Item 5. Market for Registrant’s Common Equity
ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
On
January 31, 2025, our Class A common stock began trading on the NYSE under the symbol INR. Prior to that time, there was no public market for our Class A common stock. There is no public trading market for our Class B
common stock.
Holders of Common Stock
As of March 21, 2025, there was one shareholder of record of our Class A common stock and 15 holders of record of our Class B
common stock.
Dividend Policy
We
currently intend to retain all available funds and any future earnings to fund the development and growth of our business, and therefore we do not anticipate declaring or paying any cash dividends on our Class A common stock in the foreseeable
future. Except in certain limited circumstances, holders of our Class B common stock are not entitled to participate in any dividends declared by our board of directors. Furthermore, because we are a holding company, our ability to pay cash
dividends on our Class A common stock depends on our receipt of cash distributions from INR Holdings. Any distributions by INR Holdings will be made to the INR Unit Holders and us on a pro rata basis in accordance with our respective percentage
ownership of INR Units. Our Credit Facility contains certain covenants that restrict, subject to certain exceptions, our ability to pay dividends. Any future determination as to the declaration and payment of dividends, if any, will be at the
discretion of our board of directors and subject to the requirements of applicable law, compliance with contractual restrictions and covenants in the agreements governing our future indebtedness. Any such determination will also depend upon our
business prospects, results of operations, financial condition, cash requirements and availability and other factors that our board of directors may deem relevant.
Securities Authorized for Issuance Under Equity Compensation Plans
Information about securities authorized for issuance under our equity compensation plans is incorporated herein by reference to Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters of Part III of this Annual Report.
Recent Sales
of Unregistered Securities
On January 30, 2025, in connection with the recapitalization of INR Holdings, we issued an aggregate
of 45,638,889 shares of Class B common stock to the Legacy Owners in exchange for the cancellation of their existing equity interests. No underwriters were involved in the foregoing issuances of securities. Such issuance was undertaken in
reliance on an exemption from the registration requirements of the Securities Act pursuant to Section 4(a)(2) thereof as sales by an issuer not involving any public offering. The Companys reliance upon Section 4(a)(2) of the
Securities Act was based upon the following factors: (a) the issuance of the shares was an isolated private transaction by us which did not involve a public offering and (b) there was a limited number of recipients.
Use of Proceeds
On February 3,
2025, we completed the IPO of 13,250,000 shares of Class A common stock at a price to the public of $20.00 per share, less underwriting discounts and commission. On February 6, 2025, the underwriters fully exercised their option to
purchase an additional 1,987,500 shares of Class A common stock at the public offering price of $20.00 per share, less underwriting discounts and commissions. The IPO, including the full exercise of the underwriters overallotment option,
generated gross proceeds of approximately $304.8 million, which resulted in net proceeds to us of approximately $286.5 million, after deducting underwriting discounts and commissions of approximately $18.3 million. All shares issued
and sold were registered pursuant to a registration statement on Form S-1 (File No. 333-282502), as amended (the Registration Statement), declared
effective by the SEC on January 30, 2025. Citigroup Global Markets Inc., Raymond James & Associates, Inc. and RBC Capital Markets, LLC acted as representatives of the underwriters for the IPO. The IPO commenced January 21, 2025
and terminated after the sale of all securities registered pursuant to the Registration Statement. No offering expenses were paid or are payable, directly or indirectly, to (i) any of our officers or directors or their associates, (ii) any
persons owning 10% or more of any class of our equity securities or (iii) any of our affiliates.
We contributed all of the net
proceeds from the IPO to INR Holdings. In turn, INR Holdings used all of the net proceeds (net of underwriting discounts) from the IPO after paying certain offering expenses to repay $285.0 million of outstanding borrowings under the Credit
Facility. There has been no material change in the expected use of the net proceeds from the IPO as described under the heading Use of Proceeds in our final prospectus filed with the SEC on February 3, 2025 pursuant to Rule
424(b)(4) relating to the Registration Statement.
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Stock Repurchases
We did not repurchase any equity securities registered under Section 12 of the Exchange Act during the three months ended
December 31, 2024.
ITEM 6. [RESERVED]
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following should be read in conjunction with our financial statements and related notes in Item 8. Financial Statements and
Supplementary Data in this Annual Report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon
events, risks, and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not
limited to, future market prices for oil, natural gas and NGLs, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, inflation, regulatory changes, and other uncertainties, as well as
those factors discussed in Cautionary Statement Regarding Forward-Looking Statements and Item 1A. Risk Factors in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and
assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. Unless otherwise indicated, the historical
financial information presented in Managements Discussion and Analysis of Financial Condition and Results of Operations speaks only with respect to our predecessor, INR Holdings, and does not give pro forma effect to our corporate
reorganization described in Item 1. BusinessCorporate Reorganization.
Overview
We are a growth oriented independent energy company focused on the acquisition, development, and production of hydrocarbons in the Appalachian
Basin. We are focused on creating shareholder value through the identification and disciplined development of low-risk, highly economic oil and natural gas assets while maintaining a strong and flexible
balance sheet. We are an early mover into the core of the Utica Shales volatile oil window in eastern Ohio as well as the emerging dry gas Utica Shale in southwestern Pennsylvania. Our Marcellus Shale development overlays our deep dry gas
Utica assets in Pennsylvania, providing highly economic stacked development inventory that leverages the same company-owned midstream infrastructure. We have amassed approximately 93,000 net surface acres with exposure to the core of these plays
providing us a unique and balanced portfolio of high-return oil and natural gas drilling locations. This balance allows us to optimize our development plan across our portfolio to capitalize on changes in commodity pricing over time.
Market Conditions and Operational Trends
Our revenue, profitability, and ability to return cash to our equity holders can depend on factors beyond our control, such as economic,
political, and regulatory developments that impact market supply and demand. Prices for crude oil, natural gas and NGLs have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future.
The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2023 through
December 31, 2024, spot prices for NYMEX WTI crude oil ranged from $69.99 per Bbl to $89.43 per Bbl, while the range for NYMEX Henry Hub natural gas spot prices was between $1.57 per MMBtu and $4.75 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.
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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 2023:
2023
2024
Q1
Q2
Q3
Q4
YE
Q1
Q2
Q3
Q4
YE
Oil (per Bbl)
$
76.08
$
73.76
$
82.29
$
78.41
$
77.64
$
77.56
$
81.72
$
76.24
$
70.73
$
76.56
Gas (per MMBtu)
$
3.44
$
2.09
$
2.54
$
2.88
$
2.74
$
2.25
$
1.89
$
2.15
$
2.79
$
2.77
Lower commodity prices and lower futures curves for oil and natural gas prices may result in impairments of
our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our operating cash flows, liquidity, financial condition, results of operations, future business and operations, and/or our ability to finance
planned capital expenditures, which could in turn impact our ability to comply with covenants under our Credit Agreement. Lower realized prices may also reduce the borrowing base under our Credit Agreement, which is determined at the discretion of
the lenders and is based on the collateral value of our proved reserves that has been mortgaged to the lenders. Upon a redetermination, if any borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately
repay a portion of the debt outstanding under the Credit Agreement.
Recent Developments
Initial Public Offering
In
February 2025, Infinity completed its IPO of 15,237,500 shares of its Class A common stock (including 1,987,500 shares pursuant to an over-allotment option) at a price to the public of $20.00 per share. The aggregate gross proceeds of the IPO
were $304.8 million. After subtracting underwriting discounts and commissions, we received net proceeds of $286.5 million. We contributed all of the net proceeds from the IPO to INR Holdings in exchange for 15,237,500 INR Units. In turn,
INR Holdings used all of the net proceeds from the IPO (net of underwriting discounts) after paying certain offering expenses to repay $285.0 million of outstanding borrowings under the Credit Facility. After giving effect to the IPO and the
transactions related thereto, we had 15,237,500 shares of Class A common stock and 45,638,889 shares of Class B common stock issued and outstanding. In connection with the closing of the IPO, all outstanding performance-based incentive
units of INR Holdings vested. Consequently, INR Holdings will recognize $126.1 million of non-recurring, non-cash compensation expense related to these awards in
the first quarter of 2025, in accordance with the guidance provided by ASC 710.
Corporate Reorganization
In connection with the IPO we underwent a Corporate Reorganization whereby: (a) the membership interests of the Legacy Owners in INR
Holdings (including the Incentive Units, as defined in Item 11. Executive CompensationNarrative Disclosure to Summary Compensation TableLong-Term Equity Incentive Compensation) were recapitalized into a single class of units
(the INR Units), and, in exchange for their existing membership interests, the Legacy Owners received INR Units and an equal number of shares of Class B common stock; and (b) we contributed the net proceeds of the IPO to INR
Holdings in exchange for newly issued INR Units and a managing member interest in INR Holdings. After giving effect to the Corporate Reorganization and the IPO, we own an approximate 25.0% interest in INR Holdings and the Legacy Owners own an
approximate 75.0% interest in INR Holdings.
Infinity is a holding company whose sole material asset consists of membership interests in
INR Holdings. Infinity is the managing member of INR Holdings and controls and is responsible for all operational, management and administrative decisions relating to INR Holdings business and consolidates the financial results of INR Holdings
and reports non-controlling interests in its consolidated financial statements related to the INR Units that the Legacy Owners own in INR Holdings. In connection with the Corporate Reorganization, INR Holdings
and Infinity entered into the INR Holdings LLC Agreement and a Tax Receivable Agreement. For additional information on the INR Holdings LLC Agreement and Tax Receivable Agreement, see Item 13. Certain Relationships and Related Transactions,
and Director Independence.
Muskingum Watershed Lease
In December 2024, we closed on a lease with Muskingum Watershed Conservancy District for approximately 1,900 acres in Guernsey and Noble
Counties, Ohio.
Sources of Revenues
We derive our revenues predominantly from the sale of our oil and natural gas production and the sale of NGLs that are extracted from our
natural gas during processing. Our production is entirely from within the continental United States and is similarly sold to purchasers within the United States; however, some of our production revenues are attributable to customers who may export
our products.
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Increases or decreases in our revenue, profitability and future production growth are highly
dependent on the commodity prices we receive. Oil, natural gas, and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate. During 2024 and 2023, our oil, natural gas, and NGL
revenues were comprised of 63% and 53%, respectively, from the sale of oil, 20% and 31%, respectively, from the sale of natural gas, and 17% and 15%, respectively, from the sale of NGLs.
We utilize unaffiliated third parties to market a portion of our oil, natural gas, and NGL production to various purchasers, which consist of
credit-worthy counterparties, including utilities, LNG producers, industrial consumers, major corporations and super majors in our industry. The third parties collect proceeds directly from these purchasers and remit to us the total of all amounts
collected on our behalf less the third partys fee for making such sales. We do not believe the loss of any purchaser would have a material adverse effect on our business, as other purchasers or markets are currently accessible to us.
Midstream activities revenues, which consist of gathering, compression, and water handling, are derived from our ownership of INR Midstream.
Our gathering and compression revenues relate to activities located within the dry gas areas of southwestern Pennsylvania. Our water handling revenues relate to activities associated with delivering water for stimulation activities in both eastern
Ohio and southwestern Pennsylvania.
Principal Components of Our Cost Structure
Lease operating . LOE are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water
disposal, materials, and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor, materials, and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on
activities performed during a specific period. For instance, repairs to our well equipment or surface facilities result in increased LOE in periods during which they are performed. Certain operating cost components are variable and fluctuate based
on production levels. For example, the disposal of produced water usually increases in conjunction with increased production. Also, we monitor our LOE in absolute dollar terms and on a per Boe and/or Mcfe basis to assess our performance and to
determine if any wells or properties should be shut in, repaired or recompleted.
Gathering, processing, and transportation .
Gathering, processing, and transportation expense includes fees paid to third parties who operate low- and high-pressure gathering systems that transport our gas. It also includes costs to process, extract,
and fractionate NGLs from our liquids-rich gas and transport our natural gas and NGLs to market.
Production and ad valorem
taxes . Pennsylvania imposes an annual impact fee on each producing shale well for a period of 15 years beginning in the year the well is spud. Ohio imposes a production tax which is based upon annual production. The proportion of our
production and producing wells from each state may change over time and, as a result, the proportion of our production taxes and impact fees will vary depending on volumes produced from the Utica Shale, the number of producing shale wells in
Pennsylvania, and the applicable production tax rates and impact fees then in effect. In addition, we are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our
oil and gas properties as well as the value of property and equipment.
Depreciation, depletion, and amortization .
Depreciation, depletion, and amortization includes the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas. Under the full- cost method of accounting, we capitalize costs within a cost center and then
systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on all capitalized costs, other than the cost of investments in unproved properties and major
development projects for which proved reserves cannot yet be assigned, less accumulated amortization. Accretion expense related to our asset retirement obligations is also included within this balance.
General and administrative . General and administrative (G&A) expenses are costs incurred for overhead, including
payroll and benefits for our corporate staff, costs of maintaining our headquarters, IT expenses, legal, audit and other fees for professional services. G&A expenses are offset by recoveries for overhead that are billed to our joint-interest
partners as outlined in a joint operating agreement or other similar documents.
Interest expense . We have financed a
portion of our working capital requirements and property acquisitions with borrowings under our prior credit facility and Credit Facility. As a result, we incur interest expense that is affected by fluctuations in interest rates and, in the case of
the prior credit facility and Credit Facility based on outstanding borrowings. We expect to see a reduction in cash interest expense following the completion of the IPO in February 2025 as we repaid substantially all of our outstanding borrowings
under the Credit Facility with the net proceeds of the IPO.
Gains and losses on derivatives . We utilize commodity
derivative contracts to reduce our exposure to fluctuations in the price of oil, natural gas, and NGLs. We recognize gains and losses associated with our open commodity derivative contracts as commodity
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prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes.
Consequently, these commodity derivative contracts are recorded at fair value as of the balance sheet date with changes in fair value recognized as a gain or loss in our results of operations. Our operating cash flows are impacted to the extent the
actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.
Factors That Significantly Affect
Comparability of Our Financial Condition and Results of Operations
Our historical financial condition and results of operations for
the periods presented may not be comparable, either from period to period or going forward, for the following reasons:
Public
Company Expenses . We expect to incur direct, incremental G&A expenses as a result of being a public company, including costs associated with Exchange Act compliance, tax compliance, PCAOB support fees, SOX compliance costs, investor
relations activities, listing fees, registrar and transfer agent fees, stock-based compensation, incremental director and officer liability insurance costs, and independent director compensation. We estimate these direct, incremental G&A
expenses could total approximately $4 million to $6 million per year, which are not included in our historical results of operations.
Corporate Reorganization . The historical consolidated financial statements included in this Annual Report are based on the
financial statements of our predecessor, INR Holdings, prior to our reorganization in connection with the IPO as described in Item 1. BusinessCorporate Reorganization. Our historical financial data may not yield an accurate
indication of what our actual results would have been if those transactions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. In connection with the closing of the IPO, all
outstanding performance-based incentive units of INR Holdings vested. Consequently, INR Holdings will recognize $126.1 million of non-recurring, non-cash
compensation expense related to these awards in the first quarter of 2025, in accordance with the guidance provided by ASC 710.
Interest Expense . In connection with the IPO, we materially reduced our indebtedness through the repayment of substantially all
of our outstanding borrowings under the Credit Facility with net proceeds of the IPO. As a result, we expect an immediate reduction in cash interest expense.
Income Taxes . Our predecessor, INR Holdings, was organized as a limited liability company not subject to federal income taxes.
Accordingly, no provision for federal income taxes has been provided for in our historical results of operations because taxable income was passed through to our members. Although we are a corporation under the Internal Revenue Code of 1986, as
amended (the Code), we do not expect to report any income tax benefit or expense prior to the consummation of the IPO.
Results of
Operations
For the Year Ended December 31, 2024 Compared to the Year Ended December 31, 2023
The following table provides the components of our net revenues and net production for the periods indicated, as well as each periods
average prices (before and after the effects of derivatives) and average daily production volumes:
For the Year Months
Ended
December 31,
Increase / (Decrease)
2024
2023 (1)
$
%
Net revenues ( in thousands ):
Oil sales
$
161,514
$
85,276
$
76,238
89
%
Natural gas sales
51,157
49,617
1,540
3
%
Natural gas liquids sales
45,035
24,639
20,396
83
%
Oil, natural gas, and natural gas liquids sales
$
257,706
$
159,532
$
98,174
62
%
Average sales prices:
Oil price (per Bbl)
$
67.86
$
70.77
$
(2.91
)
(4)
%
Effects of derivative settlements on average price (per Bbl)
$
(0.93
)
$
0.26
$
(1.19
)
(458)
%
Oil price including the effects of derivatives (per Bbl)
$
66.93
$
71.03
$
(4.10
)
(6)
%
Wtd. Average NYMEX WTI price for oil (per
Bbl) (3)
$
76.42
$
78.12
$
(1.70
)
(2)
%
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Oil differential to NYMEX
$
(8.56
)
$
(7.35
)
$
(1.21
)
(17
)%
Natural gas price (per Mcf)
$
1.81
$
1.80
$
0.01
1
%
Effects of derivative settlements on average price (per Mcf)
$
0.66
$
0.62
$
0.04
7
%
Natural gas price including the effects of derivatives (per Mcf)
$
2.47
$
2.42
$
0.05
2
%
Wtd. Average NYMEX Henry Hub price for natural gas (per MMBtu) (3)
$
2.27
$
2.79
$
(0.52
)
(19
)%
Natural gas differential to NYMEX
$
(0.46
)
$
(0.99
)
$
0.53
54
%
NGL price excluding GP&T (per Bbl)
$
26.14
$
22.16
$
3.98
18
%
Effects of derivative settlements on average price (per Bbl)
$
2.52
$
1.84
$
0.68
37
%
NGL price including the effects of derivatives (per Bbl)
$
28.66
24.00
$
4.66
19
%
Net production (1)
Oil (MBbls)
2,380
1,205
1,175
98
%
Natural gas (MMcf)
28,291
27,506
785
3
%
NGL (Bbls)
1,723
1,112
611
55
%
Net production (MBoe) (2)
8,818
6,901
1,917
28
%
Average daily net production (1)
Oil (Bbls/d)
6,502
3,301
3,201
97
%
Natural gas (Mcf/d)
77,297
75,359
1,938
3
%
NGLs (Bbls/d)
4,708
3,047
1,661
55
%
Average daily net production
(Boe/d) (2)
24,093
18,907
5,186
27
%
(1)
Includes the results of operations related to the assets acquired from Utica Resources Ventures and PEO Ohio on
October 1, 2023 for the fourth quarter of 2023 and thereafter.
(2)
Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
(3)
Based on Netherland, Sewell and Associates Inc. (NSAI) found at
https://netherlandsewell.com/resources/pricing-data/ and EIA commodity pricing. (NSAI) found at https://netherlandsewell.com/resources/pricing-data/ and U.S. Energy Information Administration (EIA). Weighted
average is based on INRs 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 year ended December 31, 2024 increased by
$98.2 million, or 62%, compared to the year ended December 31, 2023. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Net production volumes for oil, natural gas, and NGLs increased 98%, 3% and 55%, respectively, between periods. The oil and NGL production
volume increase resulted from placing fourteen (14) wells on production from the Ohio Uticas Volatile Oil Window since December 31, 2023. The higher increase in natural gas volumes between periods was due to the fourteen
(14) wells that were placed on production during the year 2024, offset from the normal production decline across existing wells. The combination of a full year of production from the wells acquired from Utica Resource Ventures and PEO Ohio and
wells placed into production throughout 2024 contributed to the overall increase of 1.9 MMBoe in production, or of 28% relative to the prior year.
Average realized sales prices for NGLs increased 18% during the period while average realized oil and natural gas sales prices decreased 4%
and 2%, respectively, for the year ended December 31, 2024 compared to the prior year. Average realized natural gas prices remained consistent when compared to the same period a year earlier. The 4% decrease in the average realized oil price
was mainly driven by lower NYMEX WTI oil prices during the period along with higher regional differentials compared to the same period a year earlier. The average realized natural gas price decreased 2% due to 19% lower average NYMEX gas prices
between periods offset by lower natural gas differentials. The 18% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in 2024 compared to 2023 and changes in
product composition between periods.
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Operating Expenses
For the Year Ended December 31,
Change
2024
2023
Amount
Percent
(in thousands)
Gathering, processing, and transportation
$
49,290
$
31,097
$
18,193
59
%
Lease operating
28,154
18,371
9,783
53
%
Production and ad valorem taxes
1,071
886
185
21
%
Depreciation, depletion and amortization
73,726
53,796
19,930
37
%
General and administrative
13,045
4,885
8,160
167
%
Total operating expenses
$
165,286
$
109,035
$
56,251
52
%
($ per Boe)
Gathering, processing, and transportation
$
5.59
$
4.51
$
1.08
24
%
Lease operating
3.19
2.66
0.53
20
%
Production and ad valorem taxes
0.12
0.13
(0.01
)
(8
)%
Depreciation, depletion and amortization
8.36
7.80
0.57
7
%
General and administrative
1.48
0.71
0.77
108
%
Total operating expenses
$
18.74
$
15.80
$
2.94
19
%
Gathering, processing, and transportation. Gathering, processing, and transportation
(GP&T) for the year ended December 31, 2024, increased $18.2 million compared to the year ended December 31, 2023. This increase is attributed to additional wells brought online in Ohio between periods. GP&T per
Boe was $5.59 for the year ended December 31, 2024, which represents an increase of $1.08 per Boe or 24% from the prior year. This increase was primarily related to increased gas volumes in Ohio that are on third party gathering systems and
lower volumes on INRs owned gathering system in Pennsylvania.
Lease operating . Lease operating expense
(LOE) for the year ended December 31, 2024, increased $9.8 million compared to the prior year. LOE per Boe was $3.19 for the year ended December 31, 2024, which represents an increase of $0.53 per Boe, or 20%, from the
prior year. This increase in LOE was primarily related to higher 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. The higher well count as of December 31, 2024 was primarily due to the acquisition of 50 gross operated horizontal wells from Utica Resources Ventures and PEO Ohio that INR operated for the fourth quarter
2023 and 14 wells INR placed on production since December 31, 2023. In addition, lower natural gas volumes from our assets located in Pennsylvania contributed to the per unit increase.
Production and ad valorem taxes . Production and ad valorem taxes for the year ended December 31, 2024, increased
$0.2 million compared to the prior year. Production taxes in Ohio are based on our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary
across the different counties in which we operate. Production taxes in Pennsylvania are assessed on producing wells by imposing an impact fee determined based on the market price for natural gas, which commences on the date the well is initially
spud and continues for a period of 15 years.
Depreciation, Depletion and Amortization. For the year ended December 31,
2024, DD&A expense was to $73.7 million, an increase of $19.9 million over the prior year. The primary factor contributing to higher DD&A expense in 2024 was the increase in our overall production volumes between periods, which
increased DD&A expense by $13.7 million, while our higher DD&A rate of $8.10 per Boe increased total DD&A expense by $6.5 million between periods. Our DD&A rate can fluctuate as a result of finding and development costs
incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves.
General and
Administrative Expenses. G&A expenses for the year ended December 31, 2024 were $13.0 million compared to $4.9 million for the prior year. This increase was primarily due to fees related to legal, accounting and
auditing services. We also had higher payroll and employee-related costs due to higher headcount, which increased from 49 as of December 31, 2023 to 80 as of December 31, 2024.
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.
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The following table presents gains and losses on our derivative instruments for the periods
indicated:
Year Ended December 31,
2024
2023
(in thousands)
Realized cash settlement gains (losses)
$
28,360
$
19,438
Non-cash mark-to-market derivative gain (losses)
(50,407
)
25,884
Total
$
(22,047
)
$
45,322
For the Year Ended December 31, 2023 Compared to the Year Ended December 31, 2022
Refer to Managements Discussion and Analysis of Financial Condition and Results of
Operations in the Companys final prospectus filed with the SEC on February 3, 2025 pursuant to Rule 424(b)(4) for a discussion of the results of operations for the year ended December 31, 2023 compared to the
year ended December 31, 2022.
Liquidity and Capital Resources
Historically, our primary sources of liquidity have been cash flows from operations, borrowings incurred under our Credit Facility and proceeds
from sales of equity securities. Going forward, we expect our primary sources of liquidity to be cash flows from operations, borrowings incurred under our Credit Facility, proceeds from offerings of debt or equity securities, 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 cash capital expenditures incurred for development during the year ended December 31, 2024 were $279.7 million, which includes $165.8 million on drilling and completion activities, $5.5 million on
midstream and $108.3 on maintenance leasehold and land investment. We funded our capital expenditures for the year ended December 31, 2024 from cash flows from operations and borrowings incurred under our Credit Facility. Our drilling and
completion capital budget for 2025 is $240 million to $280 million, along with $9 million to $12 million of midstream capital expenditures. We expect to fund our 2025 capital expenditures budget through a combination of cash
flows from operations and additional borrowings under our Credit Facility. Our ability to utilize cash flows from operations to fund our development program is driven by our oil and gas production, current commodity prices and our commodity hedge
positions in place.
We operate the vast majority of our acreage and therefore can largely control the amount and timing of our capital
expenditures. Accordingly, we can choose to defer or accelerate a portion of our planned capital expenditures depending on a variety of factors, including but not limited to: (i) prevailing and anticipated prices for oil and natural gas;
(ii) the success of our drilling activities; (iii) the availability of necessary equipment, infrastructure and capital; (iv) the receipt and timing of required regulatory permits and approvals; (v) seasonal conditions;
(vi) property or land acquisition costs; and (vii) the level of participation by other working interest owners.
In February
2025, we completed our IPO of 15.2 million shares of our Class A common stock at a price to the public of $20.00 per share, resulting in net cash proceeds of $286.5 million after deducting underwriting discounts and commissions. We
used all of the net proceeds after paying certain offering expenses to repay borrowings outstanding under our Credit Facility.
Our
liquidity requirements also include operating expenses, which have been impacted by elevated levels of inflation. High oil prices have historically led to more development activity in oil-focused shale basins
and resulted in service cost inflation across all U.S. shale basins, including our areas of operation. Ongoing inflationary pressures may result in increases to the costs of our oilfield goods, services and personnel, which would, in turn, cause our
capital expenditures and operating costs to rise. We closely monitor costs and are cost conscious in managing our operations. We may solicit bids from multiple vendors or contractors or source materials from multiple suppliers to take advantage of
cost competition, and we may buy surplus materials if we can acquire them on attractive terms. Where we anticipate elevated costs may be more sustained, such as in the cost of services, we may enter into contracts with certain service providers to
lock in rates. We are also strategic in the duration of our contracts to provide flexibility to take advantage of cost declines when they occur. Sustained levels of high inflation have also caused the U.S. Federal Reserve and other central banks to
increase interest rates, which has raised the cost of capital and increased our interest expense.
Although we cannot provide any
assurance that cash flows from operations or other sources of needed capital will be available to us at acceptable terms, or at all, and noting that our ability to access the public or private debt or equity capital markets at economic
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terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, the value and performance of our
debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control, we believe that based on our current expectations and projections, we have sufficient liquidity to fund future operations and to meet
obligations as they become due for at least one year following the date that our consolidated financial statements are issued.
Cash Flow Activity
Our financial condition and results of operations, including our liquidity and profitability, are significantly affected by the prices
that we realize for our oil, natural gas and NGLs and the volumes of oil and natural gas that we produce. Oil, natural gas and NGLs are commodities for which established trading markets exist.
Accordingly, our operating cash flow is sensitive to a number of variables, the most significant of which are the volatility of oil, natural
gas and NGL prices and production levels both regionally and across the United States, the availability and price of alternative fuels, infrastructure capacity to reach markets, costs of operations, and other variable factors. We monitor factors
that we believe could be likely to influence price movements including new or expanded oil and natural gas markets, gas imports, LNG and other exports, and regional and industry-wide capital intensity levels.
Our produced volumes have a high correlation to our level of capital expenditures such that our ability to fund it through operating and
financing cash flows may be affected by multiple factors discussed further herein.
The following summarizes our cash flow activity for
the periods indicated:
2024
2023
(in thousands)
Net cash provided by operating activities
$
177,666
$
106,475
Net cash used in investing activities
(256,118
)
(436,686
)
Net cash provided by financing activities
79,151
330,976
Net increase (decrease) in cash and cash equivalents
$
699
$
765
Analysis of Cash Flow Changes Between the Years Ended December 31, 2024 and 2023
Operating activities
For the year ended
December 31, 2024, we generated $177.7 million of cash from operating activities, an increase of $71.2 million from the prior year. Cash provided by operating activities increased primarily due to higher production volumes and
associated revenues as compared to the prior year. These factors were partially offset by higher LOE, severance and ad valorem taxes, GP&T, G&A, interest expense and lower realized prices for oil and natural gas during the year ended
December 31, 2024 as compared to the prior year. Refer to Results of Operations for more information on the impact of volumes and prices on revenues and on fluctuations in our operating costs between periods.
Investing activities
For the year ended
December 31, 2024, we spent $249.5 million on capital expenditures in conjunction with our drilling and completion activities in which we drilled and brought online 14 gross operated wells and land and leasehold costs. We also spent
$6.6 million on other property and equipment largely related to midstream activities.
For the year ended December 31, 2023, we
spent $146.0 million on capital expenditures in conjunction with our drilling and completion activities in which we drilled and brought online 10 gross operated wells and land and leasehold costs, and $279.0 million to complete the Utica
Resource Acquisition and PEO Ohio Acquisition, which included 50 gross operated wells. We also spent $11.7 million on other property and equipment.
Financing activities
For the year ended
December 31, 2024, the change in financing activity was primarily related to borrowing $168.1 million under our credit facility and repaying $79.7 million of borrowings. In September 2024, as part of entering into the new Credit
Facility, we used funds from the new Credit Facility of $243.4 million for the repayment of the outstanding balance on the prior credit facility. We also paid approximately $5.2 million of syndication fees associated with the new Credit
Facility.
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For the year ended December 31, 2023, the change in financing activity was primarily
related to borrowing $203.9 million under our prior credit facility and repaying $90.8 million of borrowings. Additionally, there was a capital raise for $222.3 million used to partially fund the Utica Resource Acquisition and PEO
Ohio Acquisition. We also paid approximately $4.3 million in syndication fees associated with the prior credit facility.
Analysis of Cash Flow
Changes Between the Year Ended December 31, 2023 and 2022
Refer to Managements Discussion and
Analysis of Financial Condition and Results of Operations in the Companys final prospectus filed with the SEC on February 3, 2025 pursuant to Rule 424(b)(4) for a discussion of the cash flows for the year ended
December 31, 2023 compared to the year ended December 31, 2022.
Derivative Activities
We are exposed to volatility in market prices and basis differentials for oil, natural gas and NGLs, which impacts the predictability of our
cash flows related to the sale of those commodities. Accordingly, to achieve more predictable cash flow and reduce our exposure to adverse fluctuations in commodity prices, we use commodity derivatives, such as swaps, to hedge price risk associated
with our anticipated production and to underpin our development program. This helps reduce potential negative effects of reductions in oil and gas prices but also reduces our ability to benefit from increases in oil and gas prices. In certain
circumstances, where we have unrealized gains in our derivative portfolio, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to utilize their value to further
our strategic pursuits.
A fixed price swap has an established fixed price. When the settlement price is below the fixed price, the
counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the
difference between the settlement price and the fixed price multiplied by the hedged contract volume.
A basis swap involves swapping
variable interest rates based on different reference rates. We receive a fixed price differential and pays the floating market price differential to the counterparty which is calculated based on the differential between NYMEX and the natural gas
price at a specific delivery point.
A put option has an established floor price. The buyer of that put option pays the seller a premium
to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the
settlement price is above the floor price, the put option expires worthless.
A call option has an established ceiling price. The buyer of
the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied
by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.
The following
tables provide information about our derivative financial instruments as of December 31, 2024.
Volume
Weighted Average Price
Fair Value as of
December 31, 2024
Oil
(in MBbls)
($ per Bbl)
(in thousands)
Fixed price swaps
2025
1,510
$
71.62
$
2,449
2026
519
$
69.58
1,465
2027
35
$
68.04
88
2028
$
Total
2,064
$
4,002
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Volume
Weighted Average Price
Fair Value as of
December 31, 2024
Natural gas
(in MMBtu)
($ per MMBtu)
(in thousands)
Fixed price swaps
2025
28,530
$
3.39
$
(2,093
)
2026
30,780
$
3.71
(6,555
)
2027
14,005
$
3.78
(1,731
)
2028
1,070
$
4.25
(109
)
Total
74,385
$
(10,488
)
Volume
Basis Differential
Fair Value as of
December 31, 2024
Natural gas
(in MMBtu)
($ per MMBtu)
(in thousands) 1
Basis swaps
2025
42,565
$
(1.03
)
$
(10,113
)
2026
37,345
$
(1.00
)
(3,172
)
2027
14,005
$
(0.92
)
22
2028
1,070
$
(0.83
)
(0
)
Total
94,985
$
(13,263
)
Volume
Weighted Average Price
Fair Value as of
December 31, 2024
Ethane
(in gallons)
($ per gallon)
(in thousands)
Fixed price swaps
2025
10,915,000
$
0.25
$
(57
)
2026
6,063,500
$
0.28
67
2027
435,000
$
0.30
(1
)
2028
$
Total
17,413,500
$
9
Volume
Weighted Average Price
Fair Value as of
December 31, 2024
Propane
(in gallons)
($ per gallon)
(in thousands)
Fixed price swaps
2025
15,940,000
$
0.71
$
(995
)
2026
8,080,500
$
0.70
(143
)
2027
577,000
$
0.72
6
2028
$
Total
24,597,500
$
(1,132
)
Volume
Weighted Average Price
Fair Value as of
December 31, 2024
Isobutane
(in gallons)
($ per gallon)
(in thousands)
Fixed price swaps
2025
3,372,000
$
0.86
$
(632
)
2026
1,667,500
$
0.83
(131
)
2027
114,000
$
0.82
(6
)
2028
$
Total
5,153,500
$
(769
)
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Volume
Weighted Average Price
Fair Value as of
December 31, 2024
Normal butane
(in gallons)
($ per gallon)
(in thousands)
Fixed price swaps
2025
5,267,500
$
0.82
$
(932
)
2026
2,686,000
$
0.81
(141
)
2027
192,000
$
0.81
(3
)
2028
$
Total
8,145,500
$
(1,076
)
Volume
Weighted Average Price
Fair Value as of
December 31, 2024
Pentane
(in gallons)
($ per gallon)
(in thousands)
Fixed price swaps
2025
4,329,000
$
1.41
$
(224
)
2026
2,168,500
$
1.38
2
2027
149,000
$
1.35
1
2028
$
Total
6,646,500
$
(221
)
(1)
These natural gas basis swap contracts are settled based on the difference between Dominion South or TETCO M2
price and the NYMEX price of natural gas during each applicable monthly settlement period.
Changes in the fair value of
derivative contracts from December 31, 2023 to December 31, 2024, are presented below:
(in thousands)
Commodity Derivative
Asset (Liability)
Net fair value of oil and gas derivative contracts outstanding as of December 31,
2023
$
27,469
Commodity hedge contract settlement payments, net of any receipts
(28,360
)
Cash and non-cash mark-to-market gains (losses) on commodity hedge contracts (1)
22,047
Net fair value of oil and gas derivative contracts outstanding as of December 31,
2024
$
21,156
(1)
At inception, new derivative contracts entered into by us have no intrinsic value.
Financing Agreements
Credit Facility
On September 25, 2024, we entered into a new credit facility led by Citibank, N.A. (the Credit Facility). The Credit Facility has a
total facility size of $1.5 billion, an initial borrowing base of $325.0 million and available capacity of $65.7 million as of December 31, 2024. The Credit Facility replaced our prior credit facility (as defined below), which
was terminated in connection with entry into the Credit Facility. As of December 31, 2024, our reserves supported a $325.0 million facility of which $259.3 million was outstanding leaving $65.7 million of unused capacity.
The Credit Facility also requires us to maintain compliance with the following financial ratios:
Current ratio the ratio of consolidated current assets (including an add back of unused commitments under
the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Amended
and Restated Credit Facility and non-cash derivative liabilities) of not less than 1.0 to 1.0; and
Leverage ratio the ratio of total funded debt to consolidated EBITDAX of not greater than 3.0 to 1.0.
We used all of the net proceeds after paying certain offering expenses of the IPO to repay outstanding borrowings under
the Credit Facility. Following such repayment, as of February 28, 2024, we had $2.4 million of borrowings outstanding under the Credit Facility.
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We were in compliance with the covenants and applicable financial ratios described above as
of December 31, 2024.
Prior Credit Facility
On October 4, 2023, we entered into an amended and restated credit facility with a syndicate of banks led by the Bank of Oklahoma (the
prior credit facility). Borrowings under our prior credit facility were subject to borrowing base limitations based upon the collateral value of the pledged assets and were subject to semi-annual redeterminations. The prior credit
facility was scheduled to mature in April 2026, but was terminated on September 20, 2024, in connection with entry into the Credit Facility.
The prior credit facility also required us to maintain compliance with the following financial ratios:
Current ratio the ratio of consolidated current assets (including an add back of unused commitments under
the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Amended
and Restated Credit Facility and non-cash derivative liabilities) of not less than 1.0 to 1.0; and
Leverage ratio the ratio of total funded debt to consolidated EBITDAX of not greater than 3.0 to 1.0. We
were in compliance with the covenants and applicable financial ratios described above as of December 31, 2023.
Other long-term debt
Other long-term debt principally relates to car loans associated with the Companys car fleet to support the Companys team
to service and maintain its operated wells.
Payments due by fiscal year related to other long-term debt as of December 31, 2024, are
as follows:
Long-Term Note Payable
(in thousands)
2025
$
101
2026
45
2027
14
2028
2029
Total payments
$
160
Critical Accounting Estimates
Our financial statements are prepared in accordance with U.S. GAAP. In connection with preparing of our financial statements, we are required
to make assumptions and estimates about future events, and to apply judgments that affect the reported amounts of assets, liabilities, revenue, expense and the related disclosures. We base our assumptions, estimates and judgments on historical
experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments
to ensure that our financial statements are presented fairly and in accordance with U.S. GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and
estimates.
Our significant accounting policies are discussed in our audited financial statements included in Item 8. Financial
Statements and Supplementary Data in this Annual Report. Management believes that the following accounting estimates are those most critical to fully understanding and evaluating our reported financial results, and they require
managements most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain.
Method of Accounting for Oil and Natural Gas Properties
We account for oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs, including non-productive costs and certain general and administrative costs such as salaries, benefits and other internal costs directly associated with acquisition, exploration and development of oil and natural gas
properties, are capitalized. Under the full cost method of accounting, capitalized costs are amortized based on units-of-production and proved oil and natural gas
reserves. If we maintain production levels year over year, our depreciation, depletion, and amortization expense may be significantly different if our estimates of remaining reserves or future development costs change significantly. On a quarterly
basis, we review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC, which is referred to as a cost center ceiling test.
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The primary factors impacting this test are reserve estimates and the unweighted arithmetic
average of index prices on the first day of each month within the 12-month period that ends as of each quarterly balance sheet date. Downward revisions to estimates of oil and natural gas reserves and/or
unfavorable prices may have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes (which our predecessor, INR Holdings, has not been subject to historically for federal
income tax purposes), is generally written off as an expense. We did not record any impairment of oil and natural gas properties for years ended December 31, 2024 and 2023.
Additionally, costs associated with unevaluated properties are excluded from properties subject to amortization until we have made a
determination as to the existence of proved reserves. We assess all items classified as unevaluated property at least annually for possible impairment. This assessment is subjective and includes consideration of numerous factors, including drilling
plans, remaining lease terms, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. We did not record any impairment on
our unevaluated properties for the years ended December 31, 2024 and 2023, but any such future impairment could potentially be material to our consolidated financial statements.
Oil and Natural Gas Reserves
Proved oil and gas reserves, as defined by SEC Regulation S-X, Rule
4-10, are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from
known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire unless evidence indicates that renewal is reasonably certain regardless
of whether deterministic or probabilistic methods are used for the estimation.
Reserve estimates are prepared by independent engineers.
Revisions may result from changes in, among other things, reservoir performance, development plans, prices, operating costs, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in certain proved
reserves due to reaching economic limits sooner. A material change in the estimated volume of reserves could have an impact on the depletion rate calculation and our consolidated financial statements.
We estimate future net cash flows from natural gas, NGLs and oil reserves based on selling prices and costs using a 12-month average price, which is calculated as the unweighted arithmetic average of the first-day-of-the- month price for each month within the 12-month period and, as such, is subject to change in subsequent periods. Operating costs,
production and ad valorem taxes and future development costs are based on current costs with no escalation. Income tax expense (which our predecessor, INR Holdings, has not been subject to historically for federal income tax purposes) is based on
currently enacted statutory tax rates and tax deductions and credits available under current laws.
Revenue Recognition
We derive revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when production is sold to a purchaser
at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. Our performance obligations are satisfied at a point in time and payments from purchasers are unconditional once the
performance obligations have been satisfied, which occurs when control is transferred to the purchaser upon delivery of production volumes at a specified point. The pricing provisions of our contracts with customers are based on market indices, with
certain adjustments for quality, supply and demand conditions, and location differentials, among other factors.
At the end of each month,
we estimate the amount of production delivered to purchasers for that month and estimate revenues based on the price we expect to receive. Payments are generally received between 30 and 60 days after the date of production. Any variances between our
accrued revenue estimates and the actual amounts of payments received for the sales of our production are recorded in the month that each payment is received from our purchasers. Such variances have historically not been significant.
The revenue derived from our midstream activities is generated from gathering assets owned by our wholly- owned subsidiary, INR Midstream. We
charge a gathering fee per MMBtu transported through our gathering system and fees are recognized as revenue based on measured volumes at the specified delivery points when the associated service is performed.
Derivative Instruments
We use
commodity derivatives for the purpose of mitigating the risk resulting from fluctuations in the market prices of crude oil and natural gas. We exercise significant judgment in determining the types of instruments to be used, the level of production
volumes to include in our commodity derivative contracts, the prices at which we enter into commodity derivative contracts and counterparty creditworthiness. We do not use commodity derivative instruments for speculative or trading purposes.
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We have not designated our derivative instruments as hedges for accounting purposes and, as
a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are
also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the
changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and is generally determined using various inputs and assumptions including established index prices and other sources which are based
upon, among other things, futures prices, time to maturity, implied volatilities and counterparty credit risk.
These fair values are
recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. Changes in the fair values of our commodity derivative
instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in
the period in which they occur.
Tax Receivable Agreement
As described in Item 1. BusinessCorporate Reorganization, Infinity Natural Resources entered into a Tax Receivable Agreement
in connection with the closing of the IPO under which it is contractually committed to pay the Legacy Owners 85% of the net cash savings, if any, in U.S. federal, state and local income tax that Infinity Natural Resources (a) actually realizes
with respect to taxable periods ending after the IPO or (b) is deemed to realize in the event of a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business
combinations and certain changes to the composition of the INR board of directors) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach) with respect to any taxable periods ending on or after such change of
control or early termination event, in each case, as a result of (i) the tax basis increases resulting from the exchange of INR Units and the corresponding surrender of an equivalent number of shares of Class B common stock by the Existing
Owners for a number of shares of Class A common stock on a one-for-one basis or, at our option, the receipt of an equivalent amount of cash pursuant to the INR
Holdings LLC Agreement and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement.
The projection of future taxable income and utilization of tax attributes associated with the Tax Receivable Agreement involve estimates which
require significant judgment. The amount of the Companys actual taxable income (which may differ from our estimates), passage of future legislation, or consummation of significant transactions in the future may significantly impact the
liability related to the Tax Receivable Agreement. The Company will account for amounts payable under the Tax Receivable Agreement in accordance with Accounting Standard Codification Topic 450, Contingencies .
JOBS Act
The JOBS Act permits us, as an
emerging growth company, to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies. We have elected to take advantage of this extended transition period, which
means that the financial statements included in this Annual Report, as well as any financial statements that we file or furnish in the future, will not be subject to all new or revised accounting standards generally applicable to public companies
for the transition period for so long as we remain an emerging growth company.
Adoption of New Accounting Standards
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280)Improvements to
Reportable Segment Disclosures (ASU 2023-07), which updates reportable segment disclosure requirements primarily by enhancing disclosures about significant segment expenses and information used to
assess segment performance. Additionally, ASU 2023-07 enhances interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss and provides
new segment disclosure requirements for entities with a single reportable segment. The amendments are effective for annual periods beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15,
2024. Early adoption is permitted. The amendments should be applied retrospectively to all prior periods presented in the financial statements. We adopted this ASU and applied the amendments retrospectively to all prior periods presented in our
consolidated financial statements. Refer to Note 15 - Segment Information for additional discussion.
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Accounting Standards Not Yet Adopted
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740) Improvements to
Income Tax Disclosures (ASU 2023-09), which requires that certain information in a reporting entitys tax rate reconciliation be disaggregated and provides additional requirements
regarding income taxes paid. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted, and should be applied either prospectively or retrospectively. Management is currently evaluating
this ASU to determine its impact on INR Holdings disclosures. The Company is in the process of assessing the impact of this ASU on its consolidated financial statements subsequent to the IPO transaction in February 2025.
In March 2024, the FASB issued ASU 2024-01, Compensation-Stock Compensation (Topic 718). This ASU
illustrates how to apply the scope guidance to determine whether a profits interest award should be accounted for as a share-based payment arrange under Accounting Standards Codification (ASC) 718 or another accounting standard. The
amendments in this update are effective for public entities for fiscal years beginning after December 15, 2024. As of December 31, 2024, this is ASU is not applicable to the company due no stock compensation expense. The Company is in the
process of assessing the impact of this ASU on its consolidated financial statements subsequent to the IPO transaction in February 2025.
In November 2024, the FASB issued ASU 2024-03 - Income Statement - Reporting Comprehensive
Income - Expense Disaggregation Disclosures (Subtopic 220-40). This ASU requires entities to disaggregate any relevant expense caption presented on the face of the income statement within continuing operations
into the following required natural expense categories within the footnotes, as applicable: (1) purchases of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, and (5) DD&A recognized
as part of oil- and gas-producing activities or other depletion expenses. The amendments in this ASU are effective for annual reporting periods beginning after
December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating the impact of the adoption of this guidance .
We considered the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable or not
material upon adoption.
Contractual Obligations and Commitments
We routinely enter into or extend operating and transportation agreements, office and equipment leases, drilling rig contracts, and other
agreements, in the ordinary course of business. We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in consolidated debt or
losses. The following table summarizes our obligations and commitments as of December 31, 2024, to make future payments under long-term contracts for the time periods specified below:
2024
2025
2026
2027
2028
Thereafter
Total
(in millions)
Prior Credit Facility Principal
$
259.3
$
259.3
Prior Credit Facility Interest (1)
21.6
21.6
21.6
21.6
16.2
102.6
Asset Retirement Obligation
3.0
3.0
Other (2)
1.4
0.4
0.3
0.2
0.1
0.8
3.2
Total
$
23.0
$
22.0
$
21.9
$
21.8
$
275.6
$
3.8
$
368.1
(1)
This debt bears interest at the Secured Overnight Financing Rate (SOFR) plus a borrowing spread. In
determining future interest, we used outstanding amounts at December 31, 2024 and the average borrowing cost for calendar year 2024.
(2)
This amount includes commitments from drilling rig contracts, vehicle notes, and operating leases.