Infinity Natural Resources Inc.
11/10/2025 | Press release | Distributed by Public on 11/10/2025 15:26
Quarterly Report for Quarter Ending September 30, 2025 (Form 10-Q)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 have amassed approximately 95,600 net surface acres with exposure to the core of the Marcellus and Utica Shale plays providing us a unique and balanced portfolio of high-return oil and natural gas drilling locations. This balance allows us to optimize our development plan across our portfolio to capitalize on changes in commodity pricing over time.
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, the Federal Reserve's recent decisions to adjust interest rates, OPEC+'s recent decisions to increase production and resulting increases in global oil and natural gas supply levels and the potential for a global trade war resulted in oil price deterioration throughout 2024 and 2025. Oil prices have continued to be volatile and have been influenced by geopolitical tensions, tariffs and trade policies as well as global economic slowdowns resulting in more downward pressure on prices. Natural gas prices remained low for the majority of 2024 driven by an over-supply due to mild winter weather, liquefied natural gas project delays and higher than expected natural gas production, but prices have improved during 2025 relative to 2024 due to a combination of weather-related demand spikes, tightening supply, and increased global exports, particularly of liquified natural gas, though prices remain volatile.
The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2025 through September 30, 2025, spot prices for NYMEX WTI crude oil ranged from $62.17 per Bbl to $75.74 per Bbl, while the range for NYMEX Henry Hub natural gas spot prices was between $2.87 per MMBtu and $3.96 per MMBtu. We expect that the commodity market will continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. We use a derivative portfolio and firm sales contracts to mitigate the risks of price volatility.
The following table highlights the quarterly average price trends for NYMEX WTI spot prices for crude oil and NYMEX Henry Hub index price for natural gas since the first quarter of 2024:
| 2024 | 2025 | ||||||||||||||||||||||||||||||||||||||||
| Q1 | Q2 | Q3 | Q4 | Q1 | Q2 | Q3 | |||||||||||||||||||||||||||||||||||
|
Oil (per Bbl)
|
$ | 77.56 | $ | 81.72 | $ | 76.24 | $ | 70.73 | $ | 71.84 | $ | 64.63 | $ | 65.74 | |||||||||||||||||||||||||||
|
Gas (per MMBtu)
|
$ | 2.25 | $ | 1.89 | $ | 2.15 | $ | 2.79 | $ | 3.65 | $ | 3.44 | $ | 3.07 | |||||||||||||||||||||||||||
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 for the remainder of 2025 due to concerns over global trade wars and changes in tariff policies. Inflationary pressures such as these may also result in increases to the costs of our oilfield goods, services and personnel, which can in turn cause our capital expenditures and operating costs to rise.
Recent Developments
On November 10, 2025, our board of directors authorized a share repurchase program, whereby we may purchase up to an aggregate of $75.0 million of our Class A common stock. Repurchases under the program may be made from time to time in the open market, in privately negotiated transactions, through purchases made in accordance with Rule 10b5-1 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), or by such other means as will comply with applicable state and federal securities laws. The timing of any such repurchases will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.
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 have incurred and expect to continue to incur direct, incremental G&A expenses as a result of being a public company, including costs associated with compliance with the Exchange Act, tax compliance, PCAOB support fees, the Sarbanes-Oxley Act compliance costs, investor relations activities, listing fees, registrar and transfer agent fees, stock-based compensation, incremental director and officer liability insurance costs, and independent director compensation. We estimate these direct, incremental G&A expenses could total approximately $4 million to $6 million per year, which are not included in our historical results of operations of our predecessor.
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 received 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 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 September 30, 2025, Compared to the Three Months Ended September 30, 2024
The following table provides the components of our net revenues and net production for the periods indicated, as well as each period's average prices (before and after the effects of derivatives) and average daily production volumes:
| For the Three Months Ended September 30, | Increase / (Decrease) | ||||||||||||||||||||||
| 2025 | 2024 | $ | % | ||||||||||||||||||||
| Net revenues (in thousands): | |||||||||||||||||||||||
| Oil sales | $41,023 | $45,745 | ($4,722) | (10)% | |||||||||||||||||||
| Natural gas sales | $27,293 | $11,737 | $15,556 | 133% | |||||||||||||||||||
| Natural gas liquids sales | $9,938 | $11,489 | ($1,551) | (13)% | |||||||||||||||||||
| Oil, natural gas, and natural gas liquids sales | $78,254 | $68,971 | $9,283 | 13% | |||||||||||||||||||
| Average sales prices: | |||||||||||||||||||||||
| Oil price (per Bbl) | $57.14 | $68.38 | ($11.24) | (16)% | |||||||||||||||||||
| Effects of derivative settlements on average price (per Bbl) | $4.55 | ($1.23) | $5.78 | 470% | |||||||||||||||||||
| Oil price including the effects of derivatives (per Bbl) | $61.69 | $66.53 | ($4.84) | (7)% | |||||||||||||||||||
| Wtd. Average NYMEX WTI price for oil (per Bbl) (2) | $65.25 | $77.91 | ($12.66) | (16)% | |||||||||||||||||||
| Oil differential to NYMEX | ($8.11) | ($9.53) | $1.42 | 15% | |||||||||||||||||||
| Natural gas price (per Mcf) | $2.15 | $1.57 | $0.58 | 37% | |||||||||||||||||||
| Effects of derivative settlements on average price (per Mcf) | $0.22 | $1.46 | ($1.24) | (85)% | |||||||||||||||||||
| Natural gas price including the effects of derivatives (per Mcf) | $2.37 | $1.83 | $0.54 | 29% | |||||||||||||||||||
| Wtd. Average NYMEX Henry Hub price for natural gas (per MMBtu)(2) | $3.06 | $2.11 | $0.95 | 45% | |||||||||||||||||||
| Natural gas differential to NYMEX | ($0.91) | ($0.54) | ($0.37) | (69)% | |||||||||||||||||||
| NGL price excluding GP&T (per Bbl) | $20.88 | $18.61 | $2.27 | 12% | |||||||||||||||||||
| Effects of derivative settlements on average price (per Bbl) | $0.53 | $7.56 | ($7.03) | (93)% | |||||||||||||||||||
| NGL price including the effects of derivatives (per Bbl) | $21.41 | $27.33 | ($5.92) | (22)% | |||||||||||||||||||
| Net production | |||||||||||||||||||||||
| Oil (MBbls) | 718 | 669 | 49 | 7% | |||||||||||||||||||
| Natural gas (MMcf) | 12,722 | 7,484 | 5,238 | 70% | |||||||||||||||||||
| NGL (Bbls) | 476 | 474 | 2 | -% | |||||||||||||||||||
| Net production (MBoe)(1) | 3,314 | 2,391 | 923 | 39% | |||||||||||||||||||
| Average daily net production | |||||||||||||||||||||||
| Oil (Bbls/d) | 7,808 | 7,272 | 536 | 7% | |||||||||||||||||||
| Natural gas (Mcf/d) | 138,277 | 81,348 | 56,929 | 70% | |||||||||||||||||||
| NGLs (Bbls/d) | 5,172 | 5,152 | 20 | -% | |||||||||||||||||||
| Average daily net production (Boe/d)(1) | 36,027 | 25,989 | 10,038 | 39% | |||||||||||||||||||
_____________
(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. 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.
Revenues
Oil, natural gas, and NGL sales. Total oil, natural gas and NGL net revenues for the three months ended September 30, 2025 increased by $9.3 million, or 13%, compared to the three months ended September 30, 2024. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Net production volumes for oil increased 7%, natural gas volumes increased 70% and NGL volumes remained flat between periods for the three months ended September 30, 2025 and 2024. The increase in oil volumes between periods was due primarily to six wells placed into service in Ohio during the third quarter of 2025. The increase in natural gas volumes was predominantly related to the four wells coming online in the third quarter of 2025 in the Marcellus Shale in Pennsylvania and the six Ohio wells. The wells placed into service in the third quarter 2025 contributed to the overall increase of 10.0 MBoe/d, or 39%, in production relative to the prior period, offset by the natural decline of producing wells.
Average realized oil prices fell 16% driven by a lower NYMEX WTI oil price during the period. Natural gas prices rose 37%, reflecting a 45% increase in NYMEX gas prices. NGL prices increased 12% primarily due to a reduced ethane recovery, which improved the blend price compared to the prior period.
Operating Expenses
| For the Three Months Ended September 30, | Change | ||||||||||||||||||||||
| 2025 | 2024 | Amount | Percent | ||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||
| Gathering, processing, and transportation | $ | 12,737 | $ | 15,324 | $ | (2,587) | (17)% | ||||||||||||||||
| Lease operating | 6,655 | 6,825 | (170) | (2)% | |||||||||||||||||||
| Production and ad valorem taxes | 799 | 383 | 416 | 109% | |||||||||||||||||||
| Depreciation, depletion and amortization | 27,579 | 21,067 | 6,512 | 31% | |||||||||||||||||||
| General and administrative (including share-based compensation) | 8,053 | 2,690 | 5,363 | 199% | |||||||||||||||||||
| Total operating expenses | $ | 55,823 | $ | 46,289 | $ | 9,534 | 21% | ||||||||||||||||
| ($ per Boe) | |||||||||||||||||||||||
| Gathering, processing, and transportation | $ | 3.84 | $ | 6.41 | $ | (2.57) | (40)% | ||||||||||||||||
| Lease operating | 2.01 | 2.85 | (0.85) | (30)% | |||||||||||||||||||
| Production and ad valorem taxes | 0.24 | 0.16 | 0.08 | 50% | |||||||||||||||||||
| Depreciation, depletion and amortization | 8.32 | 8.81 | (0.49) | (6)% | |||||||||||||||||||
| General and administrative | 2.43 | 1.13 | 1.30 | 116% | |||||||||||||||||||
| Total operating expenses | $ | 16.84 | $ | 19.36 | $ | (2.52) | (13)% | ||||||||||||||||
Gathering, processing, and transportation.GP&T for the three months ended September 30, 2025, decreased $2.6 million compared to the three months ended September 30, 2024. This decrease was attributed to fewer wells being brought online in Ohio between periods combined with the natural decline of production volumes from existing wells. GP&T per Boe was $3.84 for the three months ended September 30, 2025, which represents a decrease of $2.57 per Boe, or 40%, from the prior period. The decrease in per-unit GP&T rate was primarily attributable to increased production volumes in our natural gas-weighted areas of Pennsylvania, which are subject to lower GP&T rates. This shift in volume mix reduced our overall average GP&T rate, as these areas incur fewer processing charges compared to our wet gas-weighted areas in Ohio, where the NGLs require additional processing.
Lease operating expenses.LOE for the three months ended September 30, 2025, decreased $0.2 million compared to the prior period. LOE per Boe was $2.01 for the three months ended September 30, 2025, which represents a decrease of $0.85 per Boe, or 30%, from the prior period. This decrease in LOE was primarily related to lower fixed and semi-variable
well costs, such as water disposal, equipment rentals, repair work, wellhead chemicals, labor and electricity, associated with a higher well count from new producing wells drilled or acquired.
Production and ad valorem taxes.Production and ad valorem taxes for the three months ended September 30, 2025, increased $0.4 million compared to the prior period. Production taxes in Ohio are based on our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. Production taxes in Pennsylvania are assessed on producing wells by imposing an impact fee determined based on the market price for natural gas, which commences on the date the well is initially spud and continues for a period of 15 years.
Depreciation, Depletion and Amortization.For the three months ended September 30, 2025, DD&A expense was $27.6 million, an increase of $6.5 million over the prior period. The primary factor contributing to higher DD&A expense in 2025 was the increase in our overall production volumes between periods resulting in an average DD&A rate of $8.10 per Boe.
General and Administrative Expenses.G&A expenses for the three months ended September 30, 2025 were $8.1 million compared to $2.7 million for the prior period. This increase was primarily related to expenses associated with stock compensation and professional services associated with being a public company.
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:
| Three Months Ended September 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| (in thousands) | |||||||||||
| Realized cash settlement gains (losses) | $ | 6,375 | $ | 12,454 | |||||||
| Non-cash mark-to-market derivative gain (losses) | 8,876 | 16,995 | |||||||||
| Total | $ | 15,251 | $ | 29,449 | |||||||
For the Nine Months Ended September 30, 2025, Compared to the Nine Months Ended September 30, 2024
The following table provides the components of our net revenues and net production for the periods indicated, as well as each period's average prices (before and after the effects of derivatives) and average daily production volumes:
| For the Nine Months Ended September 30, | Increase / (Decrease) | ||||||||||||||||||||||
| 2025 | 2024 | $ | % | ||||||||||||||||||||
|
Net revenues (in thousands):
|
|||||||||||||||||||||||
|
Oil sales
|
$119,624 | $121,570 | ($1,946) | (2)% | |||||||||||||||||||
|
Natural gas sales
|
$80,625 | $35,874 | $44,751 | 125% | |||||||||||||||||||
|
Natural gas liquids sales
|
$34,660 | $31,433 | $3,227 | 10% | |||||||||||||||||||
|
Oil, natural gas, and natural gas liquids sales
|
$234,909 | $188,877 | $46,032 | 24% | |||||||||||||||||||
|
Average sales prices:
|
|||||||||||||||||||||||
|
Oil price (per Bbl)
|
$59.22 | $69.75 | ($10.53) | (15%) | |||||||||||||||||||
|
Effects of derivative settlements on average price (per Bbl)
|
$4.46 | ($2.36) | $6.82 | 289% | |||||||||||||||||||
|
Oil price including the effects of derivatives (per Bbl)
|
$63.68 | $67.39 | ($3.71) | (6%) | |||||||||||||||||||
|
Wtd. Average NYMEX WTI price for oil (per Bbl)(2)
|
$67.50 | $78.31 | ($10.81) | (14%) | |||||||||||||||||||
|
Oil differential to NYMEX
|
($8.28) | ($8.56) | $0.28 | 3% | |||||||||||||||||||
|
Natural gas price (per Mcf)
|
$2.63 | $1.65 | $0.98 | 59% | |||||||||||||||||||
|
Effects of derivative settlements on average price (per Mcf)
|
$- | $0.82 | ($0.82) | (100%) | |||||||||||||||||||
|
Natural gas price including the effects of derivatives (per Mcf)
|
$2.63 | $2.47 | $0.16 | 6% | |||||||||||||||||||
|
Wtd. Average NYMEX Henry Hub price for natural gas (per MMBtu)(2)
|
$3.33 | $2.09 | $1.24 | 59% | |||||||||||||||||||
|
Natural gas differential to NYMEX
|
($0.70) | ($0.44) | ($0.26) | (59)% | |||||||||||||||||||
|
NGL price excluding GP&T (per Bbl)
|
$21.84 | $24.14 | ($2.30) | (10)% | |||||||||||||||||||
|
Effects of derivative settlements on average price (per Bbl)
|
($0.97) | $2.94 | ($3.91) | (133%) | |||||||||||||||||||
|
NGL price including the effects of derivatives (per Bbl)
|
$20.87 | $27.08 | ($6.21) | (23%) | |||||||||||||||||||
|
Net production(1)
|
|||||||||||||||||||||||
|
Oil (MBbls)
|
2,020 | 1,743 | 277 | 16% | |||||||||||||||||||
|
Natural gas (MMcf)
|
30,660 | 21,783 | 8,877 | 41% | |||||||||||||||||||
|
NGL (Bbls)
|
1,587 | 1,302 | 285 | 22% | |||||||||||||||||||
|
Net production (MBoe)(2)
|
8,717 | 6,676 | 2,041 | 31% | |||||||||||||||||||
|
Average daily net production(1)
|
|||||||||||||||||||||||
|
Oil (Bbls/d)
|
7,399 | 6,361 | 1,038 | 16% | |||||||||||||||||||
|
Natural gas (Mcf/d)
|
112,309 | 79,500 | 32,809 | 41% | |||||||||||||||||||
|
NGLs (Bbls/d)
|
5,814 | 4,751 | 1,063 | 22% | |||||||||||||||||||
|
Average daily net production (Boe/d)(2)
|
31,931 | 24,362 | 7,569 | 31% | |||||||||||||||||||
_____________
(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. 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.
Revenues
Oil, natural gas, and NGL sales. Total oil, natural gas and NGL net revenues for the nine months ended September 30, 2025 increased by $46.0 million, or 24%, compared to the nine months ended September 30, 2024. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Net production volumes for oil increased 16%, natural gas increased 41% and NGLs increased 22%, respectively, between periods. The oil, natural gas and NGL production volume increase resulted from placing 23 wells on production across our oil weighted assets in the Ohio Utica's Volatile Oil Window and our natural gas weighted assets in the Marcellus Shale in Pennsylvania during the fourth quarter of 2024 and 2025. The addition of these wells contributed to the overall increase of 7.6 MBoe/d, or 31%, in production relative to the prior period.
Average realized natural gas prices rose 59% during the period driven by higher NYMEX prices and improved differentials. Oil prices fell 15%, reflecting lower NYMEX WTI prices. NGL prices decreased 10% due to lower Mont Belvieu spot prices and changes in product mix.
Operating Expenses
| For the Nine Months Ended September 30, | Change | ||||||||||||||||||||||
| 2025 | 2024 | Amount | Percent | ||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||
| Gathering, processing, and transportation | $ | 39,322 | $ | 37,852 | $ | 1,470 | 4% | ||||||||||||||||
| Lease operating | 20,383 | 20,715 | (332) | (2)% | |||||||||||||||||||
| Production and ad valorem taxes | 4,502 | 1,264 | 3,238 | 256% | |||||||||||||||||||
| Depreciation, depletion and amortization | 72,489 | 56,344 | 16,145 | 29% | |||||||||||||||||||
| General and administrative (excluding share-based compensation) | 145,068 | 8,268 | 136,800 | 1655% | |||||||||||||||||||
| Total operating expenses | $ | 281,764 | $ | 124,443 | $ | 157,321 | 126% | ||||||||||||||||
| ($ per Boe) | |||||||||||||||||||||||
| Gathering, processing, and transportation | $ | 4.51 | $ | 5.67 | $ | (1.16) | (20%) | ||||||||||||||||
| Lease operating | 2.34 | 3.10 | (0.76) | (25%) | |||||||||||||||||||
| Production and ad valorem taxes | 0.52 | 0.19 | 0.33 | 173% | |||||||||||||||||||
| Depreciation, depletion and amortization | 8.32 | 8.44 | (0.12) | (1)% | |||||||||||||||||||
| General and administrative | 16.64 | 1.24 | 15.40 | 1244% | |||||||||||||||||||
| Total operating expenses | $ | 32.32 | $ | 18.64 | $ | 13.68 | 73% | ||||||||||||||||
Gathering, processing, and transportation.GP&T for the nine months ended September 30, 2025, increased $1.5 million compared to the nine months ended September 30, 2024. This increase was attributed to additional wells brought online in Ohio between periods. GP&T per Boe was $4.51 for the nine months ended September 30, 2025, which represents a decrease of $1.16 per Boe, or 20%, from the prior period. The decrease in per-unit GP&T rate was primarily attributable to increased production volumes in our natural gas-weighted areas of Pennsylvania, which are subject to lower GP&T rates on our internal gathering systems. This shift in volume mix reduced our overall average GP&T rate, as these areas incur fewer processing charges compared to our wet gas-weighted areas in Ohio, where the NGLs require additional processing.
Lease operating.LOE for the nine months ended September 30, 2025, decreased $0.3 million compared to the prior period. LOE per Boe was $2.34 for the nine months ended September 30, 2025, which represents a decrease of $0.76 per Boe, or 25%, from the prior period. This decrease in LOE was primarily related to a combination of (a) lower fixed and semi-variable well costs, such as water disposal, equipment rentals, repair work, wellhead chemicals, labor and electricity, associated with a higher well count from new producing wells drilled or acquired and (b) higher volumes driven by our Pennsylvania Marcellus development.
Production and ad valorem taxes.Production and ad valorem taxes for the nine months ended September 30, 2025, increased $3.2 million compared to the prior period. Production taxes in Ohio are based on our production at the wellhead,
while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. Production taxes in Pennsylvania are assessed on producing wells by imposing an impact fee determined based on the market price for natural gas, which commences on the date the well is initially spud and continues for a period of 15 years.
Depreciation, Depletion and Amortization.For the nine months ended September 30, 2025, DD&A expense was $72.5 million, an increase of $16.1 million over the prior period. The primary factor contributing to higher DD&A expense in 2025 was the increase in our overall production volumes between periods, which resulted in an average DD&A rate of $8.12 per Boe.
General and Administrative Expenses.G&A expenses for the nine months ended September 30, 2025 were $145.1 million compared to $8.3 million for the prior period. This increase was primarily due to expenses associated with being a public company and a one-time stock compensation expense of $126.1 million incurred in connection with the IPO. We also had higher payroll and employee-related costs due to higher headcount associated with the growth of the business.
Net Gain (Loss) on Derivative Instruments. The following table presents gains and losses on our derivative instruments for the periods indicated:
| Nine Months Ended September 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| (in thousands) | |||||||||||
| Realized cash settlement gains (losses) | $ | 5,567 | $ | 27,755 | |||||||
| Non-cash mark-to-market derivative gain (losses) | 24,586 | (21,358) | |||||||||
| Total | $ | 30,153 | $ | 6,397 | |||||||
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 the three and nine months ended September 30, 2025 were $95.0 million and $263.8 million, respectively. For the three months ended September 30, 2025, we incurred $83.2 million in development activities, including drilling and completion and midstream, and $11.8 million related to land activities. During the nine months ended September 30, 2025, we incurred $237.9 million in development activities and $25.9 million related to land activities. We funded our capital expenditures for the three and nine months ended September 30, 2025 from cash flows from operations and borrowings incurred under the Credit Facility, which we expect to continue for the remainder of 2025. Our ability to utilize cash flows from operations to fund our development program is driven by our oil and gas production, current commodity prices and our commodity hedge positions in place.
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. The net proceeds from the offering, along with cash from operations, were used to repay outstanding borrowings 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:
| Nine Months Ended September 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| (in thousands) | |||||||||||
| Net cash provided by operating activities | $ | 186,700 | $ | 147,566 | |||||||
| Net cash used in investing activities | (279,297) | (194,755) | |||||||||
| Net cash provided by financing activities | 94,966 | 47,250 | |||||||||
| Net increase in cash and cash equivalents | $ | 2,369 | $ | 61 | |||||||
Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2025 and 2024
Operating activities
For the nine months ended September 30, 2025, we generated $186.7 million of cash from operating activities, an increase of $39.1 million from the prior period. Cash provided by operating activities increased primarily due to higher production volumes and higher realized prices for natural gas and associated revenues as compared to the prior period. These factors were partially offset by higher operating expenses during the nine months ended September 30, 2025 as compared to the prior period. Refer to "Results of Operations" for more information on the impact of volumes and prices on revenues and on fluctuations in our operating costs between periods.
Investing activities
For the nine months ended September 30, 2025, we spent $269.1 million on capital expenditures in connection with our development activities. We also spent $10.2 million on other property and equipment largely related to midstream activities.
For the nine months ended September 30, 2024, we spent $189.6 million on capital expenditures in connection with our development activities. We also spent $5.2 million on other property and equipment.
Financing activities
For the nine months ended September 30, 2025, the change in financing activity was primarily related to the IPO which generated net proceeds of $286.5 million. We used funds from the IPO, along with cash from operating activities to pay down borrowings under the Credit Facility of $327.0 million since the beginning of the year and paid approximately
$6.8 million of other costs associated with the IPO. We have also made borrowings under the Credit Facility of $143.0 million during the period.
For the nine months ended September 30, 2024, the change in financing activity was primarily related to borrowing $366.9 million under our prior credit facility and repaying $313.1 million of borrowings.
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 Managementfor more information on our derivative activities.
Changes in the fair value of derivative contracts from December 31, 2024 to September 30, 2025, are presented below:
| (in thousands) | Commodity Derivative Asset | ||||
| Net fair value of oil and gas derivative contracts outstanding as of December 31, 2024 | $ | (22,938) | |||
|
Commodity hedge contract settlement payments, net of any receipts
|
(5,567) | ||||
| Cash and non-cash mark-to-market gains on commodity hedge contracts (1) | 30,153 | ||||
| Net fair value of oil and gas derivative contracts outstanding as of September 30, 2025 | $ | 1,648 | |||
_____________
(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 $325.0 million to $350.0 million. On May 29, 2025, the Company amended the Credit Agreement to, among other things, amend certain provisions relating to hedging requirements and restrictions in the Credit Agreement. As of September 30, 2025, the Company's reserves supported a $350.0 million borrowing base, of which $75.4 million was outstanding, leaving $274.6 million of unused capacity. Effective October 1, 2025, the borrowing base under the Credit Facility was increased from $350.0 million to $375.0 million and the aggregate elected commitment amount was also increased from $350.0 million to $375.0 million.
For the three months ended September 30, 2025 and 2024, total interest expense on the Credit Facility was $1.8 million and $6.7 million, respectively. We did not capitalize any interest expense for the three months ended September 30, 2025 and 2024. For the three months ended September 30, 2025 and 2024, the Company's weighted-average interest rate was 4.4% and 9.3%, respectively.
For the nine months ended September 30, 2025 and 2024, total interest expense on the Credit Facility was $5.3 million and $14.8 million, respectively. We did not capitalize any interest expense for the nine months ended September 30, 2025 and 2024. For the nine months ended September 30, 2025 and 2024, the Company's weighted-average interest rate was 4.2% and 9.1%, respectively.
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 inNote 2 - Summary of Significant Accounting Policiesto 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 Contingenciesto our unaudited condensed consolidated financial statements in this Quarterly Report.
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