Infinity Natural Resources Inc.
03/10/2026 | Press release | Distributed by Public on 03/10/2026 14:49
Annual Report for Fiscal Year Ending 12/31, 2025 (Form 10-K)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Overview
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. 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. 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).
Market Conditions and Operational Trends
Our revenue, profitability, and ability to return cash to our equity holders can depend on factors beyond our control, such as economic, political, and regulatory developments that impact market supply and demand. Prices for crude oil, natural gas and NGLs have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future.
The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2024 through December 31, 2025, spot prices for NYMEX WTI crude oil ranged from $68.24 per Bbl to $85.35 per Bbl, while the range for NYMEX Henry Hub natural gas spot prices was between $1.57 per MMBtu and $3.91 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.
The following table highlights the quarterly average price trends for NYMEX WTI spot prices for crude oil and NYMEX Henry Hub index price for natural gas since the first quarter of 2024:
| 2024 | 2025 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Q1 | Q2 | Q3 | Q4 | YE | Q1 | Q2 | Q3 | Q4 | YE | ||||||||||||||||||||||||||||||||||||||||||||||||||
|
Oil (per Bbl)
|
$ | 77.56 | $ | 81.72 | $ | 76.24 | $ | 70.73 | $ | 76.56 | $ | 71.84 | $ | 64.63 | $ | 65.74 | $ | 59.64 | $ | 65.46 | |||||||||||||||||||||||||||||||||||||||
|
Gas (per MMBtu)
|
$ | 2.25 | $ | 1.89 | $ | 2.15 | $ | 2.79 | $ | 2.77 | $ | 3.65 | $ | 3.44 | $ | 3.07 | $ | 3.55 | $ | 3.43 | |||||||||||||||||||||||||||||||||||||||
Lower commodity prices and lower futures curves for oil and natural gas prices may result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our operating cash flows, liquidity, financial condition, results of operations, future business and operations, and/or our ability to finance planned capital expenditures, which could in turn impact our ability to comply with covenants under our Credit Agreement. Lower realized prices may also reduce the borrowing base under our Credit Agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that has been mortgaged to the lenders. Upon a redetermination, if any borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under the Credit Agreement.
Recent Developments
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.
Sources of Revenues
We derive our revenues predominantly from the sale of our oil and natural gas production and the sale of NGLs that are extracted from our natural gas during processing. Our production is entirely from within the continental United States and is similarly sold to purchasers within the United States; however, some of our production revenues are attributable to customers who may export our products.
Increases or decreases in our revenue, profitability and future production growth are highly dependent on the commodity prices we receive. Oil, natural gas, and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate. During 2025 and 2024, our oil, natural gas, and NGL revenues 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.
Midstream activities revenues, which consist of gathering, compression, and water handling, are derived from our ownership of INR Midstream. Our gathering and compression revenues relate to activities located within the dry gas areas of southwestern Pennsylvania. Our water handling revenues relate to activities associated with delivering water for stimulation activities in both eastern Ohio and southwestern Pennsylvania.
Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations
Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:
Corporate Reorganization.The 2023 and 2024 consolidated financial statements included in this Annual Report are based on the financial statements of our predecessor, INR Holdings, prior to our Corporate 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.
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, our cash interest 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 was provided for in our historical results of operations for 2024 because taxable income was passed through to our members. Following the Corporate Reorganization, we are a corporation under the Internal Revenue Code of 1986, as amended (the "Code"), and we will report income tax benefit or expense for 2025 and going 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.
Results of Operations
For the Year Ended December 31, 2025, Compared to the Year Ended December 31, 2024
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:
| For the Year Ended December 31, | Increase / (Decrease) | ||||||||||||||||||||||
| 2025 | 2024 | $ | % | ||||||||||||||||||||
|
Net revenues (in thousands):
|
|||||||||||||||||||||||
|
Oil sales
|
$173,612 | $161,514 | $12,098 | 7 | % | ||||||||||||||||||
|
Natural gas sales
|
127,448 | 51,157 | 76,291 | 149 | % | ||||||||||||||||||
|
Natural gas liquids sales
|
49,315 | 45,035 | 4,280 | 10 | % | ||||||||||||||||||
|
Oil, natural gas, and natural gas liquids sales
|
$350,375 | $257,706 | $92,669 | 36 | % | ||||||||||||||||||
|
Average sales prices:
|
|||||||||||||||||||||||
|
Oil price (per Bbl)
|
$56.48 | $67.86 | ($11.38) | (17 | %) | ||||||||||||||||||
|
Effects of derivative settlements on average price (per Bbl)
|
$4.50 | ($0.93) | $5.43 | 584 | % | ||||||||||||||||||
|
Oil price including the effects of derivatives (per Bbl)
|
$60.98 | $66.93 | ($5.95) | (9 | %) | ||||||||||||||||||
|
Wtd. Average NYMEX WTI price for oil (per Bbl)(2)(3)
|
$64.81 | $76.42 | ($11.61) | (15 | %) | ||||||||||||||||||
|
Oil differential to NYMEX
|
($8.33) | ($8.56) | $0.23 | 3 | % | ||||||||||||||||||
|
Natural gas price (per Mcf)
|
$2.80 | $1.81 | $0.99 | 54 | % | ||||||||||||||||||
|
Effects of derivative settlements on average price (per Mcf)
|
$0.01 | $0.66 | ($0.65) | (98 | %) | ||||||||||||||||||
|
Natural gas price including the effects of derivatives (per Mcf)
|
$2.81 | $2.47 | $0.34 | 14 | % | ||||||||||||||||||
|
Wtd. Average NYMEX Henry Hub price for natural gas (per MMBtu)(2)(3)
|
$3.41 | 2.27 | $1.14 | 50 | % | ||||||||||||||||||
|
Natural gas differential to NYMEX
|
($0.62) | ($0.46) | ($0.16) | (35) | % | ||||||||||||||||||
|
NGL price excluding GP&T (per Bbl)
|
$22.32 | $26.14 | ($3.82) | (15 | %) | ||||||||||||||||||
|
Effects of derivative settlements on average price (per Bbl)
|
($0.10) | $2.52 | ($2.62) | (104 | %) | ||||||||||||||||||
|
NGL price including the effects of derivatives (per Bbl)
|
$22.22 | $28.66 | ($6.44) | (22 | %) | ||||||||||||||||||
|
Net production
|
|||||||||||||||||||||||
|
Oil (MBbls)
|
3,074 | 2,380 | 694 | 29 | % | ||||||||||||||||||
|
Natural gas (MMcf)
|
45,596 | 28,291 | 17,305 | 61 | % | ||||||||||||||||||
|
NGL (Bbls)
|
2,209 | 1,723 | 486 | 28 | % | ||||||||||||||||||
|
Net production (MBoe)(1)
|
12,882 | 8,818 | 4,064 | 46% | |||||||||||||||||||
|
Average daily net production
|
|||||||||||||||||||||||
|
Oil (Bbls/d)
|
8,422 | 6,502 | 1,920 | 30% | |||||||||||||||||||
|
Natural gas (Mcf/d)
|
124,920 | 77,297 | 47,623 | 62% | |||||||||||||||||||
|
NGLs (Bbls/d)
|
6,052 | 4,708 | 1,344 | 29% | |||||||||||||||||||
|
Average daily net production (Boe/d)(1)
|
35,293 | 24,093 | 11,200 | 46% | |||||||||||||||||||
_____________
(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.
Revenues
Oil, natural gas, and NGL sales.During 2025 and 2024, our oil, natural gas, and NGL revenues 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, 2025 increased by $92.7 million, or 36%, compared to the year ended December 31, 2024. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Net production volumes for oil increased 29%, natural gas increased 61% and NGLs increased 28%, 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 11.2 MBoe/d, or 46%, in production relative to the prior 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.
Operating Expenses
| For the Year Ended December 31, | Change | ||||||||||||||||||||||
| 2025 | 2024 | Amount | Percent | ||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||
| Gathering, processing, and transportation | $ | 54,779 | $ | 49,290 | $ | 5,489 | 11 | % | |||||||||||||||
| Lease operating | 26,675 | 28,154 | (1,479) | (5 | %) | ||||||||||||||||||
| Production and ad valorem taxes | 5,918 | 1,071 | 4,847 | 453 | % | ||||||||||||||||||
| Depreciation, depletion and amortization | 103,751 | 73,726 | 30,025 | 41 | % | ||||||||||||||||||
| General and administrative | 153,413 | 13,045 | 140,368 | 1076 | % | ||||||||||||||||||
| Total operating expenses | $ | 344,536 | $ | 165,286 | $ | 179,250 | 108 | % | |||||||||||||||
| ($ per Boe) | |||||||||||||||||||||||
| Gathering, processing, and transportation | $ | 4.25 | $ | 5.59 | $ | (1.34) | (24 | %) | |||||||||||||||
| Lease operating | 2.07 | 3.19 | (1.12) | (35 | %) | ||||||||||||||||||
| Production and ad valorem taxes | 0.46 | 0.12 | 0.34 | 283 | % | ||||||||||||||||||
| Depreciation, depletion and amortization | 8.05 | 8.36 | (0.31) | (4 | %) | ||||||||||||||||||
| General and administrative | 11.91 | 1.48 | 10.43 | 705 | % | ||||||||||||||||||
| Total operating expenses | $ | 26.74 | $ | 18.74 | $ | 8.00 | 43 | % | |||||||||||||||
Gathering, processing, and transportation. Gathering, processing, and transportation ("GP&T") for the year ended December 31, 2025, increased $5.5 million compared to the year ended December 31, 2024. This increase was attributed to additional wells brought online in Ohio between periods. GP&T per Boe was $4.25 for the year ended December 31, 2025, which represents a decrease of $1.34 per Boe, or 24%, 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.
Lease operating. Lease operating expense ("LOE") for the year ended December 31, 2025, decreased $1.5 million compared to the prior period. LOE per Boe was $2.07 for the year ended December 31, 2025, which represents a decrease of $1.12 per Boe, or 35%, 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 from our Pennsylvania Marcellus development.
Production and ad valorem taxes.Production and ad valorem taxes for the year ended December 31, 2025, increased $4.8 million compared to the prior year. 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.
Depreciation, Depletion and Amortization.For the year ended December 31, 2025, depreciation, depletion and amortization ("DD&A") expense was $103.8 million, an increase of $30.0 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 $7.81 per Boe.
General and Administrative Expenses.General and administrative ("G&A") expenses for the year ended December 31, 2025 were $153.4 million compared to $13.0 million for the prior year. This increase was primarily due to higher payroll and employee costs, including a one-time non-cash stock compensation expense of $126.1 million expense recognized at IPO.
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:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (in thousands) | |||||||||||
| Realized cash settlement gains (losses) | $ | 12,213 | $ | 28,360 | |||||||
| Non-cash mark-to-market derivative gain (losses) | 46,194 | (50,407) | |||||||||
| Total | $ | 58,407 | $ | (22,047) | |||||||
For the Year Ended December 31, 2024, Compared to the Year Ended December 31, 2023
Refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in the 2024 Annual Report on Form 10-K filed with the SEC for a discussion of the results of operations for the year ended December 31, 2024 compared to the year ended December 31, 2023.
Liquidity and Capital Resources
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 capital expenditures incurred for development during the year ended December 31, 2025 were $326.2 million, which includes $274.7 million on drilling and completion activities, $16.1 million on midstream and $35.5 million on land activities. We funded our capital expenditures for the year ended December 31, 2025 from cash flows from operations and borrowings incurred under our Credit Facility. Our development capital budget for 2026 is $450 million to $500 million, which includes drilling and completions and midstream capital expenditures. We expect to fund our 2026 capital expenditures budget through a combination of cash flows from operations and additional borrowings under our Credit 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.
We operate the vast majority of our acreage and therefore can largely control the amount and timing of our capital expenditures. Accordingly, we can choose to defer or accelerate a portion of our planned capital expenditures depending on
a variety of factors, including but not limited to: (i) prevailing and anticipated prices for oil and natural gas; (ii) the success of our drilling activities; (iii) the availability of necessary equipment, infrastructure and capital; (iv) the receipt and timing of required regulatory permits and approvals; (v) seasonal conditions; (vi) property or land acquisition costs; and (vii) the level of participation by other working interest owners.
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. We used all of the net proceeds after paying certain offering expenses to repay borrowings outstanding under our Credit Facility.
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.
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. Sustained levels of high inflation have also caused the U.S. Federal Reserve and other central banks to increase interest rates, which has raised the cost of capital and increased our interest expense.
Although we cannot provide any assurance that cash flows from operations or other sources of needed capital will be available to us at acceptable terms, or at all, and noting that our ability to access the public or private debt or equity capital markets at economic terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control, we believe that based on our current expectations and projections, we have sufficient liquidity to fund future operations and to meet obligations as they become due for at least one year following the date that our consolidated financial statements are issued.
Cash Flow Activity
Our financial condition and results of operations, including our liquidity and profitability, are significantly affected by the prices that we realize for our oil, natural gas and NGLs and the volumes of oil and natural gas that we produce. Oil, natural gas and NGLs are commodities for which established trading markets exist.
Accordingly, our operating cash flow is sensitive to a number of variables, the most significant of which are the volatility of oil, natural gas and NGL prices and production levels both regionally and across the United States, the availability and price of alternative fuels, infrastructure capacity to reach markets, costs of operations, and other variable factors. We monitor factors that we believe could be likely to influence price movements including new or expanded oil and natural gas markets, gas imports, LNG and other exports, and regional and industry-wide capital intensity levels.
Our produced volumes have a high correlation to our level of capital expenditures such that our ability to fund it through operating and financing cash flows may be affected by multiple factors discussed further herein.
The following summarizes our cash flow activity for the periods indicated:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (in thousands) | |||||||||||
| Net cash provided by operating activities | $ | 261,787 | $ | 177,666 | |||||||
| Net cash used in investing activities | (430,167) | (256,118) | |||||||||
| Net cash provided by financing activities | 169,026 | 79,151 | |||||||||
| Net increase in cash and cash equivalents | $ | 646 | $ | 699 | |||||||
Analysis of Cash Flow Changes Between the Years Ended December 31, 2025 and 2024
Operating activities
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, we generated $177.7 million of cash from operating activities, an increase of $71.2 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 LOE, severance and ad valorem taxes, GP&T, G&A, interest expense and lower realized prices for oil and natural gas during the year ended December 31, 2024 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.
Investing activities
For the year ended December 31, 2025, we spent $356.4 million on capital expenditures in conjunction with our development activities in which we drilled and brought online 23 gross operated wells and land and leasehold costs, and $61.2 million on deposits related to the Antero Acquisition. We also spent $12.6 million on other property and equipment largely related to midstream activities.
For the year ended December 31, 2024, we spent $249.5 million on capital expenditures in conjunction with our development activities in which we drilled and brought online 14 gross operated wells and land and leasehold costs. We also spent $6.6 million on other property and equipment largely related to midstream activities.
Financing activities
For the year ended December 31, 2025, the change in financing activity was primarily related to borrowing $253.5 million under our credit facility and repaying $362.0 of borrowings. We received approximately $286.5 million of funds associated with the IPO used 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 Years Ended December 31, 2024 and 2023
Refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources" in the 2024 Annual Report on Form 10-K filed with the SEC for a discussion of the cash flows for the year ended December 31, 2024 compared to the year ended December 31, 2023.
Derivative Activities
We are exposed to volatility in market prices and basis differentials for oil, natural gas and NGLs, which impacts the predictability of our cash flows related to the sale of those commodities. Accordingly, to achieve more predictable cash flow and reduce our exposure to adverse fluctuations in commodity prices, we use commodity derivatives, such as swaps, to hedge price risk associated with our anticipated production and to underpin our development program. This helps reduce potential negative effects of reductions in oil and gas prices but also reduces our ability to benefit from increases in oil and gas prices. In certain circumstances, where we have unrealized gains in our derivative portfolio, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to utilize their value to further our strategic pursuits.
A fixed price swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
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.
A put option has an established floor price. The buyer of that put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless.
A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.
The following tables provide information about our derivative financial instruments as of December 31, 2025.
| Volume | Weighted Average Price |
Fair Value as of December 31, 2025 |
|||||||||||||||
| Oil | (in MBbls) |
($ per Bbl)
|
(in thousands) | ||||||||||||||
|
Fixed price swaps
|
|||||||||||||||||
| 2026 | 1,540 | $ | 64.06 | $ | 10,777 | ||||||||||||
| 2027 | 97 | $ | 63.95 | 683 | |||||||||||||
| 2028 | - | $ | - | - | |||||||||||||
| 2029 | - | $ | - | - | |||||||||||||
| 2030 | - | $ | - | - | |||||||||||||
| 2031 | - | $ | - | - | |||||||||||||
|
Total
|
1,637 | $ | 11,460 | ||||||||||||||
| Volume | Weighted Average Price |
Fair Value as of December 31, 2025 |
|||||||||||||||
| Natural gas | (in MMBtu) |
($ per MMBtu)
|
(in thousands) | ||||||||||||||
|
Fixed price swaps
|
|||||||||||||||||
| 2026 | 50,726,000 | $ | 3.86 | $ | 16,467 | ||||||||||||
| 2027 | 45,438,000 | $ | 3.94 | 1,969 | |||||||||||||
| 2028 | 35,967,000 | $ | 3.77 | 917 | |||||||||||||
| 2029 | 30,320,000 | $ | 3.62 | 194 | |||||||||||||
| 2030 | 26,580,000 | $ | 3.57 | (1,276) | |||||||||||||
| 2031 | 2,120,000 | $ | 4.08 | (169) | |||||||||||||
|
Total
|
191,151,000 | $ | 18,102 | ||||||||||||||
| Volume | Basis Differential |
Fair Value as of December 31, 2025 |
|||||||||||||||
| Natural gas | (in MMBtu) |
($ per MMBtu)
|
(in thousands) | ||||||||||||||
|
Basis swaps
|
|||||||||||||||||
| 2026 | 53,439,000 | $ | (0.89) | $ | (6,850) | ||||||||||||
| 2027 | 31,629,000 | $ | (0.64) | (1,717) | |||||||||||||
| 2028 | 32,603,750 | $ | (0.52) | (1,178) | |||||||||||||
| 2029 | 2,607,500 | $ | (0.30) | (78) | |||||||||||||
| 2030 | - | $ | - | - | |||||||||||||
| 2031 | - | $ | - | - | |||||||||||||
|
Total
|
120,279,250 | $ | (9,823) | ||||||||||||||
| Volume | Weighted Average Price |
Fair Value as of December 31, 2025 |
|||||||||||||||
| Ethane | (in gallons) | ($ per gallon) | (in thousands) | ||||||||||||||
|
Fixed price swaps
|
|||||||||||||||||
| 2026 | 8,604,000 | $ | 0.28 | $ | 282 | ||||||||||||
| 2027 | 708,000 | $ | 0.30 | 14 | |||||||||||||
| 2028 | - | $ | - | - | |||||||||||||
| 2029 | - | $ | - | - | |||||||||||||
| 2030 | - | $ | - | - | |||||||||||||
| 2031 | - | $ | - | - | |||||||||||||
|
Total
|
9,312,000 | $ | 296 | ||||||||||||||
| Volume | Weighted Average Price |
Fair Value as of December 31, 2025 |
|||||||||||||||
| Propane | (in gallons) | ($ per gallon) | (in thousands) | ||||||||||||||
|
Fixed price swaps
|
|||||||||||||||||
| 2026 | 19,377,000 | $ | 0.71 | $ | 2,008 | ||||||||||||
| 2027 | 1,524,000 | $ | 0.71 | 103 | |||||||||||||
| 2028 | - | $ | - | - | |||||||||||||
| 2029 | - | $ | - | - | |||||||||||||
| 2030 | - | $ | - | - | |||||||||||||
| 2031 | - | $ | - | - | |||||||||||||
|
Total
|
20,901,000 | $ | 2,111 | ||||||||||||||
| Volume | Weighted Average Price |
Fair Value as of December 31, 2025 |
|||||||||||||||
| Isobutane | (in gallons) | ($ per gallon) | (in thousands) | ||||||||||||||
|
Fixed price swaps
|
|||||||||||||||||
| 2026 | 3,498,000 | $ | 0.84 | $ | 98 | ||||||||||||
| 2027 | 276,000 | $ | 0.83 | 4 | |||||||||||||
| 2028 | - | $ | - | - | |||||||||||||
| 2029 | - | $ | - | - | |||||||||||||
| 2030 | - | $ | - | - | |||||||||||||
| 2031 | - | $ | - | - | |||||||||||||
|
Total
|
3,774,000 | $ | 102 | ||||||||||||||
| Volume | Weighted Average Price |
Fair Value as of December 31, 2025 |
|||||||||||||||
| Normal butane | (in gallons) | ($ per gallon) | (in thousands) | ||||||||||||||
|
Fixed price swaps
|
|||||||||||||||||
| 2026 | 5,743,000 | $ | 0.82 | $ | 397 | ||||||||||||
| 2027 | 455,000 | $ | 0.82 | 19 | |||||||||||||
| 2028 | - | $ | - | - | |||||||||||||
| 2029 | - | $ | - | - | |||||||||||||
| 2030 | - | $ | - | - | |||||||||||||
| 2031 | - | $ | - | - | |||||||||||||
|
Total
|
6,198,000 | $ | 416 | ||||||||||||||
| Volume | Weighted Average Price |
Fair Value as of December 31, 2025 |
|||||||||||||||
| Pentane | (in gallons) | ($ per gallon) | (in thousands) | ||||||||||||||
|
Fixed price swaps
|
|||||||||||||||||
| 2026 | 2,487,000 | $ | 1.38 | $ | 553 | ||||||||||||
| 2027 | 190,000 | $ | 1.34 | 39 | |||||||||||||
| 2028 | - | $ | - | - | |||||||||||||
| 2029 | - | $ | - | - | |||||||||||||
| 2030 | - | $ | - | - | |||||||||||||
| 2031 | - | $ | - | - | |||||||||||||
|
Total
|
2,677,000 | $ | 592 | ||||||||||||||
_____________
(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.
Changes in the fair value of derivative contracts from December 31, 2024 to December 31, 2025, are presented below:
| (in thousands) | Commodity Derivative Asset | ||||
| Net fair value of oil and gas derivative contracts outstanding as of December 31, 2024 | $ | (22,938) | |||
|
Commodity hedge contract settlement payments, net of any receipts
|
(12,213) | ||||
| Cash and non-cash mark-to-market gains on commodity hedge contracts (1) | 58,407 | ||||
| Net fair value of oil and gas derivative contracts outstanding as of December 31, 2025 | $ | 23,256 | |||
_____________
(1)At inception, new derivative contracts entered into by us have no intrinsic value.
Financing Agreements
Credit Facility
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, subject to lender commitments and borrowing base limitations. As of December 31, 2025, our elected commitments and borrowing base were $375.0 million of which $150.9 million was outstanding. 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.
The Credit Facility replaced our prior credit facility (as defined below), which was terminated in connection with entry into the Credit Facility.
The Credit Facility also requires us to maintain compliance with the following financial ratios:
•Current ratio - the ratio of consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Amended and Restated Credit Facility and non-cash derivative liabilities) of not less than 1.0 to 1.0 ; and
•Leverage ratio - the ratio of total funded debt to consolidated EBITDAX of not greater than 3.0 to 1.0 .
We were in compliance with the covenants and applicable financial ratios described above as of December 31, 2025.
Prior Credit Facility
On October 4, 2023, we entered into an amended and restated credit facility with a syndicate of banks led by the Bank of Oklahoma (the "prior credit facility"). Borrowings under our prior credit facility were subject to borrowing base limitations based upon the collateral value of the pledged assets and were subject to semi-annual redeterminations. The prior credit facility was scheduled to mature in April 2026, but was terminated on September 20, 2024, in connection with entry into the Credit Facility.
The prior credit facility also required us to maintain compliance with the following financial ratios:
•Current ratio - the ratio of consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Amended and Restated Credit Facility and non-cash derivative liabilities) of not less than 1.0 to 1.0; and
•Leverage ratio - the ratio of total funded debt to consolidated EBITDAX of not greater than 3.0 to 1.0. We were in compliance with the covenants and applicable financial ratios described above as of December 31, 2023.
Other long-term debt
Other long-term debt principally relates to car loans associated with the Company's car fleet to support the Company's team to service and maintain its operated wells.
Payments due by fiscal year related to other long-term debt as of December 31, 2025, are as follows:
| Notes Payable | |||||
| (in thousands) | |||||
| 2026 | $ | 40 | |||
| 2027 | 15 | ||||
| 2028 | - | ||||
| 2029 | - | ||||
| 2030 | - | ||||
|
Total payments
|
$ | 55 | |||
Critical Accounting Estimates
Our financial statements are prepared in accordance with accounting principles generally accepted in the United States ("U.S. GAAP"). In connection with preparing our financial statements, we are required to make assumptions and estimates about future events, and to apply judgments that affect the reported amounts of assets, liabilities, revenue, expense and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with U.S. GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.
Our significant accounting policies are discussed in our audited financial statements included in "Item 8. Financial Statements and Supplementary Data" in this Annual Report. Management believes that the following accounting estimates are those most critical to fully understanding and evaluating our reported financial results, and they require management's most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain.
Method of Accounting for Oil and Natural Gas Properties
We account for oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs, including non-productive costs and certain general and administrative costs such as salaries, benefits and other internal costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Under the full cost method of accounting, capitalized costs are amortized based on units-of-production and proved oil and natural gas reserves. If we maintain production levels year over year, our depreciation, depletion, and amortization expense may be significantly different if our estimates of remaining reserves or future development costs change significantly. On a quarterly basis, we review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC, which is referred to as a cost center ceiling test.
The primary factors impacting this test are reserve estimates and the unweighted arithmetic average of index prices on the first day of each month within the 12-month period that ends as of each quarterly balance sheet date. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices may have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes (which our predecessor, INR Holdings, has not been subject to historically for federal income tax purposes), is generally written off as an expense. We did not record any impairment of oil and natural gas properties for years ended December 31, 2025 and 2024.
Additionally, costs associated with unevaluated properties are excluded from properties subject to amortization until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property at least annually for possible impairment. This assessment is subjective and includes consideration of numerous factors, including drilling plans, remaining lease terms, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. We did not
record any impairment on our unevaluated properties for the years ended December 31, 2025 and 2024, but any such future impairment could potentially be material to our consolidated financial statements.
Oil and Natural Gas Reserves
Proved oil and gas reserves, as defined by SEC Regulation S-X, Rule 4-10, are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire unless evidence indicates that renewal is reasonably certain regardless of whether deterministic or probabilistic methods are used for the estimation.
Reserve estimates are prepared by independent engineers. Revisions may result from changes in, among other things, reservoir performance, development plans, prices, operating costs, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in certain proved reserves due to reaching economic limits sooner. A material change in the estimated volume of reserves could have an impact on the depletion rate calculation and our consolidated financial statements.
We estimate future net cash flows from natural gas, NGLs and oil reserves based on selling prices and costs using a 12-month average price, which is calculated as the unweighted arithmetic average of the first-day-of-the- month price for each month within the 12-month period and, as such, is subject to change in subsequent periods. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Income tax expense (which our predecessor, INR Holdings, was not subject to historically for federal income tax purposes for periods prior to the Corporate Reorganization) is based on currently enacted statutory tax rates and tax deductions and credits available under current laws.
Revenue Recognition
We derive revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. Our performance obligations are satisfied at a point in time and payments from purchasers are unconditional once the performance obligations have been satisfied, which occurs when control is transferred to the purchaser upon delivery of production volumes at a specified point. The pricing provisions of our contracts with customers are based on market indices, with certain adjustments for quality, supply and demand conditions, and location differentials, among other factors.
At the end of each month, we estimate the amount of production delivered to purchasers for that month and estimate revenues based on the price we expect to receive. Payments are generally received between 30 and 60 days after the date of production. Any variances between our accrued revenue estimates and the actual amounts of payments received for the sales of our production are recorded in the month that each payment is received from our purchasers. Such variances have historically not been significant.
The revenue derived from our midstream activities is generated from gathering assets owned by our wholly- owned subsidiary, INR Midstream. We charge a gathering fee per MMBtu transported through our gathering system and fees are recognized as revenue based on measured volumes at the specified delivery points when the associated service is performed.
Derivative Instruments
We use commodity derivatives for the purpose of mitigating the risk resulting from fluctuations in the market prices of crude oil and natural gas. We exercise significant judgment in determining the types of instruments to be used, the level of production volumes to include in our commodity derivative contracts, the prices at which we enter into commodity derivative contracts and counterparty creditworthiness. We do not use commodity derivative instruments for speculative or trading purposes.
We have not designated our derivative instruments as hedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based
on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and is generally determined using various inputs and assumptions including established index prices and other sources which are based upon, among other things, futures prices, time to maturity, implied volatilities and counterparty credit risk.
These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur.
Tax Receivable Agreement
As described in "Item 1. Business-Corporate Reorganization," Infinity Natural Resources entered into a Tax Receivable Agreement in connection with the closing of the IPO under which it is contractually committed to pay the Legacy Owners 85% of the net cash savings, if any, in U.S. federal, state and local income tax that Infinity Natural Resources (a) actually realizes with respect to taxable periods ending after the IPO or (b) is deemed to realize in the event of a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of the INR board of directors) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach) with respect to any taxable periods ending on or after such change of control or early termination event, in each case, as a result of (i) the tax basis increases resulting from the exchange of INR Units and the corresponding surrender of an equivalent number of shares of Class B common stock by the Legacy Owners for a number of shares of Class A common stock on a one-for-one basis or, at our option, the receipt of an equivalent amount of cash pursuant to the INR Holdings LLC Agreement and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement.
The projection of future taxable income and utilization of tax attributes associated with the Tax Receivable Agreement involve estimates which require significant judgment. The amount of the Company's actual taxable income (which may differ from our estimates), passage of future legislation, or consummation of significant transactions in the future may significantly impact the liability related to the Tax Receivable Agreement. The Company will account for amounts payable under the Tax Receivable Agreement in accordance with Accounting Standard Codification Topic 450, Contingencies.
JOBS Act
The JOBS Act permits us, as an "emerging growth company," to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies. We have elected to take advantage of this extended transition period, which means that the financial statements included in this Annual Report, as well as any financial statements that we file or furnish in the future, will not be subject to all new or revised accounting standards generally applicable to public companies for the transition period for so long as we remain an emerging growth company.
Recently Issued Accounting Standards
Refer to Note 2-Summary of Significant Accounting Policies, in Part II, Item 8. Financial Statements and Supplementary Data in this Annual Report for a discussion of recently issued accounting standards and their anticipated effect on our business.
Contractual Obligations and Commitments
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. The following table summarizes our obligations and commitments as of December 31, 2025, to make future payments under long-term contracts for the time periods specified below:
| 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total | |||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||
|
Credit Facility Principal(1)
|
$ | - | $ | - | $ | 150.9 | $ | - | $ | - | $ | - | $ | 150.9 | |||||||||||||||||||||||||||
|
Credit Facility Interest (2)
|
10.9 | 10.9 | 8.2 | - | - | - | 30.0 | ||||||||||||||||||||||||||||||||||
|
Asset Retirement Obligation
|
- | - | - | - | - | 3.3 | 3.3 | ||||||||||||||||||||||||||||||||||
|
Other (3)
|
6.2 | 0.3 | 0.2 | 0.2 | 0.1 | 0.7 | 7.7 | ||||||||||||||||||||||||||||||||||
|
Total
|
$ | 17.1 | $ | 11.2 | $ | 159.3 | $ | 0.2 | $ | 0.1 | $ | 4.0 | $ | 191.9 | |||||||||||||||||||||||||||
____________
(1)This reflects borrowings outstanding under our Credit Facility as of December 31, 2025; Credit Facility borrowings may be repaid and reborrowed prior to maturity.
(2)This debt bears interest at the SOFR plus a borrowing spread. In determining future interest, we used outstanding amounts at December 31, 2025 and the average borrowing cost for calendar year 2025.
(3)This amount includes commitments from drilling rig contracts, vehicle notes, and operating leases.
Infinity Natural Resources Inc. published this content on March 10, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on March 10, 2026 at 20:50 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]