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 2025 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, production and gathering of hydrocarbons in the Appalachian Basin. We are focused on creating shareholder value through the identification and disciplined development of low-risk, highly economic oil and natural gas assets while maintaining a strong and flexible balance sheet. Our operations are focused on the Utica Shale in eastern Ohio as well as our dry gas assets in both the Marcellus and Utica Shales in southwestern Pennsylvania, providing highly economic stacked development inventory that leverages shared infrastructure and operational efficiencies. Our portfolio is balanced across oil and natural gas assets, allowing us to optimize our development plan to respond to changes in commodity prices over time.
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.
Commodity prices were volatile in the first half of 2026, and we expect commodity prices to continue to be volatile for the remainder of 2026 due to macroeconomic uncertainty, changes to the regulatory environment and geopolitical instability and tensions, including in the Middle East, Russia and Ukraine, and potential further imposition of domestic and foreign tariffs. For example, since late February, there has been an ongoing military conflict involving the United States, Israel and Iran in the Middle East, causing geopolitical uncertainty in global energy markets. Concerns over disruptions to oil, natural gas and LNG production and shipping routes in the region have contributed to, and may continue to contribute to, market price volatility for an undeterminable period of time. Domestically, natural gas prices have been negatively impacted in recent months by a combination of mild weather and increased production. Our revenue, profitability, liquidity and financial position will continue to be impacted in the future by the market prices for oil, natural gas and NGLs.
The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2026 through June 30, 2026, monthly index prices for NYMEX WTI crude oil ranged from $60.04 per Bbl to $102.13 per Bbl, while the range for NYMEX Henry Hub natural gas monthly index prices were between $2.56 per MMBtu and $7.49 per MMBtu. We expect that the commodity market will continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. We use a derivative portfolio and firm sales contracts to mitigate the risks of price volatility.
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 2025:
2025 2026
1Q 2Q 3Q 4Q 1Q 2Q
Oil (per Bbl) (1) $ 71.84 $ 64.63 $ 65.74 $ 59.64 $ 71.98 $ 95.75
Gas (per MMBtu) (1) $ 3.65 $ 3.44 $ 3.07 $ 3.55 $ 5.05 $ 2.90
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(1)Benchmark prices presented above are calendar-quarter averages and may differ from production-weighted benchmark prices presented elsewhere in this Quarterly Report.
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.
Following the Antero Acquisition, the Company became party to substantial firm transportation commitments that increase exposure to transportation utilization and transportation optimization economics. As a result, gathering, processing and transportation expense and related transportation optimization revenues may be impacted by future utilization levels, contracted transportation capacity and optimization opportunities.
Recent Developments
Chase Acquisition
On January 20, 2026, the Company and INR Holdings entered into a purchase and sale agreement (the “Chase Purchase Agreement”) with Chase Oil Corporation, a New Mexico corporation, and certain other sellers (each a “Chase Seller” and, collectively, “Chase Sellers”) for the acquisition of certain non-operated rights, title and interests in oil and gas properties, rights and related assets located in the State of Pennsylvania from the Chase Sellers (the “Chase Acquisition”), for consideration of 2,517,194 shares of the Company’s Class A common stock. The Chase Acquisition closed on January 20, 2026, simultaneously with the execution of the Chase Purchase Agreement.
Preferred Stock Transaction
On February 23, 2026, we issued and sold an aggregate 350,000 shares of Series A Preferred Stock to affiliates of Quantum and Carnelian for consideration of $350 million in the Preferred Stock Transaction. After deducting placement agent fees, Infinity received net proceeds of approximately $334.0 million. Quantum acquired 275,000 shares of Series A Preferred Stock, and Carnelian acquired 75,000 shares of Series A Preferred Stock. The Company used the proceeds of the Preferred Stock Transaction to fund a portion of the purchase price for the Antero Acquisition and used the remaining proceeds for general corporate purposes.
On July 15, 2026, we paid a $7.1 million dividend on the Series A Preferred Stock.
Antero Acquisition
On February 23, 2026 the Company completed the Antero Acquisition of certain upstream oil and gas properties and related midstream assets in Ohio for a purchase price of $720.0 million for cash consideration of $683.9 million. The Antero Acquisition was financed with the proceeds of the issuance of Series A Preferred Stock and borrowings under the Credit Facility.
Notes Offering
On March 20, 2026, the Company completed the offering of the Notes. The proceeds from the issuance of the Notes were used to repay outstanding borrowings under our Credit Facility and for other general corporate purposes.
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:
Antero Acquisition. On February 23, 2026, the Company completed the Antero Acquisition. As a result, the Company’s results of operations for the three months ended March 31, 2026 include only a partial period of contribution from the acquired assets, whereas future periods will reflect a full‑period contribution. The Antero Acquisition significantly
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increased the Company’s production volumes, proved reserves, gathering and transportation capacity, and overall asset base, which materially impacts the comparability of revenues, operating expenses (including gathering, processing and transportation, lease operating expenses, production and ad valorem taxes, and depreciation, depletion and amortization), and cash flows between periods.
Full‑Period Versus Partial‑Period Effects. The Company’s results for the three and six months ended June 30, 2026 reflect the impact of assets placed into service or acquired at different points in time, including wells placed on production throughout 2025 and early 2026 and the partial‑period contribution from the Antero Acquisition. As a result, production volumes, revenues, and certain operating costs for the current period are not directly comparable to the prior‑year period, which did not include the acquired properties or a full period of production from certain development activity. Additionally, certain operating costs include a higher proportion of fixed or semi‑fixed components that do not scale linearly with production; therefore, per‑unit cost metrics may fluctuate between periods as production volumes increase.
Non-Cash Compensation Expense. In connection with the closing of the IPO in 2025, all outstanding incentive units of INR Holdings vested. Consequently, INR Holdings recognized $126.1 million of non-recurring, non-cash stock compensation expense related to these awards for the three months ended March 31, 2025, in accordance with the guidance provided by ASC 710.
Results of Operations
For the Three Months Ended June 30, 2026, Compared to the Three Months Ended June 30, 2025
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:
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For the Three Months Ended June 30, Increase / (Decrease)
2026 2025 $ %
Net revenues (in thousands):
Oil sales $96,599 $31,555 $65,044 206%
Natural gas sales $46,145 $30,483 $15,662 51%
Natural gas liquids sales $27,666 $10,433 $17,233 165%
Oil, natural gas, and natural gas liquids sales $170,410 $72,471 $97,939 135%
Midstream and other revenues $609 $2,005 ($1,396) (70)%
Total revenues $171,019 $74,476 $96,543 130%
Average sales prices:
Oil price (per Bbl) $85.41 $56.45 $28.96 51%
Effects of derivative settlements on average price (per Bbl) ($17.10) $8.55 ($25.65) (300)%
Oil price including the effects of derivatives (per Bbl) $68.31 $65.00 $3.31 5%
Wtd. Average NYMEX WTI price for oil (per Bbl) (2) $92.51 $64.47 $28.04 43%
Oil differential to NYMEX ($7.10) ($8.02) $0.92 11%
Natural gas price (per Mcf) $2.34 $2.67 ($0.33) (12)%
Effects of derivative settlements on average price (per Mcf) $0.74 ($0.14) $0.88 629%
Natural gas price including the effects of derivatives (per Mcf) $3.08 $2.53 $0.55 22%
Wtd. Average NYMEX Henry Hub price for natural gas (per MMBtu)(2) $2.89 $3.45 ($0.56) (16)%
Natural gas differential to NYMEX ($0.53) ($0.78) $0.25 32%
NGL price excluding Gathering, processing and transportation (per Bbl) $32.27 $18.93 $13.34 70%
Effects of derivative settlements on average price (per Bbl) ($1.99) ($0.71) ($1.28) (180)%
NGL price including the effects of derivatives (per Bbl) $30.28 $18.22 $12.06 66%
Net production
Oil (MBbls) 1,131 559 572 102%
Natural gas (MMcf) 19,725 11,420 8,305 73%
NGL (Bbls) 867 551 316 57%
Net production (MMcfe)(1) 31,713 18,080 13,633 75%
Average daily net production
Oil (Bbls/d) 12,429 6,143 6,286 102%
Natural gas (Mcf/d) 216,758 125,495 91,263 73%
NGLs (Bbls/d) 9,527 6,055 3,472 57%
Average daily net production (Mcfe/d)(1) 348,495 198,681 149,814 75%
_____________
(1)Calculated by converting oil, condensate and NGLs to natural gas equivalent at a ratio of one barrel of oil or NGL to six Mcf.
(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. Production-weighted average NYMEX benchmark prices are calculated using monthly benchmark prices weighted by the Company’s monthly production volumes during the applicable period.
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Revenues
Oil, Natural Gas and NGL Sales. Total oil, natural gas and NGL net revenues for the three months ended June 30, 2026 increased by $97.9 million, or 135%, compared to the three months ended June 30, 2025. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Net production volumes for oil increased 102%, natural gas volumes increased 73% and NGL volumes increased 57% between periods for the three months ended June 30, 2026 and 2025. The increase in oil volumes between periods was a result of placing 23 wells into service in Ohio between the third quarter of 2025 and second quarter of 2026. The increase in natural gas and NGL volumes was a result of a combination of placing 23 wells in Ohio and seven wells in Pennsylvania into service between the third quarter of 2025 and second quarter of 2026, and a full quarter of production from wells acquired in the Antero Acquisition. The wells in service contributed to the overall increase of 149.8 Mcfe/d, or 75%, in production relative to the prior period, offset by the natural decline of producing wells.
Average realized oil prices rose 51% driven by a higher NYMEX WTI oil price during the period. Natural gas prices decreased 12%, reflecting a 16% decrease in NYMEX gas prices. NGL prices increased 70% due to gas compositional changes alongside strengthened oil, as Middle East disruptions tightened global LPG balances.
Midstream and Other Revenue. Midstream and other revenue was approximately $0.6 million and $2.0 million for the three months ended June 30, 2026 and 2025, respectively. Such revenues primarily consist of gathering revenues earned from third-party and working interest owner volumes transported through the Company’s gathering systems, as well as transportation optimization revenues derived from asset management arrangements, capacity utilization fees, spread-share arrangements and transportation reimbursements associated with the Company’s firm transportation capacity.
Operating Expenses
For the Three Months Ended June 30, Change
2026 2025 Amount Percent
(in thousands)
Gathering, processing, and transportation $ 29,401 $ 14,515 $ 14,886 103%
Lease operating 10,028 5,583 4,445 80%
Production and ad valorem taxes 1,902 3,071 (1,169) (38)%
Midstream operations and maintenance expense 2,359 711 1,648 232%
Direct operating costs 43,690 23,880 19,810 83%
Depreciation, depletion and amortization 44,414 23,652 20,762 88%
General and administrative (including share-based compensation) 12,411 5,265 7,146 136%
Total operating expenses $ 100,515 $ 52,797 $ 47,718 90%
($ per Mcfe)
Gathering, processing, and transportation $ 0.93 $ 0.80 $ 0.13 17%
Lease operating 0.32 0.31 0.01 3%
Production and ad valorem taxes 0.06 0.17 (0.11) (65)%
Midstream operations and maintenance expense 0.07 0.04 0.03 64%
Direct operating costs 1.38 1.32 0.06
Depreciation, depletion and amortization 1.40 1.31 0.09 7%
General and administrative (including share-based compensation) 0.39 0.29 0.10 34%
Total operating expenses $ 3.17 $ 2.92 $ 0.25 9%
Gathering, Processing and Transportation Expense. Gathering, processing and transportation (“GP&T”) expense increased $14.9 million for the three months ended June 30, 2026, compared to the three months ended June 30, 2025. The
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increase was primarily attributable to higher production volumes, including volumes associated with the Antero Acquisition, the contribution from 23 wells brought online in Ohio between periods, increased gathering and processing rates under certain agreements, greater volumes transported through third-party midstream systems, and firm transportation commitments assumed in the Antero Acquisition. GP&T expense was $29.4 million, or $0.93 per Mcfe, for the three months ended June 30, 2026, compared to $14.5 million, or $0.80 per Mcfe, in the prior-year period. The increase in GP&T expense per Mcfe was primarily driven by approximately $7.5 million of firm transportation expense associated with the assumed firm transportation commitments. Excluding these firm transportation costs, GP&T expense was $21.9 million, or $0.69 per Mcfe, compared to $14.5 million, or $0.80 per Mcfe, in the prior-year period. The decrease in GP&T expense per Mcfe, excluding firm transportation costs, was primarily attributable to higher volumes from the acquired assets and increased production from the Company’s Pennsylvania natural gas assets, both of which benefit from transportation through Company-owned midstream assets, and a larger production base over which gathering and transportation costs are spread.
Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended June 30, 2026, increased $4.4 million compared to the prior period. LOE per Mcfe was $0.32 for the three months ended June 30, 2026, which represents an increase of $0.01 per Mcfe, or 3%, from the prior period. This increase in LOE was primarily related to 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 June 30, 2026, decreased $(1.2) 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.
Midstream Operations and Maintenance Expense. Midstream operations and maintenance expense increased $1.6 million to $2.4 million for the three months ended June 30, 2026, primarily reflecting the addition of acquired midstream assets in connection with the Antero Acquisition and higher throughput volumes during the period. On a per‑unit basis, midstream operating expenses remained generally consistent with the prior‑year period, as increased operating activity and integration‑related costs were largely offset by higher volumes and improved utilization of the acquired midstream assets.
Depreciation, Depletion and Amortization. For the three months ended June 30, 2026, depreciation, depletion and amortization (“DD&A”) expense was $44.4 million, an increase of $20.8 million over the prior period. The primary factor contributing to higher DD&A expense during the period was the increase in our overall production volumes between periods resulting in an average DD&A rate of $1.40 per Mcfe.
General and Administrative Expenses. General and administrative (“G&A”) expenses for the three months ended June 30, 2026 were $12.4 million compared to $5.3 million for the prior period. This increase was primarily related to expenses associated with the integration of the Antero Acquisition, an increase in headcount and $3.0 million of non-cash compensation expense.
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 June 30,
2026 2025
(in thousands)
Realized cash settlement gains (losses) $ (6,427) $ 2,777
Non-cash mark-to-market derivative gain (losses) 63,969 49,343
Total $ 57,542 $ 52,120
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For the Six Months Ended June 30, 2026, Compared to the Six Months Ended June 30, 2025
Summary Results of Operations
Total revenues for the six months ended June 30, 2026 increased $166.3 million, or 104%, compared to the six months ended June 30, 2025, primarily driven by higher production volumes resulting from development activity and contribution of assets acquired in the Antero Acquisition, as well as higher realized natural gas and oil prices. Net production increased 81% period over period, reflecting production from assets acquired in the Antero Acquisition and production from wells placed on production throughout 2025 and early 2026.
Total operating expenses for the six months ended June 30, 2026 decreased $35.9 million, or 16%, compared to the prior‑year period, primarily due to the absence of $126.1 million of non‑recurring, non‑cash stock‑based compensation expense recognized in connection with the Company’s IPO in the prior‑year period. Excluding this item, operating expenses increased due to higher production volumes, the contribution of assets acquired in the Antero Acquisition, and increased development and operating activity.
On a per‑unit basis, direct operating expenses for six months ended June 30, 2026 declined $0.05 per Mcfe to $1.30 per Mcfe, or 4%, compared to the prior-year period, reflecting improved cost absorption and scale benefits associated with higher production volumes.
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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 Six Months Ended June 30, Increase / (Decrease)
2026 2025 $ %
Net revenues (in thousands):
Oil sales $153,422 $78,601 $74,821 95%
Natural gas sales $120,670 $53,332 $67,338 126%
Natural gas liquids sales $47,022 $24,722 $22,300 90%
Oil, natural gas, and natural gas liquids sales $321,114 $156,655 $164,459 105%
Midstream and other revenues $4,777 $2,986 $1,791 60%
Total revenues $325,891 $159,641 $166,250 104%
Average sales prices:
Oil price (per Bbl) $76.86 $60.42 $16.44 27%
Effects of derivative settlements on average price (per Bbl) ($12.88) $4.41 ($17.29) (392)%
Oil price including the effects of derivatives (per Bbl) $63.98 $64.83 ($0.85) (1%)
Wtd. Average NYMEX WTI price for oil (per Bbl)(2) $83.93 $68.74 $15.19 22%
Oil differential to NYMEX ($7.07) ($8.32) $1.25 15%
Natural gas price (per Mcf) $3.24 $2.97 $0.27 9%
Effects of derivative settlements on average price (per Mcf) $0.07 ($0.17) $0.24 141%
Natural gas price including the effects of derivatives (per Mcf) $3.31 $2.80 $0.51 18%
Wtd. Average NYMEX Henry Hub price for natural gas (per MMBtu)(2) $3.82 $3.52 $0.30 9%
Natural gas differential to NYMEX ($0.58) ($0.55) ($0.03) (5)%
NGL price excluding gathering, processing and transportation (per Bbl) $29.95 $22.25 $7.70 35%
Effects of derivative settlements on average price (per Bbl) ($0.78) ($0.29) ($0.49) (169%)
NGL price including the effects of derivatives (per Bbl) $29.17 $21.96 $7.21 33%
Net production
Oil (MBbls) 1,996 1,301 695 53%
Natural gas (MMcf) 37,256 17,939 19,317 108%
NGL (Bbls) 1,570 1,111 459 41%
Net production (MMcfe)(1) 58,652 32,411 26,241 81%
Average daily net production
Oil (Bbls/d) 11,028 7,188 3,840 53%
Natural gas (Mcf/d) 205,834 99,110 106,724 108%
NGLs (Bbls/d) 8,674 6,138 2,536 41%
Average daily net production (Mcfe/d)(1) 324,044 179,066 144,978 81%
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(1)Calculated by converting oil, condensate and NGLs to natural gas equivalent at a ratio of one barrel of oil or NGL to six Mcf.
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(2)Based on Netherland, Sewell and Associates Inc. found at https://netherlandsewell.com/resources/pricing-data/ and EIA commodity pricing. Production-weighted average NYMEX benchmark prices are calculated using monthly benchmark prices weighted by the Company’s monthly production volumes during the applicable period.
Revenues
Oil, Natural Gas and NGL Sales. Total oil, natural gas and NGL revenues for the six months ended June 30, 2026 increased $164.5 million, or 105%, compared to the six months ended June 30, 2025. The increase was primarily driven by higher production volumes, partially offset by the effects of commodity price volatility and derivative settlements.
Net production volumes increased 81% period over period, reflecting increased development activity and production from the 241 producing wells acquired in the Antero Acquisition. Oil production increased 53%, natural gas production increased 108%, and NGL production increased 41%, driven by wells placed on production across the Company’s oil‑weighted assets in the Ohio Utica Shale and natural gas‑weighted assets in the Marcellus Shale in Pennsylvania during the second quarter of 2025 through the first half of 2026, as well as the contribution of assets acquired in the Antero Acquisition.
Average realized natural gas prices increased 9% compared to the prior‑year period, primarily due to higher NYMEX Henry Hub pricing. Average realized oil prices increased 27%, reflecting higher NYMEX WTI prices, partially offset by derivative settlements. Average realized NGL prices increased 35% due to changes in product mix and pricing dynamics. The combined impact of increased production volumes and higher realized commodity prices resulted in the significant increase in revenues compared to the prior‑year period.
Midstream and Other Revenue. Midstream and other revenue was approximately $4.8 million and $3.0 million for the six months ended June 30, 2026 and 2025, respectively. Such revenues primarily consist of gathering revenues earned from third-party and working interest owner volumes transported through the Company’s gathering systems, as well as transportation optimization revenues derived from asset management arrangements, capacity utilization fees, spread-share arrangements and transportation reimbursements associated with the Company’s firm transportation capacity.
Operating Expenses
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For the Six Months Ended June 30, Change
2026 2025 Amount Percent
(in thousands)
Gathering, processing, and transportation $ 49,124 $ 26,585 $ 22,539 85%
Lease operating 18,944 12,354 6,590 53%
Production and ad valorem taxes 4,251 3,703 548 15%
Midstream operations and maintenance expense 3,837 1,374 2,463 179%
Direct operating costs 76,156 44,016 32,140 73%
Depreciation, depletion and amortization 80,074 44,910 35,164 78%
Total general and administrative (including share-based compensation) 33,824 137,015 (103,191) (75)%
Total operating expenses $ 190,054 $ 225,941 (35,887) (16)%
($ per Mcfe)
Gathering, processing, and transportation $ 0.84 $ 0.82 $ 0.02 2%
Lease operating 0.32 0.38 (0.06) (16%)
Production and ad valorem taxes 0.07 0.11 (0.04) (36)%
Midstream operations and maintenance expense 0.07 0.04 0.03 75%
Direct operating costs 1.30 1.35 (0.05) (4)%
Depreciation, depletion and amortization 1.37 1.36 0.01 —%
Total general and administrative (including share-based compensation) 0.58 4.23 (3.65) (86)%
Total operating expenses 3.24 6.97 (3.73) (54)%
Gathering, Processing, and Transportation Expense. GP&T expense increased $22.5 million to $49.1 million for the six months ended June 30, 2026, primarily due to higher production volumes and the contribution of acquired upstream assets from the Antero Acquisition. GP&T expense increased on a per unit basis to $0.84 per Mcfe from $0.82 per Mcfe in the prior‑year period. The firm transportation costs were approximately $9.1 million associated with the assumed firm transportation commitments. Excluding these firm transportation costs, GP&T expense was $40.0 million, or $0.68 per Mcfe representing a decrease of 17% when compared to the prior year period. The decrease in GP&T expense per Mcfe, excluding firm transportation costs, was primarily attributable to higher volumes from the acquired assets and increased production from the Company’s Pennsylvania natural gas assets, both of which benefit from transportation through Company-owned midstream assets, and a larger production base over which gathering and transportation costs are spread.
Lease Operating Expenses. LOE increased $6.6 million to $18.9 million for the six months ended June 30, 2026, driven primarily by higher production volumes, an increased well count from development activity, and the contribution of wells acquired in the Antero Acquisition. On a per‑unit basis, lease operating expense declined to $0.32 per Mcfe from $0.38 per Mcfe in the prior‑year period, reflecting improved cost efficiency and dilution of fixed and semi‑variable costs across higher production volumes, particularly in the Company’s Marcellus Shale assets.
Production and Ad Valorem Taxes. Production and ad valorem taxes increased $0.5 million to $4.3 million for the three months ended June 30, 2026, primarily due to higher production volumes and the addition of acquired properties.
Midstream Operations and Maintenance Expense. Midstream operations and maintenance expense increased $2.5 million to $3.8 million for the six months ended June 30, 2026, primarily reflecting the addition of acquired midstream assets in connection with the Antero Acquisition and higher throughput volumes during the period.
Depreciation, Depletion and Amortization. DD&A expense increased $35.2 million to $80.1 million for the six months ended June 30, 2026, primarily due to higher production volumes and the contribution of acquired assets from the Antero Acquisition. On a per‑unit basis, DD&A increased to $1.37 per Mcfe from $1.36 per Mcfe in the prior‑year period.
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General and Administrative Expenses. G&A expense decreased $103.2 million to $33.8 million for the six months ended June 30, 2026, compared to the prior‑year period. The decrease was primarily attributable to the absence of $126.1 million of non‑recurring, non‑cash stock‑based compensation expense related to the Company’s IPO recognized in the prior‑year period, partially offset by transaction costs associated with the Antero Acquisition of $15.2 million.
Net Gain (Loss) on Derivative Instruments. The following table presents gains and losses on our derivative instruments for the periods indicated:
Six Months Ended June 30,
2026 2025
(in thousands)
Realized cash settlement gains (losses) $ (24,419) $ (808)
Non-cash mark-to-market derivative gain (losses) 16,827 15,710
Total $ (7,592) $ 14,902
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 debt and equity securities. Going forward, we expect our primary sources of liquidity to be cash flows from operations, borrowings incurred under the Credit Facility, proceeds from offerings of debt or equity securities, such as the Preferred Stock Transaction and the Notes offering, or proceeds from the sale of oil and gas properties. Our future cash flows are subject to a number of variables, including oil and natural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary uses of capital have been for drilling and development capital expenditures and the acquisition of oil and natural gas properties.
We continually evaluate our capital needs and compare them to our capital resources. Our total capital expenditures incurred for the three and six months ended June 30, 2026 were $137.3 million and $259.9 million, respectively. For the three months ended June 30, 2026, we incurred $129.1 million in development activities, including drilling and completion and midstream, and $8.2 million related to land activities. During the six months ended June 30, 2026 , we incurred $240.6 million in development activities and $19.3 million related to land activities. We funded our capital expenditures for the three and six months ended June 30, 2026 from cash flows from operations and cash provided by financing activities (including the proceeds from the issuance of the Notes and the Series A Preferred Stock), which we expect to continue for the remainder of 2026. 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.
On March 20, 2026, the Company completed the offering of the Notes for total net proceeds of $537.6 million. The proceeds from the issuance of the Notes were used to repay outstanding borrowings under our Credit Facility and for other general corporate purposes.
On February 23, 2026, we closed the Antero Acquisition for consideration of approximately $683.9 million net to Infinity. We funded the transaction with cash on hand, the proceeds of the Preferred Stock Transaction and borrowings under our Credit Facility, the borrowing base and aggregate elected commitment amount of which increased from $375.0 million to $875.0 million in connection with closing.
In connection with the closing of the Antero Acquisition, we also completed the Preferred Stock Transaction, which generated gross proceeds of $350 million and net proceeds of $334.0 million after deducting placement agent fees and offering expenses. The Series A Preferred Stock provides long-term capital with no stated maturity and accrues cumulative dividends in accordance with its terms. The Company elected a PIK dividend for the quarter ended March 31, 2026, which
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increased the liquidation preference of the Series A Preferred Stock. The dividend declared for the quarter ended June 30, 2026 was paid in cash, resulting in a cash payment of approximately $7.1 million on July 15, 2026. We believe the Preferred Stock Transaction enhances our overall liquidity and financial flexibility while supporting the execution of our development and acquisition strategy.
Our liquidity requirements also include operating expenses, which have been impacted by elevated levels of inflation. High oil prices have historically led to more development activity in oil-focused shale basins and resulted in service cost inflation across all U.S. shale basins, including our areas of operation. Ongoing inflationary pressures may result in increases to the costs of our oilfield goods, services and personnel, which would, in turn, cause our capital expenditures and operating costs to rise. We closely monitor costs and are cost conscious in managing our operations. We may solicit bids from multiple vendors or contractors or source materials from multiple suppliers to take advantage of cost competition, and we may buy surplus materials if we can acquire them on attractive terms. Where we anticipate elevated costs may be more sustained, such as in the cost of services, we may enter into contracts with certain service providers to lock in rates. We are also strategic in the duration of our contracts to provide flexibility to take advantage of cost declines when they occur.
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:
Six Months Ended June 30,
2026 2025
(in thousands)
Net cash provided by operating activities $ 196,277 $ 144,631
Net cash used in investing activities (877,609) (194,546)
Net cash provided by financing activities 704,366 53,994
Net increase in cash and cash equivalents $ 23,034 $ 4,079
Analysis of Cash Flow Changes Between the Six Months Ended June 30, 2026 and 2025
Operating Activities
For the six months ended June 30, 2026, we generated $196.3 million of cash from operating activities, an increase of $51.6 million from the prior period. Cash provided by operating activities increased compared to the prior-year period primarily due to increased revenue generated from our development activities, more favorable pricing conditions, and benefits associated with the Antero Acquisition. 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.
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Investing Activities
For the six months ended June 30, 2026, we spent $241.1 million on capital expenditures in connection with our development activities. We also spent $13.8 million on other property and equipment largely related to midstream activities. In connection with the Antero Acquisition, we spent $622.7 million on certain upstream oil and gas properties and related midstream assets.
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.
Financing Activities
For the six months ended June 30, 2026, the change in financing activity was primarily related to proceeds received from the issuance of the Notes and Series A Preferred Stock of $550.0 million and $350.0 million, respectively. We incurred issuance-related costs of $25.3 million. We made borrowings under the Credit Facility of $430.5 million during the period. We used funds from the financing activities, along with cash from operating activities to pay down borrowings under the Credit Facility of $581.4 million since the beginning of the year.
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 during the period. We 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.
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 pay the floating market price differential to the counterparty which is calculated based on the differential between NYMEX and the natural gas price at a specific delivery point.
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 8 – Derivatives and Risk Management to this Quarterly Report for more information on our derivative activities.
Changes in the fair value of derivative contracts from December 31, 2025 to June 30, 2026, are presented below:
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(in thousands) Commodity Derivative Asset
Net fair value of oil and gas derivative contracts outstanding as of December 31, 2025 $ 23,256
Commodity hedge contract settlement payments, net of any receipts 24,418
Cash and non-cash mark-to-market losses on commodity hedge contracts (1) (7,592)
Net fair value of oil and gas derivative contracts outstanding as of June 30, 2026 $ 40,082
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(1)At inception, new derivative contracts entered into by us have no intrinsic value.
Financing Agreements
Senior Notes
On March 20, 2026, INR Holdings issued $550.0 million aggregate principal amount of the Notes at par. The Notes were issued pursuant to the Indenture and bear interest at a fixed rate of 7.625% per annum, payable semi-annually in arrears on April 1 and October 1 of each year, commencing on October 1, 2026. The Notes will mature on April 1, 2031, unless earlier redeemed or repurchased.
The Notes are the general unsecured, senior obligations of INR Holdings. The Notes are guaranteed on a senior unsecured basis by the Guarantors and may be guaranteed by certain future subsidiaries of INR Holdings. The Notes and the related guarantees rank equally in right of payment with the borrowings under our Credit Facility and any of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The Notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our Credit Facility) to the extent of the value of the collateral securing such indebtedness and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the Notes.
INR Holdings may, at its option, redeem all or a portion of the Notes at any time on or after April 1, 2028 at certain redemption prices. At any time prior to April 1, 2028, INR Holdings may redeem up to 40% of the aggregate principal amount of the Notes, with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 107.625% of the aggregate principal amount of the Notes redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. In addition, at any time prior to April 1, 2028, INR Holdings may, on any one or more occasions, redeem all or a part of the Notes at a redemption price equal to 100.00% of the principal amount of the Notes redeemed, plus a “make whole” premium and accrued and unpaid interest, if any, to, but excluding, the date of redemption.
If INR Holdings experiences certain kinds of changes of control, each holder of the Notes may require INR Holdings to repurchase all or a portion of its Notes for cash at a price equal to 101% of the aggregate principal amount of such Notes, plus accrued and unpaid interest, if any, to the date of repurchase.
The Indenture contains covenants that, among other things and subject to certain exceptions and qualifications, limit the ability of INR Holdings and its restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from its restricted subsidiaries to INR Holdings or any of their restricted subsidiaries; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
Credit Facility
On September 25, 2024, INR Holdings entered into the Credit Facility. The Credit Facility has a total facility size of $1.5 billion, subject to lender commitments and borrowing base limitations. On February 23, 2026, in connection with the closing of the Antero Acquisition, we amended our Credit Facility to, among other things, increase the aggregate elected commitment amount from $375.0 million to $875.0 million and increase the borrowing base from $375.0 million to $875.0 million. As of June 30, 2026, our elected commitments and borrowing base were $875.0 million. There were no borrowings outstanding under the Credit Facility and no letters of credit issued, resulting in approximately $875.0 million of available borrowing capacity.
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The Credit Facility also requires INR Holdings to maintain compliance as of the end of each fiscal quarter with financial covenants consisting of a current ratio of not less than 1.0 to 1.0 and a leverage ratio no greater than 3.0 to 1.0, each of which is defined within the terms of the Credit Agreement. We were in compliance with the covenants and financial ratios under the Credit Facility described above through the date these unaudited condensed consolidated financial statements were available to be issued.
For the three months ended June 30, 2026 and 2025, total interest expense on the Credit Facility was $0.9 million for both periods. For the six months ended June 30, 2026 and 2025, total interest expense on the Credit Facility was $5.3 million and $3.5 million, respectively. We capitalized interest expense of $0.1 million and $0.2 million for the three and six months ended June 30, 2026 and did not capitalize any interest expense for the three and six months ended June 30, 2025. For the six months ended June 30, 2026 and 2025, the Company’s weighted-average interest rate was 6.8% and 4.2%, respectively.
Critical Accounting Estimates
Our unaudited condensed consolidated financial statements are prepared in accordance with 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 unaudited condensed 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 2025 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 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, 2025, there have not been any significant, non-routine changes in our contractual obligations other than: the Notes entered into in March of 2026 and due in 2031 as discussed in Note 7 – Long-Term Debt to this Quarterly Report, drilling rig contracts and the firm transportation agreement entered into as discussed in Note 16 – Commitments and Contingencies to this Quarterly Report.
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