Under the Up-C structure, PIH Rollover Holders own all of the shares of Class B Common Stock which are non-economic voting only shares of the Company. PIH Unit Holders’ economic interest in the Company is held through their ownership (the “Common Units”) in the Opco. Pursuant to the amended and restated limited liability company agreement of the Opco (the “A&R LLC Agreement”), the Company’s ownership of Common Units in the Opco at all times equals the number of shares of the Company’s Class A Common Stock then outstanding, and PIH Rollover Holders’ ownership of Common Units in the Opco at all times equals the number of shares of Class B Common Stock then outstanding. The Opco was formed for the purpose of executing the Company’s organization with PIH Rollover Holders into an Up-C structure. The Opco, through its subsidiaries, owns, operates, and manages oil and gas properties and manages the Company’s outstanding debt and derivative instruments. The Company’s wholly-owned subsidiary, EQV Surviving Subsidiary, is the managing member of the Opco. Subsidiaries of the Opco own and operate all our oil and gas assets. The Company and the Opco are holding companies with no other operations, material cash flows, or material assets or liabilities other than the equity interests in their subsidiaries.

Holders of Common Units (other than the Company) have the right (an “exchange right”), subject to certain limitations, to exchange Presidio Interests (each consisting of one Common Unit and one share of Class B Common Stock, par value $0.0001 per share, of the Company (“Presidio Class B Common Stock” and, together with an EQV Holdings Common Unit, a “Presidio Interest”)) for, at the Company’s option, (i) shares of Presidio Class A Common Stock on a one-for-one basis, subject to adjustment for stock splits, stock dividends, reorganizations, recapitalizations and the like (collectively, “adjustments”), or (ii) a corresponding amount of cash. The Company’s decision to make a cash payment or issue shares upon an exercise of an exchange right will be made by the Company’s independent directors.

Holders of EQV Holdings Common Units (other than the Company) will generally be permitted to exercise the exchange right on a quarterly basis, subject to certain de minimis allowances. In addition, additional exchanges may occur in connection with certain specified events, and any exchanges involving more than a specified number of Common Units (subject to the Company’s discretion to permit exchanges of a lower number of units) may occur at any time with advanced notice. The exchange rights are subject to certain limitations and restrictions intended to reduce the administrative burden of exchanges upon the Company and ensure that Opco will continue to be treated as a partnership for U.S. federal income tax purposes.

The Opco is considered a variable interest entity for which the Company is the primary beneficiary. This conclusion was based on a qualitative analysis that considered the Opco’s governance structure and the Company’s control over operations of the Opco. The Company, through its wholly owned subsidiary, EQV Surviving Subsidiary, as the managing member of EQV Holdings, has the decision making authority along with the ability to control the most significant activities of the Opco and participate significantly in the Opco’s benefits and losses, where the PIH Rollover Holders directly holding other Common Units have neither substantive kick-out rights nor substantive participating rights. As such, because the Company has both power and economics in the Opco, the Company determined it is the primary beneficiary of the Opco and consolidates the Opco in the Company’s condensed consolidated financial statements. The Company reflects a non-controlling interest in the condensed consolidated financial statements based on the proportion of Common Units owned by PIH Rollover Holders relative to the total number of Common Units outstanding. The non-controlling interest is presented as a component of equity in the accompanying condensed consolidated financial statements and represents the ownership interest held by PIH Rollover Holders in the Opco.

The non-controlling interest percentage may be affected by the issuance of shares of Class A Common Stock, repurchases or cancellation of Class A Common Stock, the exchange of Class B Common Stock and the redemption of Common Units (and concurrent cancellation of Class B Common Stock), among other things. The percentage is based on the proportionate number of Opco Common Units held by PIH Rollover Holders relative to the total Common Units outstanding. As of March 31, 2026, the Company owned 27,652,068 Opco Common Units, representing a 94.3% interest in the Opco, and PIH Rollover Holders owned 1,676,830 Common Units, representing the remaining 5.7% interest.

When the Company’s relative ownership interest in the Opco changes, adjustments to Non-controlling interest and Paid-in capital, tax effected, will occur. Because these changes in the ownership interest in the Opco do not result in a change of control, the transactions are accounted for as equity transactions under authoritative guidance in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 810, Consolidation (“ASC 810”), which requires that any differences between the carrying value of the Company’s basis in the Opco and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. Additionally, based on the A&R LLC Agreement, there are no substantive profit sharing arrangements that would cause distributions to be other than pro rata. Therefore, profits and losses are attributed to the common shareholders and non-controlling interest pro rata based on ownership interests in the Opco.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Additionally, the prices received for crude oil, natural gas, and NGLs production can heavily influence our assumptions, judgments and estimates, and continued volatility of crude oil and natural gas prices could have a significant impact on our estimates. Estimates significant to our condensed consolidated financial statements include the following:

The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company had no cash equivalents as of March 31, 2026 and December 31, 2025.

At the closing date of the ABS II securitization transaction (see Note 7 — Debt), the Company was required to deposit $15.7 million into a separate liquidity reserve account. At each note payment date, a portion of the liquidity reserve account balance is used to fund the priority of payments as required by the securitized note agreements as long as the balance exceeds the expected note interest for the six payment dates following such payment date for controlling securities, and senior transaction fees. The account is also used to fund the required principal and interest payments associated with the ABS II debt if available funds are insufficient. Following the payment in full of the aggregate outstanding amount of the Notes and of all other amounts owed, any amount remaining on deposit in the liquidity reserve account shall be distributed back to the Company.

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and accounts receivable. The Company maintains deposits at financial institutions, which at times may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Company has not experienced any losses related to amounts in excess of FDIC limits and believes the counter party risks are minimal based on the reputation and history of the institutions in which the funds are deposited and held.

During the Successor period from March 4, 2026 through March 31, 2026, oil, natural gas and NGL revenues from four purchasers totaled approximately 22%, 17%, 11%, and 11% of gross oil, natural gas and NGL revenues. During the Predecessor period from January 1, 2026 through March 3, 2026, oil, natural gas and NGL revenues from four purchasers totaled approximately 22%, 15%, 13%, and 11% of gross oil, natural gas and NGL revenues. Significant customers’ accounts receivable balances totaled approximately 23%, 20%, 14%, 12%, and 10% of oil and natural gas receivables as of March 31, 2026. During three months ended March 31, 2025, oil, natural gas and NGL revenues from four purchasers totaled approximately 26%, 13%, 12%, and 10% of gross oil, natural gas and NGL revenues. Significant customers’ accounts receivable balances totaled approximately 33%, 11%, 11%, and 10% of oil and natural gas receivables as of December 31, 2025.

No other customer balance represented greater than 10% of total accounts receivable as of March 31, 2026 or December 31, 2025. We believe that sufficient alternative purchasers exist for the Company’s oil, natural gas and NGL production and that the loss of any single purchaser would not be considered a significant interruption or business risk to the Company.

The Company sells oil, natural gas and NGLs to various customers. Oil, natural gas and NGLs sales receivables related to these operations are generally unsecured and most payments for production are received within three months after the production date. Joint interest receivables are generally secured pursuant to the operating agreement between the operator and the joint interest owner. The Company regularly evaluates the collectability of joint interest receivables, including an assessment of expected credit losses. When appropriate based on credit risk considerations, the Company has the ability to settle receivables through netting of anticipated future production revenues. Accounts receivable amounts due from joint interest owners are stated net of an allowance for credit losses.

The Company establishes allowances for credit losses by applying an aged-based loss-rate to estimate expected lifetime credit losses on its joint interest receivables. The historical allowance for credit losses on joint interest receivables was eliminated through the Business Combination. As such, the allowance for credit losses on joint interest receivables was $0.0 million as of March 31, 2026. The allowance for credit losses on joint interest receivables was $1.4 million as of December 31, 2025. There were no write-offs of joint interest receivables during the Successor period from March 4, 2026 through March 31, 2026 or the Predecessor period from January 1, 2026 through March 3, 2026.

The Company has entered into derivative instruments to mitigate a portion of its exposure to market changes in hydrocarbon prices and basis differentials. Swap instruments require a sale of the hedged commodity at a fixed price and a purchase at a floating market price, as defined in each instrument, to a counterparty. The Company recognizes all price risk management instruments as either assets or liabilities measured at fair value. The Company has presented the fair value of derivative assets and liabilities on a net basis by counterparty in the accompanying condensed consolidated balance sheet where the right of offset exists.

The ABS II securitization transaction included certain hedging requirements. At the close date of the ABS II securitization transaction, the Company was required to hedge 85% of the projected production of oil, natural gas and NGLs following the close date for five years, eight years and four years, respectively. Natural gas basis differential swaps are required to be hedged 85% for three years following the close date. These initial hedging requirements have been satisfied. Following the third anniversary of the ABS II securitization closing date, the Company shall maintain at all times 24 months of commodity hedges in an amount not less than 85% of the projected production of oil, natural gas and NGLs until the earlier of (x) the Final Scheduled Payment Date or (y) the redemption of the Notes. As of March 31, 2026, the Company was in compliance with these requirements. The new Citizens Bank credit facility (see Note 7 — Debt) also includes certain hedging requirements in which the Company, at all times, maintains 36 months of commodity hedges in an amount not less than 75% of the projected production of oil, natural gas and NGLs.

The Company has not designated any price risk management instruments as fair value or cash flow hedges during the three months ended March 31, 2026.

The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, costs of acquiring properties, drilling successful exploration wells, development costs, and workover costs result in additions to proved properties that are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if the determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical and seismic costs are expensed as incurred.

The capitalized costs of proved properties are depleted using the unit-of-production method based on proved developed or total proved reserves as applicable. Costs of significant non-producing properties, wells in the process of being drilled and prepaid development costs are excluded from depletion until proved reserves are established or, if unsuccessful, impairment is determined.

Producing property is considered impaired when the carrying cost of property exceeds its undiscounted future net cash flows. When a property is impaired the carrying value is reduced to the discounted future net cash flows and an impairment charge of the difference between cost and discounted future net cash flows is recorded. Non-producing properties are considered impaired when the Company considers it likely that the associated leasehold will expire without plans to renew or extend the lease.

Other property and equipment are carried at cost less accumulated depreciation. Major renovations and improvements are capitalized while expenditures for maintenance and repairs are expensed as incurred. Upon sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts and any gain or loss is recognized. Depreciation is calculated using the straight-line method over the estimated useful lives of the various assets. See Note 5 — Property, Plant and Equipment.

The carrying value of proved oil and natural gas properties, salt water disposal wells and related facilities, and other property and equipment is periodically evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value.

Under ASC Topic 360, Property, Plant, and Equipment, the Company evaluates impairment of proved and unproved oil and natural gas properties based on expected future net cash flows from the asset group. As the Company’s properties are managed and evaluated as a single field, impairment testing is performed on that basis. No impairment was recorded during the Successor period from March 4, 2026 through March 31, 2026 or the Predecessor period from January 1, 2026 through March 3, 2026.

The Company leases office space and vehicles. Right-of-use assets and lease liabilities are initially recorded at the commencement date based on the present value of lease payments over the lease term. The Company uses its incremental borrowing rate to discount future lease payments. Certain leases contain variable costs above the minimum required payments and are not included in the right-of-use assets or lease liabilities. Options to extend or terminate a lease are included in the lease term when it is reasonably certain the Company will exercise that option. For operating leases, lease cost is recognized on a straight-line basis over the term of the lease. Leases with an initial term of 12 months or less are not included on the condensed consolidated balance sheet. The Company elected a practical expedient to not separate non-lease components from lease components for office space leases. The Company did not elect this practical expedient for vehicle leases.

Asset retirement obligations relate to the future costs associated with the plugging, dismantlement, remediation, and abandonment (“P&A”) of oil and natural gas wells and locations. Estimates are based on projected remaining lives of those wells based on reserve estimates and internal estimates of the future cost to P&A the wells at the end of their remaining lives. The Company records the discounted present value of those anticipated costs as its asset retirement obligation liability.

Future periodic accretion of the discount on asset retirement obligations will be recorded as an expense in the accompanying condensed consolidated statements of operations.

Upstream Revenues

The Company disaggregates revenues from contracts with customers by type of commodity. Upstream revenues include the sale of oil, gas and NGL production which are recognized at a point in time when control is transferred to the purchaser upon delivery of contract-specified production volumes at a specified point. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received within 30 days of the end of the production month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying condensed consolidated statements of operations.

The Company also evaluates its contracts for the principal/agent provisions. If the Company is determined to be the principal, it would recognize revenue at the gross purchase price and record an expense for certain fees charged by the customer (such as transportation and fractionation fees) incurred prior to the transfer of control, as the Company would still have control of the product when these activities take place. Alternatively, when the Company is determined to be the agent, it recognizes the revenues based on the net price received from the purchaser, as control is determined to have transferred prior to the activities. During this evaluation, the Company concluded that it acts as the agent in all current contracts. Accordingly, revenue is recognized based on the net proceeds received from the purchaser.

Oil Sales

The Company sells its crude oil production at the wellhead for a contractually-specified index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s condensed consolidated statements of operations.

Natural Gas and NGL Sales

Under the Company’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. The Company has determined that it is the agent in these transactions and recognizes revenue on a net basis, with transportation, gathering, processing, treating and compression fees as a reduction to revenues in the condensed consolidated statements of operations.

Satisfaction of Performance Obligation and Revenue Recognition

Because the Company has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company recognizes revenue for sales at the time the crude oil, natural gas or NGLs are delivered at a fixed or determinable price.

Transaction Price Allocated to Remaining Performance Obligations

The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligations under any of its product sales contracts.

Under the Company’s revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract Balances

Under the Company’s commodity sales contracts, the Company recognizes revenue after its performance obligations have been satisfied, at which point the Company has an unconditional right to receive payment. Accordingly, the Company’s commodity sales contracts generally do not give rise to contract assets or contract liabilities under ASC 606. Instead, the Company’s unconditional rights to receive consideration are presented as a receivable within accounts receivable attributable to oil and gas sales in its condensed consolidated balance sheets. The Company has not recognized any contract assets or liabilities as of March 31, 2026 or December 31, 2025.

The opening balance of accounts receivable attributable to oil and natural gas sales was $16.7 million and $20.1 million as of January 1, 2026 and 2025, respectively.

Field Services Revenues

The Company provides field services through its Trail Dust subsidiary, including compression, forward-looking infrared (“FLIR”) surveys, emissions reduction equipment, tubing scanning, and line locating services, with compression and FLIR surveys representing the Company’s most significant service lines. When these services are provided to third party customers, including its third-party working interest partners, the Company generates supplemental, other revenues.

Revenue from compression services is recognized as earned in the month the work is performed in accordance with the contractual obligations. Revenue from FLIR surveys, tubing scanning, and line locating services is recognized at the point in time when the service is completed and the customer has accepted the work performed. Revenue from the sale of emissions reduction equipment is recognized upon delivery.

The Company utilizes a fair value hierarchy established by ASC 820, Fair Value Measurement (“ASC 820”) to categorize its assets and liabilities based on inputs to the valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described below:

Level 1 — Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the Company has the ability to access.

Level 2 — Inputs to the valuation methodology include:

If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.

Level 3 — Inputs to the valuation methodology are unobservable and significant to the fair value measurements.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

General and administrative (“G&A”) expenses primarily consist of employee compensation and related benefits, professional services, and other corporate overhead costs incurred in the normal course of business. Compensation and benefits represent the largest component of G&A.

For the Successor period from March 4, 2026 through March 31, 2026, G&A included $0.4 million of compensation expense recognized for RSUs granted in connection with the Business Combination.

For the Predecessor period from January 1, 2026 through March 3, 2026, G&A included $47.0 million of compensation expense recognized in connection with the accrual of a share-based compensation liability associated with the final vesting and settlement of PIH’s Class B units in accordance with the original terms of the awards. The measurement of the share-based compensation liability is equal to the amount of cash and value of equity in the Company (either in Class A Common Stock or Opco Common Units with a corresponding number of Class B Common Stock, at the election of each PIH Class B unitholder) used to settle the awards. The share-based compensation liability was accounted for as an assumed liability in the Business Combination, and settlement of the share-based compensation liability is accounted for in the Successor period. In connection with the Business Combination, PIH’s Class B units are no longer outstanding.

For the three months ended March 31, 2025 (Predecessor), G&A included $15.0 million of compensation expense recognized in connection with PIH’s Class B unit distribution.

In addition, the Company provides administrative services to non-operated working interest owners under Council of Petroleum Accountants Societies (“COPAS”) joint operating agreements. Reimbursements received for such services are recorded as an offset to G&A expenses in the condensed consolidated statements of operations.

The Company accounts for income taxes under ASC Topic 740, Income Taxes (“ASC 740”), which requires an asset and liability approach to financial accounting and reporting for income taxes. Deferred tax assets and liabilities are computed for differences between the financial statement and tax bases of assets and liabilities that will result in future taxable or deductible amounts, based on enacted tax laws and rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amount expected to be realized.

ASC 740 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be sustained upon examination by taxing authorities. Recognized tax positions are measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized. The Company recognizes accrued interest and penalties related to unrecognized tax benefits as income tax expense.

Prior to the closing of the Business Combination, the Predecessor was a partnership for income tax purposes. Any taxable income or loss was passed through to its owners and was recognized by the owners on their respective income tax returns. Accordingly, no federal, state, or local income taxes have been reflected in the accompanying condensed consolidated financial statements of the Predecessor. Significant differences may exist between the results of operations reported in these condensed consolidated financial statements and those determined for income tax purposes primarily due to the use of different asset valuation methods for tax purposes.

Successor

Basic net income (loss) per share of common stock is computed by dividing net income (loss) available to common stockholders by the weighted average number of shares of common stock outstanding during the period, including any common shares issuable for nominal consideration for which all contingencies have been satisfied and excluding any legally outstanding common shares subject to forfeiture. Net income (loss) attributable to non-controlling interests is excluded from net income (loss) available to common stockholders. Dividends on Series A Redeemable Preferred Stock (as defined in Note 3 — Business Combinations), whether payable in cash or in-kind, and adjustments to the carrying amount of the redeemable preferred stock, as applicable, reduce net income, or increase net loss, available to common stockholders. Allocations of undistributed earnings to participating securities under the two-class method reduce net income available to common stockholders.

Diluted net income (loss) per share reflects the potential dilution from outstanding instruments that may be exercised, converted, exchanged, or settled in shares of the Company’s Class A Common Stock. The Company applies the treasury stock method, the if-converted method, the contingently issuable share method, and the two-class method, as applicable, and includes only those potential common shares whose effect is dilutive. Potential common shares are excluded from the diluted net income (loss) per share calculation when their effect would be antidilutive.

The Company’s Class B Common Stock has no economic rights to the undistributed earnings of the Company and is not considered a participating security under ASC 260, Earnings Per Share (“ASC 260”). Accordingly, the Company does not present net income (loss) per share for the Class B Common Stock, and shares of Class B Common Stock are excluded from the calculation of net income (loss) per share for the Class A Common Stock.

Predecessor

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of PIH Class A units outstanding during the period. Diluted net income (loss) per share is calculated to give effect to potentially issuable dilutive common shares. PIH did not have additional instruments or other substantive classes of equity to create a dilutive effect on net income (loss) per share during the period.

Series A Redeemable Preferred Stock and Series B Convertible Redeemable Preferred Stock (as defined in Note 3 — Business Combinations) are presented within the condensed consolidated balance sheet as of March 31, 2026 as mezzanine equity as both instruments are contingently redeemable upon the occurrence of events not solely within the Company’s control. The Series A Redeemable Preferred Stock was issued in connection with freestanding equity-classified warrants; as such, net proceeds from the issuance were allocated between the two instruments on a relative fair value basis, creating a discount on the Series A Redeemable Preferred Stock. The Series B Convertible Redeemable Preferred Stock was recorded at fair value upon issuance, net of issuance costs and discounts.

In addition, certain embedded features (“embedded derivatives”) included in the Series A Redeemable Preferred Stock required bifurcation under the authoritative guidance in ASC 815-15, Derivatives and Hedging, Embedded Derivatives (“ASC 815-15”) and were classified as derivative liabilities. The embedded derivative is measured at fair value at inception, creating a discount on the host preferred stock instrument, and subsequently remeasured at fair value each reporting date thereafter, with changes in fair value recognized in the condensed consolidated statement of operations in the period of change. Embedded features deemed not clearly and closely related to the host preferred stock instrument at inception are reassessed under ASC 815-15 each subsequent reporting date while the host instrument is outstanding. However, as of the issuance date and March 31, 2026, the Company determined the embedded derivative had a minimal fair value and, as such, was not recorded.

As of March 31, 2026, both the Series A Redeemable Preferred Stock and Series B Convertible Redeemable Preferred Stock were neither currently redeemable nor probable of becoming redeemable in the future based on an evaluation of the likelihood of the events that would trigger redemption occurring. As such, the carrying values were not adjusted during the Successor period from March 4, 2026 through March 31, 2026. The Company accrues for the mandatory, unconditional dividend obligations on the Series A Redeemable Preferred Stock as they become contractually payable, regardless of whether any dividends are declared.

The Company accounts for warrants as either equity-classified or liability-classified instruments based on an assessment of the warrant’s specific terms and applicable authoritative guidance in ASC 480, Distinguishing Liabilities from Equity (“ASC 480”) and ASC 815-40, Derivatives and Hedging, Contracts in an Entity’s Own Equity (“ASC 815-40”). The assessment considers whether the warrants are freestanding financial instruments pursuant to ASC 480, meet the definition of a liability pursuant to ASC 480, and, if not, whether the warrants meet all of the requirements for equity classification under ASC 815-40, including whether the warrants are indexed to the Company’s own common stock and meet all other conditions for equity classification. This assessment is conducted at the time of warrant issuance and as of each subsequent reporting date while the warrants are outstanding.

In accordance with ASC 815-40, the Company has classified all its warrant instruments as equity. Warrant instruments are recorded and measured at fair value at the time of issuance, net of issuance costs, as applicable.

In connection with the Business Combination, EQV Ventures Sponsor LLC, a Delaware limited liability company (the “Sponsor”), agreed to subject certain of its founder shares to vesting (or forfeiture) on the basis of achieving certain trading price thresholds during the first five years following the closing of the Business Combination pursuant to an earnout program (“Earnout Shares”) (see Note 3 — Business Combinations for further information). The Earnout Shares do not contain dividend or voting rights prior to vesting. The Earnout Shares represent freestanding equity-linked contracts and are assessed for either liability or equity classification under the authoritative guidance in ASC 480 and ASC 815-40.

In accordance with ASC 815-40, the Earnout Shares are reported as liabilities within the Company’s condensed consolidated balance sheet because they do not qualify as being indexed to the Company’s own equity. The Earnout Shares are measured at fair value at inception and at each reporting date thereafter, with changes in fair value recognized in the condensed consolidated statement of operations in the period of change.

PIH’s equity in the Predecessor period consisted of membership interests in the form of (i) Class A units issued and held by PIH’s former private-equity sponsor and certain members of management in exchange for capital contributions, and (ii) Class B units held by certain members of PIH which represented non-voting, equity compensation awards intended to constitute profit interests within the meaning of IRS guidelines. Distributions to holders of Class A units and Class B units were made in accordance with the PIH Amended and Restated Limited Liability Company Agreement (“PIH LLC Agreement”).

The Class B units vested 20% annually over four years, with the final 20% vesting upon the occurrence of a change of control event. Holders of the Class B units were entitled to cash payouts upon the return of contributed capital plus a rate of return to specified holders of Class A units, and the Class B units were forfeitable upon termination of employment with PIH at the discretion of management. The achievement of these payouts was determined to be a performance condition that required PIH to assess, at each reporting period, the probability that an event of payout would occur. Compensation expense was required to be recognized at such time that the payout triggers were deemed probable of being met. The Class B units were accounted for as liability-classified awards in scope of ASC Topic 718, Compensation – Stock Compensation (“ASC 718”) as the achievement of the payout conditions required the settlement of such awards by transferring cash to the incentive unit holders.

On January 6, 2025, the Board of Representatives of PIH approved a cash distribution totaling $75.0 million to its members, including $15.0 million to the Class B unit holders which was recorded as compensation expense for the three months ended March 31, 2025. The distribution was paid on January 8, 2025, and was allocated among equity holders in accordance with the PIH LLC Agreement.

As a result of the Business Combination, all PIH Class A and Class B units were exchanged at the unitholders’ election for either (i) cash or (ii) equity in either (a) Presidio Class A Common Stock or (b) EQV Holdings Common Units and an equal number of shares of Presidio Class B Common Stock. No Class A or Class B units remained issued or outstanding following the Business Combination. See “General and Administrative” in this Note 2 — Basis of Presentation and Summary of Significant Accounting Policies for settlement of the PIH Class B units in connection with the Business Combination.

The Company accounts for share-based compensation in accordance with ASC 718. Share-based awards are measured at their grant-date fair value and recognized as compensation expense on a straight-line basis over the requisite service period, which generally corresponds to the vesting period of the award.

For restricted stock units, which are equity-classified, fair value is determined based on the closing stock price of the Company’s Class A common stock on the grant date. The Company accounts for forfeitures as they occur. See Note 10 — Share-based Compensation (Successor) for further discussion.

In July 2025, the FASB issued Accounting Standards Update No. 2025-05, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivable and Contract Assets” (“ASU 2025-05”). ASU 2025-05 provides a practical expedient that all entities can use when estimating expected credit losses for current accounts receivable and current contract assets arising from transactions accounted for under ASC 606, Revenue from Contracts with Customers. The Company adopted ASU 2025-05 effective January 1, 2026 and elected to apply the guidance prospectively. Based on the short-term nature of the Company’s accounts receivable and contract assets, historical loss experience, and current credit risk management practices, the adoption of ASU 2025-05 did not have a material impact on the Company’s consolidated financial statements or related disclosures.

In April 2026, the FASB issued ASU 2026-01, “Equity (Topic 505): Initial Measurement of Paid-in-Kind Dividends on Equity-Classified Preferred Stock.” The ASU requires that PIK dividends on equity-classified preferred stock be initially measured on the basis of the PIK dividend rate stated in the preferred stock agreement. The standard is effective for all entities for annual reporting periods beginning after December 15, 2026, and interim reporting periods within those annual reporting periods, with early adoption permitted. The Company elected to early adopt ASU 2026-01 effective March 4, 2026 (the Closing Date of the Business Combination), using the prospective transition method. The Company has applied the guidance to the initial measurement of PIK dividends on its Series A Redeemable Preferred Stock, under which the PIK dividend rate is applied to the then-current investment amount (defined as the subscription amount plus accrued but unpaid dividends) in accordance with the Series A Certificate of Designation. The adoption of ASU 2026-01 did not have a material impact on the Company’s condensed consolidated financial statements.

In November 2024 and January 2025, the FASB issued ASU 2024-03 and ASU 2025-01, “Income Statement — Reporting Comprehensive Income — Expense Disaggregation Disclosures (Subtopic 220-40).” The amendments require disclosure, in the notes to financial statements, of specified information about certain costs and expenses included in each relevant expense caption on the face of the income statement, including the amounts of employee compensation, depreciation, depletion and amortization, and other prescribed categories. ASU 2025-01 clarified the effective date to be annual reporting periods beginning after December 15, 2026, and interim reporting periods within annual periods beginning after December 15, 2027, with early adoption permitted. The Company is currently assessing the impact this update will have on its financial statement disclosures.

In September 2025, the FASB issued ASU 2025-06, “Intangibles — Goodwill and Other — Internal-Use Software (Subtopic 350-40): Targeted Improvements.” The amendments make targeted improvements to the guidance on accounting for costs incurred in connection with internal-use software, including clarification of which development costs should be capitalized versus expensed. The standard is effective for annual reporting periods beginning after December 15, 2027, with early adoption permitted. The Company is currently assessing the impact this update will have on its financial statements.

The following table summarizes the total consideration transferred to the EQVR unitholders:

The following table summarizes the recognized amounts of identified assets acquired and liabilities assumed:

Set forth below are the summarized amounts, terms and gross fair values of outstanding commodity derivative instruments as of December 31, 2025 (Predecessor):