Infinity Natural Resources, Inc.: Form 10-Q for the period ended Mar 31, 2025

The following should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included elsewhere in this Quarterly 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 Quarterly Report and the 2024 Form 10-K, 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. We are an early mover into the core of the Utica Shale’s volatile oil window in eastern Ohio as well as the emerging dry gas Utica Shale in southwestern Pennsylvania. Our Marcellus Shale development overlays our deep dry gas Utica assets in Pennsylvania, providing highly economic stacked development inventory that leverages the same company-owned midstream infrastructure. We have amassed approximately 93,000 net surface acres with exposure to the core of these plays providing us a 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.

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.

Concerns of global economic growth, inflation, 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 influenced by geopolitical tensions and trade policies as well as global economic slowdowns resulting in more downward pressure of prices at the end of the first quarter and beginning of the second quarter of 2025. 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 early 2025.

The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2024 through March 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:

24

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.

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 throughout 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.

Recent Developments

Initial Public Offering. On January 30, 2025, the Company's registration statement on Form S-1 relating to its initial public offering (“IPO”) was declared effective by the Securities and Exchange Commission (“SEC”), and the shares of its Class A common stock began trading on the New York Stock Exchange (“NYSE”) on January 31, 2025. The IPO closed in February 2025, pursuant to which the Company issued and sold 15,237,500 shares of its Class A common stock at a public offering price of $20.00 per share, including 1,987,500 shares issued pursuant to the full exercise of the underwriters’ option to purchase additional shares. The Company received net proceeds of approximately $286.5 million, after deducting underwriting discounts and commissions of $18.3 million. The Company contributed the net proceeds of the IPO to INR Holdings, and INR Holdings used the net proceeds, after payment of certain offering expenses, to repay borrowings outstanding under its revolving credit facility

Corporate Reorganization. In connection with the IPO, we underwent a Corporate Reorganization whereby: (a) the membership interests of the existing owners (the “Legacy Owners”) in Infinity Natural Resources, LLC (“INR Holdings”) were recapitalized into a single class of units (the “INR Units”), and, in exchange for their existing membership interests, the Legacy Owners received INR Units and an equal number of shares of our Class B common stock; and (b) we contributed the net proceeds of the IPO to INR Holdings in exchange for newly issued INR Units and a managing member interest in INR Holdings. After giving effect to the Corporate Reorganization and the IPO, we own an approximate 25.0% interest in INR Holdings and the Legacy Owners own an approximate 75.0% interest in INR Holdings.

The Company is a holding company whose sole material asset consists of membership interests in INR Holdings. The Company is the managing member of INR Holdings and controls and is responsible for all operational, management and administrative decisions relating to INR Holdings’ business and consolidates the financial results of INR Holdings and reports redeemable non-controlling interests in its consolidated financial statements related to the INR Units that the Legacy Owners own in INR Holdings.

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 the three months ended March 31, 2025 and 2024, our oil, natural gas, and NGL revenues were comprised of 56% and 54%, respectively, from the sale of oil, 27% from the sale of natural gas in each period, and 17% and 19%, respectively, from the sale of NGLs.

We utilize unaffiliated third parties to market a portion of our oil, natural gas, and NGL production to various purchasers, which consist of credit-worthy counterparties, including utilities, LNG producers, industrial consumers, major corporations and super majors in our industry. The third parties collect proceeds directly from these purchasers and remit to us the total of all amounts collected on our behalf less the third party’s fee for making such sales. We do not believe the loss of any purchaser would have a material adverse effect on our business, as other purchasers or markets are currently accessible to us.

Midstream activities revenues, which consist of gathering, compression, and water handling, are derived from our ownership of INR Midstream, LLC, a subsidiary of INR Holdings. 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.

Principal Components of Our Cost Structure

Lease operating. Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water disposal, materials, and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor, materials, and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our well equipment or surface facilities result in increased LOE in periods during which they are performed. Certain operating cost components are variable and fluctuate based on production levels. For example, the disposal of produced water usually increases in conjunction with increased production. Also, we monitor our LOE in absolute dollar terms and on a per Boe and/or Mcfe basis to assess our performance and to determine if any wells or properties should be shut in, repaired or recompleted.

Gathering, processing, and transportation. Gathering, processing, and transportation (“GP&T”) expense includes fees paid to third parties who operate low- and high-pressure gathering systems that transport our gas. It also includes costs to process, extract, and fractionate NGLs from our liquids-rich gas and transport our natural gas and NGLs to market.

Production and ad valorem taxes. Pennsylvania imposes an annual impact fee on each producing shale well for a period of 15 years beginning in the year the well is spud. Ohio imposes a production tax which is based upon annual production. The proportion of our production and producing wells from each state may change over time and, as a result, the proportion of our production taxes and impact fees will vary depending on volumes produced from the Utica Shale, the number of producing shale wells in Pennsylvania, and the applicable production tax rates and impact fees then in effect. In addition, we are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties as well as the value of property and equipment.

Depreciation, depletion, and amortization. Depreciation, depletion, and amortization (“DD&A”) includes the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas. Under the full- cost method of accounting, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization. Accretion expense related to our asset retirement obligations is also included within this balance.

General and administrative. General and administrative (“G&A”) expenses are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, IT expenses, legal, audit and other fees for professional services. G&A expenses are offset by recoveries for overhead that are billed to our joint-interest partners as outlined in a joint operating agreement or other similar documents.

Interest expense. We have financed a portion of our working capital requirements and property acquisitions with borrowings under the Credit Facility. As a result, we incur interest expense that is affected by fluctuations in interest rates and, in the case of the prior credit facility and Credit Facility, based on outstanding borrowings. We have seen a reduction in cash interest expense following the completion of the IPO in February 2025 as we repaid substantially all of our outstanding borrowings under the Credit Facility with the net proceeds of the IPO.

Gains and losses on derivatives. We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of oil, natural gas, and NGLs. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are recorded at fair value as of the balance sheet date with changes in fair value recognized as a gain or loss in our results of operations. Our operating cash flows are impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

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:

Public Company Expenses. We expect to incur direct, incremental G&A expenses as a result of being a public company, including costs associated with compliance with the Securities Exchange Act of 1934, as amended (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.

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.

Interest Expense. In connection with the IPO, we materially reduced our indebtedness through the repayment of substantially all of our outstanding borrowings under the Credit Facility with net proceeds of the IPO. As a result, we expect an immediate reduction in cash interest expense.

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.

Non-Cash Compensation Expense. In connection with the closing of the IPO, all outstanding performance-based 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.

Results of Operations

For the Three Months Ended March 31, 2025, Compared to the Three Months Ended March 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:

(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 EIA commodity pricing. (“NSAI”) found at https://netherlandsewell.com/resources/pricing-data/ and U.S. Energy Information Administration (“EIA”). 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. Total oil, natural gas and NGL net revenues for the three months ended March 31, 2025 increased by $34.3 million, or 69%, compared to the three months ended March 31, 2024. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.

Net production volumes for oil and NGLs increased 87% and 48%, respectively, between periods. Net production volumes for natural gas declined 5% between the three months ended March 31, 2025 and 2024. The oil and NGL production volume increase resulted from placing six (6) wells on production from the Ohio Utica’s Volatile Oil Window in late 2024 and one (1) well in early 2025. The decrease in natural gas volumes between periods was due primarily to the normal production decline across existing wells offset by turning into sales five (5) Marcellus Shale wells in Pennsylvania at the end of March 2025. The combination of a full quarter of production from the wells placed into production in late 2024 and new wells placed into production in the first quarter of 2025 contributed to the overall increase of 5.4 Mboe/d, or 25%, in production relative to the prior period.

Average realized sales prices for natural gas and NGLs increased 82% and 3%, respectively, during the period while average realized oil prices decreased 7% for the three months ended March 31, 2025 compared to the prior period. The 7% decrease in the average realized oil price was mainly driven by lower NYMEX WTI oil prices during the period along with higher regional differentials compared to the same period a year earlier. The average realized natural gas price increased 81% due to 59% higher average NYMEX gas prices between periods and lower natural gas differentials. The 3% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in 2025 compared to 2024 and changes in product composition between periods.

Operating Expenses

(in thousands)

Gathering, processing, and transportation. GP&T for the three months ended March 31, 2025, increased $1.6 million compared to the three months ended March 31, 2024. This increase is attributed to additional wells brought online in Ohio between periods. GP&T per Boe was $5.05 for the three months ended March 31, 2025, which represents a decrease of $0.38 per Boe, or 7%, from the prior period. The per unit decrease was attributable to improved weighted average costs associated with various midstream systems in Ohio offset partially by lower volumes on INR's owned gathering system in Pennsylvania.

Lease operating. LOE for the three months ended March 31, 2025, increased $0.1 million compared to the prior period. LOE per Boe was $3.11 for the three months ended March 31, 2025, which represents a decrease of $0.68 per Boe, or 18%, 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.

Production and ad valorem taxes. Production and ad valorem taxes for the three months ended March 31, 2025, increased $0.3 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.

Depreciation, Depletion and Amortization. For the three months ended March 31, 2025, DD&A expense was $21.3 million, an increase of $5.7 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 increased DD&A expense by $3.6 million, while our higher average DD&A rate of $8.68 per Boe increased total DD&A expense by $2.0 million between periods. Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves.

General and Administrative Expenses. G&A expenses for the three months ended March 31, 2025 were $131.8 million compared to $2.1 million for the prior period. This increase was primarily due to non cash stock compensation expense of $126.9 million, of which $126.1 million was a one time charge associated with the IPO. We also had higher payroll and employee-related costs due to higher headcount, which increased from 53 as of March 31, 2024 to 91 as of March 31, 2025.

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:

(in thousands)

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 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.

We continually evaluate our capital needs and compare them to our capital resources. Our total capital expenditures incurred for development during the three months ended March 31, 2025 were $88.3 million, which includes $78.2 million on drilling and completion activities, $3.5 million on midstream and $6.6 million on land activities. Our drilling and completion capital budget for 2025 is $240 million to $280 million, along with $9 million to $12 million of midstream capital expenditures. We funded our capital expenditures for the three months ended March 31, 2025 from cash flows from operations and borrowings incurred under the Credit Facility. We expect to fund our 2025 capital expenditures budget through a combination of cash flows from operations and additional borrowings under the Credit Facility. 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 the Credit Facility.

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 filing of this Quarterly Report and for the foreseeable future.

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:

(in thousands)

Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2025 and 2024

Operating activities

For the three months ended March 31, 2025, we generated $74.2 million of cash from operating activities, an increase of $44.1 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 LOE, severance and ad valorem taxes, GP&T, G&A, and lower realized prices for oil and during the three months ended March 31, 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.

Investing activities

For the three months ended March 31, 2025, we spent $105.6 million on capital expenditures in connection with our drilling and completion activities. We also spent $2.8 million on other property and equipment largely related to midstream activities.

For the three months ended March 31, 2024, we spent $36.3 million on capital expenditures in connection with our drilling and completion activities. We also spent $1.9 million on other property and equipment.

Financing activities

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.

For the three months ended March 31, 2024, the change in financing activity was primarily related to borrowing $43.5 million under our prior credit facility and repaying $34.0 million of borrowings. Additionally, there was a capital raise for $0.5 million.

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.

See Note 7 – Derivatives and Risk Management for more information on our derivative activities.

Changes in the fair value of derivative contracts from December 31, 2024 to March 31, 2025, are presented below:

(in thousands)

(1) At inception, new derivative contracts entered into by us have no intrinsic value.

Financing Agreements

Credit Facility

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.

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 $325,000,000 to $350,000,000. As of March 31, 2025, the Company’s reserves supported a $350.0 million borrowing base of which $11.3 million was outstanding, leaving $338.7 million of unused capacity.

For the three months ended March 31, 2025 and 2024, total interest expense on the Credit Facility was $2.6 million and $4.1 million, respectively. We did not capitalize any interest expense for the three months ended March 31, 2025 and 2024. For the three months ended March 31, 2025 and 2024, the Company’s weighted-average interest rate was 5.2% and 8.9%, respectively.

Critical Accounting Estimates

Our unaudited condensed consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”) and involve a significant level of estimation uncertainty. In connection with preparing our unaudited condensed consolidated 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. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the 2024 Form 10-K for information on our critical accounting estimates.

Our significant accounting policies are discussed in Note 2 – Summary of Significant Accounting Policies to our unaudited condensed consolidated financial statements in this Quarterly Report.

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. 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.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.

Oil, Natural Gas and NGL Revenues

Our revenues and cash flows from operations are subject to many variables, the most significant of which is the volatility of commodity prices. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by global economic factors, pipeline capacity constraints, inventory levels, basis differentials, weather conditions and other factors. Commodity prices have long been volatile and unpredictable, and we expect this volatility to continue in the future.

There can be no assurance that commodity prices will not be subject to continued wide fluctuations in the future. A substantial or extended decline in such prices could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil and gas reserves that may be economically produced, which could result in impairments of our oil and gas properties.

Commodity Price Risk and Hedges

Our primary market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Oil, natural gas and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue for the foreseeable future. Our revenues, profitability and future growth are highly dependent on the prices we receive for our oil, natural gas and NGL sales, and the levels of our production, and depend on numerous factors beyond our control, some of which are described in “Item 1A. Risk Factors” in the 2024 Form 10-K.

Based on our production for the three months ended March 31, 2024, our oil, natural gas and NGL sales for the three months ended March 31, 2024 would have moved up or down $2.7 million for each 10% change in oil prices per Bbl, $1.3 million for each 10% change in gas prices per Mcf, and $0.9 million for each 10% change in NGL prices per Bbl. Based on our production for the three months ended March 31, 2025, our oil, natural gas and NGL sales for the three months ended March 31, 2025 would have moved up or down $4.7 million for each 10% change in oil prices per Bbl, $2.3 million for each 10% change in gas prices per Mcf, and $1.4 million for each 10% change in NGL prices per Bbl.

Due to this volatility, we have historically used, and we may elect to continue to selectively use, commodity derivative instruments (such as collars, swaps, puts and basis swaps) to mitigate price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flows that can emanate from fluctuations in oil and natural gas prices, and thereby provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices, but alternatively they partially limit our potential gains from future increases in prices. Our Credit Agreement limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated, projected production from proved properties. “Item 1A. Risk Factors” in the 2024 Form 10-K contains additional information regarding the volumes of our production covered by derivatives and the associated risks.

Counterparty and Customer Credit Risk

Our derivatives expose us to credit risk in the event of nonperformance by counterparties. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. We minimize the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; and (ii) only entering into hedging arrangements with counterparties that are also participants in the Credit Agreement, all of which have investment-grade credit ratings.

Our principal exposures to credit risk are through receivables resulting from the sales of our oil, natural gas, and NGLs. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our customers is high.

We sell our production to a relatively small number of customers, as is customary in our business. We extend and monitor credit based on an evaluation of their financial conditions and publicly available credit ratings. The future availability of a ready market for oil, natural gas and NGLs depends on numerous factors outside of our control, none of which can be predicted with certainty. For the three months ended March 31, 2025, we had four customers that exceeded 10% of total revenues. We do not believe the loss of any single purchaser would materially impact our operating results as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Interest Rate Risk

As of March 31, 2025, our reserves supported a $350.0 million credit facility of which $11.3 million in borrowings was outstanding, leaving $338.7 million of unused capacity. Our largest exposure with respect to variable-rate debt comes from changes in the relevant benchmark rate underlying such debt financings, principally SOFR. We currently do not have an interest rate hedge program to hedge our exposure to floating interest rates on our variable-rate debt obligations. If annual interest rates increase 50 basis points, based on our March 31, 2024 and 2025, variable-rate debt, annual interest expense on variable-rate debt would increase by approximately $0.4 million and $0.1 million, respectively.

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, evaluated, as of the end of the period covered by this Quarterly Report, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were not effective because of certain material weaknesses in our internal control over financial reporting, as described in “Item 9A. Controls and Procedures” in the 2024 Form 10-K.

Changes in Internal Control Over Financial Reporting

There was no change in the Company’s internal control over financial reporting during the period ended March 31, 2025 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in the 2024 Form 10-K. There have been no material changes to the risks described in such report. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.