross proceeds of $350 million and net proceeds of $337.1 million after deducting placement agent fees. The proceeds from the Preferred Investment were used to fund a portion of the acquisition. The Series A Preferred Stock provides long‑term capital with no stated maturity; however, it accrues cumulative dividends that may be paid in kind for a limited period, after which dividends must be paid in cash, subject to restrictions under our Credit Facility. Any dividends paid in kind increase the liquidation preference of the Series A Preferred Stock and may increase future cash requirements. We believe the Preferred Investment enhances our overall liquidity and financial flexibility while supporting the execution of our development and acquisition strategy.
For the year ended December 31, 2025, we generated $261.8 million of cash from operating activities, an increase of $84.1 million from the prior year. Cash provided by operating activities increased primarily due to higher production volumes and associated revenues as compared to the prior year. These factors were partially offset by higher severance and ad valorem taxes, GP&T, G&A, and lower realized prices for oil and natural gas liquids during the year ended December 31, 2025 as compared to the prior year. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and on fluctuations in our operating costs between periods.
For the year ended
December 31, 2024,2025, we spent $249.5$356.4 million on capital expenditures in conjunction with our drilling and completiondevelopment activities in which we drilled and brought online 1423 gross operated wells and land and leasehold costs.costs, and $61.2 million on deposits related to the Antero Acquisition. We also spent
$6.6 $12.6 million on other property and equipment largely related to midstream activities.
For the year ended December 31, 2023,2024, we
spent $146.0$249.5 million on capital expenditures in conjunction with our drilling and completiondevelopment activities in which we drilled and brought online 1014 gross operated wells and land and leasehold costs, and $279.0 million to complete the Utica
Resource Acquisition and PEO Ohio Acquisition, which included 50 gross operated wells.costs. We also spent $11.7$6.6 million on other property and equipment.equipment largely related to midstream activities.
For the year ended
December 31, 2024, the change in financing activity was primarily related to borrowing $168.1 million under our credit facility and repaying $79.7 million of borrowings. In September 2024, as part of entering into the new Credit
Facility, we used funds from the new Credit Facility of $243.4 million for the repayment of the outstanding balance on the prior credit facility. We also paid approximately $5.2 million of syndication fees associated with the new Credit
Facility.
For the year ended December 31, 2023,2025, the change in financing activity was primarily
related to borrowing $203.9$253.5 million under our prior credit facility and repaying $90.8$362.0 of borrowings. We received approximately $286.5 million of borrowings. Additionally, there was a capital raise for $222.3 million used to partially fund the Utica Resource Acquisition and PEO
Ohio Acquisition. We also paid approximately $4.3 million in syndication feesfunds associated with the priorIPO creditused facility.in the repayment of borrowings.
For the year ended December 31, 2024, the change in financing activity was primarily related to borrowing $168.1 million under our prior credit facility and repaying $79.7 million of borrowings. We also paid approximately $5.2 million in syndication fees associated with the prior credit facility.
Analysis of Cash Flow
Changes Between the YearYears Ended December 31, 20232024 and 20222023
Refer to “Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in the Company’s2024 finalAnnual prospectusReport on Form 10-K filed with the SEC on February 3, 2025 pursuant to Rule 424(b)(4) for a discussion of the cash flows for the year ended
December 31, 20232024 compared to the year ended December 31, 2022.2023.
(1)These natural gas basis swap contracts are settled based on the difference between Dominion South, REX Zone 3 or TETCO M2 price and the NYMEX price of natural gas during each applicable monthly settlement period.
What changed in the latest 10-Q
Risk Factors
We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in the 2025 Form 10-K. There have been no material changes to the risks described in such report. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
No wording changes found in this section.
Full comparison: every changed paragraph (0)
Management's Discussion & Analysis (MD&A)
New heading “For the Three Months Ended June 30, 2026, Compared to the Three Months Ended June 30, 2025”
New heading “For the Six Months Ended June 30, 2026, Compared to the Six Months Ended June 30, 2025”
New heading “Summary Results of Operations”
New heading “Operating Expenses”
Removed heading “For the Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025”
Largest changes
“For the Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025”see in full comparison
“For the Three Months Ended June 30, 2026, Compared to the Three Months Ended June 30, 2025”see in full comparison
“For the Six Months Ended June 30, 2026, Compared to the Six Months Ended June 30, 2025”see in full comparison
“Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended June 30, 2026, increased $4.4 million compared to the prior period. LOE per Mcfe was $0.32 for the three months ended June 30, 2026, which represents an increase of $0.01 per Mcfe, or 3%, from the prior period. This increase in LOE was primarily related to semi-variable well costs, such as water disposal, equipment rentals, repair work, wellhead chemicals, labor and electricity, associated with a higher well count from new producing wells drilled or acquired.”see in full comparison
Full comparison: every changed paragraph (68)
Commodity prices were volatile in the first quarterhalf of 20262026, and we expect commodity prices to continue to be volatile for the remainder of 2026 due to macroeconomic uncertainty, changes to the regulatory environment and geopolitical instability and tensions, including in the Middle East, Venezuela, Russia and Ukraine, and potential further imposition of domestic and foreign tariffs. For example, insince late FebruaryFebruary, andthere earlyhas Marchbeen 2026,an ongoing military conflict involving the United States, Israel and Iran escalated in the Middle East, increasingcausing geopolitical uncertainty in global energy markets. Concerns over disruptions to oil, natural gas and LNG production and shipping routes in the region have contributed to, and may continue to contribute toto, market price volatility for an undeterminable period of time. Domestically, natural gas prices have been negatively impacted in recent months by a combination of mild weather and increased production. Our revenue, profitability, liquidity and financial position will continue to be impacted in the future by the market prices for oil, natural gas and NGLs.
The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2026 through MarchJune 31,30, 2026, monthly index prices for NYMEX WTI crude oil ranged from $60.04 per Bbl to $91.38$102.13 per Bbl, while the range for NYMEX Henry Hub natural gas monthly index prices were between $2.98$2.56 per MMBtu and $7.49 per MMBtu. We expect that the commodity market will continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. We use a derivative portfolio and firm sales contracts to mitigate the risks of price volatility.
(1)Benchmark prices presented above are calendar-quarter averages and may differ from production-weighted benchmark prices presented elsewhere in this Quarterly Report.
Following the Antero Acquisition, the Company became party to substantial firm transportation commitments that increase exposure to transportation utilization and transportation optimization economics. As a result, gathering, processing and transportation expense and related transportation optimization revenues may be impacted by future utilization levels, contracted transportation capacity and optimization opportunities.
On February 23, 2026, we issued and sold an aggregate 350,000 shares of Series A Preferred Stock to affiliates of Quantum and Carnelian for consideration of $350 million.million in the Preferred Stock Transaction. After deducting placement agent fees, Infinity received net proceeds of approximately $334.0 million. Quantum acquired 275,000 shares of Series A Preferred Stock, and Carnelian acquired 75,000 shares of Series A Preferred Stock. The Company used the proceeds of the Preferred Stock Transaction to fund a portion of the purchase price for the Antero Acquisition and used the remaining proceeds for general corporate purposes.
On July 15, 2026, we paid a $7.1 million dividend on the Series A Preferred Stock.
Full‑Period Versus Partial‑Period Effects. The Company’s results for the three and six months ended MarchJune 31,30, 2026 reflect the impact of assets placed into service or acquired at different points in time, including wells placed on production throughout 2025 and early 2026 and the partial‑period contribution from the Antero Acquisition. As a result, production volumes, revenues, and certain operating costs for the current period are not directly comparable to the prior‑year period, which did not include the acquired properties or a full period of production from certain development activity. Additionally, certain operating costs include a higher proportion of fixed or semi‑fixed components that do not scale linearly with production; therefore, per‑unit cost metrics may fluctuate between periods as production volumes increase.
For the Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025
Summary Results of Operations
For the Three Months Ended June 30, 2026, Compared to the Three Months Ended June 30, 2025
Total revenues for the three months ended March 31, 2026 increased $66.5 million, or 79%, compared to the three months ended March 31, 2025, primarily driven by higher production volumes resulting from development activity and the partial‑period contribution of assets acquired in the Antero Acquisition, as well as higher realized natural gas and oil prices. Net production increased 88% period over period, reflecting a partial period of production from assets acquired in the Antero Acquisition and production from wells placed on production throughout 2025 and early 2026.
Total operating expenses for the three months ended March 31, 2026 decreased $83.6 million, or 48%, compared to the prior‑year period, primarily due to the absence of $126.1 million of non‑recurring, non‑cash stock‑based compensation expense recognized in connection with the Company’s initial public offering in the prior‑year period. Excluding this item, operating expenses increased due to higher production volumes, the partial‑period contribution of assets acquired in the Antero Acquisition, and increased development and operating activity.
On a per‑unit basis, direct operating expenses for three months ended March 31, 2026 declined $0.20 per Mcfe to $1.20 per Mcfe, or 14%, compared to the prior-year period, reflecting improved cost absorption and scale benefits associated with higher production volumes.
(2)Based on Netherland, Sewell and Associates Inc. found at https://netherlandsewell.com/resources/pricing-data/ and U.S. Energy Information Administration (“EIA”) commodity pricing. WeightedProduction-weighted average isNYMEX basedbenchmark onprices INR’sare calculated using monthly benchmark prices weighted by the Company’s monthly production in a given monthvolumes during the courseapplicable of the calendar year.period.
Oil, Natural Gas and NGL Sales. Total oil, natural gas,gas and NGL net revenues for the three months ended MarchJune 31,30, 2026 increased $66.5by $97.9 million, or 79%,135%, compared to the three months ended MarchJune 31,30, 2025. TheRevenues increaseare wasa primarily driven by higher production volumes, partially offset by the effectsfunction of commodityoil, pricenatural volatilitygas and derivativeNGL settlements.volumes sold and average commodity prices realized.
Net production volumes for oil increased 102%, natural gas volumes increased 73% and NGL volumes increased 57% between periods for the three months ended June 30, 2026 and 2025. The increase in oil volumes between periods was a result of placing 23 wells into service in Ohio between the third quarter of 2025 and second quarter of 2026. The increase in natural gas and NGL volumes was a result of a combination of placing 23 wells in Ohio and seven wells in Pennsylvania into service between the third quarter of 2025 and second quarter of 2026, and a full quarter of production from wells acquired in the Antero Acquisition. The wells in service contributed to the overall increase of 149.8 Mcfe/d, or 75%, in production relative to the prior period, offset by the natural decline of producing wells.
Average realized oil prices rose 51% driven by a higher NYMEX WTI oil price during the period. Natural gas prices decreased 12%, reflecting a 16% decrease in NYMEX gas prices. NGL prices increased 70% due to gas compositional changes alongside strengthened oil, as Middle East disruptions tightened global LPG balances.
Midstream and Other Revenue. Midstream and other revenue was approximately $0.6 million and $2.0 million for the three months ended June 30, 2026 and 2025, respectively. Such revenues primarily consist of gathering revenues earned from third-party and working interest owner volumes transported through the Company’s gathering systems, as well as transportation optimization revenues derived from asset management arrangements, capacity utilization fees, spread-share arrangements and transportation reimbursements associated with the Company’s firm transportation capacity.
Net production volumes increased 88% period over period, reflecting increased development activity and a full month of production from the 241 producing wells acquired in the Antero Acquisition. Oil production increased 16%, natural gas production increased 169%, and NGL production increased 25%, driven by wells placed on production across the Company’s oil‑weighted assets in the Ohio Utica Shale and natural gas‑weighted assets in the Marcellus Shale in Pennsylvania during the second quarter of 2025 through the first quarter of 2026, as well as the contribution of assets acquired in the Antero Acquisition.
Average realized natural gas prices increased 20% compared to the prior‑year period, primarily due to higher NYMEX Henry Hub pricing and improved differentials. Average realized oil prices increased 4%, reflecting higher NYMEX WTI prices, partially offset by derivative settlements. Average realized NGL prices increased 11% due to changes in product mix and pricing dynamics. The combined impact of increased production volumes and higher realized commodity prices resulted in the significant increase in revenues compared to the prior‑year period.
Gathering, Processing and Transportation Expense. Gathering, processing and transportation (“GP&T”) expense increased $14.9 million for the three months ended June 30, 2026, compared to the three months ended June 30, 2025. The increase was primarily attributable to higher production volumes, including volumes associated with the Antero Acquisition, the contribution from 23 wells brought online in Ohio between periods, increased gathering and processing rates under certain agreements, greater volumes transported through third-party midstream systems, and firm transportation commitments assumed in the Antero Acquisition. GP&T expense was $29.4 million, or $0.93 per Mcfe, for the three months ended June 30, 2026, compared to $14.5 million, or $0.80 per Mcfe, in the prior-year period. The increase in GP&T expense per Mcfe was primarily driven by approximately $7.5 million of firm transportation expense associated with the assumed firm transportation commitments. Excluding these firm transportation costs, GP&T expense was $21.9 million, or $0.69 per Mcfe, compared to $14.5 million, or $0.80 per Mcfe, in the prior-year period. The decrease in GP&T expense per Mcfe, excluding firm transportation costs, was primarily attributable to higher volumes from the acquired assets and increased production from the Company’s Pennsylvania natural gas assets, both of which benefit from transportation through Company-owned midstream assets, and a larger production base over which gathering and transportation costs are spread.
Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended June 30, 2026, increased $4.4 million compared to the prior period. LOE per Mcfe was $0.32 for the three months ended June 30, 2026, which represents an increase of $0.01 per Mcfe, or 3%, from the prior period. This increase in LOE was primarily related to semi-variable well costs, such as water disposal, equipment rentals, repair work, wellhead chemicals, labor and electricity, associated with a higher well count from new producing wells drilled or acquired.
Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended June 30, 2026, decreased $(1.2) million compared to the prior period. Production taxes in Ohio are based on our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. Production taxes in Pennsylvania are assessed on producing wells by imposing an impact fee determined based on the market price for natural gas, which commences on the date the well is initially spud and continues for a period of 15 years.
Gathering, processing, and transportation. Gathering, processing, and transportation expense (“GP&T”) increased $7.7 million to $19.7 million for the three months ended March 31, 2026, primarily due to higher production volumes and the partial‑period contribution of acquired upstream assets from the Antero Acquisition. Although total GP&T expense increased on an absolute basis, GP&T expense per unit declined to $0.73 per Mcfe from $0.84 per Mcfe in the prior‑year period. The reduction in per‑unit GP&T expense was primarily attributable to higher production volumes and a shift in production mix toward the Company’s natural gas‑weighted assets in Pennsylvania, which benefit from lower gathering and processing costs and greater utilization of Company-owned gathering infrastructure compared to the Company’s wet‑gas‑weighted assets.
Lease operating. Lease operating expenses increased $2.1 million to $8.9 million for the three months ended March 31, 2026, driven primarily by higher production volumes, an increased well count from development activity, and the partial‑period contribution of wells acquired in the Antero Acquisition. On a per‑unit basis, lease operating expense declined to $0.33 per Mcfe from $0.47 per Mcfe in the prior‑year period, reflecting improved cost efficiency and dilution of fixed and semi‑variable costs across higher production volumes, particularly in the Company’s Marcellus assets.
Production and ad valorem taxes. Production and ad valorem taxes increased $1.7 million to $2.3 million for the three months ended March 31, 2026, primarily due to higher production volumes and the addition of acquired properties.
Midstream Operations and Maintenance Expense. Midstream operations and maintenance expense increased $0.8$1.6 million to $1.5$2.4 million for the three months ended MarchJune 31,30, 2026, primarily reflecting the addition of acquired midstream assets in connection with the Antero Acquisition and higher throughput volumes during the period. On a per‑unit basis, midstream operating expenses remained generally consistent with the prior‑year period, as increased operating activity and integration‑related costs were largely offset by higher volumes and improved utilization of the acquired midstream assets.
Depreciation, Depletion and Amortization. For the three months ended June 30, 2026, depreciation, depletion and amortization (“DD&A”) expense was $44.4 million, an increase of $20.8 million over the prior period. The primary factor contributing to higher DD&A expense during the period was the increase in our overall production volumes between periods resulting in an average DD&A rate of $1.40 per Mcfe.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $14.4 million to $35.7 million for the three months ended March 31, 2026, primarily due to higher production volumes and the partial‑period contribution of acquired assets from the Antero Acquisition. On a per‑unit basis, DD&A declined to $1.32 per Mcfe from $1.48 per Mcfe in the prior‑year period, reflecting increased production volumes and the effect of spreading the depreciable base over a larger production base.
General and Administrative Expenses. General and administrative expense(“G&A”) decreased $110.3 million to $21.4 millionexpenses for the three months ended MarchJune 31,30, 2026,2026 were $12.4 million compared to $5.3 million for the prior‑year period. TheThis decreaseincrease was primarily attributable to the absence of $126.1 million of non‑recurring, non‑cash stock‑based compensation expense related to the Company’s IPO recognized in the prior‑year period, partially offset by transaction costsexpenses associated with the Antero Acquisitionintegration of $13.5the million.Antero Acquisition, an increase in headcount and $3.0 million of non-cash compensation expense.
Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding; and (ii) monthly cash settlements on any closed out hedge positions during the period.
The following table presents gains and losses on our derivative instruments for the periods indicated:
For the Six Months Ended June 30, 2026, Compared to the Six Months Ended June 30, 2025
Summary Results of Operations
Total revenues for the six months ended June 30, 2026 increased $166.3 million, or 104%, compared to the six months ended June 30, 2025, primarily driven by higher production volumes resulting from development activity and contribution of assets acquired in the Antero Acquisition, as well as higher realized natural gas and oil prices. Net production increased 81% period over period, reflecting production from assets acquired in the Antero Acquisition and production from wells placed on production throughout 2025 and early 2026.
Total operating expenses for the six months ended June 30, 2026 decreased $35.9 million, or 16%, compared to the prior‑year period, primarily due to the absence of $126.1 million of non‑recurring, non‑cash stock‑based compensation expense recognized in connection with the Company’s IPO in the prior‑year period. Excluding this item, operating expenses increased due to higher production volumes, the contribution of assets acquired in the Antero Acquisition, and increased development and operating activity.
On a per‑unit basis, direct operating expenses for six months ended June 30, 2026 declined $0.05 per Mcfe to $1.30 per Mcfe, or 4%, compared to the prior-year period, reflecting improved cost absorption and scale benefits associated with higher production volumes.
The following table provides the components of our net revenues and net production for the periods indicated, as well as each period’s average prices (before and after the effects of derivatives) and average daily production volumes:
(1)Calculated by converting oil, condensate and NGLs to natural gas equivalent at a ratio of one barrel of oil or NGL to six Mcf.
(2)Based on Netherland, Sewell and Associates Inc. found at https://netherlandsewell.com/resources/pricing-data/ and EIA commodity pricing. Production-weighted average NYMEX benchmark prices are calculated using monthly benchmark prices weighted by the Company’s monthly production volumes during the applicable period.
Revenues
Oil, Natural Gas and NGL Sales. Total oil, natural gas and NGL revenues for the six months ended June 30, 2026 increased $164.5 million, or 105%, compared to the six months ended June 30, 2025. The increase was primarily driven by higher production volumes, partially offset by the effects of commodity price volatility and derivative settlements.
Net production volumes increased 81% period over period, reflecting increased development activity and production from the 241 producing wells acquired in the Antero Acquisition. Oil production increased 53%, natural gas production increased 108%, and NGL production increased 41%, driven by wells placed on production across the Company’s oil‑weighted assets in the Ohio Utica Shale and natural gas‑weighted assets in the Marcellus Shale in Pennsylvania during the second quarter of 2025 through the first half of 2026, as well as the contribution of assets acquired in the Antero Acquisition.
Average realized natural gas prices increased 9% compared to the prior‑year period, primarily due to higher NYMEX Henry Hub pricing. Average realized oil prices increased 27%, reflecting higher NYMEX WTI prices, partially offset by derivative settlements. Average realized NGL prices increased 35% due to changes in product mix and pricing dynamics. The combined impact of increased production volumes and higher realized commodity prices resulted in the significant increase in revenues compared to the prior‑year period.
Midstream and Other Revenue. Midstream and other revenue was approximately $4.8 million and $3.0 million for the six months ended June 30, 2026 and 2025, respectively. Such revenues primarily consist of gathering revenues earned from third-party and working interest owner volumes transported through the Company’s gathering systems, as well as transportation optimization revenues derived from asset management arrangements, capacity utilization fees, spread-share arrangements and transportation reimbursements associated with the Company’s firm transportation capacity.
Operating Expenses
Gathering, Processing, and Transportation Expense. GP&T expense increased $22.5 million to $49.1 million for the six months ended June 30, 2026, primarily due to higher production volumes and the contribution of acquired upstream assets from the Antero Acquisition. GP&T expense increased on a per unit basis to $0.84 per Mcfe from $0.82 per Mcfe in the prior‑year period. The firm transportation costs were approximately $9.1 million associated with the assumed firm transportation commitments. Excluding these firm transportation costs, GP&T expense was $40.0 million, or $0.68 per Mcfe representing a decrease of 17% when compared to the prior year period. The decrease in GP&T expense per Mcfe, excluding firm transportation costs, was primarily attributable to higher volumes from the acquired assets and increased production from the Company’s Pennsylvania natural gas assets, both of which benefit from transportation through Company-owned midstream assets, and a larger production base over which gathering and transportation costs are spread.
Lease Operating Expenses. LOE increased $6.6 million to $18.9 million for the six months ended June 30, 2026, driven primarily by higher production volumes, an increased well count from development activity, and the contribution of wells acquired in the Antero Acquisition. On a per‑unit basis, lease operating expense declined to $0.32 per Mcfe from $0.38 per Mcfe in the prior‑year period, reflecting improved cost efficiency and dilution of fixed and semi‑variable costs across higher production volumes, particularly in the Company’s Marcellus Shale assets.
Production and Ad Valorem Taxes. Production and ad valorem taxes increased $0.5 million to $4.3 million for the three months ended June 30, 2026, primarily due to higher production volumes and the addition of acquired properties.
Midstream Operations and Maintenance Expense. Midstream operations and maintenance expense increased $2.5 million to $3.8 million for the six months ended June 30, 2026, primarily reflecting the addition of acquired midstream assets in connection with the Antero Acquisition and higher throughput volumes during the period.
Depreciation, Depletion and Amortization. DD&A expense increased $35.2 million to $80.1 million for the six months ended June 30, 2026, primarily due to higher production volumes and the contribution of acquired assets from the Antero Acquisition. On a per‑unit basis, DD&A increased to $1.37 per Mcfe from $1.36 per Mcfe in the prior‑year period.
General and Administrative Expenses. G&A expense decreased $103.2 million to $33.8 million for the six months ended June 30, 2026, compared to the prior‑year period. The decrease was primarily attributable to the absence of $126.1 million of non‑recurring, non‑cash stock‑based compensation expense related to the Company’s IPO recognized in the prior‑year period, partially offset by transaction costs associated with the Antero Acquisition of $15.2 million.
We continually evaluate our capital needs and compare them to our capital resources. DuringOur total capital expenditures incurred for the three and six months ended June 30, 2026 were $137.3 million and $259.9 million, respectively. For the three months ended MarchJune 31,30, 2026, we incurred $111.5$129.1 million of capital expenditures onin development activitiesactivities, including drilling and $11.1completion and midstream, and $8.2 million related to land activities. OurDuring the six months ended June 30, 2026 , we incurred $240.6 million in development capitalactivities budgetand for 2026 is $450$19.3 million related to $500land million, which includes drilling and completions and midstream capital expenditures.activities. We funded our capital expenditures for the three and six months ended MarchJune 31,30, 2026 from cash flows from operations, borrowings incurred under the Credit Facilityoperations and netcash provided by financing activities (including the proceeds from capitalthe marketissuance activities.of Wethe Notes and the Series A Preferred Stock), which we expect to fundcontinue ourfor 2026the capital expenditures budget through a combinationremainder of cash flows from operations and additional borrowings under the Credit Facility, as well as the proceeds of the Preferred Stock Transaction and the Notes offering.2026. Our ability to utilize cash flows from operations to fund our development program is driven by our oil and gas production, current commodity prices and our commodity hedge positions in place.
In connection with the closing of the Antero Acquisition, we also completed the Preferred Stock Transaction, which generated gross proceeds of $350 million and net proceeds of $334.0 million after deducting placement agent fees and offering expenses. The Series A Preferred Stock provides long‑termlong-term capital with no stated maturity; however, itand accrues cumulative dividends that may be paid in kindaccordance with its terms. The Company elected a PIK dividend for athe limitedquarter period,ended afterMarch 31, 2026, which dividends must be paid in cash, subject to restrictions under our Credit Facility. Any dividends paid in kind increaseincreased the liquidation preference of the Series A Preferred StockStock. andThe maydividend increasedeclared futurefor the quarter ended June 30, 2026 was paid in cash, resulting in a cash requirements.payment of approximately $7.1 million on July 15, 2026. We believe the Preferred Stock Transaction enhances our overall liquidity and financial flexibility while supporting the execution of our development and acquisition strategy.
Analysis of Cash Flow Changes Between the ThreeSix Months Ended MarchJune 31,30, 2026 and 2025
For the threesix months ended MarchJune 31,30, 2026, we generated $58.4$196.3 million of cash from operating activities, aan decreaseincrease of $15.8$51.6 million from the prior period. Cash provided by operating activities decreased modestlyincreased compared to the prior-year period primarily due to integration-relatedincreased costsrevenue generated from our development activities, more favorable pricing conditions, and benefits associated with the Antero Acquisition, partially offset by higher production volumes.Acquisition. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and on fluctuations in our operating costs between periods.
For the threesix months ended MarchJune 31,30, 2026, we spent $75.6$241.1 million on capital expenditures in connection with our development activities. We also spent $0.8$13.8 million on other property and equipment largely related to midstream activities. In connection with the Antero Acquisition, we spent $622.5$622.7 million on certain upstream oil and gas properties and related midstream assets.
For the threesix months ended MarchJune 31,30, 2025, we spent $105.6$188.3 million on capital expenditures in connection with our developmentdrilling and completion activities. We also spent $2.8$6.2 million on other property and equipment.equipment largely related to midstream activities.
For the threesix months ended MarchJune 31,30, 2026, the change in financing activity was primarily related to proceeds received from the issuance of the Notes and Series A Preferred Stock of $550.0 million and $350.0 million, respectively. We incurred issuance-related costs of $9.6 million and $14.4 million in connection with the issuance of the Notes and the Series A Preferred Stock, respectively. We also had debt issuance payments associated with the increase in the borrowing base and elected commitments of the Credit Facility of $13.3$25.3 million. We made borrowings under the Credit Facility of $430.5 million during the period. We used funds from the financing activities, along with cash from operating activities to pay down borrowings under the Credit Facility of $550.0$581.4 million since the beginning of the year.
For the threesix months ended MarchJune 31,30, 2025, the change in financing activity was primarily related to the IPO which generated net proceeds of $286.5 million. We used funds from the IPO, along with cash from operating activities to pay down borrowings under the Credit Facility of $304.0$307.0 million during the period,period. andWe wealso made borrowings under the Credit Facility of $56.0$82.0 million during the period. We also paid approximately $0.9$6.8 million of other costs associated with the IPO.
INR insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 10 Form 4 filings (5 insiders, 13 trade dates, 198,283 shares, about $2.6M) and open-market sales in 0 filings. Net open-market shares: 198,283 (purchases minus sales); net value about $2.6M.Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
| Trade date | Insider | Transaction | Shares | Price | Value |
|---|---|---|---|---|---|
| 2026-09-25 | Baetz Cary D |
Open-market purchase | 316 | $13.58 | $4.3K |
| 2026-09-24 | Baetz Cary D |
Open-market purchase | 22,000 | $13.44 | $295.7K |
| 2026-09-22 | Gieselman Scott |
Open-market purchase | 10,000 | $13.07 | $130.7K |
| 2026-09-21 | Gieselman Scott |
Open-market purchase | 18,467 | $12.62 | $233.1K |
| 2026-06-17 | Gieselman Scott |
Open-market purchase | 10,000 | $12.94 | $129.4K |
| 2026-06-12 | Gray Steven D |
Open-market purchase | 25,000 | $12.81 | $320.2K |
| 2026-06-11 | Quinn William J |
Open-market purchase | 11,497 | $13.20 | $151.8K |
| 2026-06-11 | Poole David P |
Open-market purchase | 4,000 | $13.50 | $54.0K |
| 2026-06-10 | Poole David P |
Open-market purchase | 7,500 | $14.00 | $105.0K |
| 2026-06-05 | Quinn William J |
Open-market purchase | 44,000 | $13.19 | $580.4K |
| 2026-06-03 | Quinn William J |
Open-market purchase | 10,503 | $13.20 | $138.6K |
| 2026-06-03 | Gieselman Scott |
Open-market purchase | 670 | $13.44 | $9.0K |
| 2026-06-02 | Gieselman Scott |
Open-market purchase | 13,430 | $13.35 | $179.3K |
| 2026-05-26 | Gieselman Scott |
Open-market purchase | 20,000 | $14.10 | $282.0K |
| 2026-05-22 | Gieselman Scott |
Open-market purchase | 900 | $14.34 | $12.9K |
Well-known investors holding INR (13F)
| Investor | Quarter | Shares | Reported value | % of their 13F | Change vs prior quarter |
|---|---|---|---|---|---|
| Renaissance Technologies | 2026-06-30 | 392,200 | $5.0M | 0.01% | Added 16% |
| AQR Capital Management (Cliff Asness) | 2026-06-30 | 254,784 | $3.2M | 0.0% | Added 78% |
| D. E. Shaw & Co. | 2026-06-30 | 169,936 | $2.2M | 0.0% | New position |
| Millennium Management (Israel Englander) | 2026-06-30 | 161,963 | $2.1M | 0.0% | Added 27% |
| Point72 Asset Management (Steve Cohen) | 2026-06-30 | 48,706 | $857.7K | — | Sold out |
| Citadel Advisors (Ken Griffin) | 2026-06-30 | 12,857 | $163.3K | 0.0% | Reduced 92% |