Epsilon Energy Ltd.

Our consolidated balance sheets as of December 31, 2025 and 2024, and the consolidated statements of operations and comprehensive income, changes in shareholders’ equity and cash flows for years ended December 31, 2025 and 2024 included in this annual report have been prepared in accordance with U.S. GAAP.

Shareholders and Board of Directors

Epsilon Energy Ltd.

Houston, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Epsilon Energy Ltd. (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of operations and comprehensive income, changes in shareholders’ equity, and cash flows for each of the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2025 and 2024, and the results of its operations and its cash flows for the years then ended**,** in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Estimation of Future Production Volumes Used to Estimate Proved Oil and Natural Gas Reserves and the Associated Effect on Depreciation, Depletion and Amortization (“DD&A”) Expense Related to Proved Oil and Natural Gas Properties

As described in Note 3 to the consolidated financial statements, the Company uses the successful efforts method of accounting for its oil and natural gas producing activities which involves management making significant estimates, including estimating the future production volumes of proved oil and natural gas reserves. As disclosed in Note 5, the Company’s oil and natural gas properties, net balance as of December 31, 2025 was $181 million, which includes proved

oil and natural gas properties of $233.3 million and accumulated depletion, amortization and impairment of $131.6 million. Depletion, depreciation, amortization, and accretion expense was $12.2 million for the year ended December 31, 2025.

We have identified the estimation of future production volumes used to estimate proved oil and natural gas reserves and the associated effect on DD&A expense related to proved oil and natural gas properties as a critical audit matter. Estimating future production volumes involves a high degree of subjectivity from management and their independent petroleum engineers. Changes in this estimate could have a significant effect on the measurement of DD&A expense. Auditing the estimation of future production volumes required subjective and complex auditor judgment.

The primary procedures we performed to address this critical audit matter included:

Estimation of Future Production Volumes Used to Estimate Fair Value of the Acquired Proved Oil and Gas Properties in the Peak Acquisition

As described in Note 4 to the consolidated financial statements, on November 14, 2025, the Company completed an acquisition of Peak E&P, LLC and Peak BLM, LLC (“Peak Acquisition”) for a total consideration of $88.5 million. In connection with the Peak Acquisition, the Company recognized proved oil and gas properties of $47.9 million. To determine the acquisition date fair value of the oil and gas properties, management used internal engineers to make significant estimates, including estimating the future production volumes of the acquired oil and gas reserves.

We have identified the estimation of future production volumes used to estimate the fair value of the acquired proved oil and gas properties in the Peak Acquisition as a critical audit matter. Estimating future production volumes involves a high degree of subjectivity from management and their internal petroleum engineers. Changes in this estimate could have a significant effect on the fair value of the acquired oil and natural gas properties. Auditing the estimation of future production volumes requires subjective and complex auditor judgement.

The primary procedures we performed to address this critical audit matter included:

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We have served as the Company’s auditor since 2017.

Houston, Texas

March 27, 2026

Consolidated Statements of Operations and Comprehensive Income

Consolidated Statements of Changes in Shareholders’ Equity

Notes to the Consolidated Financial Statements

1. Description of Business

Epsilon Energy Ltd. (the “Company” or “Epsilon” or “we”) was incorporated under the laws of the Province of Alberta, Canada on March 14, 2005. On February 14, 2019, Epsilon’s registration statement on Form 10 was declared effective by the United States Securities and Exchange Commission and on February 19, 2019, we began trading in the United States on the NASDAQ Global Market under the trading symbol “EPSN.” Epsilon is a North American on-shore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves.

2. Basis of Preparation

Principles of Consolidation

The Company’s consolidated financial statements include the accounts of the Company and its wholly owned subsidiary, Epsilon Energy USA, Inc. and its wholly owned subsidiaries, Epsilon Midstream, LLC, Epsilon Operating, LLC, Dewey Energy GP, LLC, Peak Exploration & Production LLC, Peak BLM Lease LLC, Peak Powder River Resources, LLC, Peak Energy Operating #2, LLC, Willow Springs Development, LLC, Peak Powder River Acquisition, LLC and Altolisa Holdings, LLC. With regard to the gathering system, in which Epsilon owns an undivided interest in the asset, proportionate consolidation accounting is used. All inter-company transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. 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. The most significant estimates pertain to proved natural gas reserves and related cash flow estimates used in impairment tests of oil and natural gas and gathering system properties, asset retirement obligations, accrued natural gas and oil revenues and operating expenses, accrued gathering system revenues and operating expenses, as well as the valuation of commodity derivative instruments. Actual results could differ from those estimates.

3. Summary of Significant Accounting Policies

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents includes cash on hand and short term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.

Restricted cash consists of amounts deposited to back bonds or letters of credit. The Company presents restricted cash with cash and cash equivalents in the Consolidated Statements of Cash Flows.

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported in the Consolidated Balance Sheets to the total of the amounts in the Consolidated Statements of Cash Flows as of December 31, 2025 and 2024:

Oil and Natural Gas Properties

Epsilon accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting.

Oil and natural gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and natural gas properties. Lease delay rentals are expensed as incurred.

Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether Epsilon has discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized (see Note 5).

Depreciation, depletion and amortization of the cost of proved oil and natural gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.

When circumstances indicate that proved (developed and undeveloped) oil and natural gas properties may be impaired, Epsilon compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the carrying value of the asset. If the expected undiscounted future cash flows, based on Epsilon’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the carrying value of the asset, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach which considers estimated discounted future cash flows. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable.

Gas Gathering System Properties

Epsilon’s 35% portion of asset development costs are capitalized when incurred. All other costs are expensed.

Depreciation, depletion and amortization of the cost of gathering system properties is calculated using the unit-of- production method. The reserve base used to calculate depreciation, depletion and amortization for the gathering system includes only proved Pennsylvania natural gas developed reserves.

When circumstances indicate that the gathering system properties may be impaired, Epsilon compares expected undiscounted future cash flows related to the gathering system to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach, which considers estimated discounted future cash flows.

Revenue Recognition

Revenues are comprised primarily of sales of natural gas, crude oil and NGLs, along with the revenue generated from the Company’s ownership interest in the gas gathering system in the Auburn field in Pennsylvania.

Revenue recognition is evaluated through the following five steps: (i) identification of the contract, or contracts, with a customer; (ii) identification of the performance obligations in the contract; (iii) determination of the transaction

price; (iv) allocation of the transaction price to the performance obligations in the contract; and (v) recognition of revenue when or as a performance obligation is satisfied.

Accounting Policies

Revenue is recognized when performance obligations under the terms of a contract with a customer are satisfied. The Company recognizes upstream revenue at the point in time when control has been transferred to the customer, generally at the time natural gas reaches an agreed-upon delivery point and collectability is reasonably assured. Upstream revenue is based upon a fixed price, based on market pricing, and is measured as the amount of consideration the Company expects to receive in exchange for the transferring of the natural gas and oil. The services provided by the gas gathering system take place continuously and as a practical expedient, the revenues are recognized monthly for the volumes that are processed and transported for the upstream producers during that period of time. Revenue for the services performed are based on the rates outlined in the Anchor Shipper Gas Gathering Agreement for Northern Pennsylvania (the “ASGGA”) effective January 1, 2024 that governs all volumes gathered and processed by the system. The gathering rate is fixed, but is adjusted annually by the Consumer Price Index for All Urban Consumers (“CPI-U”) as published by US Bureau of Labor Statistics. Typically, the Company sells its natural gas directly to customers, under agreements with payment terms less than 30 days after delivery and 60 days on the revenue generated by the gas gathering system. For operated assets in Wyoming, payment is received within 30 days after the end of a month for oil and 60 days after the end of the month for natural gas and NGLs.

Natural Gas Revenues

The Company’s natural gas purchase contracts are generally structured such that Epsilon commits and dedicates for sale its proportionate share of natural gas production per day to a purchaser. Natural gas is sold at market prices. Control transfers at the delivery point specified in the contract, which typically is stated as the inlet of the third-party sales transportation pipeline. The Company recognizes revenue proportionate to its entitled share of volumes sold. Currently, the vast majority of Epsilon’s natural gas production comes from the Appalachian Basin in Pennsylvania.

Epsilon uses a third-party service for its natural gas marketing. In this capacity, the third-party is responsible for carrying out marketing activities such as submission of nominations, receipt of payments, submission of invoices and negotiation of contracts. Commissions payable to the third-party broker for these services are treated as lease operating expenses in the financial statements.

For the Company’s operated assets in Wyoming, revenues from the sale of natural gas and NGLs are recognized, as the product is delivered to the customers’ custody transfer points and collectability is reasonably assured. The Company fulfills the performance obligations under the customer contracts through daily delivery of natural gas and NGLs to the customers’ custody transfer points. Revenues are recorded on a monthly basis using the prices received under the Company’s contracts. These contracts are generally derived from stated market prices which are adjusted to reflect deductions, including transportation, fractionation and processing. As a result, the revenues from the sale of natural gas and NGLs are subject to change with the increase or decrease in market prices. As a result, the sale of natural gas and NGLs, as presented on the consolidated statements of operations, represent the Company’s share of revenues, net of gathering and processing costs, net of royalties and excluding revenue interests owned by others. When selling natural gas and NGLs on behalf of royalty owners or working interest owners, the Company acts as an agent and therefore reports the revenue on a net share basis. To the extent actual volumes and prices of natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Historically, differences between revenue estimates and actual revenue received have not been significant.

The majority of product sale commitments of the Company are short term in nature with a contractual term of one year or less. For these contracts, the Company applies the practical expedient in Accounting Standards Codification (“ASC”) 606-10-50-14, which exempts entities from disclosing the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.

For contracts with terms greater than one-year, the Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in ASC 606-10-50-14A,

which applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Gas Gathering System Revenue

The Company has a 35% ownership interest in the Auburn GGS. This system aggregates the natural gas from the various pads in the field and transports the natural gas to the inlet of the Auburn CF where it is dehydrated, compressed and injected into the Tennessee Gas Pipeline. The gathering and compression services operate under fee-based contracts. The producers in the area served by the gathering system pay fees to the system owners based on the services provided to them in getting their share of the gas production to the third-party sales transmission point. Revenue is recognized over time as the services are provided.

Oil and Natural Gas Liquids Revenue

The source of the Company’s oil and natural gas liquids revenue is its ownership in wells in Wyoming, the Permian Basin, and Alberta, Canada. With the exception of Wyoming, the Company does not operate the wells and has elected not to receive its proportionate share of the production. As such, under the Joint Operating Agreement, the operators have control of the marketing of this production at current market prices and remits our net revenue interest less taxes and fees on a monthly basis. The Company recognizes revenue with a monthly accrual of its proportionate share of volumes produced at an estimated market price.

For the Company’s operated assets in Wyoming, revenue from the sale of oil and natural gas liquids are recognized, as the product is delivered to the customers’ custody transfer points and collectability is reasonably assured. The Company fulfills the performance obligations under the customer contracts through daily delivery of oil and natural gas liquids to the customers’ custody transfer points. Revenues are recorded on a monthly basis using the prices received under the Company’s contracts. These contracts are generally derived from stated market prices which are adjusted to reflect deductions, including transportation, fractionation and processing. As a result, the revenues from the sale of oil and natural gas liquids are subject to change with the increase or decrease in market prices. As a result, the sales of oil and natural gas liquids, as presented on the consolidated statements of operations, represent the Company’s share of revenues, net of gathering and processing costs, net of royalties and excluding revenue interests owned by others. When selling oil and natural gas liquids on behalf of royalty owners or working interest owners, the Company acts as an agent and therefore reports the revenue on a net share basis. To the extent actual volumes and prices of oil and natural gas liquids sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Historically, differences between revenue estimates and actual revenue received have not been significant.

The majority of product sale commitments of the Company are short term in nature with a contractual term of one year or less. For these contracts, the Company applies the practical expedient in Accounting Standards Codification (“ASC”) 606-10-50-14, which exempts entities from disclosing the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.

For contracts with terms greater than one-year, the Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in ASC 606-10-50-14A, which applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Accounts Receivable

Oil, natural gas liquid and natural gas receivables consist of amounts due from purchasers or operators for commodity sales from our revenue interest in the leases in Pennsylvania, Wyoming, the Permian Basin, and Alberta, Canada. Payments from purchasers are typically due by the last day of the month following the month of delivery. Gathering fee revenue consists of fees due from the operator of the Auburn GGS, as an agent for the Company fulfilling the operations of the gathering system. Payments from the operator are typically due 60 days from the last day of the month

of transmission. The Company’s operations do not result in any contract assets or liabilities on the accompanying consolidated balance sheets.

For its operated assets in Wyoming, the Company accrues for oil, natural gas and natural gas liquids sales based on actual production dates. These are due within 45 days of production for oil and 60 days for natural gas and other liquids. To the extent the Company has joint interest owners in properties, joint interest billings represent monthly billings to working interest owners in the properties the Company operates. Joint interest billings are due within 30 days, with a right of offset against revenues due to working interest owners in the respective properties. The Company monitors the creditworthiness of its counterparties by reviewing credit ratings, financial statements, and payment history.

Buildings and Other Property and Equipment

Buildings are depreciated on a straight-line basis over the estimated useful life of the property,30 years. The Company’s office building in Durango is stated at cost and depreciated over the estimated useful life of 25 years using straight-line method.

Other property and equipment consists of computer hardware and software, and furniture and fixtures. Other property and equipment is generally depreciated on a straight-line basis over the estimated useful lives of the property and equipment, which range from 3 years to 7 years.

Financial Instruments and Fair Value

Epsilon’s financial instruments consist of cash and cash equivalents, restricted cash, commodity derivative contracts, accounts receivable, accounts payable, and long term debt.

The Company classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instrument.

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

Level 3—Valuations in this level are those with inputs for the asset or liability that are not based on observable market data. The Company makes its own assumptions about how market participants would price the assets and liabilities.

Cash, restricted cash, accounts receivable, and accounts payable are carried at cost, which approximates fair value because of the short term maturity of these instruments. Cash equivalents are carried at fair value. The Company’s revolving line of credit has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates and the applicable margins represent market rates. The revolving line of credit is classified within Level 2 of the fair value hierarchy.

Commodity derivative instruments consist of NYMEX HH and NYMEX WTI CMA swaps and options as well as basis swap contracts for natural gas. The Company’s derivative contracts are valued based on a marked to market approach. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.

Derivative Instruments

The Company enters into derivative contracts to hedge price risk associated with a portion of natural gas and oil production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated, which has, and could, result in over-hedged volumes. Natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the NYMEX or the published natural gas index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. Our derivative transactions have included the following:

Derivative instruments are recorded on the consolidated balance sheets at fair value as either current or non-current assets or liabilities based on their anticipated settlement date. Gains or losses on derivative contracts are recorded as gain (loss) on derivative contracts in the consolidated statements of operations and comprehensive income. Hedge accounting is not used for our derivative assets and liabilities.

Asset Retirement Obligations

The Company records a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method of the asset’s useful life. Recognized asset retirement obligations relate to the plugging and abandonment of oil and natural gas wells and decommissioning of the gas gathering system. Management reviews the estimates of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate. These adjustments are recorded to the asset retirement obligations with an offsetting change to oil and gas properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the forecast inflation due to the passage of time, which is recorded in depreciation, depletion, amortization, and accretion expense in the consolidated statements of operations and comprehensive income.

Concentrations of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. Exposure to credit risk associated with these instruments is controlled by (i) placing assets and other financial interests with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring paying history, although the Company does not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties with a legal right of offset.

At December 31, 2025 and 2024, cash and cash equivalents were primarily concentrated in one financial institution the U.S. We currently have $8.5 million in excess of the federally insured limits. The Company periodically assesses the financial condition of these institutions and believes that any possible credit risk is minimal.

For the year ended December 31, 2025, the Company hadfive customers that accounted for more than 90% of the total trade accounts receivable. For the year ended December 31, 2024, the Company hadthree customers that accounted for 89.1% of the total trade accounts receivable.

Geographic Locations of Operations

Approximately 67% and 50% of our revenue during fiscal years 2025 and 2024, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania. Approximately 19% and 40% of our revenue during fiscal year 2025 and 2024, respectively, was derived from oil, natural gas, and natural gas liquids revenues in the state of Texas.

As a result of this geographic concentration, we may be disproportionately exposed to the effect of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of crude oil or natural gas.

Income Taxes

The Company accounts for income taxes in accordance with ASC 740, Income Taxes, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the financial statement carrying amounts and the tax bases of assets and liabilities, and for operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the periods in which those temporary differences are expected to reverse. Significant judgment is required in evaluating the realizability of deferred tax assets, including the need for and amount of any valuation allowance. (see Note 10).

Foreign Currency Transactions

Even though the Canadian dollar is the functional currency of Epsilon Energy Ltd. (the parent entity), the United States dollar is the reporting currency for all of Epsilon’s consolidated subsidiaries. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. Gains and losses on translation of balances denominated in Canadian dollars, calculated using the end of the period exchange rate, are included in accumulated other comprehensive income.

Stock Based Compensation

The Company has issued time-based restricted stock units (“RSU”), performance share units (“PSU”), and dividend equivalent rights shares (“DER”) to employees and directors of the Company. The fair value of the time-based RSU and the DER shares is determined using the fair value of the Company’s common shares on the date of grant. The fair value of the PSUs is determined by the performance requirements. The RSU and PSU awards vest ratably over athree-year period. The DER awards vest immediately. Compensation expense and a corresponding increase to additional paid in capital are recorded over the vesting period.

Leases

The Company leases office space to be used for general, administrative, and executive offices with terms typically ranging from five toseven years, subject to certain renewal options as applicable. The Company considers renewal or termination options that are reasonably certain to be exercised in the determination of the lease term and initial measurement of lease liabilities and right-of-use assets. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Interest expense for finance leases is incurred based on the carrying value of the lease liability. Leases with an initial term of 12 months or less are not recorded on the Company’s Consolidated Balance Sheets and lease agreements with lease and non-lease components are generally accounted for as a single lease component.

The Company determines whether a contract is, or contains, a lease at inception of the contract and whether that lease meets the classification criteria of a finance or operating lease. When available, the Company uses the rate implicit in the lease to discount lease payments to present value; however, most of the Company’s leases do not provide a readily determinable implicit rate. Therefore, the Company must discount lease payments based on an estimate of its incremental borrowing rate based on prevailing financial market conditions at the later of date of adoption or lease commencement, credit analysis of comparable companies and management judgments to determine the present values of its lease payments (see Note 12).

Joint Interests

The majority of the Company’s oil and natural gas exploration, development and production activities, and the gathering system, are conducted jointly with others and, accordingly, these financial statements reflect only the Company’s proportionate interest in such jointly controlled assets.

Deferred Financing Costs

The Company has deferred financing costs - upfront fees and expenses that include origination, underwriting, legal and other fees – that were incurred to secure our revolving credit facility. The fees are amortized using the straight-line method, which approximates the effective interest method, over the life of the credit facility and are recognized in our consolidated statements of operations as interest expense. The unamortized deferred financing costs related to the credit facility are reported in the consolidated balance sheets as Deferred financing costs in non-current assets.

Business Combinations

The Company accounts for business combinations in accordance with FASB ASC Topic 805, Business Combinations. The Company accounts for our acquisitions that qualify as a business using the acquisition method in which the Company recognizes and measures identifiable assets acquired, liabilities assumed, and any non-controlling interest in the acquired entity at their fair values as of the acquisition date. If the set of assets and activities acquired is not considered a business, it is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model, the cost of the acquisition, including certain transaction costs, is allocated to the assets acquired on the basis of relative fair values.

The Company includes the results of operations of acquired businesses beginning on the respective acquisition dates. In accordance with the acquisition method, the Company allocates the purchase price of an acquired business to its identifiable assets and liabilities based on the estimated fair values. The fair values of identifiable assets acquired and liabilities assumed are determined based on various valuation techniques, including market prices, discounted cash flow analysis, and independent appraisals. This fair value measurement is based on unobservable (Level 3) inputs. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. The excess value of the net identifiable assets and liabilities acquired over the purchase price of an acquired business, if any, is recorded as a bargain purchase gain. Transaction costs related to the business combination are expensed as incurred.

Recently Issued Accounting Standards

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires public entities, on an annual basis, to disclose disaggregated information about a reporting entity’s effective tax rate reconciliation, using both percentages and reporting currency amounts for specific standardized categories, as well as disclosure of income taxes paid disaggregated by jurisdiction. Effective January 1, 2025, the Company adopted ASU 2023‑09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments enhance income tax disclosures, primarily related to the effective tax rate reconciliation and income taxes paid. The Company adopted the amendments on a prospective basis. The adoption did not have a material impact on the Company’s consolidated financial statements, as the amendments relate primarily to expanded disclosures and do not change the recognition or measurement of income taxes. Because the amendments were adopted prospectively, the enhanced disclosures required by ASU 2023‑09 are provided for the year ended December 31, 2025. Prior‑year disclosures continue to be presented in accordance with the Company’s previously applied accounting guidance. See Note 9 “Income Taxes” in the Notes to Consolidated Financial Statements.

In March 2024, the FASB issued ASU No. 2024-01, Compensation – Stock Compensation (Topic 718): Scope Applications of Profits Interest and Similar Awards (“ASU 2024-01”). The amendments in ASU 2024-01 improves its overall clarity and operability without changing the guidance and adding illustrative examples to determine whether profits interest award should be accounted for in accordance with Topic 718. The guidance is effective for fiscal years beginning after December 15, 2024, and interim periods within those annual periods. The Company has adopted ASU No. 2024-01 as of December 31, 2025 with no material impact.

In November 2024, the FASB issued ASU 2024-3 "Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures." The ASU will improve the decision usefulness for investors by requiring public business entities to disclose more detailed information about their expenses such as (a) inventory and manufacturing expense, (b) employee compensation, (c) depreciation, (d) intangible asset amortization, etc. The amendments will be effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027, with early adoption permitted. The amendments will be applied prospectively with an option for a retrospective application. The Company is evaluating the impact of this new standard and believes that the adoption will result in additional disclosures, but will not have any other impact on its consolidated financial statements.

In July 2025, the FASB issued ASU 2025-05, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit losses for Accounts Receivable and Contract Assets. The amendments in this update provide (1) all entities with a practical expedient to assume that current conditions as of the balance sheet date do not change for the remaining life of the assets and (2) entities other than public business entities with an accounting policy election to consider collection activity after the balance sheet date when estimating expected credit losses for current accounts receivable and current contract assets arising from transactions accounted for under Topic 606. The amendments will be effective for fiscal years beginning after December 15, 2025, with early adoption permitted. The Company is evaluating the impact of this new standard and believes that the adoption may result in additional disclosures, but will not have any material impact on its consolidated financial statements.

4. Business Combination

During the year ended December 31, 2025, Epsilon acquired 100% of the ownership interest in Peak Exploration & Production LLC and Peak BLM Lease LLC and their subsidiaries (together, “Peak”) for total consideration of $88.5 million consisting of 1) issuance of 5,681,489 common shares valued at $27.6 million, 2) contingent consideration of up to 2,500,000 common shares valued at $10.6 million, and the settlement of $50.3 million of debt. The contingent consideration was settled on November 19, 2025, through the issuance of 2,234,847 common shares for $10.6 million. The acquired assets primarily include operated and non-operated production and leasehold interests in the core of the Powder River Basin in Wyoming.

The following table summarizes the allocation of the total purchase price to the assets acquired and liabilities assumed based on the estimated fair value as of the closing date of the acquisition.

The Company funded the acquisition through the issuance of shares and borrowings under our credit facility. The results of operations attributable to Peak since the closing date of the acquisition have been included in the consolidated statements of operations and comprehensive income and include $4 million of total revenues and a $5,747 net loss for the year ended December 31, 2025.

Pro Forma Operating Results (Unaudited)

The following supplemental, unaudited pro forma combined financial information for the year ended December 31, 2025 reflects the consolidated results of operations of the Company as if the Peak acquisition had occurred on January 1, 2024. The information below reflects pro forma adjustments based on available information and certain assumptions that the Company believes are factual and supportable. The unaudited pro forma information includes adjustments for (i) leasehold expense (ii) depreciation, depletion, amortization, and accretion, (iii) loss on impairment of long term assets, (iv) interest expense related to long term debt, and (v) loss on sale of assets. In addition, for the year ended December 31, 2025 and 2024, the pro forma information has been effected for income taxes with an effective tax rate of 6.31% and 45.79%, respectively.

The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Peak acquisition been completed as of January 1, 2024, and should not be taken as indicative of the Company's future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results.

5. Property and Equipment

The following table summarizes the Company’s property and equipment at December 31, 2025 and 2024:

Asset Acquisitions

During the year ended December 31, 2025, Epsilon hadno asset acquisitions.

During the year ended December 31, 2024, Epsilon made the following four acquisitions. Management determined that substantially all of the fair value of the gross assets acquired were concentrated in oil and gas properties and therefore accounted for these transactions as asset acquisitions and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

Property Sale

During the year ended December 31, 2025, Epsilon sold all of its interest in Dewey Energy Holding, LLC for $2.5 million. This sale resulted in a loss of $19.3 million. During the year ended December 31, 2024, Epsilon hadno asset sales.

Property Impairment

Epsilon performs a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable. When indicators of impairment are present, the Company first compares expected future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount to the estimated fair values is required. This is determined based on discounted cash flow techniques using significant assumptions including production volumes, future commodity prices, and a market-specific weighted average cost of capital which are affected by expectations about future market and economic conditions. Additionally, U.S. GAAP requires that if an exploratory well is determined not to have found proved reserves, the costs incurred, net of any salvage value, are charged to expense. For unproved properties, such as leasehold costs, expected current and future market prices for similar assets are considered relative to carrying values in evaluating impairment.

For the year ended December 31, 2025, the Company recorded an impairment of $3.2 million on the Canadian wells (2 gross,0.5 net) and $0.7 million on the New Mexico wells (2 gross,0.2 net) due to low forward oil prices on December 31, 2025 (which are required to be used in impairment testing) and an offset frac hit impacting production and reserves in New Mexico. During the year ended December 31, 2024, Epsilon recorded an impairment of $1.45 million on the Killam project (interest acquired in April 2024) in Alberta, Canada as a result of a decrease in forecasted reserves. Refer to Note 16 – Fair Value Measurements.

6. Revolving Line of Credit

The Company closed a new senior secured reserve based revolving credit facility on October 10, 2025 with Frost Bank as administrative agent and Frost Bank and Texas Capital Bank as lenders. As of December 31, 2025, the borrowing base was $80 million, supported by the Company’s producing reserves and is subject to semi-annual redeterminations with a maturity date of October 10, 2029. Interest will be charged at the 3-month Term SOFR rate plus a margin of 3-4% (depending on facility utilization), payable quarterly. The facility is secured by the assets of the Company’s Epsilon Energy USA subsidiary. During March 2026, the Company made a $5 million repayment on the outstanding credit facility.

Under the terms of the facility, the Company must adhere to the following financial covenants:

Additionally, the Company is required to hedge 50% of its forecasted Proved Developed Producing production over a rolling 18-month period. If the facility utilization drops below 50%, then the required hedging drops to 25% of Proved Developed Producing production for the last 6 months of the 18-month period.

We were in compliance with the financial covenants of the agreement as of December 31, 2025.

7. Shareholders’ Equity

Authorized shares

The Company is authorized to issue an unlimited number of common shares withno par value and an unlimited number of Preferred Shares withno par value.

Purchases of Equity Securities

On February 18, 2026, the Board authorized a new share repurchase program of up to 3,014,986 common shares, representing 10% of the outstanding common shares of the Company at such time, for an aggregate purchase price of not more than US $15.0 million. The program commenced on February 19, 2026 and is set to expire February 18, 2027, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination.

On February 12, 2025, the Board authorized a new share repurchase program of up to 2,200,876 common shares, representing 10% of the current outstanding common shares of Epsilon, for an aggregate purchase price of not more than US $13.0 million. The program commenced on February 12, 2025 and expired on February 11, 2026.

On March 19, 2024, the Board of Directors authorized a new share repurchase program of up to 2,191,320 common shares, representing 10% of the outstanding common shares of Epsilon at such time, for an aggregate purchase price of not more than US $12.0 million. The program commenced on March 27, 2024 and expired on February 12, 2025, when the Board terminated and revoked authority under the program. During the year ended December 31, 2024, we repurchased 125,000 common shares and spent $627,500 at an average price of $5.00 per share (excluding commissions) under the plan.

In 2024, the Company also repurchased 248,700 common shares and spent $1,203,708 at an average price of $4.82 per share (excluding commissions) and retired 319,574 common shares under the 2023-2024 repurchase program before the plan terminated on March 26, 2024. During the year ended December 31, 2024, the Company repurchased a total of 373,700 shares and spent $1,831,208 at an average price of $4.88 per share (excluding commissions) under the two previous repurchase programs.

Equity Incentive Plan

The Board adopted the 2020 Equity Incentive Plan (the “2020 Plan”) on July 22, 2020 subject to approval by Epsilon’s shareholders at Epsilon’s 2020 Annual General and Special Meeting of shareholders, which occurred on September 1, 2020 (the “Meeting”). Shareholders approved the 2020 Plan at the Meeting.

The 2020 Plan provides for incentive compensation in the form of stock options, stock appreciation rights, restricted stock and stock units, performance shares and units, dividend equivalent rights, other stock-based awards and cash-based awards. Under the 2020 Plan, Epsilon is authorized to issue up to 2,000,000 common shares.

Restricted Stock Unit

For the year ended December 31, 2025,488,283 restricted common shares with a weighted average grant date fair value of $4.78 were awarded to the Company’s management, employees, and board of directors. For the year ended December 31, 2024,300,052 restricted common shares with a weighted average grant date fair value of $5.97 were awarded to the Company’s management, employees, and board of directors. These shares vest over athree orfour-year period, with an equal number of shares being issued per period on the anniversary of the award resolution. The vesting of the shares is contingent on the individuals’ continued employment or service. The Company determined the fair value of the granted Restricted Stock-based on the market price of the common shares of the Company on the date of grant.

The following table summarizes restricted stock for the years ended December 31, 2025 and 2024:

Stock compensation expense for the granted Restricted Stock is recognized over the vesting period. Stock compensation expense recognized during the year ended December 31, 2025 was $1,524,902 (during the year ended December 31, 2024, $1,244,416). The total fair value of vested shares during the year ended December 31, 2025 was $1,763,433 (during the year ended December 31, 2024: $1,303,187).

At December 31, 2025, the Company had unrecognized stock-based compensation related to these shares of $4,146,227 to be recognized over a weighted-average period of 1.37 years.

Dividend Equivalent Rights

Per the 2020 Plan, all employees and directors are entitled to Dividend Equivalent Rights with respect to the payment of cash dividends on Common Shares during the period beginning on the grant date of this award and ending, with respect to each share subject to the award, on the earlier of the date the Award is settled or the date on which it is terminated. Dividend Equivalent Rights shall be paid by crediting the holder with a cash amount or with additional whole RSUs within 30 days of the date of payment of such cash dividends on Common Shares, as determined by the Committee, subject to the holder’s continued service with the Company. Such cash amount or additional RSUs shall be subject to the same terms and conditions and shall be settled in the same manner and at the same time as the RSUs originally subject to this Award.

For the year ended December 31, 2025,47,417 common shares were issued as dividend equivalent rights. Stock compensation expense recognized during the year ended December 31, 2025 was $200,015.

8. Revenue Recognition

Revenues are comprised primarily of sales of natural gas, oil and NGLs, along with the revenue generated from the Company’s ownership interest in the Auburn GGS in Pennsylvania.

Overall, product sales revenue generally is recorded in the month when contractual delivery obligations are satisfied, which occurs when control is transferred to the Company’s customers at delivery points based on contractual terms and conditions. In addition, gathering and compression revenue generally is recorded in the month when contractual service obligations are satisfied, which occurs as control of those services is transferred to the Company’s customers. Gathering System revenues derived from Epsilon’s production, which have been eliminated from total gathering system revenues (“elimination entry”), amounted to $1.9 million and $1.1 million, respectively, for the years ended December 31, 2025 and 2024.

The following table details revenue for the years ended December 31, 2025 and 2024:

(1)Net of elimination

Product Sales Revenue

The Company enters into contracts with third-party purchasers to sell its natural gas, oil, NGLs and condensate production. Under these product sales arrangements, the sale of each unit of product represents a distinct performance obligation. Product sales revenue is recognized at the point in time that control of the product transfers to the purchaser based on contractual terms which reflect prevailing commodity market prices. To the extent that marketing costs are incurred by the Company prior to the transfer of control of the product, those costs are included in lease operating expenses on the Company’s consolidated statements of operations and comprehensive income.

Settlement statements for product sales, and the related cash consideration, are generally received from the purchaser within 30 days. For operated production in Wyoming, cash consideration is typically received within 30 days after the end of a production month for oil, while natural gas and NGLs cash consideration is typically received within 60 days after the end of a production month. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the natural gas, oil, NGLs, or condensate. Estimated revenue due to the Company is recorded within the receivables line item on the accompanying consolidated balance sheets until payment is received.

Gas Gathering and Compression Revenue

The Company also provides natural gas gathering and compression services through its ownership interest in the Auburn GGS in Pennsylvania. For the provision of gas gathering and compression services, the Company collects its share of the gathering and compression fees per unit of gas serviced and recognizes gathering revenue over time using an output method based on units of gas gathered.

The settlement statement from the operator of the Auburn GGS is receivedtwo months after transmission and compression has occurred. As a result, the Company must estimate the amount of production that was transmitted and compressed within the system. Estimated revenue due to the Company is recorded within the receivables line item on the accompanying consolidated balance sheets until payment is received.

Current Expected Credit Losses

Under ASU 326, Financial Instruments – Credit Losses, estimated losses on financial assets are provided through an allowance for credit losses. We also have accounts receivable which are primarily from purchasers of oil and natural gas, counterparties to our financial instruments, and revenues earned for compression and gathering services. Our oil, gas, and natural gas liquids accounts receivables are generally collected within 30 days after the end of the month. Compression and gathering receivables are generally collected within 60 days after the end of the month. We assess collectability through various procedures, including review of our trade receivable balances by counterparty, assessing economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount and age of past due accounts. As of December 31, 2025 and 2024, we determined that our allowance for credit loss wasnil.

The following table details accounts receivable as of December 31, 2025, 2024 and 2023:

9. Accumulated Other Comprehensive Income

Accumulated other comprehensive income includes certain transactions that have generally been reported in the consolidated statements of changes in shareholders’ equity. The activity in accumulated other comprehensive income during the years ended December 31, 2025 and 2024 consisted of the following:

10. Income Taxes

Net income (loss) before income taxes is as follows for the periods indicated:

We file income tax returns in the United States, Canada, and various state and local jurisdictions.

We believe that we have appropriate support for the income tax positions taken and to be taken on the Company's tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company's tax returns are open to audit under the statute of limitations for the years ending December 31, 2021 through December 31, 2025.

The following tables present the Company’s current and deferred tax (benefit) expense for the periods indicated:

The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate to the income tax provision in our financial statements. Our effective tax rate for 2025 differs from the statutory rate primarily due to states taxes, foreign withholding taxes, and the recognition of a valuation allowance on our Canadian and Oklahoma state deferred tax assets.

*State taxes in Pennsylvania made up the majority (greater than 50 percent) of the tax effect in this category.

Our effective tax rate for 2024 differs from the statutory rate primarily due to states taxes, foreign withholding taxes, & the recognition of a valuation allowance on our Canadian and Oklahoma state deferred tax assets. Our effective tax rate for 2024, excluding the impact of Canadian loss net valuation allowance, is 25.48%.

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

Net deferred tax liabilities consisted of the following at December 31, 2025 and 2024:

As of December 31, 2025, we have $1.4 million of U.S. federal net operating loss carry-forwards, all of which has an indefinite carryforward period but is limited to offset 80% of taxable income in any future year. We also have approximately $30.8 million of state net operating loss carry-forwards (tax-effected $0.6 million), of which $0.2 million expires in 2037 and the remaining can be carried forward indefinitely. These loss carryforwards may reduce future taxable income, however, the extent of which may be limited in the circumstances that an IRC Section 382 limitation would apply due to an ownership change. A state valuation allowance of $0.4 million is applicable to the net state deferred tax assets attributable to Oklahoma because of objective negative evidence on the cumulative loss incurred in the state over the three-year period ended December 31, 2025. As of December 31, 2025, we have $48.2 million (tax-effected 11.1 million) of Canadian net operating loss carry-forwards. A separate valuation allowance of $12.8 million attributable to Canadian net operating losses and other tax carryovers is recorded because it is more likely than not to be utilized.

The Company does not have any material uncertain tax positions. The Company recognizes interest expense and penalties related to the uncertain tax position in the income tax expense line in the accompanying consolidated statements

of operations and comprehensive loss. Accrued interest and penalties are included in other non-current liabilities in the consolidated balance sheet and were $0 as of December 31, 2025 and 2024.

Total net income tax payments were $2.2 million for the year ended December 31, 2025. The following table lists the components of the payments for income taxes:

11. Commitments and Contingencies

The Company also enters into commitments for capital expenditures in advance of the expenditures being made. As of December 31, 2025, our commitments for capital expenditures were $3.8 million related to drilling costs.

Litigation

In 2025, the Company filed a lawsuit against a contractor regarding alleged non-performance while running casing in a well. The Company is seeking damages due to its inability to complete the Leavitt Fed 2-9-4MH well. The Company is in the process of scheduling arbitration

The Company has intervened as a defendant-intervenor in litigation challenging BLM’s issuance of federal oil and gas leases acquired by the Company in 2017, 2018, and 2020. Plaintiffs allege deficiencies in BLM’s environmental review under NEPA. The Company intervened to protect its leasehold interests. Management does not believe the outcome will have a material adverse effect on the Company’s financial position.

Between September 30, 2025 and October 28, 2025, we received multiple demand letters on behalf of purported Epsilon stockholders (the “Demands”). The Demands primarily alleged that the Preliminary Proxy Statement filed on September 19, 2025 or the Definitive Proxy Statement filed on October 10, 2025, as applicable, failed to disclose certain material information with respect to the acquisition of Peak Exploration and Production, LLC, and Peak BLM Lease LLC.

On October 16, 2025, we received a copy of a complaint filed against Epsilon and certain members of Epsilon’s Board of Directors in the Supreme Court of the State of New York, County of New York, on behalf of purported Epsilon stockholder Anthony Morgan (the “Morgan Complaint”). On October 17, 2025, we received a copy of a complaint filed against Epsilon and certain members of Epsilon’s Board of Directors in the Supreme Court of the State of New York, County of New York, on behalf of purported Epsilon stockholder Richard Lawrence (the “Lawrence Complaint,” and together with the Morgan Complaint, the “Complaints”).

The Complaints allege, among other things, that Epsilon and the other named defendants (the “Epsilon Defendants”) violated New York common law based on claims of negligence, negligent misrepresentation and concealment. Specifically, the Complaints allege that the Preliminary Proxy Statement or the Definitive Proxy Statement, as applicable, failed to disclose, among other things, certain details regarding the background of the Transactions. Among other remedies, the Complaints sought an injunction against consummating the Transactions, rescission or actual and punitive damages if the Transactions are consummated, costs and attorneys’ fees. To date, we have not been served with the Complaints, and the Plaintiffs have not taken any additional steps in furtherance of prosecuting the Complaints.

While we believe that the disclosures set forth in the Preliminary Proxy Statement and the Definitive Proxy Statement comply fully with applicable law, to moot certain of the claims made in the Demands and Complaints, to avoid nuisance and potential expense and delay, we voluntarily supplemented the Definitive Proxy Statement with certain disclosures in our Supplemental Disclosures to Definitive Proxy Statement filed on October 31, 2025. Nothing in our

Supplemental Disclosures was an admission of the legal necessity or materiality under applicable law of any of the disclosures set forth in the Preliminary Proxy Statement or the Definitive Proxy Statement. To the contrary, we deny all allegations in the Demands and Complaints that any additional disclosure was required.

12. Leases

Under ASC 842, Leases, the Company recognized an operating lease related to its corporate office as of December 31, 2025 summarized in the following table:

On March 1, 2023, the Company commenced a new office lease with a 70 month lease term and future lease payments estimated to be approximately $0.85 million. Through its subsidiaries, the Company also leases office space in both Englewood, CO and Wright, WY. Lease expense for operating leases was $0.27 million and $0.24 for the years ended December 31, 2025 and 2024, respectively. This lease expense is presented in other general and administrative expenses in the consolidated statements of operations and comprehensive income.

Future minimum lease payments as of December 31, 2025 are as follows:

13. Net Income Per Share

Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities.

The net income used in the calculation of basic and diluted net income per share are as follows:

In calculating the net income per share, basic and diluted, the following weighted-average shares were used:

We excluded the following shares from the diluted net income per share because their inclusion would have been anti-dilutive.

14. Operating Segments

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker (CODM). The CODM, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as executive management consisting of the Chief Executive Officer, Chief Financial Officer, and Chief Operating Officer. The CODM uses the Company’s consolidated financial results, including operating income or loss by segment, to make key operating decisions, assess performance, and to allocate resources. Segment performance is evaluated based on operating income or loss as shown in the table below. Interest income and income taxes are managed separately on a group basis.

The Company’sreportable segments are as follows:

Segment activity as of, and for the years ended December 31, 2025 and 2024 is as follows:

15. Commodity Risk Management Activities

Commodity Price Risks

Epsilon engages in price risk management activities from time to time. These activities are intended to manage Epsilon’s exposure to fluctuations in commodity prices for natural gas and oil by securing fixed price contracts for a portion of expected sales volumes.

Inherent in the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company may be required to post collateral depending on the cumulative balance owed to a counterparty on a mark-to-market basis.

The Company enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future natural gas and oil production and related cash flows. The natural gas and oil revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future natural gas and oil sales from the risk of significant declines in commodity prices, which helps ensure the Company’s ability to fund the capital budget.

Epsilon has historically elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for these financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as*(loss) gain on derivative contracts* on the consolidated statements of operations and comprehensive income. The related cash flow impact is reflected in cash flows from operating activities. During 2025, Epsilon recognized gains on financial commodity derivative contracts of $5,500,486. This amount included cash received on the settlement of these contracts of $1,163,662. During 2024, Epsilon recognized losses on financial commodity derivative contracts of $391,147. This amount included cash received on the settlement of these contracts of $1,196,656.

Commodity Derivative Contracts

At December 31, 2025, the Company had outstanding NYMEX HH swaps totaling 1.68 Bcf, NYMEX HH options totaling 4.51 Bcf, NYMEX WTI CMA swaps totaling 340,916 Bbls, and NYMEX WTI CMA options totaling 181,634 Bbls for the contract period of January 2026 to January 2028.

At December 31, 2024, the Company had outstanding NYMEX HH swaps totaling 2.2615 Bcf and Tennessee Z4 basis swaps totaling 2.2615 Bcf for the contract period of January 2025 to October 2025, and NYMEX WTI CMA swaps totaling 20,662 Bbls for the contract period of January 2026 to June 2025.

The following table presents the changes in the fair value of Epsilon’s commodity derivatives for the periods indicated:

The following table presents the fair value of derivatives, as presented in the Consolidated Balance Sheets, on a net basis as they are subject to master netting arrangements:

16. Asset Retirement Obligations

Asset retirement obligations are estimated by management based on Epsilon’s net ownership interest in all wells and the gathering system, estimated costs to reclaim and abandon such assets and the estimated timing of the costs to be incurred in future periods, and the forecast risk free cost of capital. Epsilon has estimated the net present value of its total asset retirement obligations to be $7.4 million as of December 31, 2025 ($3.7 million at December 31, 2024). We acquired $3.8 million of additional asset retirement obligation with the Peak acquisition. Each year we review, and to the extent necessary, revise our asset retirement obligations estimates in accordance with recent activity and current service costs.

The following table presents the activity in Epsilon’s asset retirement obligations for the periods indicated:

17. Fair Value Measurements

The methodologies used to determine the fair value of our financial assets and liabilities at December 31, 2025 were the same as those used at December 31, 2024.

Cash, restricted cash, accounts receivable, and accounts payable are carried at cost, which approximates fair value because of the short term maturity of these instruments. Cash equivalents from the Company’s money market accounts are carried at fair value. The Company’s revolving line of credit has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates and the applicable margins represent market rates. The revolving line of credit is classified within Level 2 of the fair value hierarchy.

Commodity derivative instruments consist of NYMEX HH swap and option contracts and basis swap contracts for natural gas and NYMEX WTI CMA swap and option contracts for crude oil. The Company’s derivative contracts are valued based on a marked to market approach. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.

Non-Recurring Fair Value Measurements

For the year ended December 31, 2025, the Company performed an impairment test on our oil and gas properties and it was determined that the carrying amount in New Mexico and Canada each exceeded the estimated undiscounted future cash flows resulting in a reduction of the carrying amount of the oil properties to their estimated fair values by $3.9 million. Fair value is determined using management’s best estimate of proved reserves and net cash flows by area, using forward commodity prices from the last day of the year. The undiscounted future net cash flows are compared to the carrying value of each area. This nonrecurring fair value measurement is classified within Level 3 of the fair value hierarchy.

The table below summarizes the fair value of the impaired assets as of the fair value measurement date, December 31, 2025.

For the year ended December 31, 2024, the Company performed an impairment test on our oil and gas properties and it was determined that the carrying amount of the Killam project in Alberta, Canada exceeded the estimated undiscounted future cash flows resulting in a reduction of the carrying amount of the oil properties to their estimated fair values by $1.45 million. Fair value is determined using management’s best estimate of proved reserves and net cash flows by area, using forward commodity prices from the last day of the year. The undiscounted future net cash flows are compared to the carrying value of each area. This nonrecurring fair value measurement is classified within Level 3 of the fair value hierarchy.

The table below summarizes the fair value of the impaired assets as of the fair value measurement date, December 31, 2024.

SUPPLEMENTAL NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)

Natural Gas and Oil Reserves

Users of this information should be aware that the process of estimating quantities of ‘‘proved’’, ‘‘proved developed’’ and ‘‘proved undeveloped’’ crude oil, natural gas liquids (NGLs) and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity; evolving production history; crude oil and condensate, NGL and natural gas prices; and continual reassessment of the viability of production under varying economic conditions.

Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved reserves represent estimated quantities of crude oil, NGLs and natural gas, which, 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 under then-existing economic conditions, operating methods and government regulations before 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.

Proved developed reserves are proved reserves expected to be recovered under operating methods being utilized at the time the estimates were made, through wells and equipment in place or if the cost of any required equipment is relatively minor compared to the cost of a new well.

Proved undeveloped reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. PUDs can be recorded in respect of a particular undrilled location only if the location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the date that the PUDs are to be recorded, unless specific factors (such as those described in interpretative guidance issued by the Staff of the SEC) justify a longer timeframe. Likewise, absent any such specific factors, PUDs associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond five years from the date that the PUDs were recorded. Epsilon has formulated development plans for all drilling locations associated with its PUDs at December 31, 2025. Under these plans, each PUD location will be drilled within five years from the date it was recorded.

Estimates for PUDs are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

The following tables set forth Epsilon’s net proved reserves at December 31, 2025 and 2024 and changes for each of the two years in the year ended December 31, 2025. Net proved reserves at December 31 are estimated by the Company’s independent petroleum engineers, DeGolyer and MacNaughton for Pennsylvania, Texas, New Mexico, and Canada. Net proved reserves at December 31 are estimated by the Company’s independent petroleum engineers, Cawley, Gillespie & Associates for Wyoming.

NET PROVED RESERVE SUMMARY

Capitalized Costs Relating to Natural Gas and Oil Producing Activities

The following table sets forth the capitalized costs relating to Epsilon’s crude oil and natural gas production activities at December 31, 2025 and 2024:

Costs Incurred for Oil and Natural Gas Property Acquisition, Exploration and Development Activities

The following table summarizes costs incurred and capitalized in oil and natural gas properties related to acquisition, exploration and development activities. Property acquisition costs are those costs incurred to lease property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling, as well as the costs to develop the gathering system.

Results of Operations for Natural Gas and Oil Producing Activities

The following table sets forth results of operations for natural gas and oil producing activities for the years ended December 31, 2025 and 2024:

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves

The following information has been developed utilizing procedures prescribed by the Extractive Activities—Natural Oil and Gas (Topic 932) of the ASC and based on natural gas reserves and production volumes estimated by our independent petroleum consultants, DeGolyer and MacNaughton and Cawley Gillespie & Associates. The commodity prices estimated below were based on a 12-month average of first-day-of-the-month commodity prices for the years 2025 and 2024. The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating Epsilon or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of Epsilon.

The future cash flows presented below are based on expense and cost rates in existence as of the date of the projections. It is expected that material revisions to some estimates of natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Estimated future income taxes are computed using current statutory income tax rates including consideration of the current tax basis of the properties and related carryforwards. The resulting tax-effected future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible reserves as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The following table sets forth the standardized measure of discounted future net cash flows from projected production of Epsilon’s gas reserves as of December 31, 2025 and 2024.

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2025 and 2024: