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Item 7. Management’s Discussion and Analysis

2026-03-27 compared with 2025-03-19 · 155 added, 104 removed, 192 unchanged (57% of the section changed)

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(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 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, 2024 our total estimated net proved reserves were 69,401 MMcf of natural gas reserves, 876,808 Bbls of NGL reserves, and 1,572,465 Bbls of oil and condensate, and we held leasehold rights to approximately 102,506 gross (23,602 net) acres.

We have natural gas production from our non-operated wells in Pennsylvania;

natural gas, oil and other liquids production from our non-operated wells in the Permian Basin, Oklahoma;

and oil production from our non-operated well in Alberta, Canada.

Our areas of operations are the Appalachian Basin in Pennsylvania, the Powder River Basin in Wyoming, the Permian Basin in Texas and New Mexico, and the Western Canadian Sedimentary Basin in Alberta, Canada.

At December 31, 2025 our total estimated net proved reserves were 86.4 Bcf of natural gas reserves, 9.3 MMBbls of oil reserves, and 2.4 MMBbls of NGL reserves, and we held leasehold rights to approximately 101,265 gross (54,044 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.

We are committed to disciplined capital allocation which could include shareholder returns in the form of dividends and/or share buybacks.

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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.

On February 26, 2024, Epsilon acquired a 25% interest in three producing wells and 3,620 gross undeveloped acres in Ector County, Texas from a private operator.

The Company participated in the drilling and completion of 2 gross (0.5 net) wells during 2024 which were put on production in May 2024 and July 2024.

Together with the transaction completed in 2023, the Company holds a 25% working interest in 16,592 gross acres and 7 producing wells in Texas.

Total capital expenditures (net to Epsilon) through year-end 2024 in the project (including undeveloped leasehold) are $38.6 million.

On April 11, 2024, Epsilon acquired a 50% working interest in 14,243 gross undeveloped acres in Alberta, Canada.

The Company participated in the drilling and completion of 2 gross (0.5 net) wells.

One well was put on production in September 2024.

One well was deemed non-commercial.

Total capital expenditures (net to Epsilon) through year-end 2024 in the project (including undeveloped leasehold) are $2.9 million.

In October 2024, Epsilon formed a joint venture with a private operator covering approximately 130,000 gross acres in Garrington and Harmattan areas in Alberta, Canada.

The Company will provide a $7 million drilling carry during 2025 in favor of the operator in exchange for a 25% working interest in the leasehold.

To date, the Company participated in the drilling and completion of 2 gross (0.5 net) wells.

Total capital expenditures (net to Epsilon) through year-end 2024 are $1.4 million.

We continue to evaluate new opportunities in numerous onshore North American natural gas and oil basins.

During 2024, we realized net income of $1.9 million as compared to net income of $6.9 million for 2023.

We have a substantial remaining drillable location inventory within our existing leaseholds in Pennsylvania, Wyoming, and Texas.

On November 14, 2025, Epsilon acquired Peak Exploration and Production LLC and Peak BLM Lease LLC and their subsidiaries (together, "Peak") through a business combination.

The acquisition added 284 gross (60 net) wells, including 105 gross (45 net) operated wells, and 60,945 gross (39,566 net) acres located in Campbell, Converse and Johnson Counties, Wyoming.

On December 11, 2025, Epsilon divested Dewey Energy Holdings, LLC, a wholly owned subsidiary of the Company to an undisclosed private buyer.

The assets sold included approximately 964 Mcfe/d (60% natural gas) of production and approximately 6,400 net deep acres and 2,200 net shallow acres of leasehold, all located in Dewey County, Oklahoma.

During 2025, we realized net loss of $5.8 million as compared to net income of $1.9 million for 2024.

This included a $19.3 million loss in Q4 2025 on the sale of our Anadarko Basin assets in Oklahoma, which provides potential tax benefits that may be utilized going forward.

At December 31, 2025, our total estimated net proved developed reserves were 109,444 MMcfe, a 69% increase from December 31, 2024.

The increase is mainly attributable to transfers from proved undeveloped reserves in Pennsylvania and acquisitions in Texas.

The increase is mainly attributable to Wyoming reserves acquired from the Peak acquisition.

At December 31, 2025, our total estimated net proved reserves were 156,037 MMcfe, a 86% increase from December 31, 2024.

This increase is primarily due to revisions in previous estimates related to changes to previously adopted development plans and well performance and acquisitions in Texas As a non-operating working interest owner, we often do not have direct control or visibility over the pace of investment in our assets by the operator.

We must have confirmation from the operator on near-term development to designate an undeveloped well location as proved.

The increase is mainly attributable to Wyoming reserves acquired from the Peak acquisition.

Our standardized measure of discounted future net cash flows as of December 31, 2025 and 2024 was $156.1 million and $50.7 million, respectively.

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Total OK Revenues

Natural gas revenue

Volume (MMcf)

Price ($/Mcf)

Natural gas liquids revenue

Volume (MBoe)

Price ($/Bbl)

Oil and condensate revenue

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Price ($/Bbl)

Total WY Revenues

Natural gas revenue

Volume (MMcf)

Price ($/Mcf)

Natural gas liquids revenue

Volume (MBoe)

Price ($/Bbl)

Oil and condensate revenue

Volume (MBbl)

Price ($/Bbl)

Total Canada Revenues

Total Revenues

Upstream natural gas revenue for the year ended December 31, 2024 decreased by $4.1 million, or 27%, from 2023.

A decrease of $0.2 million was due to lower natural gas prices and a decrease of $3.9 million was due to lower produced volumes as a result of natural decline in the wells and operator elected well shut-ins due to poor natural gas pricing in Pennsylvania.

Upstream natural gas revenue for the year ended December 31, 2025 increased by $18.3 million, or 170%, from 2024.

An increase of $11.6 million was due to higher natural gas prices and an increase of $6.8 million was due to higher produced volumes as a result of previously delayed wells coming on line and the end of operator-elected well shut-ins in Pennsylvania.

Upstream natural gas liquids revenue for the year ended December 31, 2025 increased by $0.5 million, or 34% from 2024.

An increase of $0.8 million was due to higher produced volumes from new wells in the Permian Basin and a reduction of $0.3 million was due to lower natural gas liquids prices.

An increase of $0.2 million was due to higher produced volumes from new wells in the Permian and Powder River Basins and an increase of $0.3 million was due to higher natural gas liquids prices.

Upstream oil and condensate revenue for the year ended December 31, 2025 increased by $0.1 million, or 1% over 2024.

An increase of $9.4 million was due to increased production from new wells in the Permian Basin offset by a reduction of $0.8 million due to lower oil prices.

Gathering system revenue (net of elimination) for the year ended December 31, 2024 decreased by $4.3 million, or 44% over 2023.

The decrease was primarily due to lower anchor shipper volumes as 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 Auburn gathering rate.

An increase of $2.7 million was due to increased production from new wells in the Permian and Powder River Basins offset by a reduction of $2.6 million due to lower oil prices.

Gathering system revenue (net of elimination) for the year ended December 31, 2025 increased by $1.2 million, or 21% over 2024.

The increase was primarily due to slightly higher throughput, but more importantly, crossflow gas being displaced with Anchor Shipper gas which is charged a higher gathering fee.

Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues, amounted to $1.9 million and $1.1 million, respectively, for the years ended December 31, 2025 and 2024.

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Operating costs include the effects of elimination entries to remove the gathering fees paid to Epsilon’s ownership in the gathering system.

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 ready it for sale.

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 prepare it for sale.

For the year ended December 31, 2025, upstream operating costs increased by $5.3 million, or 72% from the same period in 2024.

The increase is primarily due to the acquired and developed wells in the Permian Basin.

The increase is primarily due to the increase in gas production in Pennsylvania and the acquired production in the Powder River Basin.

The higher unit operating cost is primarily due to the higher liquids (oil and natural gas liquids) proportion of total sales (Mcfe).

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For leasehold acquisition costs and the cost to acquire proved and unproved properties, the reserve base used to calculate depreciation and depletion is total proved reserves.

For natural gas and oil development and gathering system costs, the reserve base used to calculate depletion and depreciation is proved developed reserves.

For natural gas and oil

development and gathering system costs, the reserve base used to calculate depletion and depreciation is proved developed reserves.

A reserve report is prepared as of December 31, each year.

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During the year ended December 31, 2025, DD&A expense increased by $2 million, or 19%, compared to the same period in 2024.

This increase was a result of the lower third-party reserves causing an increased depletion rate in addition to higher production from the Permian Basin.

This increase was primarily a result of higher produced volumes in Pennsylvania and acquired properties in Wyoming.

Year ended December 31,

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Additionally, GAAP requires that if an exploratory well is determined not to have found proved reserves, the costs incurred, net of any salvage value, should be charged to expense.

For the year ended December 31, 2024, the Company recorded an impairment of $1.45 million on the Killam project (interest acquired in April 2024) in Alberta, Canada.

One well was impaired as a result of a decrease in reserves ($0.53 million) and one well drilled during the year was deemed non-commercial ($0.92 million).

For the year ended December 31, 2023, there was no 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.

Loss on Sale of Assets

Year ended December 31,

Loss on sale of assets

For the year ended December 31, 2025, the Company sold all of its interests in Oklahoma for $2.5 million.

This resulted in a loss on the sale of $19.3 million, primarily on undeveloped leasehold.

The Company had no asset sales in 2024.

Transaction Costs

Year ended December 31,

Transaction Costs

For the year ended December 31,2025, the Company had transaction costs related to the Peak acquisition of $2.9 million for advisory and legal services incurred by the Company.

General and Administrative (“G&A”)

Year ended December 31,

General and administrative

General and administrative expenses

Stock based compensation expense

Other general and administrative expense

Total general and administrative expenses

G&A expenses consist of general corporate expenses such as compensation, legal, accounting and professional fees, consulting services, travel and other related corporate costs such as restricted shares of stock granted and the related non-cash compensation.

G&A expenses for the year ended December 31, 2024 decreased by $0.3 million, or 5%, compared to the same period in 2023.

This decrease was primarily due to a reduction in legal expenses.

G&A expenses for the year ended December 31, 2025 increased by $2 million, or 29%, compared to the same period in 2024.

An increase of $1.2 million is related to higher compensation expense, an increase of $0.5 million in stock based compensation, and an increase of $0.1 million in audit and tax fees.

Interest Income

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During the year ended December 31, 2025, interest income decreased by $0.3 million, or 62%, from the same period in 2024.

This decrease was primarily due to the reduction in the balance of cash and short term investments.

This decrease was primarily due to the reduction in the balance of cash equivalents associated with the maturation of all short term investments in June 2024.

Interest Expense

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Interest expense relates to the interest and commitment fees paid on the revolving line of credit.

Interest expense decreased by $0.03 million, or 42%, during the year ended December 31, 2024 from 2023.

The decrease is due to higher fees in 2023 associated with our new credit facility.

Net (loss) gain on commodity contracts

Interest expense increased by $0.6 million, or 1245%, during the year ended December 31, 2025 from 2024.

The increase is due to interest charged on the outstanding debt balance from the closing of the Peak acquisition on November 14, 2025, commitment fees on unused debt capacity, and the amortization of front-end fees related to the new credit facility entered into in October 2025.

Gain (Loss) on Derivative Contracts, net

Year ended December 31,

(Loss) gain on derivative contracts

During the year ended December 31, 2024, the Company had NYMEX Henry Hub (“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.

During the year ended December 31, 2023, the Company had NYMEX HH Natural Gas Futures swaps and Tennessee Gas Pipeline Zone 4 basis swaps derivative contracts for the same hedging purpose.

Gain (loss) on derivative contracts, net

During the year ended December 31, 2025, the Company had NYMEX Henry Hub (“HH”) Natural Gas Futures swaps, NYMEX HH 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, 2024, the Company had NYMEX HH Natural Gas Futures swaps, 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.

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For the year ended December 31, 2024, the Company received net cash settlements of $1,196,656.

At December 31, 2024, the Company had outstanding NYMEX HH swaps totaling 2.2615 Bcf with a weighted average strike price of $3.26 and Tennessee Z4 basis swaps totaling 2.2615 Bcf with a weighted average strike price of ($0.91) for the contract period of January 2025 to October 2025, and NYMEX WTI CMA swaps totaling 20,662 Bbls with a weighted average strike price of $73.49 for the contract period of January 2025 to June 2025.

At December 31, 2023, the Company had outstanding NYMEX HH swaps totaling 1.905 Bcf with a weighted average strike price of $3.25 and Tennessee Z4 basis swaps totaling 1.905 Bcf with a weighted average strike price of ($1.10) to hedge a portion of expected volumes for the contract period of January 2024 to October 2024.

Income Tax Expense

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 2025 to June 2025.

Income Tax (Benefit) Expense

Year ended December 31,

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During the year ended December 31, 2025, income tax expense decreased by $1.3 million, or 78%, from the same period in 2024.

This decrease was primarily due to a decrease in taxable income as a result of losses on derivative contracts and higher intangible drilling cost deductions.

Net Income Compared to Adjusted EBITDA

This decrease was primarily due to a decrease in taxable income as a result of loss on the asset sale, as well as increased expenses related to the Peak acquisition.

Net (Loss) Income Compared to Adjusted EBITDA

Year ended December 31,

Interest income, net

Income tax expense

Net (loss) income

Interest expense (income), net

Income tax (benefit) expense

Depreciation, depletion, amortization, and accretion

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Loss on sale of assets

Loss on derivative contracts net of cash received or paid on settlement

Transaction costs

(Gain) loss on derivative contracts net of cash received or paid on settlement

Foreign currency translation loss

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) other income.

Adjusted EBITDA is not a measure of financial performance as determined under U.S.

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 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 EBITDA provides useful information regarding our ability to service debt and to fund capital expenditures.

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.

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Capital Resources and Liquidity

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 during the year ended December 31, 2023 was funds generated from operations.

For the year ended December 31, 2025 the primary uses of 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, we had a working capital surplus of $7.0 million, a decrease of $26.2 million from the $33.2 million surplus at December 31, 2023.

The surplus decreased from December 31, 2023 due to lower cash and short term investment balances.

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.

At December 31, 2025, we had a working capital surplus of $7.6 million, an increase of $0.5 million from the $7.1 million surplus at December 31, 2024.

The surplus increased from December 31, 2024 due to an increase in current assets.

We anticipate that our current cash balance, available borrowings, and cash flows from operations to be sufficient to meet our cash requirements for at least the next twelve months.

Year ended December 31, 2025 compared to 2024

During the year ended December 31, 2024, $16.8 million was provided by our operating activities, compared to $18.2 million in 2023, a $1.4 million, or 7%, decrease.

The decrease was primarily due to lower production and throughput volumes in the Marcellus due to operator elected shut-ins, offset by higher production volumes in Texas.

The company used $16.7 million for investing activities during the year ended December 31, 2024, compared to $38.4 million in 2023, a $21.7 million, or 57%, decrease.

The decrease was primarily due to a $40.8 million decrease in purchases of short-term investments, offset by a $15.2 million increase in capital investments in upstream properties.

During the year ended December 31, 2024, the Company used $7.3 million for financing activity compared to $11.7 million in 2023, a $4.4 million, or 38% decrease.

The decrease was due to fewer repurchases of our common shares.

During the year ended December 31, 2025, $20.6 million was provided by our operating activities, compared to $16.8 million in 2024, a $3.8 million, or 23%, increase.

The increase was primarily due to higher production and throughput volumes in Pennsylvania due to new wells turned on line as well as curtailed wells returning to production.

The Company used $61.6 million for investing activities during the year ended December 31, 2025, compared to $16.7 million in 2024, a $44.9 million, or 270%, increase.

The increase was primarily due to $49.8 million paid for the Peak acquisition.

During the year ended December 31, 2025, $43.7 million was provided by financing activities compared to $7.3 million used in 2024, a $51 million, or 697% decrease.

The decrease was primarily due to the $50.5 million draw on the Company’s credit facility to repay the outstanding debt of Peak related to the acquisition.

Credit Agreement

The Company closed a senior secured reserve based revolving credit facility on June 28, 2023 with Frost Bank as issuing bank and sole lender.

The current borrowing base is $45 million (redetermined as of February 10, 2025), supported by the Company’s upstream assets in Pennsylvania and subject to semi-annual redeterminations with a maturity date of June 28, 2027.

Interest will be charged at the Daily Simple SOFR rate plus a margin of 3.25%.

The facility is secured by the assets of the Company’s Epsilon Energy USA subsidiary (Borrower).

There are currently no borrowings under the facility.

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 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.

The current balance as of March 25, 2026 is $45.5 million.

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

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● Leverage ratio of less than 2.5 to 1.0 (total debt / income adjusted for interest, taxes and non-cash amounts)

Additionally, if the leverage ratio is greater than 1.0 to 1.0, or the borrowing base utilization is greater than 50%, the Company is required to hedge 50% of the anticipated production from PDP reserves for a rolling 24 month period.

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.

Repurchase Transactions

On February 18, 2026, the Board authorized a new share repurchase program of up to 3,014,986 common shares, representing 10% of the current outstanding common shares of Epsilon, for an aggregate purchase price of not more than

US $15.0 million.

The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act.

The program will commence on February 19, 2026 and end on 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 outstanding common shares of the Company at such time, for an aggregate purchase price of not more than US $13.0 million.

The program is pursuant to a normal course issuer bid and conducted in accordance with Rule 10b-18 under the Exchange Act.

The program commenced on February 12, 2025 and expired on February 11, 2026.

No shares were repurchased under this program.

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 was pursuant to a normal course issuer bid and was conducted in accordance with Rule 10b-18 under the Exchange Act.

The program commenced on March 27, 2024 and was set to expire on March 26, 2025, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination.

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.

On February 12, 2025, the Board terminated and revoked authority under the program.

The previous share repurchase program commenced on March 9, 2023.

During the year ended December 31, 2023, we repurchased 968,149 common shares of the maximum of 2,292,644 authorized for repurchase and spent $4,940,295 under the plan.

The repurchased stock had an average price of $5.08 per share (excluding commissions) and 897,275 common shares were retired during the year ended December 31, 2023.

In 2024, we 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 before the plan terminated on March 26, 2024.

In 2024, the Company repurchased 373,700 shares and spent $1,831,208 at an average price of $4.88 per share (excluding commissions) under the two consecutive repurchase programs.

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 is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act.

The program will commence on February 12, 2025 and end on February 11, 2026, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination.

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.

Derivative Transactions

The Company has entered into hedging arrangements to reduce the impact of natural gas price volatility on operations.

By removing the price volatility from a significant portion of natural gas production, the potential effects of changing prices on operating cash flows have been mitigated, but not eliminated.

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.

At December 31, 2025, Epsilon’s outstanding natural gas and crude oil commodity contracts consisted of the following:

Weighted Average

Price ($/MMbtu)

Weighted Average Price ($/Mmbtu)

Fair Value of Asset

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December 31, 2025

NYMEX Henry Hub swap

Tennessee Z4 basis swap

Weighted Average

NYMEX Henry Hub (LD) Options Call

NYMEX Henry Hub (LD) Options Put

NYMEX Henry Hub (LD) Swaps

NYMEX Henry Hub (LD) Options Call

NYMEX Henry Hub (LD) Options Put

NYMEX Henry Hub (LD) Swaps

NYMEX Henry Hub (LD) Options Call

NYMEX Henry Hub (LD) Options Put

NYMEX Henry Hub (LD) Swaps

Weighted Average Price ($/Mmbtu)

Fair Value of Asset

Derivative Type

Price ($/Bbl)

Crude Oil NYMEX WTI CMA

December 31, 2025

NYMEX WTI CMA Options Call

NYMEX WTI CMA Options Put

NYMEX WTI CMA Swaps

NYMEX WTI CMA Options Call

NYMEX WTI CMA Options Put

NYMEX WTI CMA Swaps

NYMEX WTI CMA Options Call

NYMEX WTI CMA Options Put

NYMEX WTI CMA Swaps

Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2025.

Payments Due by Period

Derivative liabilities

Asset retirement obligations, undiscounted

Capital expenditure commitments

Total future commitments

We enter into commitments for capital expenditures in advance of the expenditures being made.

As of December 31, 2024, our commitments for capital expenditures were $7.8 million.

All of the capital commitments are related to the first two wells of the joint venture 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.

As of December 31, 2025, our commitments for capital expenditures were $3.8 million related to the drilling of 1 gross (0.25 net) well in Texas.

Summary of Critical Accounting Estimates

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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 quantities 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.

The process of estimating future 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.

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The carrying value of unproved and proved oil and natural gas properties and gathering system assets are reviewed for impairment whenever events indicate that the carrying amounts for those assets may not be recoverable.

Such indicators include changes in our business plans, changes in commodity prices leading to unprofitable performance, and, for natural

gas and oil properties, significant downward revisions of estimated proved reserve quantities or significant increases in the estimated development costs.

Such indicators include changes in our business plans, changes in commodity prices leading to unprofitable performance, and, for natural gas and oil properties, significant downward revisions of estimated proved reserve quantities or significant increases in the estimated development costs.

We compare expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the carrying value of the asset.

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The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the natural gas and oil or gathering system asset.

The initial recognition of an ARO fair value requires that management make numerous assumptions regarding such factors as the amounts and timing of settlements;

The initial recognition of an ARO fair value requires that management make numerous assumptions regarding such factors as the amounts and timing

of settlements;

the credit-adjusted risk-free discount rate;

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We consider all positive and negative evidence, including historical operating results, the existence of cumulative losses, estimates of future operating income, and the reversal of existing taxable temporary differences in assessing the need for a valuation allowance.

Income tax filings are subject to audits and

re-assessments.

Income tax filings are subject to audits and re-assessments.

Changes in facts, circumstances, and interpretations of the standards may result in a material increase or decrease in our provision for income taxes.

Business Combinations

We account for acquisitions that have been determined to be business combinations using the acquisition method of accounting.

Accordingly, identifiable assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair values.

We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in these acquisitions.

The most significant assumptions relate to the estimated fair values of proved and unproved oil and gas properties.

The fair value of identifiable assets acquired and liabilities assumed is determined based on various valuation techniques, including market prices, discounted cash flow analysis, and independent appraisals.

Significant judgments and assumptions are inherent in these valuation techniques and include, among other things, estimates of reserves, estimates of future production volumes, estimates of future commodity prices, expected development costs, lease operating costs and the discount rate that reflects the risk of the underlying cash flow estimates.

Estimated fair values assigned to assets acquired can have a significant impact on future results of operations presented in the Company's financial statements.

A higher fair value assigned to a property results in higher DD&A expense, which results in lower net income.

In the event that future commodity prices or reserve quantities are lower than those used as inputs to determine estimates of acquisition date fair values, the likelihood increases that certain costs may be determined to not be recoverable.

Recently Issued Accounting Standards

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis