EPSN 10-K & 10-Q changes, risk factors and insider trading

Revenues, profitability, liquidity, ability to access capital and future growth prospects are highly dependent on the prices received for oil and natural gas. The prices of these commodities are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile, and this volatility may continue in the future. The volatility of the energy markets generally makes it extremely difficult to predict future oil and natural gas price movements. Also, prices for oil and prices for natural gas do not necessarily move in tandem. Declines in oil or natural gas prices would not only reduce revenue but could also reduce the amount of oil and natural gas that can be economically produced and therefore potentially lower natural gas and oil reserve quantities. If the oil and natural gas industry continues to experienceexperiences low prices, we may, among other things, be unable to meet all our financial obligations or make planned expenditures.

Our long-termlong term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves, the failure of which could result in under-use of capital and in losses.

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Our long-termlong term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, any existing reserves that we may have at any particular time and the production from those reserves will decline over time as those reserves are exploited. A future increase in our reserves will depend not only on our ability to explore and develop any properties we may have from time to time, but also on our ability to select and acquire suitable producing properties or prospects. We cannot assure you that we will be able to locate and continue to locate satisfactory properties for acquisition or participation. Moreover, if we do identify such acquisitions or participations, we may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. We cannot assure you that we will discover or acquire further commercial quantities of oil and natural gas.

In accordance with applicable securities laws, the technical report on our oil and natural gas reserves prepared by DeGolyer and MacNaughton, independent petroleum consultants, as of December 31, 20242025 and 2023,2024 or the (“DeGolyer Reserve Report,Report”), and the report by Cawley, Gillespie & Associates as of December 31, 2025 (“CGA Reserve Report”), used SEC guideline prices and cost estimates in calculating net cash flows from oil and natural gas reserve quantities included within the report. Actual future net revenue will be affected by other factors such as actual commodity prices, production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs. Actual production and revenues derived therefrom will vary from the estimates contained in the DeGolyer Reserve Report and CGA Reserve Report, and such variations could be material. The DeGolyer Reserve Report isand the CGA Reserve Report are based in part on the assumed success of activities that we intend to undertake in future years. The oil and natural gas reserves and estimated cash flows to be derived therefrom contained in thethese DeGolyerreserve Reserve Reportreports will be reduced to the extent that such activities do not achieve the level of success assumed in thethese DeGolyerreserve Reserve Report.reports.

If there is a sustained economic downturn or recession in the United States or globally, natural gas and oil prices may fall and may become and remain depressed for a long period of time, which may adversely affect our results of operations. We may be unable to obtain additional capital required to implement our business plan, which could restrict our ability to grow.sustain or grow our business.

We anticipate making capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. If our revenues or reserves decline, we may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing or cash generated by operations will be available or sufficient to meet these requirements, or for other corporate purposes. If debt or equity financing is available, there is no assurance that it will be on terms acceptable to us. Moreover, future activities may require us to alter our capitalization significantly. Additional capital raised through the issuance of common shares or other securities convertible into common shares may result in a change of control of us and dilution to shareholders. Our inability to access sufficient capital for our operations could have a material adverse effect on our financial condition and results of operations.

The borrowing base under our credit facility may be reduced in light of commodity price declines,declines or reserve changes, which could limit us in the future.

Lower commodity volumes and prices may reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of our lenders primarily based on the collateral value of our provedProved reservesDeveloped Reserves that have been mortgaged to the lenders, and is subject to twicesemiannual yearly redeterminations, as well as special redeterminations described in the credit agreement.redeterminations. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under our credit agreement. In addition, we may be unable to access the equity or debt capital markets to meet our obligations, including any such debt repayment obligations.outstanding.

The contractagreement that governs our revolving credit facility contains covenants that impose operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-termlong term best interest, including restrictions on our ability, subject to satisfaction of certain conditions, to incur additional indebtedness, sell assets, enter into transactions with affiliates, and enter into or refrain from entering into hedging contracts.

A breach of the covenants or restrictions under the contract that governs our revolving credit facility could result in an event of default under the applicable indebtedness. Such a default may allow the creditors to accelerate the relatedrepayment debt.of the outstanding indebtedness. In the event our lenders accelerate the repayment of our borrowings, we may not have sufficient assetsresources to repay that indebtedness.

Our operations involve utilizing the latest drilling and completion techniques in order to maximize cumulative recoveries and generate high returns. If drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, or if crude oil and natural gas prices decline, the return on our investment in these areas may not be as attractive as anticipated. Further, less than anticipated results in developments could incur material write-downswrite downs of our oil and natural gas properties and the value of undeveloped acreage could decline in the future.

Approximately 50%67% and 77%50% of our revenue during fiscal years 20242025 and 2023,2024, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania. Approximately 40%19% and 6%40% of our revenue during fiscal years 20242025 and 2023,2024, respectively, was derived from oil, natural gas, and natural gas liquids revenues in the state of Texas. Epsilon’sIn managementNovember expects2025, tothe continueCompany tocompleted seekthe opportunitiesacquisition of oil and gas assets in otherthe NorthPowder AmericanRiver basinsBasin, toWyoming which could provide the Company the enhanced flexibility to respond to market conditions by allocating capital across multiple basins and commodities.

AsHowever, athe resultCompany ofis thisstill subject to geographic concentration,concentration and we may be disproportionately exposed to the effect of regional supply and demand factors, delays or interruptions of production from wells in thisthese areaareas 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.

In addition to the operator, ourOur success will depend in large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse effect on us. We do not have key-personkey person insurance in effect for management. The contributions of these individuals to our immediate operations are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is intense, and there can be no assurance that we will be able to continue to attract and retain all personnel necessary for the development and operation of our business. Certain of our directors are also directors of other companies and as such may, in certain circumstances, have a conflict of interest requiring them to abstain from certain decisions. Conflicts, if any, will be subject to the procedures and remedies of the Conflicts Committee of our board of directors.

Our involvement in the exploration for and development of oil and natural gas properties may result in our becoming subject to liability for pollution, blow outs,blowouts, property damage, personal injury or other hazards. Although before drilling we plan to obtain insurance in accordance with industry standards to address certain of these risks, such insurance may not be available, be price-prohibitive,price prohibitive, or contain limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not in all circumstances be insurable, or, in certain circumstances, we may elect not to obtain insurance to deal with specific risks because of the high premiums associated with such insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to us. The occurrence of a significant event that we are not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on our financial position and our results of operations.

Additionally, we may, due to circumstances beyond our control, be put in a position of over-hedging.over hedging. If this occurs, our revenue could be adversely affected due to the necessity of buying oil and natural gas at the current market rate in order to fulfill hedging sales obligations.

The marketability and price of oil and natural gas that we may produce, acquire or discover will be affected by numerous factors beyond our control. Our ability to market our oil and natural gas may depend upon our ability to acquire space on pipelines that deliver crude oil and natural gas to commercial markets. This risk is somewhat mitigated in Pennsylvania by our 35% ownership of a gathering system in the Marcellus Shale innortheast Pennsylvania. We may also be affected by extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, and many other aspects of the oil and natural gas business.

We depend on information technology systems that we manage, and others that are managed by third-party service and equipment providers, to conduct our day-to-day operations, including critical systems, and these systems are subject to risks associated with cyber incidents or attacks, especially originating from countries such as China, Russia, Iran, and North Korea as broadly reported in the media. Our technology systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches. A cyber incident could negatively impact the Company in a number of ways, including but not limited to: (i) remediation costs, such as liability for stolen assets or information and repairs of system damage; (ii) increased cybersecurity protection costs, which may include the costs of making organizational changes, deploying additional personnel and protection technologies, training employees, and engaging third-party experts and consultants; (iii) lost revenue resulting from downtime, operational disruptions, the unauthorized use of proprietary information or the failure to retain or attract customers following an attack; (iv) litigation and legal risks, including regulatory actions by state and federal governmental authorities and non-U.S. authorities and related investigation costs; (v) increased insurance premiums; (vi) reputational damage that adversely affects customer or investor confidence; (vii) the loss, theft, corruption or unauthorized release of intellectual property, proprietary information, customer and vendor data or other critical data and (viii) damage to the Company’s competitiveness, stock price, and long-termlong term stockholder value. Certain cyber incidents, such as surveillance, may remain undetected for an extended period of time. As the sophistication of cyber incidents continues to evolve, we will likely be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.

We are a “smaller reporting company” as defined under the Exchange Act, and we will remain a smaller reporting company until the fiscal year following the determination that our voting and non-voting common shares held by non-affiliates is more than $250 million measured on the last business day of our second fiscal quarter,quarter orand our annual revenue is more than $100 million during the most recently completed fiscal year and our voting and non-voting common shares held by non-affiliates is more than $700 million measured on the last business day of our second fiscal quarter.million. Smaller reporting companies are able to provide simplified executive compensation disclosure and have certain other reduced disclosure obligations, including, among other things, being required to provide only two years of audited financial statements and not being required to provide selected financial data, supplemental financial information or risk factors.

As we grow, we may be subject to growth-relatedgrowth related risks including capacity constraints and pressure on our internal systems and controls. Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to train and manage our employee base.

Because of the natural decline in production from existing wells, our success depends on the Anchor Shippers’ economically developing the remaining Marcellus Shale reserves.reserves in Pennsylvania.

Our natural gas gathering system is dependent upon the level of production from natural gas wells, from which production will naturally decline over time. In order to maintain or increase throughput levels on our gathering system and compression facility, we must continually develop reserves within the Auburn GGS boundary or obtain new supplies external to the Auburn GGS boundary. Developing reserves within the system boundary is the priority as external natural gas volumes have a contractual gathering rate that is 25% of the Anchor Shipper rate. The primary factors affecting our ability to obtain new supplies of natural gas is the level of successful drilling activity from the Anchor Shippers, of which Epsilon is one, as well as our ability to compete for volumes from successful new wells drilled by third parties proximate to our system. If we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, throughput on our pipelines and the utilization rates of our compression facility would decline, which could have an adverse effect on our business, results of operations, financial position and cash flows. Although gross throughput at the Auburn CF has declined from 2018-2024, the share of Anchor Shipper gas has increased.

Because of the large supply of gas, and limited availability of transportation out of the Marcellus Shale area,Pennsylvania, our gas is subject to a price differential.

Differential is an energy industry term that refers to the discount or premium received for the sale of a petroleum product at a specific location relative to a nationally recognized sales hub. In the Marcellus Shale,Pennsylvania, natural gas is significantly discounted to Henry Hub pricing and the size of the differential can be volatile. Many factors influence the size and duration of differentials including local supply / demand imbalances, seasonal fluctuations in demand, transportation availability and cost, as well as the regulatory environment as it pertains to constructing new transportation pipelines. In Northeastnortheast Pennsylvania, negative differentials have persisted for many years due to rapid increases in supply as a result of advances in well completion techniques. Despite substantial increases in local demand for natural gas coupled with pipeline expansions, optimizations, and new pipelines that have been brought into service, the natural gas differential in Northeastnortheast Pennsylvania remains significant. There is no guarantee that future demand or pipeline transportation projects will eliminate this differential, and it will therefore remain a significant risk to demand for transportation service on the Auburn GGS, and therefore Epsilon’s revenues and cash flows.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy, or may be required to make prepayments or provide security to satisfy credit concerns. However, our credit procedures and policies cannot completely eliminate customer and counterparty credit risk. Our customers and counterparties include natural gas producers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. In a low commodity price environment certain of our customers could be negatively impacted, causing them significant economic stress including, in some cases, to file for bankruptcy protection or to renegotiate contracts. To the extent one or more of our key customers commences bankruptcy proceedings, our contracts with the customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code, or may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties or otherwise do not take or are unable to take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness, and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivable. Such write-downswrite downs or write-offswrite offs could negatively affect our operating results in the periods in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows, and financial condition.

Epsilon Energy Ltd. (the “Company”) is a North American onshore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves. Our areas of operations are the Marcellus Shale section of the Appalachian Basin in Pennsylvania, the Powder River Basin in Wyoming, the Permian Basin in Texas and New Mexico, the NW Anadarko Basin in Oklahoma, and the Western Canadian Sedimentary Basin in Alberta, Canada.

At December 31, 20242025 our total estimated net proved reserves were 69,40186.4 MMcfBcf of natural gas reserves, 876,8089.3 BblsMMBbls of oil reserves, and 2.4 MMBbls of NGL reserves, and 1,572,465 Bbls of oil and condensate, and we held leasehold rights to approximately 102,506101,265 gross (23,60254,044 net) acres. We have natural gas production from our non-operated wells in Pennsylvania; and natural gas, oilnatural andgas other liquids production from our non-operated wells in the Permian Basin, Oklahoma;liquids, and oil production from our operated and non-operated wellwells in Alberta,the Canada.Permian, Powder River, and Western Canadian Sedimentary Basins.

Our Pennsylvania (“PA”) assets are supported by our 35% ownership in the Auburn GGS. We have a substantial remaining drillable location inventory within our existing leaseholds in Pennsylvania and Texas.

At December 31, 2024,2025, our total estimated net proved developed reserves were 64,872109,444 MMcfe, a 28%69% increase from December 31, 2023.2024. The increase is mainly attributable to transfersWyoming reserves acquired from provedthe undevelopedPeak reserves in Pennsylvania and acquisitions in Texas.acquisition.

Upstream natural gas revenue for the year ended December 31, 20242025 decreasedincreased by $4.1$18.3 million, or 27%,170%, from 2023.2024. AAn decreaseincrease of $0.2$11.6 million was due to lowerhigher natural gas prices and aan decreaseincrease of $3.9$6.8 million was due to lowerhigher produced volumes as a result of naturalpreviously declinedelayed inwells coming on line and the wellsend andof operator electedoperator-elected well shut-ins due to poor natural gas pricing in Pennsylvania.

Upstream natural gas liquids revenue for the year ended December 31, 20242025 increased by $0.5 million, or 51%34% from 2023.2024. An increase of $0.8$0.2 million was due to higher produced volumes from new wells in the Permian Basinand Powder River Basins and aan reductionincrease of $0.3 million was due to lowerhigher natural gas liquids prices.

Upstream oil and condensate revenue for the year ended December 31, 20242025 increased by $8.6$0.1 million, or 170%1% over 2023.2024. An increase of $9.4$2.7 million was due to increased production from new wells in the Permian Basinand Powder River Basins offset by a reduction of $0.8$2.6 million due to lower oil prices.

Gathering system revenue (net of elimination) for the year ended December 31, 20242025 decreasedincreased by $4.3$1.2 million, or 44%21% over 2023.2024. The decreaseincrease was primarily due to lowerslightly anchorhigher shipperthroughput, volumesbut asmore importantly, crossflow gas being displaced with Anchor Shipper gas which is charged a result of natural decline in the wells and operator elected well shut-ins due to poor natural gas pricing in Pennsylvania partially offset by an increase in the Auburnhigher gathering rate.fee. Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues, amounted to $1.1$1.9 million and $1.4$1.1 million, respectively, for the years ended December 31, 20242025 and 2023.2024.

Upstream operating costs consist of lease operating expenses necessary to extract natural gas and oil, including gathering and treating the natural gas and oil to readyprepare it for sale. For the year ended December 31, 2024,2025, upstream operating costs increased by $0.9$5.3 million, or 13.4%72% from the same period in 2023.2024. The increase is primarily due to the acquiredincrease in gas production in Pennsylvania and developedthe wellsacquired production in the PermianPowder River Basin. The higher unit operating cost is primarily due to the higher liquids (oil and natural gas liquids) proportion of total sales (Mcfe).

During the year ended December 31, 2024,2025, DD&A expense increased by $2.5$2 million, or 33%,19%, compared to the same period in 2023.2024. This increase was primarily a result of thehigher lowerproduced third-party reserves causing an increased depletion ratevolumes in additionPennsylvania toand higheracquired productionproperties fromin the Permian Basin.Wyoming.

G&A expenses for the year ended December 31, 20242025 decreasedincreased by $0.3$2 million, or 5%,29%, compared to the same period in 2023.2024. ThisAn decreaseincrease wasof primarily$1.2 duemillion is related to ahigher reductioncompensation expense, an increase of $0.5 million in legalstock expenses.based compensation, and an increase of $0.1 million in audit and tax fees.

During the year ended December 31, 2024,2025, interest income decreased by $1.2$0.3 million, or 71%,62%, from the same period in 2023.2024. This decrease was primarily due to the reduction in the balance of cash andequivalents associated with the maturation of all short term investments.investments in June 2024.

Interest expense decreasedincreased by $0.03$0.6 million, or 42%,1245%, during the year ended December 31, 20242025 from 2023.2024. The decreaseincrease is due to higherinterest charged on the outstanding debt balance from the closing of the Peak acquisition on November 14, 2025, commitment fees inon 2023unused associateddebt withcapacity, ourand the amortization of front-end fees related to the new credit facility.facility entered into in October 2025.

NetGain (lossLoss) gain on commodityDerivative contractsContracts, net

During the year ended December 31, 2024,2025, the Company had NYMEX Henry Hub (“HH”) Natural Gas Futures swaps, TennesseeNYMEX GasHH Pipeline Zone 4 basis swaps,options, and crude oil NYMEX WTI CMA swaps derivative contracts for the purpose of hedging a portion of its physical natural gas and oil sales revenue. During the year ended December 31, 2023,2024, the Company had NYMEX HH Natural Gas Futures swaps andswaps, Tennessee Gas Pipeline Zone 4 basis swaps, and crude oil NYMEX HH CMA swaps derivative contracts for the same hedging purpose. The amounts recorded represent the fair value changes on our derivative instruments during the year. For the year ended December 31, 2025, the Company received net cash settlements of $1,163,662. For the year ended December 31, 2024, the Company received net cash settlements of $1,196,656. For the year ended December 31, 2023, the Company received net cash settlements of $3,251,890.

At December 31, 2023,2025, the Company had outstanding NYMEX HH swaps totaling 1.9051.68 BcfBcf, withNYMEX aHH weightedoptions averagetotaling strike4.51 priceBcf, ofNYMEX $3.25WTI and Tennessee Z4 basisCMA swaps totaling 1.905340,916 BcfBbls, withand aNYMEX weightedWTI averageCMA strikeoptions pricetotaling of181,634 ($1.10) to hedge a portion of expected volumesBbls for the contract period of January 20242026 to OctoberJanuary 2024.2028.

Income Tax (Benefit) Expense

During the year ended December 31, 2024,2025, income tax expense decreased by $1.6$1.3 million, or 49%,78%, from the same period in 2023.2024. This decrease was primarily due to a decrease in taxable income as a result of lossesloss on derivativethe contractsasset andsale, higheras intangiblewell drillingas costincreased deductions.expenses related to the Peak acquisition.

Net (Loss) Income Compared to Adjusted EBITDA

We define Adjusted EBITDA as earnings before (1) net interest expense, (2) taxes, (3) depreciation, depletion, amortization and accretion expense, (4) impairments of natural gas and oil properties, (5) non-cash stock compensation expense, (6) gain or loss on sale of assets, (7) gain or loss on derivative contracts net of cash received or paid on settlement, and (8) othertransaction income.costs and (9) gain or loss on foreign currency translation. Adjusted EBITDA is not a measure of financial performance as determined under U.S. GAAP and should not be considered in isolation from or as a substitute for net income or cash flow measures prepared in accordance with U.S. GAAP or as a measure of profitability or liquidity.

Additionally, Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We have included Adjusted EBITDA as a supplemental disclosure because its management believes that Adjusted EBITDA provides useful information regarding our ability to service debt and to fund capital expenditures. It further provides investors a helpful measure for comparing operating performance on a "normalized" or recurring basis with the performance of other companies, without giving effect to certain non-cash expenses and other items. This provides management, investors and analysts with comparative information for evaluating us in relation to other natural gas and oil companies providing corresponding non-U.S. GAAP financial measures or that have different financing and capital structures or tax rates. These non-U.S. GAAP financial measures should be considered in addition to, but not as a substitute for, measures for financial performance prepared in accordance with U.S. GAAP. The table above sets forth a reconciliation of net income to Adjusted EBITDA, which is the most directly comparable measure of financial performance calculated under U.S. GAAP and should be reviewed carefully.

The primary source of cash during the year ended December 31, 2025 was funds generated from operations and financing activities. The primary source of cash during the year ended December 31, 2024 was funds generated from operations and proceeds from short term investments. The primary source of cash duringFor the year ended December 31, 20232025 wasthe fundsprimary generateduses fromof operations.cash were development of upstream properties, the distribution of dividends, and costs related to the Peak acquisition. For the year ended December 31, 2024 the primary uses of cash were the acquisition and development of upstream properties and the distribution of dividends. For the year ended December 31, 2023 the primary uses of cash were the acquisition and development of upstream properties, investment in U.S. Treasury bills, the repurchase of shares of common stock, and the distribution of dividends.

At December 31, 2024,2025, we had a working capital surplus of $7.0$7.6 million, aan decreaseincrease of $26.2$0.5 million from the $33.2$7.1 million surplus at December 31, 2023.2024. The surplus decreasedincreased from December 31, 20232024 due to loweran cashincrease andin shortcurrent term investment balances.assets. We anticipate that our current cash balance, short term investments, available borrowings, and cash flows from operations to be sufficient to meet our cash requirements for at least the next twelve months.

During the year ended December 31, 2024,2025, $16.8$20.6 million was provided by our operating activities, compared to $18.2$16.8 million in 2023,2024, a $1.4$3.8 million, or 7%,23%, decrease.increase. The decreaseincrease was primarily due to lowerhigher production and throughput volumes in the MarcellusPennsylvania due to operatornew electedwells shut-ins,turned offseton byline higheras productionwell volumesas incurtailed Texas.wells returning to production.

The companyCompany used $16.7$61.6 million for investing activities during the year ended December 31, 2024,2025, compared to $38.4$16.7 million in 2023,2024, a $21.7$44.9 million, or 57%,270%, decrease.increase. The decreaseincrease was primarily due to a $40.8$49.8 million decreasepaid infor purchasesthe ofPeak short-term investments, offset by a $15.2 million increase in capital investments in upstream properties.acquisition.

During the year ended December 31, 2024,2025, the$43.7 Companymillion usedwas provided by financing activities compared to $7.3 million for financing activity compared to $11.7 millionused in 2023,2024, a $4.4$51 million, or 38%697% decrease. The decrease was primarily due to fewerthe repurchases$50.5 million draw on the Company’s credit facility to repay the outstanding debt of ourPeak commonrelated shares.to the acquisition.

The Company closed a new senior secured reserve based revolving credit facility on JuneOctober 28,10, 20232025 with Frost Bank as issuingadministrative bankagent and soleFrost lender.Bank Theand currentTexas Capital Bank as lenders. This replaced the Company’s previous credit facility. As of December 31, 2025, the borrowing base iswas $45$80 million (redetermined as of February 10, 2025),million, supported by the Company’s upstreamproducing assets in Pennsylvaniareserves and is subject to semi-annual redeterminations with a maturity date of JuneOctober 28,10, 2027.2029. Interest will be charged at the Daily3-month SimpleTerm SOFR rate plus a margin of 3.25%.3-4% (depending on facility utilization), payable quarterly. The facility is secured by the assets of the Company’s Epsilon Energy USA subsidiarysubsidiary. (Borrower).During ThereMarch are currently no borrowings under2026, the Company made a $5 million repayment on the outstanding credit facility. The current balance as of March 25, 2026 is $45.5 million.

The Company has entered into hedging arrangements to reduce the impact of natural gas and oil price volatility on operations. By removing the price volatility from a significant portion of natural gas and oil production, the potential effects of changing prices on operating cash flows have been mitigated, but not eliminated. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we might otherwise receive from increases in commodity prices.

We enter into commitments for capital expenditures in advance of the expenditures being made. As of December 31, 2024,2025, our commitments for capital expenditures were $7.8$3.8 million. All of the capital commitments aremillion related to the first two wellsdrilling of the1 jointgross venture(0.25 net) well in Alberta entered into in October 2024. Of the total commitment, $3.4 million is drilling carry in favor of the operator, the remaining amount is our working interest share of outstanding authorizations for future expenditures.Texas.

Our engineers estimate proved natural gas and oil reserves in accordance with SEC regulations, which directly impact financial accounting estimates, including depreciation, depletion and amortization and impairments of proved properties and related assets. Proved reserves represent estimated quantities of crude oil and condensate, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantitiesfuture production volumes of proved natural gas and oil reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Accordingly, there can be no assurance that ultimately, the reserves will be produced, nor can there be assurance that the proved undeveloped reserves will be developed within the period anticipated. 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 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. We cannot predict the types of reserve revisions that will be required in future periods. For related discussion, see the sections titled “Risk Factors” and “Supplemental Information to Consolidated Financial Statements.”

The following discussion is intended to assist in the understanding of trends and significant changes in our results of operations and the financial condition of Epsilon Energy Ltd. and its subsidiaries for the periods presented. The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this report, including the unaudited condensed consolidated financial statements as of MarchJune 31,30, 2026 and 2025 together with accompanying notes, as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2025. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward- looking statements due to a number of factors. See “Part II. Item 1A. Risk Factors” and “Forward-Looking Statements.”

At MarchJune 31,30, 2026 we held leasehold rights to 52,14952,290 net acres. We have natural gas production from our non-operated wells in Pennsylvania and natural gas, natural gas liquids, and oil production from our operated and non-operated wells in the Permian, Powder River, and Western Canadian Sedimentary Basins.

Three and six months ended MarchJune 31,30, 2026 Highlights

Epsilon defines Adjusted EBITDA as earnings before (1) net interest expense, (2) taxes, (3) depreciation, depletion, amortization and accretion expense, (4) impairments of natural gas and oil properties, (5) non-cash stock compensation expense, (6) transaction costs, (7) gain or loss on derivative contracts net of cash received or paid on settlement, and (8) netgain otheror incomelss on sale of assets, and (expense9). gain or loss on foreign currency traslations. Adjusted EBITDA is not a measure of financial performance as determined under U.S. GAAP and should not be considered in isolation from or as a substitute for net income or cash flow measures prepared in accordance with U.S. GAAP or as a measure of profitability or liquidity.

The table below sets forth a reconciliation of net income to Adjusted EBITDA for the three and six months ended MarchJune 31,30, 2026 and 2025, which is the most directly comparable measure of financial performance calculated under U.S. GAAP and should be reviewed carefully.

For the threesix months ended MarchJune 31,30, 2026, revenues increased $9.4$16.1 million, or 58%, to $25.6$43.9 million from $16.2$27.8 million during the same period of 2025.

Revenue and volume statistics for the threesix months ended MarchJune 31,30, 2026 and 2025 were as follows:

Upstream natural gas revenue for the threesix months ended MarchJune 31,30, 2026 increaseddecreased by $2.8$0.4 million, or 26%,2%, over the same period in 2025. An increase of $3.8$2.6 million was due to higher natural gas prices and a decrease of $1.0$3.0 million was a result of decrease in volume due to the natural decline in the producing wells and the sale of the Oklahoma assets partially offset due to increased volumes as a result of the Peak acquisition..acquisition. Upstream natural gas revenue for the three months ended June 30, 2026 decreased by $3.1 million, or 45%, over the same period in 2025. A decrease of $1.4 million was due to lower natural gas prices and a decrease of $1.7 million was a result of decrease in volume due to the natural decline in the producing wells and the sale of the Oklahoma assets partially offset due to increased volumes as a result of the Peak acquisition.

Upstream natural gas liquids revenue for the threesix months ended MarchJune 31,30, 2026 increased by $0.7$1.9 million, or 177%,362%, over the same period in 2025. This increase was primarily due to increased volumes as a result of the Peak acquisition. Upstream natural gas liquids revenue for the three months ended June 30, 2026 increased by $1.2 million, or 856%, over the same period in 2025. This increase was primarily due to increased volumes as a result of the Peak acquisition.

Upstream oil and condensate revenue for the threesix months ended MarchJune 31,30, 2026 increased by $6.2$15.2 million, or 189%254% over the same period in 2025. An increase of $6.5$11.5 million was due to higher volumes as a result of the Peak acquisition and aan decreaseincrease of $0.3$3.7 million was due to aan decreaseincrease in prices for oil in the Permian Basin. Upstream oil and condensate revenue for the three months ended June 30, 2026 increased by $9.0 million, or 332% over the same period in 2025. An increase of $5.0 million was due to higher volumes as a result of the Peak acquisition and an increase of $4.0 million was due to an increase in prices for oil in the Permian Basin.

Gathering system revenue for the threesix months ended MarchJune 31,30, 2026 decreased by $0.2$0.7 million, or 12%,20%, compared with the same period in 2025 due to lower thoughputthroughput volumes partially offset due to higher contractual rates for gathering and compression. Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues amounted to $0.8 million and $1.9 million, respectively, for the six months ended June 30, 2026 and 2025. Gathering system revenue for the three months ended June 30, 2026 decreased by $0.5 million, or 28%, compared with the same period in 2025 due to lower throughput volumes partially offset due to higher contractual rates for gathering and compression. Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues amounted to $0.4 million and $0.6$0.5 million, respectively, for the three months ended MarchJune 31,30, 2026 and 2025.

The following table presents total cost and cost per unit of production (Mcfe), including ad valorem, severance, and production taxes for the three and six months ended MarchJune 31,30, 2026 and 2025:

Upstream operating costs consist of lease operating expenses necessary to extract natural gas and oil, including gathering and treating the natural gas and oil in preparation for sale. For the threesix months ended MarchJune 31,30, 2026 these costs increased by $4.4$8.3 million, or 161%,159%, over the same period in 2025. The increase is primarily due to the Wyoming assets inclusion following the Peak acquisition (higher operating costs per unit relative to the other asset areas), workover expenses in Pennsylvania, and Ad Valorem taxes in TexasTexas. ($0.5 million forFor the three months ended MarchJune 31,30, 2026 these costs increased by $3.9 million, or 157%, over the same period in 2025. The increase is primarily due to the Wyoming assets inclusion following the Peak acquisition (higher operating costs per unit relative to the other asset areas).

Gathering system operating costs consist primarily of rental payments for the natural gas fueled compression units and overhead fees due to the system’s operator. For the three and six months ended MarchJune 31,30, 2026, gathering system operating costs were constant compared to the same period in 2025.

DD&A expense for the three and six months ended MarchJune 31,30, 2026 decreased by $0.5$0.4 million, or 14%,12%, and $0.9 million, or 13%, respectively, from the same period in 2025. This decrease was a result of higher reserves and lower production in Pennsylvania and Texas and the sale of the Oklahoma assets (offset by the addition of the Wyoming assets).

For the three and six months ended MarchJune 31,30, 2026, there was no impairment. For the three and six months ended MarchJune 31,30, 2025, the Company recorded an impairment of $0.01$2.7 million for coststwo on the Killam project wellwells drilled duringin 2024Alberta, thatCanada. The impairment was deemeda non-commercial.result of a decrease in estimated reserves due to early production coming in below expectations, cost overruns and lower forward commodity prices.

For the three and six months ended MarchJune 31,30, 2026, the Company had transaction costs related to the Peak acquisition of $0.1$0.2 million and $0.3 million, respectively, for advisory and legal services incurred by the Company. For the three and six months ended MarchJune 31,30, 2025, there were no transaction costs.

G&A expenses for the three and six months ended MarchJune 31,30, 2026 increased by $ 1.7$2.4 million, or 78%,128%, and $4.1 million, or 101%, respectively, from the same period in 2025. This was primarily due to $1.4 million increased compensation expenses related to the addition of 17 full-time employees as a result of the Peak acquisition and 6 former Peak employees on transition services contracts. As of June 1, 2026, the transition services contracts ended for 5 former Peak employees.

Interest income for the threesix months ended MarchJune 31,30, 2026 increased by $0.03$0.04 million, or 198%,116%, from the same period in 2025. This was primarily due to an increase in the balance of interest-bearing investments.

Interest expense during the three and six months ended MarchJune 31,30, 2026 increased by $0.9 million, or 7,611%,4,307%, and $1.8 million, or 5,563%, respectively, from the same period in 2025. This increase is related to the interest paid on the creditoutstanding facilitybalance as a result ofon the balancerevolving increase.credit facility.

Gain (Loss) on Derivative Contracts

During the threesix months ended MarchJune 31,30, 2026, the Company had NYMEX Henry Hub (“HH”) Natural Gas Futures swaps, NYMEX HH options, crude oil NYMEX WTI CMA swaps, and crude oil NYMEX WTI CMA swapsoptions derivative contracts for the purpose of hedging a portion of its physical natural gas and oil sales revenue. For the three months ended March 31, 2025, Epsilon had NYMEX HH Natural Gas futures swaps, Tennessee Gas Pipeline Zone 4 basis swaps, and crude oil NYMEX WTI CMA swaps derivative contracts for the purpose of hedging a portion of its physical natural gas and oil sales revenue. The amounts recorded represent the fair value changes on our derivative instruments during the year.

For the three and six months ended MarchJune 31,30, 2026, realized losses on derivative contracts increased by $7.5$0.3 million.million and $7.8 million, respectively. This increase was primarily the result of a significant increase in crude oil prices during the quarter and its impact on the Peak hedge book assumed in the acquisition.

The primary source of cash for Epsilon during the three and six months ended MarchJune 31,30, 2026 and 2025 was funds generated from operations. The primary uses of cash for the three and six months ended MarchJune 31,30, 2026 were the development of upstream properties, the reduction of the outstanding credit facility,facility balance, and the distribution of dividends. The primary uses of cash for the three and six months ended MarchJune 31,30, 2025 were the development of upstream properties and the distribution of dividends.

At MarchJune 31,30, 2026, we had a working capital surplusdeficit of $2.2$1.3 million, a decrease of $5.4$8.9 million from the $7.6 million surplus at December 31, 2025. The Company anticipates its current cash balance, available borrowings, and cash flows from operations to be sufficient to meet its cash requirements for at least the next twelve months.

ThreeSix months ended MarchJune 31,30, 2026 compared to 2025

During the threesix months ended MarchJune 31,30, 2026, $10.1$22.4 million was provided by the Company’s operating activities, compared to $8.6$16.9 million during the same period in 2025, representing an 18%32% increase. The increase was primarily due to produced oil volumes from the acquired Wyoming assets and higher realized gas prices in Pennsylvania.

The Company used $4.3$6.4 million and $6.8$10.7 million of cash for investing activities during the threesix months ended MarchJune 31,30, 2026 and 2025, respectively. During the threesix months ended MarchJune 31,30, 2026, the Company had net$net investments primarily in well and facilities costs and leasehold in Pennsylvania, Texas, and Wyoming.Wyoming offset by the ORRI sale in Pennsylvania. During the threesix months ended MarchJune 31,30, 2025, the Company had net investments of $6.8 million primarily in well costs in Pennsylvania, Texas, and Canada.

The Company used $6.9$13.8 million and $1.4$2.8 million of cash for financing activities during the threesix months ended MarchJune 31,30, 2026 and 2025, respectively. During the threesix months ended MarchJune 31,30, 2026, this was spent on the repayment of the outstanding balance on the credit facility and dividend payments. During the threesix months ended MarchJune 31,30, 2025, this was spent on dividend payments.

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. This replaced the Company’s previous credit facility. As of MarchJune 31,30, 2025,2026, the borrowing base was $80$90 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 Aprilthe six months ended June 30, 2026, the Company made arepayments $5of $10 million repayment on the outstanding credit facility. The current balance as of MayAugust 11,12, 2026 is $40.5 million.

During the threesix months ended MarchJune 31,30, 2026, no shares were repurchased under the new or previous program.

At MarchJune 31,30, 2026, Epsilon’s outstanding natural gas and crude oil commodity contracts consisted of the following:

The following table summarizes our contractual obligations at MarchJune 31,30, 2026.

The Company enters into commitments for capital expenditures in advance of the expenditures being made. As of MarchJune 31,30, 2026, our commitments for capital expenditures were $10.9$18 million related to the drilling and completion of 15 gross (0.25 net) well in Texas, 4 gross (0.320.37 net) wells in Pennsylvania,Pennsylvania and the completion of 26 gross (0.683.58 net) wells in Wyoming.