INFINITY NATURAL RESOURCES, INC.
For the period ended Jun 30, 2025. Filed Aug 12, 2025.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Jun 30, 2025 · Filed Aug 12, 2025
INR$12.79+4.4%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-03-31; filed 2025-05-13.
0002029118-25-000005
Item 2. Management's Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-06-30; filed 2025-08-12.
0002029118-25-000027
Item 2. Management's Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 91 previous paragraphs and 90 current paragraphs.
49 unchanged; 25 reworded; 5 added; 17 removed; 0 previous and 11 current paragraphs rearranged.
Tables are not compared: 6 previous and 9 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (5)
Current report
General and Administrative Expenses. G&A expenses for the three months ended June 30, 2025 were $5.3 million compared to $3.5 million for the prior period. This increase was primarily related to increased expenses associated with stock compensation, which totaled $2.3 million during the period and higher public company expenses.
Current report
For the Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024
Current report
Revenues
Current report
Net production volumes for oil, natural gas and NGLs increased 21%, 25% and 34%, respectively, between periods. The oil, natural gas and NGL production volume increase resulted from placing twelve (12) 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 2024 and 2025. The addition of these wells contributed to the overall increase of 6.3 Mboe/d, or 27%, in production relative to the prior period.
Current report
Operating Expenses
Removed paragraphs (17)
Previous report
Recent Developments
Previous report
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
Previous report
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.
Previous report
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.
Previous report
Sources of Revenues
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
Principal Components of Our Cost Structure
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Reworded paragraphs (25)
Previous wording
We are a growth oriented independent energy company focused on the acquisition, development, and production of hydrocarbons in the Appalachian Basin. We are focused on creating shareholder value through the identification and disciplined development of low-risk, highly economic oil and natural gas assets while maintaining a strong and flexible balance sheet. We 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.
Current wording
We are a growth oriented independent energy company focused on the acquisition, development, and production of hydrocarbons in the Appalachian Basin. We are focused on creating shareholder value through the identification and disciplined development of low-risk, highly economic oil and natural gas assets while maintaining a strong and flexible balance sheet. We 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 95,000 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.
Previous wording
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.
Current wording
Concerns of global economic growth, inflation, OPEC+’s recent decisions to increase production and resulting increases in global oil and natural gas supply levels and the potential for a global trade war resulted in oil price deterioration throughout 2024 and 2025. Oil prices have continued to be volatile and have been influenced by geopolitical tensions 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, though oil prices have moderately recovered from their lows in May. Natural gas prices remained low for the majority of 2024 driven by an over-supply due to mild winter weather, liquefied natural gas project delays and higher than expected natural gas production, but prices have improved during 2025 relative to 2024 though they remain volatile.
Previous wording
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.
Current wording
The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2025 through June 30, 2025, spot prices for NYMEX WTI crude oil ranged from $60.92 per Bbl to $75.25 per Bbl, while the range for NYMEX Henry Hub natural gas spot prices was between $3.17 per MMBtu and $3.95 per MMBtu. We expect that the commodity market will continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. We use a derivative portfolio and firm sales contracts to mitigate the risks of price volatility.
Previous wording
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.
Current wording
Public Company Expenses. We have incurred and expect to continue to incur direct, incremental G&A expenses as a result of being a public company, including costs associated with compliance with the 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.
Previous wording
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.
Current wording
Interest Expense. In connection with the IPO, we materially reduced our indebtedness through the repayment of substantially all of our outstanding borrowings under the Credit Facility with net proceeds of the IPO. As a result, we received an immediate reduction in cash interest expense.
Previous wording
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.
Current wording
Non-Cash Compensation Expense. In connection with the closing of the IPO, all outstanding incentive units of INR Holdings vested. Consequently, INR Holdings recognized $126.1 million of non-recurring, non-cash stock compensation expense related to these awards, in accordance with the guidance provided by ASC 710.
Previous wording
(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.
Current wording
(2)Based on Netherland, Sewell and Associates Inc. found at https://netherlandsewell.com/resources/pricing-data/ and U.S. Energy Information Administration (“EIA”) commodity pricing. Weighted average is based on INR’s production in a given month during the course of the calendar year.
Previous wording
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.
Current wording
Oil, natural gas, and NGL sales. Total oil, natural gas and NGL net revenues for the three months ended June 30, 2025 increased by $2.4 million, or 3%, compared to the three months ended June 30, 2024. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Previous wording
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.
Current wording
Net production volumes for oil decreased 17%, natural gas volumes increased 54% and NGL volumes increased 23% between periods for the three months ended June 30, 2025 and 2024. The increase in natural gas volumes is predominantly related to the five wells coming online in the first quarter of 2025 in the Marcellus Shale in Pennsylvania as well as the contribution from one additional well placed online in Ohio during 2025. The decrease in oil volumes between periods was due primarily to the normal production decline across existing wells as well as the timing of wells placed online during 2024. 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 7.2 Mboe/d, or 28%, in production relative to the prior period.
Previous wording
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.
Current wording
Average realized sales prices for oil and NGLs decreased 21% and 20%, respectively, during the period while average realized natural gas prices increased 83% for the three months ended June 30, 2025 compared to the prior period. The 21% decrease in the average realized oil price was mainly driven by lower NYMEX WTI oil prices during the period. The average realized natural gas price increased 83% due to 82% higher average NYMEX gas prices between periods. The 20% decrease in average realized NGL prices between periods was primarily attributable to an increase in ethane recovery resulting in a blended lower price realized relative to the prior period.
Previous wording
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.
Current wording
Lease operating expenses. LOE for the three months ended June 30, 2025, decreased $0.3 million compared to the prior period. LOE per Boe was $2.09 for the three months ended June 30, 2025, which represents a decrease of $0.71 per Boe, or 25%, from the prior period. This decrease in LOE was primarily related to lower fixed and semi-variable well costs, such as water disposal, equipment rentals, repair work, wellhead chemicals, labor and electricity, associated with a higher well count from new producing wells drilled or acquired.
Previous wording
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.
Current wording
Production and ad valorem taxes. Production and ad valorem taxes for the three months ended June 30, 2025, increased $2.5 million compared to the prior period. Production taxes in Ohio are based on our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. Production taxes in Pennsylvania are assessed on producing wells by imposing an impact fee determined based on the market price for natural gas, which commences on the date the well is initially spud and continues for a period of 15 years.
Previous wording
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.
Current wording
Gathering, processing, and transportation. GP&T for the six months ended June 30, 2025, increased $4.1 million compared to the six months ended June 30, 2024. This increase is attributed to additional wells brought online in Ohio between periods. GP&T per Boe was $4.92 for the six months ended June 30, 2025, which represents a decrease of $0.34 per Boe, or 6%, 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.
Previous wording
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.
Current wording
Depreciation, Depletion and Amortization. For the six months ended June 30, 2025, DD&A expense was $44.9 million, an increase of $9.6 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 $9.3 million, while our higher average DD&A rate of $8.13 per Boe increased total DD&A expense by $0.6 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.
Previous wording
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.
Current wording
General and Administrative Expenses. G&A expenses for the six months ended June 30, 2025 were $137.0 million compared to $5.6 million for the prior period. This increase was primarily due to expenses associated with a public company and a one-time stock compensation expense of $126.1 million incurred in connection with the IPO. We also had higher payroll and employee-related costs due to higher headcount associated with the growth of the business.
Previous wording
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.
Current wording
We continually evaluate our capital needs and compare them to our capital resources. Our total capital expenditures incurred for development during the three and six months ended June 30, 2025 were $80.6 million and $168.9 million, respectively. For the three months ended June 30, 2025, we incurred $70.4 million in drilling and completion activities, $2.7 million associated with midstream activities and $7.5 million related to land activities. During the six months ended June 30, 2025, we incurred $148.5 million in drilling and completion activities, $6.2 million associated with midstream activities and $14.2 million related to land activities. We funded our capital expenditures for the three and six months ended June 30, 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.
Previous wording
Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2025 and 2024
Current wording
Analysis of Cash Flow Changes Between the Six Months Ended June 30, 2025 and 2024
Previous wording
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.
Current wording
For the six months ended June 30, 2025, we generated $144.6 million of cash from operating activities, an increase of $47.8 million from the prior period. Cash provided by operating activities increased primarily due to higher production volumes and higher realized prices for natural gas and associated revenues as compared to the prior period. These factors were partially offset by higher operating expenses during the six months ended June 30, 2025 as compared to the prior period. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and on fluctuations in our operating costs between periods.
Previous wording
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.
Current wording
For the six months ended June 30, 2025, we spent $188.3 million on capital expenditures in connection with our drilling and completion activities. We also spent $6.2 million on other property and equipment largely related to midstream activities.
Previous wording
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.
Current wording
For the six months ended June 30, 2024, we spent $104.9 million on capital expenditures in connection with our drilling and completion activities. We also spent $3.5 million on other property and equipment.
Previous wording
For the three months ended March 31, 2025, the change in financing activity was primarily related to the IPO which generated net proceeds of $286.5 million. We used funds from the IPO, along with cash from operating activities to pay down borrowings under the Credit Facility of $304.0 million during the period, and we made borrowings under the Credit Facility of $56.0 million during the period. We also paid approximately $0.9 million of other costs associated with the IPO.
Current wording
For the six months ended June 30, 2025, the change in financing activity was primarily related to the IPO which generated net proceeds of $286.5 million. We used funds from the IPO, along with cash from operating activities to pay down borrowings under the Credit Facility of $307.0 million since the beginning of the year. We have also made borrowings under the Credit Facility of $82.0 million during the period. We also paid approximately $6.8 million of other costs associated with the IPO.
Previous wording
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.
Current wording
For the six months ended June 30, 2024, the change in financing activity was primarily related to borrowing $56.5 million under our prior credit facility and repaying $40.0 million of borrowings.
Previous wording
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.
Current wording
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
Previous wording
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.
Current wording
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. On May 29, 2025, the Company amended the Credit Agreement to, among other things, amend certain provisions relating to hedging requirements and restrictions in the Credit Agreement. As of June 30, 2025, the Company’s reserves supported a $350.0 million borrowing base of which $34.4 million was outstanding, leaving $315.6 million of unused capacity.
Previous wording
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.
Current wording
For the six months ended June 30, 2025 and 2024, total interest expense on the Credit Facility was $3.5 million and $8.1 million, respectively. We did not capitalize any interest expense for the six months ended June 30, 2025 and 2024. For the six months ended June 30, 2025 and 2024, the Company’s weighted-average interest rate was 4.2% and 8.9%, respectively.
Rearranged current paragraphs (11)
Current report — wording carried from elsewhere
Gathering, processing, and transportation. GP&T for the three months ended June 30, 2025, increased $2.4 million compared to the three months ended June 30, 2024. This increase is attributed to additional wells brought online in Ohio between periods. GP&T per Boe was $4.82 for the three months ended June 30, 2025, which represents a decrease of $0.30 per Boe, or 6%, from the prior period. The per unit decrease was attributable to improved weighted average costs associated with various midstream systems in Ohio and increased development of our natural gas weighted areas within Pennsylvania.
Current report — wording carried from elsewhere
Depreciation, Depletion and Amortization. For the three months ended June 30, 2025, DD&A expense was $23.7 million, an increase of $3.9 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 $5.1 million, while our average DD&A rate of $7.60 per Boe decreased total DD&A expense by $1.2 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.
Current report — wording carried from elsewhere
The following table provides the components of our net revenues and net production for the periods indicated, as well as each period’s average prices (before and after the effects of derivatives) and average daily production volumes:
Current report — wording carried from elsewhere
(1)Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
Current report — wording carried from elsewhere
(2)Based on Netherland, Sewell and Associates Inc. (“NSAI”) found at https://netherlandsewell.com/resources/pricing-data/ and EIA commodity pricing. Weighted average is based on INR’s production in a given month during the course of the calendar year.
Current report — wording carried from elsewhere
Oil, natural gas, and NGL sales. Total oil, natural gas and NGL net revenues for the six months ended June 30, 2025 increased by $36.7 million, or 31%, compared to the six months ended June 30, 2024. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Current report — wording carried from elsewhere
Average realized sales prices for natural gas increased 76% during the period due to 68% higher average NYMEX gas prices between periods and lower natural gas differentials. Oil prices decreased 14%, driven by lower NYMEX WTI oil prices during the period . NGL prices decreased 8% between periods primarily attributable to lower Mont Belvieu spot prices for plant products in 2025 compared to 2024 and changes in product composition between periods.
Current report — wording carried from elsewhere
Lease operating. LOE for the six months ended June 30, 2025, increased $(0.2) million compared to the prior period. LOE per Boe was $2.54 for the six months ended June 30, 2025, which represents a decrease of $0.70 per Boe, or 22%, from the prior period. This decrease in LOE was primarily related to a combination of (a) lower fixed and semi-variable well costs, such as water disposal, equipment rentals, repair work, wellhead chemicals, labor and electricity, associated with a higher well count from new producing wells drilled or acquired and (b) higher volumes driven by our Pennsylvania Marcellus development.
Current report — wording carried from elsewhere
Production and ad valorem taxes. Production and ad valorem taxes for the six months ended June 30, 2025, increased $2.8 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.
Current report — wording carried from elsewhere
Net Gain (Loss) on Derivative Instruments. The following table presents gains and losses on our derivative instruments for the periods indicated:
Current report — wording carried from elsewhere
Holdings’ subsidiaries and is secured by first priority security interests on substantially all of INR Holdings’ consolidated assets.