Exhibit 99.3

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF PRESIDIO INVESTMENT HOLDINGS LLC

The following discussion and analysis provide information that the management of Presidio Investment Holdings LLC (referred to as the “Company”, “we”, “us”, “our” and “PIH”) believes is relevant to an assessment and understanding of PIH’s consolidated results of operations and financial condition. The discussion and analysis should be read together with the section of this proxy statement/prospectus entitled “Summary Historical Consolidated Financial Information of PIH”, PIH’s audited consolidated financial statements as of and for the years ended December 31, 2025 and 2024 and the related notes thereto included elsewhere in this Current Report on Form 8-K.

This discussion includes forward-looking statements based on current expectations and projections. These statements involve risks and uncertainties, and actual results could differ materially from those discussed. A detailed description of potential risk factors can be found under “Risk Factors — Risks Related to PIH and to Presidio’s Business Following the Business Combination” and elsewhere in this proxy statement/prospectus.

Overview

PIH is an independent energy company headquartered in Texas and founded in 2017. The Company is primarily engaged in oil and gas exploration and production, with operations concentrated across the Western Anadarko Basin of Texas, Oklahoma, and Kansas. The Company’s strategy is centered on acquiring existing producing assets and applying engineering expertise to enhance performance and extend asset life. The proven business model is designed to create sustainable value by investing in long-lived reserves, reducing emissions, improving asset integrity, and generating consistent, hedge-protected cash flow. Unlike many peers focused on new resource development, PIH maximizes value by fully exploiting existing reserves — safely and efficiently operating wells to extend their productive lives and economic contribution.

Management places emphasis on operating cash flow in managing the business as operating cash flow considers the cash expenses incurred during the period and excludes non-cash expenditures not directly related to operations.

Key Factors Affecting Performance

PIH’s revenues, cash flows from operations and future growth depend substantially upon:

In addition to the factors that affect companies in the industry generally, the Company’s operating results are subject to factors specifically impacting the areas of operation in Texas, Oklahoma, and Kansas. These factors include the potential adverse impact of weather on production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect this region.

Market Conditions

Commodity price fluctuations can materially affect the value of oil and natural gas reserves, as well as revenues and cash flows, regardless of operating performance. Future movements in oil, natural gas, and natural gas liquids (“NGLs”) prices are inherently unpredictable, and historically such prices have been highly volatile. Management expects this volatility to continue. To mitigate a portion of its exposure to commodity price swings and basis differentials, the Company utilizes derivative instruments.

The oil and natural gas industry is subject to numerous risks and uncertainties. Actual results may differ materially due to factors including, but not limited to, fluctuations in commodity prices; shifts in supply and demand; regulatory changes; economic conditions; competitive dynamics; capital availability; weather; depletion rates of existing oil and natural gas wells; customers’ willingness to invest in new development; and geopolitical events.

Current uncertainties impacting market conditions include the ongoing war in Ukraine, conflict in the Middle East, interest rate volatility, global and regional supply chain disruptions, and the potential imposition of new tariffs. Additional pressures such as OPEC+’s decision to increase production beginning in November 2025, concerns over a potential economic slowdown or recession, and instability in the financial sector have contributed to recent pricing volatility and are expected to continue influencing markets beyond 2025.

At the local level, the Company remains dependent on the reliability and performance of infrastructure required to gather, process, and transport its crude oil, natural gas and NGLs.

Pursuant to the terms of its ABS II Notes, the Company is required to employ a hedging strategy in which we, at all times, maintain 24 months of commodity hedges in an amount not less than 85% of the projected production of oil, natural gas and NGLs, limiting downside risk from material change in commodity prices. Even so, the remainder of the Company’s unhedged production exposed to commodity price volatility would negatively impact the Company’s results of operations if commodity prices were to decline materially from current levels.

PIH’s price hedging strategy and future hedging transactions will be determined at management’s discretion, subject to terms of certain agreements governing the Company’s indebtedness. The prices at which the Company hedges future production will depend on prevailing commodity prices at the time such transactions are executed, which may be significantly higher or lower than current levels. Accordingly, while the hedging strategy provides downside protection against commodity price volatility, it may also limit upside during periods of rising prices.

Prices for various quantities of oil, natural gas and NGLs that are produced significantly impact revenues and cash flows. The following table summarizes average commodity prices for the periods presented with Henry Hub on a per Mcf basis, and with Mont Belvieu and WTI on a per barrel of oil basis:

Commodity Prices

WTI Oil Pricing

For the year ended December 31, 2025, the average WTI price was $64.87 per barrel, down 15% from the average of $76.63 per barrel for the year ended December 31, 2024. Settled derivatives reduced realized oil prices by $6.48 per barrel and $15.52 per barrel for the years ended December 31, 2025 and 2024, respectively.

Henry Hub Natural Gas Pricing

The average Henry Hub natural gas price was $3.43 per Mcf for the year ended December 31, 2025, up 56% from $2.19 per Mcf for the year ended December 31, 2024. Settled derivatives reduced realized gas prices by $0.46 per Mcf and increased realized gas prices by $0.09 per Mcf for the years ended December 31, 2025 and 2024, respectively.

Mont Belvieu NGLs Pricing

The average Mont Belvieu NGL price was $26.76 per Boe for the year ended December 31, 2025, an 18% decrease from $32.68 per Boe for the year ended December 31, 2024. Settled derivatives reduced realized NGL prices by $4.19 per Boe and increased realized NGL prices by $1.79 per Boe for the years ended December 31, 2025 and 2024, respectively.

Results of Operations

The following tables set forth the results of operations for the years ended December 31, 2025 and 2024. Average sales prices are derived from accrued accounting data for the relevant period indicated. Due to normal production declines and the effects of acquisitions, the historical information presented below should not be interpreted as indicative of future results.

Sources of Our Revenue

Our revenues are primarily generated from the sale of oil, natural gas and NGLs produced from our operated and non-operated wells. Oil is sold at the wellhead under index-based contracts, while natural gas is delivered to third-party midstream processors, who gather, process, and market the product; our reported revenues are net of related gathering, processing, and transportation costs. NGLs are extracted during processing and marketed separately, with net proceeds remitted to us.

We also provide field services, including compression, construction and reclamation activities, and emissions-related services. While not material relative to upstream sales, these activities contribute incremental revenues and leverage our operating scale.

In addition, we use commodity derivative contracts to reduce exposure to volatility in oil, natural gas, and NGLs prices. The fair value of these instruments can result in realized and unrealized gains or losses that meaningfully affect reported revenues and cash flows.

Oil, Natural Gas and NGLs Sales

Total oil, natural gas and NGL revenues for the year ended December 31, 2025 were $177.8 million, a 6% decline from $189.7 million for the year ended December 31, 2024. The decline was primarily attributable to lower production volumes across all commodities and a 15% decrease in realized oil prices, partially offset by a 106% increase in realized natural gas prices. Oil, natural gas and NGL production decreased 9%, 7% and 15%, respectively, due to normal production decline, midstream outages, and elevated line pressure.

Derivative Financial Instruments

The Company recorded the following gain (loss) on derivative financial instruments in the Consolidated Statement of Operations for the periods presented:

For the year ended December 31, 2025, the total net gain on commodity derivatives was $47.2 million, as compared to a net loss of $12.5 million for the year ended December 31, 2024. This included unrealized gains on unsettled contracts of $76.0 million for the year ended December 31, 2025, as compared to a net gain of $2.5 million for the year ended December 31, 2024. This gain was partially offset by realized cash settlement losses of $28.8 million for the year ended December 31, 2025, as compared to $15.0 million for the year ended December 31, 2024.

These gains and losses are consistent with the Company’s risk management strategy. With scheduled debt principal payments central to the capital plan, the Company maintains hedge coverage levels designed to protect downside risk — even if that means forgoing upside during periods of rising prices.

Principal Components of Our Cost Structure

Our cost structure includes several categories that impact operating results in different ways. Lease operating expenses represent the direct costs of producing oil and natural gas, including labor, utilities, chemicals, and equipment maintenance. These expenses tend to fluctuate with production levels but also reflect the impact of fixed field costs that do not vary with volumes. We also incur production and ad valorem taxes, which are levied by state and local governments as a percentage of commodity revenues and assessed property values. These taxes generally move in line with product revenues.

Depreciation, depletion, and accretion are non-cash charges that reflect the consumption of our proved reserves, the depreciation of other property and equipment, and the passage of time on asset retirement obligations. General and administrative expenses consist of corporate overhead, employee compensation, and professional services that support the business and are largely fixed in nature. In addition, we incur costs directly associated with our field services revenues, including labor, maintenance, and other expenses necessary to support compression, reclamation, and emissions-related activities.

Some of these costs vary with commodity prices, some trend with production activity and type, and others primarily reflect fixed or discretionary expenditures.

Lease Operating Expenses

Lease operating expenses (“LOE”) were $73.0 million for the year ended December 31, 2025, as compared to $70.7 million for 2024. On a per Boe basis, LOE per Boe increased 15% to $9.49 per Boe for the year ended December 31, 2025, from $8.25 per Boe for 2024. The increase in LOE per Boe in 2025 is primarily due to lower production volumes over which fixed costs can be spread, and increased workover expense resulting from increased maintenance and optimization projects undertaken during 2025.

Production Taxes

Production and other taxes are paid on produced oil and natural gas based on rates established by federal, state, or local taxing authorities. In general, production and other taxes paid correlate to changes in oil, natural gas and NGL revenues. Production taxes are based on the sales value of production at the wellheads. For the year ended December 31, 2025, production taxes declined to $9.8 million ($1.27 per Boe) from $10.3 million ($1.21 per Boe) for 2024, primarily due to lower revenues.

Ad Valorem Taxes

PIH’s properties in Oklahoma, Texas and Kansas are also subject to ad valorem taxes in the counties where the production is located. Ad valorem taxes are based on the fair market value of mineral interests for producing wells.

For the year ended December 31, 2025, ad valorem taxes increased to $5.5 million ($0.71 per Boe) from $5.2 million ($0.61 per Boe) for 2024. The increase was primarily attributable to changes in assessed property valuations and local ad valorem tax rates.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) for the year ended December 31, 2025 was $31.7 million, or $4.12 per Boe, compared to $37.2 million, or $4.34 per Boe, for 2024. DD&A per Boe decreased due to a lower depletion rate, primarily due to net upward revisions from higher SEC gas prices.

General and Administrative

General and administrative (“G&A”) expense for the year ended December 31, 2025 was $28.4 million, as compared to $8.0 million for 2024. The increase was primarily due to a $15.0 million Class B unit compensation payout triggered by distribution hurdles achieved during the period, as well as increased acquisition and transaction costs. There was no Class B unit compensation payout for 2024.

Interest Expense

Interest expense for the year ended December 31, 2025 was $24.5 million, as compared to $27.2 million for 2024. The decrease reflects lower average debt outstanding during 2025 as a result of principal repayments made on the Company’s ABS facility throughout the year.

Non-GAAP Financial Measures

Adjusted EBITDA

We present the supplemental non-GAAP financial performance measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income, our most directly comparable financial measure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income before (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized loss (gain) on derivative instruments, (4) non-recurring compensation expense related to our Class B Units, (5) (gain) loss on sale of assets, net, and (6) certain other non-cash or non-recurring charges, as detailed in the reconciliation table below.

Adjusted EBITDA is used as a supplemental financial performance measure by PIH management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to evaluate our operating performance and PIH’s results of operation from period to period and against our peers without regard to financing methods, capital structure or historical cost basis. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these items and related amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA is not a measurement of our financial performance under GAAP and should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as indicators of our operating performance. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDA. Our presentation of Adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual items. Our computations of Adjusted EBITDA may not be identical to other similarly titled measures of other companies.

Adjusted Unhedged EBITDA

We also present Adjusted Unhedged EBITDA, which we define as Adjusted EBITDA further adjusted to remove realized gains and losses on derivative instruments. This measure is intended to show our operating results without the impact of our hedging program. Adjusted Unhedged EBITDA is a supplemental non-GAAP measure and may not be comparable to similarly titled measures of other companies.

Reconciliations of GAAP Financial Measures to Adjusted EBITDA

The following table presents our reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure Adjusted EBITDA, as applicable, for each of the periods indicated.

Reconciliation of PV-10 to Standardized Measure

Certain of our oil and natural gas reserve disclosures included in this proxy statement/prospectus are presented on a PV-10 basis. PV-10 is a non-GAAP financial measure and represents the estimated present value of the future cash flows less future development and production costs from our proved reserves before income taxes discounted using a 10% discount rate. PV-10 of proved reserves generally differs from the standardized measure of discounted future net cash flows from production of proved oil and natural gas reserves (the “Standardized Measure”) because it does not include the effects of future income taxes, as is required in computing the Standardized Measure. However, our PV-10 for proved reserves using SEC pricing and the Standardized Measure of proved reserves are substantially equivalent because we were not subject to entity level taxation. Accordingly, no provision for federal or state income taxes has been provided in the Standardized Measure because taxable income is passed through to our unitholders.

We believe that the presentation of a pre-tax PV-10 value provides relevant and useful information because it is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and natural gas companies. Because many factors that are unique to each individual company may impact the amount and timing of future income taxes, the use of PV-10 value provides greater comparability when evaluating oil and natural gas companies. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of proved oil and gas reserves. However, the definition of PV-10 value as defined above may differ significantly from the definitions used by other companies to compute similar measures. As a result, the PV-10 value as defined may not be comparable to similar measures provided by other companies.

Investors should be cautioned that neither PV-10 nor Standardized Measure of proved reserves represents an estimate of the fair market value of our proved reserves. We and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities.

Liquidity and Capital Resources

Overview

PIH’s primary sources of liquidity are cash generated from operations and borrowings under its asset-backed securitizations (ABS) and credit facilities. These long-term, fixed-rate, fully amortizing ABS structures are secured by certain oil and natural gas assets providing stable borrowing costs and gradual leverage reduction over time through scheduled principal payments. Restricted cash, held in accounts established under the ABS debt agreements, is reserved primarily for scheduled interest and principal payments and not available for general corporate purposes. Credit facilities are used to supplement liquidity, subject to customary conditions, and primarily address the Company’s short-term working capital needs.

Debt Facilities and Covenant Compliance

As of December 31, 2025, outstanding borrowings under the ABS II Notes totaled $266.9 million, and $2.3 million was outstanding under the Trail Dust advancing term loan. Additionally, $3.5 million was drawn on the WAB RBL which was established during the third quarter of 2025. As of December 31, 2025, we were in compliance with all covenants under the ABS II Notes, the Trail Dust Loan and the WAB RBL, and we expect to remain in compliance for at least the next twelve months.

Future Liquidity Outlook

We expect our liquidity sources will be sufficient to meet operating and financing needs, including scheduled debt service, anticipated capital expenditures, and working capital requirements, for at least the next twelve months. Future liquidity will depend on commodity price realizations, production volumes, and hedge settlements. Sustained changes in commodity prices or operating costs may influence our cash flow generation and could require adjustments to our capital allocation priorities, including the pace of reinvestment, distribution levels, or financing strategy.

Working Capital

The Company monitors working capital to ensure adequate levels for operations, with excess cash primarily allocated to equity distributions. In addition to working capital management, the Company maintains a disciplined approach to operating cost control and capital allocation, with a focus on reinvesting capital into its operations and generating returns that support strategic business initiatives.

As of December 31, 2025, PIH had cash and cash equivalents of $4.1 million in addition to $11.2 million held in restricted cash required as part of its ABS securitized debt to fund interest payments. As of December 31, 2024, PIH had cash and cash equivalents of $88.8 million and restricted cash of $13.5 million. The decrease in cash from December 31, 2024 to December 31, 2025 was primarily due to distributions to Class A and B unitholders following the sale of certain undeveloped properties.

Capital expenditures totaled $4.2 million for the year ended December 31, 2025, compared to $3.5 million for 2024. The increase was primarily driven by higher spending on operated capital workovers, partially offset by lower leasehold additions, as the prior year included the acquisition of additional working interests. PIH expects to meet its capital expenditure needs for the foreseeable future through operating cash flow and existing cash and cash equivalents.

Future capital requirements will depend on several factors, including the Company’s growth trajectory, acquisition activity, and other strategic considerations.

On July 2, 2025, the Company, through Presidio WAB LLC as borrower and Presidio Investment Holdings LLC as guarantor, entered into a Reserve Based Lending instrument with SouthState Bank (“WAB RBL”). The facility provides additional liquidity with an initial borrowing base of $7.5 million, subject to periodic redeterminations, and matures on July 2, 2028. Subsequent to year-end, the borrowing base was increased to $10.0 million through April 1, 2026, at which point it will revert to $7.5 million or be reset in connection with the next scheduled redetermination. This RBL supplements the Company’s existing sources of liquidity and further supports management’s assessment that the Company will be able to satisfy working capital requirements, debt service obligations, and planned capital investments during the look-forward period. However, the Company’s ability to satisfy working capital requirements, debt service obligations, and planned capital investments will ultimately depend on future operating performance, which is subject to prevailing economic conditions in the oil and natural gas industry and other factors beyond management’s control.

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 capital markets at economic terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, 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 the next twelve months and for the foreseeable future.

Cash Flows

Our cash flows for the year ended December 31, 2025 and December 31, 2024:

Operating Activities

Net cash provided by operating activities for the year ended December 31, 2025, decreased $40.5 million as compared to 2024, primarily driven by a $45.0 million decline in net income. Non-cash adjustments were relatively flat year over year, as a $73.5 million increase in unrealized derivative gains was largely offset by a $77.1 million reduction in gains on asset sales.

Investing Activities

Net cash provided by investing activities decreased by $78.9 million for the year ended December 31, 2025, as compared to 2024. This is primarily due to proceeds received from asset divestitures totaling $8.5 million for 2025 compared to proceeds received from asset divestitures of $87.0 million for 2024.

Financing Activities

Net cash used in financing activities increased by $47.0 million for the year ended December 31, 2025, as compared to 2024, primarily as a result of $60.0 million paid in member distributions in the first quarter of 2025. The distribution was partially offset by reduced ABS principal repayments.

Known Contractual and Other Obligations

Contractual Obligations and Contingent Liabilities and Commitments

The Company has various contractual obligations arising in the normal course of operations and financing activities. These include commitments under the ABS II Notes, which require periodic principal and interest payments (see Note G to the Consolidated Financial Statements). PIH also has contractual obligations that may result in payments upon settlement of commodity derivative contracts (see Note D to the Consolidated Financial Statements). Additionally, the Company maintains both short-term and long-term lease obligations, primarily related to vehicle leases and office facilities (see Note I to the Consolidated Financial Statements).

The Company’s other liabilities represent current and noncurrent other liabilities that are primarily comprised of environmental contingencies, asset retirement obligations and other obligations for which neither the ultimate settlement amounts nor their timings can be precisely determined in advance. See Note C and Note J of Notes to the Consolidated Financial Statements.

Off-balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

Critical Accounting Estimates

The Company’s most significant accounting estimates are interconnected and primarily relate to its oil and natural gas properties. Central to these estimates are proved reserve quantities, which are inherently uncertain and require significant judgment regarding future commodity prices, operating and development costs, and recovery factors. These reserve estimates directly affect the application of the successful efforts method of accounting, as they drive the calculation of depletion under the unit-of-production method, and they also influence impairment assessments, since downward revisions or adverse pricing may reduce expected cash flows below carrying values. Accordingly, fluctuations in commodity prices or reserve estimates can have a material impact on depletion expense, potential impairment charges, and ultimately the Company’s reported financial results. These estimates are described in more detail in the following sections.

Successful Efforts Method of Accounting for Oil and Natural Gas Properties

The Company utilizes the successful efforts method of accounting for its oil and natural 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 net future cash flow. When a property is impaired, the carrying value is reduced to the future net cash flow and an impairment charge of the difference between cost and future net cash flow 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.

Applying the unit-of-production method for depletion and assessing the recoverability of our oil and natural gas properties for impairments requires the use of estimates as it relates to oil and natural gas reserves, as described more fully below.

Proved Reserve Estimates

Estimates of the Company’s proved reserves included in this proxy statement/prospectus are prepared in accordance with GAAP and SEC guidelines. The accuracy of a proved reserve estimate is a function of:

The Company’s proved reserve information as of December 31, 2025 and 2024, was prepared by independent petroleum engineers. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, proved reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.

It should not be assumed that the Standardized Measure as of December 31, 2025 and 2024, is the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the standardized measure on a twelve-month average of commodity prices on the first day of each month in each respective year and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See Note N of Notes to the Consolidated Financial Statements for additional information.

The Company’s estimates of proved reserves impact depletion expense. If the estimates of proved reserves decline, the rate at which the Company records depletion expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of the Company’s assessment of its proved properties for impairment.

Impairment of Long-Lived Assets

The carrying value of proved oil and natural gas properties, saltwater 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. All of the oil and natural gas properties owned by the Company are geographically oriented in a single basin; therefore, the Company evaluates impairment of oil and natural gas properties on an aggregated basis. No impairment was recorded during the years ended December 31, 2025 or 2024. See Note B of Notes to the Consolidated Financial Statements for additional information.

New Accounting Pronouncements

The effects of new accounting pronouncements are discussed in Note B of Notes to the Consolidated Financial Statements.

Quantitative and Qualitative Disclosures about Market Risk

The Company is exposed to various financial risks, including market risk, credit risk, liquidity risk, capital risk, and collateral risk. To manage these risks, the Company continuously monitors the unpredictability of financial markets and seeks to minimize potential adverse effects on its financial performance.

The Company’s principal financial liabilities consist of borrowings, leases, and trade and other payables, which are primarily used to finance and provide financial guarantees for its operations. The Company’s principal financial assets include cash and cash equivalents, as well as trade and other receivables derived from its operations.

Additionally, the Company also enters into derivative financial instruments, which are recorded as assets or liabilities depending on market dynamics. The Company leverages its internal resources to design and manage its derivative-related risk management activities, but also engages with third party providers to assist with the execution of derivative transactions and provide commodity trading and risk management applications.

Market Risk

Market risk refers to the possibility that the fair value of future cash flows of a financial instrument will fluctuate due to changes in market prices. Market risk is comprised of two main types of risk: interest rate risk and commodity price risk. Financial instruments affected by market risk include borrowings and derivative financial instruments.

To manage market price risks resulting from changes in commodity prices and foreign exchange rates, the Company uses both derivative and non-derivative financial instruments. These instruments help mitigate the potential negative effects on the Company’s assets, liabilities, or future expected cash flows.

Interest Rate Risk

The Company is subject to market risk exposure related to changes in interest rates. The Company’s borrowings primarily consist of fixed-rate amortizing notes and variable-rate credit facilities, as illustrated below.

The ABS II Notes are fixed-rate instruments and therefore not exposed to market interest rate fluctuations, whereas the Trail Dust Loan and WAB RBL credit facilities bear interest at floating rates. A hypothetical 100 basis point change in interest rates to the credit facilities would result in an annual change to interest expense as illustrated below:

The Company strives to maintain a prudent balance of floating and fixed-rate borrowing exposure, particularly during uncertain market conditions. As part of its risk mitigation strategy, the Company may enter into swap arrangements to adjust its exposure to floating or fixed interest rates, depending on changes in the composition of borrowings in its portfolio. Consequently, the use of derivative financial instruments to hedge principal balances may vary from period to period. As of the periods presented, the Company did not currently have outstanding interest rate hedges in place. For additional information regarding the ABS II Notes, WAB RBL and Trail Dust Loan, refer to Note G — Long-Term Debt.

Commodity Price Risk

The Company’s revenues are primarily derived from the sale of oil, natural gas and NGLs, which exposes the Company to commodity price risk. Prices for these commodities can be volatile and may fluctuate due to changes in supply and demand, weather conditions, economic conditions, and government actions. Prolonged changes in commodity prices could materially affect our revenues, cash flows and the value of our reserves.

To mitigate the risk of fluctuations in commodity prices, the Company enters into derivative financial instruments, primarily fixed-price swaps. Under the terms of our ABS debt agreements, we are required to maintain at all times a 24-month rolling hedge position covering at least 85% of projected production of oil, natural gas, and NGLs until the earlier of the Final Scheduled Payment Date or the redemption of the Notes.. These hedges reduce, but do not eliminate, exposure to commodity price volatility and may also limit the benefits we receive from price increases.

By removing price volatility from a substantial portion of our expected production through 2032, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flows. For additional information regarding derivative financial instruments, refer to Note D — Derivative Activities.

Credit and Counterparty Risk

The Company is exposed to credit and counterparty risk from the sale of its oil, natural gas and NGLs production. Accounts receivable, oil and natural gas represent amounts due from purchasers of these commodities, and their collectability depends on the financial condition of each customer. The Company evaluates the financial condition of customers before extending credit and generally does not require collateral. As of December 31, 2025 and 2024, four customers each accounted for more than 10% of the Company’s commodity revenues, and a similar concentration existed in receivable balances at year-end. No other customer accounted for more than 10% of total accounts receivable, oil and natural gas in either year.

The Company is also exposed to credit risk from joint interest owners, which are entities that own a working interest in the properties operated by the Company. Accounts receivable, joint interest owners are classified within current assets in the Consolidated Balance Sheets, net of any allowances for credit losses. A portion of our credit risk is mitigated by the Company’s ability to withhold future revenue distributions to recover amounts due.

The Company believes these receivable balances are collectible. For additional information, refer to Note B — Summary of Significant Accounting Policies.

Collateral Risk

As of December 31, 2025 and 2024, the Company has pledged substantially all of its upstream oil and natural gas properties, along with certain midstream assets, to secure borrowings under its debt instruments. The fair value of the collateral is based on reserve estimates prepared by an independent petroleum engineering firm, which utilize estimated future cash flows discounted at 10% and commodity futures pricing. These pledged assets secure repayment obligations under the Company’s ABS II Notes, WAB RBL and Trail Dust Loan.

For additional information regarding acquisitions and borrowings, refer to Note G — Long-Term Debt.