INFINITY NATURAL RESOURCES, INC.
For the period ended Mar 31, 2026. Filed May 12, 2026.
View on SEC.govAbout this filing
A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2026 · Filed May 12, 2026
INR$12.79+4.4%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-09-30; filed 2025-11-10.
0002029118-25-000035
Item 2. Management's Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-03-31; filed 2026-05-12.
0002029118-26-000052
Item 2. Management's Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 93 previous paragraphs and 93 current paragraphs.
41 unchanged; 14 reworded; 38 added; 34 removed; 4 previous and 0 current paragraphs rearranged.
Tables are not compared: 9 previous and 6 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (38)
Current report
Commodity prices were volatile in the first quarter of 2026 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, in late February and early March 2026, military conflict involving the United States, Israel and Iran escalated in the Middle East, increasing geopolitical uncertainty in global energy markets. Concerns over disruptions to oil, natural gas and LNG production and shipping routes in the region may contribute to 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.
Current report
Chase Acquisition
Current report
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.
Current report
Preferred Stock Transaction
Current report
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. 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.
Current report
Antero Acquisition
Current report
On February 23, 2026 the Company completed the Antero Acquisition of certain upstream oil and gas properties and related midstream assets in Ohio for a purchase price of $720.0 million for cash consideration of $683.9 million. The Antero Acquisition was financed with the proceeds of the issuance of Series A Preferred Stock and borrowings under the Credit Facility.
Current report
Notes Offering
Current report
On March 20, 2026, the Company completed the offering of the Notes. The proceeds from the issuance of the Notes were used to repay outstanding borrowings under our Credit Facility and for other general corporate purposes.
Current report
Antero Acquisition. On February 23, 2026, the Company completed the Antero Acquisition. As a result, the Company’s results of operations for the three months ended March 31, 2026 include only a partial period of contribution from the acquired assets, whereas future periods will reflect a full‑period contribution. The Antero Acquisition significantly increased the Company’s production volumes, proved reserves, gathering and transportation capacity, and overall asset base, which materially impacts the comparability of revenues, operating expenses (including gathering, processing and transportation, lease operating expenses, production and ad valorem taxes, and depreciation, depletion and amortization), and cash flows between periods.
Current report
Full‑Period Versus Partial‑Period Effects. The Company’s results for the three months ended March 31, 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.
Current report
Summary Results of Operations
Current report
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.
Current report
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.
Current report
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.
Current report
Total oil, natural gas, and NGL revenues for the three months ended March 31, 2026 increased $66.5 million, or 79%, compared to the three months ended March 31, 2025. The increase was primarily driven by higher production volumes, partially offset by the effects of commodity price volatility and derivative settlements.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
Midstream Operations and Maintenance Expense. Midstream operations and maintenance expense increased $0.8 million to $1.5 million for the three months ended March 31, 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.
Current report
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.
Current report
General and Administrative Expenses. General and administrative expense decreased $110.3 million to $21.4 million for the three months ended March 31, 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 $13.5 million.
Current report
We continually evaluate our capital needs and compare them to our capital resources. During the three months ended March 31, 2026, we incurred $111.5 million of capital expenditures on development activities and $11.1 million related to land activities. Our development capital budget for 2026 is $450 million to $500 million, which includes drilling and completions and midstream capital expenditures. We funded our capital expenditures for the three months ended March 31,
Current report
On March 20, 2026, the Company completed the offering of the Notes for total net proceeds of $537.6 million. The proceeds from the issuance of the Notes were used to repay outstanding borrowings under our Credit Facility and for other general corporate purposes.
Current report
On February 23, 2026, we closed the Antero Acquisition for consideration of approximately $683.9 million net to Infinity. We funded the transaction with cash on hand, the proceeds of the Preferred Stock Transaction 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.
Current report
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‑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 Stock Transaction enhances our overall liquidity and financial flexibility while supporting the execution of our development and acquisition strategy.
Current report
Our liquidity requirements also include operating expenses, which have been impacted by elevated levels of inflation. High oil prices have historically led to more development activity in oil-focused shale basins and resulted in service cost inflation across all U.S. shale basins, including our areas of operation. Ongoing inflationary pressures may result in increases to the costs of our oilfield goods, services and personnel, which would, in turn, cause our capital expenditures and operating costs to rise. We closely monitor costs and are cost conscious in managing our operations. We may solicit bids from multiple vendors or contractors or source materials from multiple suppliers to take advantage of cost competition, and we may buy surplus materials if we can acquire them on attractive terms. Where we anticipate elevated costs may be more sustained, such as in the cost of services, we may enter into contracts with certain service providers to lock in rates. We are also strategic in the duration of our contracts to provide flexibility to take advantage of cost declines when they occur.
Current report
For the three months ended March 31, 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 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 million since the beginning of the year.
Current report
Senior Notes
Current report
On March 20, 2026, INR Holdings issued $550.0 million aggregate principal amount of the Notes at par. The Notes were issued pursuant to the Indenture and bear interest at a fixed rate of 7.625% per annum, payable semi-annually in arrears on April 1 and October 1 of each year, commencing on October 1, 2026. The Notes will mature on April 1, 2031, unless earlier redeemed or repurchased.
Current report
The Notes are the general unsecured, senior obligations of INR Holdings. The Notes are guaranteed on a senior unsecured basis by the Guarantors and may be guaranteed by certain future subsidiaries of INR Holdings. The Notes and the related guarantees rank equally in right of payment with the borrowings under our Credit Facility and any of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The Notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our Credit Facility) to the extent of the value of the collateral securing such indebtedness and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the Notes.
Current report
INR Holdings may, at its option, redeem all or a portion of the Notes at any time on or after April 1, 2028 at certain redemption prices. At any time prior to April 1, 2028, INR Holdings may redeem up to 40% of the aggregate principal amount of the Notes, with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 107.625% of the aggregate principal amount of the Notes redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. In addition, at any time prior to April 1, 2028, INR Holdings may, on any one or more occasions, redeem all or a part of the Notes at a redemption price equal to 100.00% of the principal amount of the Notes redeemed, plus a “make whole” premium and accrued and unpaid interest, if any, to, but excluding, the date of redemption.
Current report
If INR Holdings experiences certain kinds of changes of control, each holder of the Notes may require INR Holdings to repurchase all or a portion of its Notes for cash at a price equal to 101% of the aggregate principal amount of such Notes, plus accrued and unpaid interest, if any, to the date of repurchase.
Current report
The Indenture contains covenants that, among other things and subject to certain exceptions and qualifications, limit the ability of INR Holdings and its restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from its restricted subsidiaries to INR Holdings or any of their restricted subsidiaries; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
Current report
On September 25, 2024, INR Holdings entered into a credit facility led by Citibank, N.A. (the “Credit Facility” and the credit agreement governing the Credit Facility, as amended, the “Credit Agreement”). The Credit Facility has a total facility size of $1.5 billion, subject to lender commitments and borrowing base limitations. On February 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 million to $875.0 million and increase the borrowing base from $375.0 million to $875.0 million. As of March 31, 2026, our elected commitments and borrowing base were $875.0 million of which zero was outstanding with $19.2 million in letters of credit.
Current report
The Credit Facility also requires INR Holdings to maintain compliance as of the end of each fiscal quarter with financial covenants consisting of a current ratio of not less than 1.0 to 1.0 and a leverage ratio no greater than 3.0 to 1.0, each of which is defined within the terms of the Credit Facility. We were in compliance with the covenants and financial ratios under the Credit Facility described above through the date these unaudited condensed consolidated financial statements were available to be issued.
Removed paragraphs (34)
Previous report
Concerns of global economic growth, inflation, the Federal Reserve’s recent decisions to adjust interest rates, OPEC+’s recent decisions to increase production and resulting increases in global oil and natural gas supply levels and the potential for a global trade war resulted in oil price deterioration throughout 2024 and 2025. Oil prices have continued to be volatile and have been influenced by geopolitical tensions, tariffs and trade policies as well as global economic slowdowns resulting in more downward pressure on prices. Natural gas prices remained low for the majority of 2024 driven by an over-supply due to mild winter weather, liquefied natural gas project delays and higher than expected natural gas production, but prices have improved during 2025 relative to 2024 due to a combination of weather-related demand spikes, tightening supply, and increased global exports, particularly of liquified natural gas, though prices remain volatile.
Previous report
Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, costs of oilfield goods and services generally also increase; however, during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as commodity prices do. In addition, the United States saw higher levels of inflation during 2024 and the beginning of 2025, which is expected to remain heightened for the remainder of 2025 due to concerns over global trade wars and changes in tariff policies. Inflationary pressures such as these may also result in increases to the costs of our oilfield goods, services and personnel, which can in turn cause our capital expenditures and operating costs to rise.
Previous report
On November 10, 2025, our board of directors authorized a share repurchase program, whereby we may purchase up to an aggregate of $75.0 million of our Class A common stock. Repurchases under the 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 Securities Exchange Act of 1934, as amended (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 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.
Previous report
Public Company Expenses. We have incurred and expect to continue to incur direct, incremental G&A expenses as a result of being a public company, including costs associated with compliance with the Exchange Act, tax compliance, PCAOB support fees, the Sarbanes-Oxley Act 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 of our predecessor.
Previous report
Corporate Reorganization. The historical consolidated financial statements included in this Quarterly Report for periods prior to the Corporate Reorganization and IPO are based on the financial statements of our predecessor, INR Holdings. The historical financial data of our predecessor may not yield an accurate indication of what our actual results would have been if the Corporate Reorganization and IPO had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.
Previous report
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 received an immediate reduction in cash interest expense.
Previous report
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 been provided for in our historical results of operations for periods prior to the Corporate Reorganization and IPO because taxable income was passed through to our members.
Previous report
Results of Operations
Previous report
Oil, natural gas, and NGL sales. Total oil, natural gas and NGL net revenues for the three months ended September 30, 2025 increased by $9.3 million, or 13%, compared to the three months ended September 30, 2024. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Previous report
Net production volumes for oil increased 7%, natural gas volumes increased 70% and NGL volumes remained flat between periods for the three months ended September 30, 2025 and 2024. The increase in oil volumes between periods was due primarily to six wells placed into service in Ohio during the third quarter of 2025. The increase in natural gas volumes was predominantly related to the four wells coming online in the third quarter of 2025 in the Marcellus Shale in Pennsylvania and the six Ohio wells. The wells placed into service in the third quarter 2025 contributed to the overall increase of 10.0 MBoe/d, or 39%, in production relative to the prior period, offset by the natural decline of producing wells.
Previous report
Average realized oil prices fell 16% driven by a lower NYMEX WTI oil price during the period. Natural gas prices rose 37%, reflecting a 45% increase in NYMEX gas prices. NGL prices increased 12% primarily due to a reduced ethane recovery, which improved the blend price compared to the prior period.
Previous report
Gathering, processing, and transportation. GP&T for the three months ended September 30, 2025, decreased $2.6 million compared to the three months ended September 30, 2024. This decrease was attributed to fewer wells being brought online in Ohio between periods combined with the natural decline of production volumes from existing wells. GP&T per Boe was $3.84 for the three months ended September 30, 2025, which represents a decrease of $2.57 per Boe, or 40%, from the prior period. The decrease in per-unit GP&T rate was primarily attributable to increased production volumes in our natural gas-weighted areas of Pennsylvania, which are subject to lower GP&T rates. This shift in 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.
Previous report
Lease operating expenses. LOE for the three months ended September 30, 2025, decreased $0.2 million compared to the prior period. LOE per Boe was $2.01 for the three months ended September 30, 2025, which represents a decrease of $0.85 per Boe, or 30%, from the prior period. This decrease in LOE was primarily related to 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.
Previous report
Production and ad valorem taxes. Production and ad valorem taxes for the three months ended September 30, 2025, increased $0.4 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.
Previous report
Depreciation, Depletion and Amortization. For the three months ended September 30, 2025, DD&A expense was $27.6 million, an increase of $6.5 million over the prior period. The primary factor contributing to higher DD&A expense in 2025 was the increase in our overall production volumes between periods resulting in an average DD&A rate of $8.10 per Boe.
Previous report
General and Administrative Expenses. G&A expenses for the three months ended September 30, 2025 were $8.1 million compared to $2.7 million for the prior period. This increase was primarily related to expenses associated with stock compensation and professional services associated with being a public company.
Previous report
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.
Previous report
For the Nine Months Ended September 30, 2025, Compared to the Nine Months Ended September 30, 2024
Previous report
(1)Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
Previous report
Revenues
Previous report
Oil, natural gas, and NGL sales. Total oil, natural gas and NGL net revenues for the nine months ended September 30, 2025 increased by $46.0 million, or 24%, compared to the nine months ended September 30, 2024. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Previous report
Net production volumes for oil increased 16%, natural gas increased 41% and NGLs increased 22%, respectively, between periods. The oil, natural gas and NGL production volume increase resulted from placing 23 wells on production across our oil weighted assets in the Ohio Utica’s Volatile Oil Window and our natural gas weighted assets in the Marcellus Shale in Pennsylvania during the fourth quarter of 2024 and 2025. The addition of these wells contributed to the overall increase of 7.6 MBoe/d, or 31%, in production relative to the prior period.
Previous report
Average realized natural gas prices rose 59% during the period driven by higher NYMEX prices and improved differentials. Oil prices fell 15%, reflecting lower NYMEX WTI prices. NGL prices decreased 10% due to lower Mont Belvieu spot prices and changes in product mix.
Previous report
Operating Expenses
Previous report
Gathering, processing, and transportation. GP&T for the nine months ended September 30, 2025, increased $1.5 million compared to the nine months ended September 30, 2024. This increase was attributed to additional wells brought online in Ohio between periods. GP&T per Boe was $4.51 for the nine months ended September 30, 2025, which represents a decrease of $1.16 per Boe, or 20%, from the prior period. The decrease in per-unit GP&T rate was primarily attributable to increased production volumes in our natural gas-weighted areas of Pennsylvania, which are subject to lower GP&T rates on our internal gathering systems. This shift in 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.
Previous report
Lease operating. LOE for the nine months ended September 30, 2025, decreased $0.3 million compared to the prior period. LOE per Boe was $2.34 for the nine months ended September 30, 2025, which represents a decrease of $0.76 per Boe, or 25%, from the prior period. This decrease in LOE was primarily related to a 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 and (b) higher volumes driven by our Pennsylvania Marcellus development.
Previous report
Production and ad valorem taxes. Production and ad valorem taxes for the nine months ended September 30, 2025, increased $3.2 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.
Previous report
Depreciation, Depletion and Amortization. For the nine months ended September 30, 2025, DD&A expense was $72.5 million, an increase of $16.1 million over the prior period. The primary factor contributing to higher DD&A expense in 2025 was the increase in our overall production volumes between periods, which resulted in an average DD&A rate of $8.12 per Boe.
Previous report
General and Administrative Expenses. G&A expenses for the nine months ended September 30, 2025 were $145.1 million compared to $8.3 million for the prior period. This increase was primarily due to expenses associated with being a public company and a one-time stock compensation expense of $126.1 million incurred in connection with the IPO. We also had higher payroll and employee-related costs due to higher headcount associated with the growth of the business.
Previous report
In February 2025, we completed our IPO of 15.2 million shares of our Class A common stock at a price to the public of $20.00 per share, resulting in net cash proceeds of $286.5 million after deducting underwriting discounts and commissions. The net proceeds from the offering, along with cash from operations, were used to repay outstanding borrowings under the Credit Facility.
Previous report
For the nine months ended September 30, 2024, the change in financing activity was primarily related to borrowing $366.9 million under our prior credit facility and repaying $313.1 million of borrowings.
Previous report
On September 25, 2024, INR Holdings entered into the Credit Facility. The borrowing base is based on the net present value of our oil and gas properties and is subject to semi-annual redeterminations. The Credit Facility is guaranteed by INR Holdings’ subsidiaries and is secured by first priority security interests on substantially all of INR Holdings’ consolidated assets.
Previous report
Borrowings under the Credit Facility may be base rate loans or Secured Overnight Financing Rate (“SOFR”) loans. Base rate loans bear interest at a rate per annum equal to the greater of: (i) the administrative agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; or (iii) the adjusted Term SOFR rate (as defined in the Credit Agreement), plus an additional basis point credit spread, plus an applicable margin ranging from 275 basis points to 375 basis points, depending on the percentage of the borrowing base utilized. SOFR loans bear interest at SOFR plus an applicable margin ranging from 275 basis points to 375 basis points, depending on the percentage of the borrowing base utilized, plus an additional basis point credit spread. We also pay a commitment fee on unused elected commitment amounts under the Credit Facility, which is also dependent on the percentage of the borrowing base utilized. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for SOFR loans. The Credit Facility matures in September 2028. On March 31, 2025, the Company amended the Credit Agreement to, among other things, increase each of the aggregate elected commitment amount and borrowing base from $325.0 million to $350.0 million. On May 29, 2025, the Company amended the Credit Agreement to, among other things, amend certain provisions relating to hedging requirements and restrictions in the Credit Agreement. As of September 30, 2025, the Company’s reserves supported a $350.0 million borrowing base, of which $75.4 million was outstanding, leaving $274.6 million of unused capacity. Effective October 1, 2025, the borrowing base under the Credit Facility was increased from $350.0 million to $375.0 million and the aggregate elected commitment amount was also increased from $350.0 million to $375.0 million.
Previous report
For the nine months ended September 30, 2025 and 2024, total interest expense on the Credit Facility was $5.3 million and $14.8 million, respectively. We did not capitalize any interest expense for the nine months ended September 30, 2025 and 2024. For the nine months ended September 30, 2025 and 2024, the Company’s weighted-average interest rate was 4.2% and 9.1%, respectively.
Reworded paragraphs (14)
Previous wording
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. We have amassed approximately 95,600 net surface acres with exposure to the core of the Marcellus and Utica Shale plays providing us a unique and balanced portfolio of high-return oil and natural gas drilling locations. This balance allows us to optimize our development plan across our portfolio to capitalize on changes in commodity pricing over time.
Current wording
We are a growth oriented independent energy company focused on the acquisition, development, production and gathering 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. Our operations are focused on the Utica Shale in eastern Ohio as well as our dry gas assets in both the Marcellus and Utica Shales in southwestern Pennsylvania, providing highly economic stacked development inventory that leverages shared infrastructure and operational efficiencies. Our portfolio is balanced across oil and natural gas assets, allowing us to optimize our development plan to respond to changes in commodity prices over time.
Previous wording
The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2025 through September 30, 2025, spot prices for NYMEX WTI crude oil ranged from $62.17 per Bbl to $75.74 per Bbl, while the range for NYMEX Henry Hub natural gas spot prices was between $2.87 per MMBtu and $3.96 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.
Current wording
The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2026 through March 31, 2026, monthly index prices for NYMEX WTI crude oil ranged from $60.04 per Bbl to $91.38 per Bbl, while the range for NYMEX Henry Hub natural gas monthly index prices were between $2.98 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.
Previous wording
Non-Cash Compensation Expense. In connection with the closing of the IPO, all outstanding incentive units of INR Holdings vested. Consequently, INR Holdings 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.
Current wording
Non-Cash Compensation Expense. In connection with the closing of the IPO in 2025, all outstanding incentive units of INR Holdings vested. Consequently, INR Holdings recognized $126.1 million of non-recurring, non-cash stock compensation expense related to these awards for the three months ended March 31, 2025, in accordance with the guidance provided by ASC 710.
Previous wording
(1)Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
Current wording
(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.
Previous wording
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 the Credit Facility, proceeds from offerings of debt or equity securities, 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.
Current wording
Historically, our primary sources of liquidity have been cash flows from operations, borrowings incurred under our Credit Facility and proceeds from sales of debt and equity securities. Going forward, we expect our primary sources of liquidity to be cash flows from operations, borrowings incurred under the Credit Facility, proceeds from offerings of debt or equity securities, such as the Preferred Stock Transaction and the Notes offering, 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.
Previous wording
We continually evaluate our capital needs and compare them to our capital resources. Our total capital expenditures incurred for the three and nine months ended September 30, 2025 were $95.0 million and $263.8 million, respectively. For the three months ended September 30, 2025, we incurred $83.2 million in development activities, including drilling and completion and midstream, and $11.8 million related to land activities. During the nine months ended September 30, 2025, we incurred $237.9 million in development activities and $25.9 million related to land activities. We funded our capital expenditures for the three and nine months ended September 30, 2025 from cash flows from operations and borrowings incurred under the Credit Facility, which we expect to continue for the remainder of 2025. 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.
Current wording
2026 from cash flows from operations, borrowings incurred under the Credit Facility and net proceeds from capital market activities. We expect to fund our 2026 capital expenditures budget through a combination 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. 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.
Previous wording
Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2025 and 2024
Current wording
Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2026 and 2025
Previous wording
For the nine months ended September 30, 2025, we generated $186.7 million of cash from operating activities, an increase of $39.1 million from the prior period. Cash provided by operating activities increased primarily due to higher production volumes and higher realized prices for natural gas and associated revenues as compared to the prior period. These factors were partially offset by higher operating expenses during the nine months ended September 30, 2025 as compared to the prior period. 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.
Current wording
For the three months ended March 31, 2026, we generated $58.4 million of cash from operating activities, a decrease of $15.8 million from the prior period. Cash provided by operating activities decreased modestly compared to the prior-year period primarily due to integration-related costs associated with the Antero Acquisition, partially offset by higher production volumes. 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.
Previous wording
For the nine months ended September 30, 2025, we spent $269.1 million on capital expenditures in connection with our development activities. We also spent $10.2 million on other property and equipment largely related to midstream activities.
Current wording
For the three months ended March 31, 2026, we spent $75.6 million on capital expenditures in connection with our development activities. We also spent $0.8 million on other property and equipment largely related to midstream activities. In connection with the Antero Acquisition, we spent $622.5 million on certain upstream oil and gas properties and related midstream assets.
Previous wording
For the nine months ended September 30, 2024, we spent $189.6 million on capital expenditures in connection with our development activities. We also spent $5.2 million on other property and equipment.
Current wording
For the three months ended March 31, 2025, we spent $105.6 million on capital expenditures in connection with our development activities. We also spent $2.8 million on other property and equipment.
Previous wording
For the nine months ended September 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 $327.0 million since the beginning of the year and paid approximately
Current wording
For the three months ended March 31, 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 million during the period, and we made borrowings under the Credit Facility of $56.0 million during the period. We also paid approximately $0.9 million of other costs associated with the IPO.
Previous wording
A basis swap involves swapping variable interest rates based on different reference rates. We receive a fixed price differential and pays the floating market price differential to the counterparty which is calculated based on the differential between NYMEX and the natural gas price at a specific delivery point.
Current wording
A basis swap involves swapping variable interest rates based on different reference rates. We receive a fixed price differential and pay the floating market price differential to the counterparty which is calculated based on the differential between NYMEX and the natural gas price at a specific delivery point.
Previous wording
For the three months ended September 30, 2025 and 2024, total interest expense on the Credit Facility was $1.8 million and $6.7 million, respectively. We did not capitalize any interest expense for the three months ended September 30, 2025 and 2024. For the three months ended September 30, 2025 and 2024, the Company’s weighted-average interest rate was 4.4% and 9.3%, respectively.
Current wording
For the three months ended March 31, 2026 and 2025, total interest expense on the Credit Facility was $4.4 million and $2.6 million, respectively. The Company capitalized $0.1 million of interest expense during the three months ended March 31, 2026 and did not capitalize any interest expense during the same period in 2025. For the three months ended March 31, 2026 and 2025, the Company’s weighted-average interest rate was 6.9% and 5.2%, respectively.
Previous wording
We routinely enter into or extend operating and transportation agreements, office and equipment leases, drilling rig contracts, and other agreements, in the ordinary course of business. We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in consolidated debt or losses. Since December 31, 2024, there have not been any significant, non-routine changes in our contractual obligations other than drilling rig contracts entered into as discussed in Note 14 – Commitments and Contingencies to our unaudited condensed consolidated financial statements in this Quarterly Report.
Current wording
We routinely enter into or extend operating and transportation agreements, office and equipment leases, drilling rig contracts, and other agreements, in the ordinary course of business. We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in consolidated debt or losses. Since December 31, 2025, there have not been any significant, non-routine changes in our contractual obligations other than drilling rig contracts and the firm transportation agreement entered into as discussed in Note 16 – Commitments and Contingencies to our unaudited condensed consolidated financial statements in this Quarterly Report.
Rearranged previous paragraphs (4)
Previous report — wording carried elsewhere
(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. Weighted average is based on INR’s production in a given month during the course of the calendar year.
Previous report — wording carried elsewhere
The following table presents gains and losses on our derivative instruments for the periods indicated:
Previous report — wording carried elsewhere
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:
Previous report — wording carried elsewhere
$6.8 million of other costs associated with the IPO. We have also made borrowings under the Credit Facility of $143.0 million during the period.