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What changed in Epsilon Energy Ltd.'s 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of Epsilon Energy Ltd.'s 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+251 added−213 removedSource: 10-K (2026-03-27) vs 10-K (2025-03-19)

Top changes in Epsilon Energy Ltd.'s 2025 10-K

251 paragraphs added · 213 removed · 186 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

53 edited+20 added−4 removed47 unchanged
Biggest changeAs of that date, we had 1,323,663 common shares granted under the 2020 Plan. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of ​ As of ​ ​ December 31, 2024 ​ December 31, 2023 ​ ​ ​ Weighted ​ Weighted ​ ​ Number of ​ Average ​ Number of ​ Average ​ ​ Options ​ Exercise ​ Options ​ Exercise ​ Outstanding Price Outstanding Price Balance at beginning of period 57,500 ​ $ 5.03 70,000 ​ $ 5.03 Exercised — ​ ​ — (12,500) ​ 5.03 Expired/Forfeited (57,500) ​ ​ — — ​ — Balance at period-end — ​ $ — 57,500 ​ $ 5.03 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Exercisable at period-end — ​ $ — 57,500 ​ $ 5.03 ​ For the years ended December 31, 2024 and 2023, we had no warrants or other common share related rights outstanding. 15 ​ ​ The following table sets out the number of time restricted common shares available to be issued upon vesting over the next three years and the changes during the year pursuant to our share compensation plans and the weighted average market price at date of issue for outstanding shares for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of ​ As of ​ ​ December 31, 2024 ​ December 31, 2023 ​ ​ ​ Weighted ​ Weighted ​ ​ Number of ​ Average ​ Number of ​ Average ​ ​ Shares ​ Grant Date ​ Shares ​ Grant Date ​ Outstanding Market Price Outstanding Market Price Balance non-vested Restricted Stock at beginning of period 491,536 ​ $ 6.00 298,210 ​ $ 3.96 Granted 300,052 ​ ​ 5.97 ​ 358,546 ​ ​ 6.28 Vested (230,618) ​ ​ 5.65 (165,220) ​ 4.34 Forfeited — ​ ​ — — ​ — Balance non-vested Restricted Stock at end of period ​ 560,970 ​ $ 5.77 491,536 ​ $ 6.00 ​ The following table sets out the number of performance-based common shares available to be issued upon vesting over the next three years and the changes during the year pursuant to our share compensation plans and the weighted average market price at date of issue for outstanding shares for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of ​ As of ​ ​ December 31, 2024 ​ December 31, 2023 ​ ​ ​ Weighted ​ Weighted ​ ​ Number of ​ Average ​ Number of ​ Average ​ ​ Shares ​ Grant Date ​ Shares ​ Grant Date ​ Outstanding Market Price Outstanding Market Price Balance non-vested Performance Shares at beginning of period — ​ $ — 15,833 ​ $ 3.84 Vested — ​ ​ — (15,833) ​ 3.48 Balance non-vested Performance Shares at end of period ​ — ​ $ — — ​ $ — ​ ​ Recent Developments None. ​ ​ ​
Biggest changeThe following table sets out the number of time restricted common shares available to be issued upon vesting over the next three years and the changes during the year pursuant to our share compensation plans and the weighted average market price at date of issue for outstanding shares for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of ​ As of ​ ​ December 31, 2025 ​ December 31, 2024 ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ Number of ​ Average ​ Number of ​ Average ​ ​ Shares ​ Grant Date ​ Shares ​ Grant Date ​ ​ ​ ​ Outstanding ​ ​ ​ Market Price ​ ​ ​ Outstanding ​ ​ ​ Market Price Balance non-vested Restricted Stock at beginning of period 560,970 ​ $ 5.77 491,536 ​ $ 6.00 Granted 488,283 ​ ​ 4.77 ​ 300,052 ​ ​ 5.97 Vested (267,461) ​ ​ 5.60 (230,618) ​ 5.65 Balance non-vested Restricted Stock at end of period ​ 781,792 ​ $ 5.15 560,970 ​ $ 5.77 ​ ​ Recent Developments Business Combination ​ On November 14, 2025, Epsilon acquired 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.
In the United States, federal proposals are rooted in the EPA’s “endangerment finding,” that was upheld by the Supreme Court. Simply, EPA has concluded that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment.
In the United States, federal proposals are rooted in the EPA’s “endangerment finding,” that was upheld by the Supreme Court. Simply, the EPA has concluded that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment.
Our Chief Operating Officer holds a Bachelor of Science degree in Petroleum Engineering and received a Master’s Degree of Business Administration. He has over 30 years of experience in upstream exploration and production, and has managed all phases of drilling, completions, production and field operations.
Our Chief Operating Officer holds a Bachelor of Science degree in Petroleum Engineering and received a Master’s Degree of Business Administration. He has over 30 years of 11 ​ ​ experience in upstream exploration and production, and has managed all phases of drilling, completions, production and field operations.
The relative mix of Anchor Shipper gas and cross-flow gas is critical to the revenue and earnings of the Auburn GGS because the cross-flow gathering rate is only 25% of the Anchor Shipper rate. Shippers cross-flowing gas must pay 9 ​ ​ the gathering rate of the originating gathering system plus 25% of the Auburn GGS gathering rate.
The relative mix of Anchor Shipper gas and cross-flow gas is critical to the revenue and earnings of the Auburn GGS because the cross-flow gathering rate is only 25% of the Anchor Shipper rate. Shippers cross-flowing gas must pay the gathering rate of the originating gathering system plus 25% of the Auburn GGS gathering rate.
However, in December 2017, the Bureau of Land Management published a final rule rescinding the March 26, 2015 rule (“BLM 2015 Rule”), entitled “Natural gas and oil; Hydraulic Fracturing on Federal and Indian Lands.” The primary purposes of the BLM 2015 Rule were to ensure that wells were constructed so as to protect water supplies, to ensure environmentally responsible management of fluids displaced by fracturing, and to provide public disclosure of chemicals used in fracturing operations.
However, in December 2017, the BLM published a final rule rescinding the March 26, 2015 rule (“BLM 2015 Rule”), entitled “Natural gas and oil; Hydraulic Fracturing on Federal and Indian Lands.” The primary purposes of the BLM 2015 Rule were to ensure that wells were constructed so as to protect water supplies, to ensure environmentally responsible management of fluids displaced by fracturing, and to provide public disclosure of chemicals used in fracturing operations.
Epsilon is unable to predict the timing, scope and effect of any currently proposed or future, laws, regulations or treaties regarding climate change and GHG emissions.
Epsilon is unable to predict the timing, scope and effect of any currently proposed or future, laws, regulations or 14 ​ ​ treaties regarding climate change and GHG emissions.
The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the 14 ​ ​ Natural Gas Act, or the NGA, and by regulations and orders promulgated under the NGA by the FERC.
The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act, or the NGA, and by regulations and orders promulgated under the NGA by the FERC.
The current system capacity of the Auburn CF at this lower design pressure is approximately 220,000 Mcf per day. The facility capacity could be increased again, if required, by either adding compression units or increasing the design suction pressure. The Auburn CF delivers processed natural gas into the Tennessee Gas Pipeline at the Shoemaker Dehy receipt meter.
The current system capacity of the Auburn CF at this lower design pressure is approximately 127,000 Mcf per day. The facility capacity could be increased again, if required, by either adding compression units or increasing the design suction pressure. The Auburn CF delivers processed natural gas into the Tennessee Gas Pipeline at the Shoemaker Dehy receipt meter.
Business Segments Our operations are conducted by two operating segments for which information is provided in our consolidated financial statements for the years ended December 31, 2024 and 2023. The two segments are as follows: Upstream: Activities include interest in the acquisition, exploration, development and production of oil and natural gas reserves.
Business Segments Our operations are conducted by two operating segments for which information is provided in our consolidated financial statements for the years ended December 31, 2025 and 2024. The two segments are as follows: Upstream: Activities include interest in the acquisition, exploration, development and production of oil and natural gas reserves.
Ilk graduated from Texas A&M University with a Doctor in Philosophy degree in Petroleum Engineering, is a member of the Society of Petroleum Engineers, and has in excess of 14 years of experience in oil and gas reservoir studies and reserves evaluations.
Ilk graduated from Texas A&M University with a Doctor in Philosophy degree in Petroleum Engineering, is a member of the Society of Petroleum Engineers, and has in excess of 15 years of experience in oil and gas reservoir studies and reserves evaluations.
On May 17, 2024, Epsilon Energy USA, Inc. (“Epsilon”) executed a new Anchor Shipper Gas Gathering Agreement for Northern Pennsylvania (the “ASGGA”) with operator Appalachia Midstream Services, LLC for a primary term of ten years and an effective date of January 1, 2024. Epsilon simultaneously terminated the prior agreement.
On May 17, 2024, Epsilon Energy USA executed a new Anchor Shipper Gas Gathering Agreement for northern Pennsylvania (the “ASGGA”) with operator Appalachia Midstream Services, LLC for a primary term of ten years and an 9 ​ ​ effective date of January 1, 2024. Epsilon Energy USA simultaneously terminated the prior agreement.
The Anchor Shippers, consisting of Epsilon Energy USA, Equinor USA Onshore Properties, Inc., and Expand Energy Corporation, dedicated approximately 18,000 mineral acres to the Auburn GGS on January 1, 2012 for an initial term of 15 years under an Anchor Shopper Gas Gathering Agreement for Northern Pennsylvania whereby the Auburn GGS owners receive a fixed percentage rate of return on the total capital invested in the construction of the system.
The Anchor Shippers, consisting of Epsilon Energy USA, Equinor USA Onshore Properties, Inc., and Expand Energy Corporation, dedicated approximately 18,000 mineral acres to the Auburn GGS on January 1, 2012 for an initial term of 15 years under an Anchor Shipper Gas Gathering Agreement for northern Pennsylvania whereby the Auburn GGS owners received a fixed percentage rate of return on the total capital invested in the construction of the system.
The person responsible for preparing the reserve report, Dilhan Ilk, is a Registered Professional Engineer (No.139334) in the State of Texas and a Senior Vice President of the firm. Dr.
The person responsible for preparing the DeGolyer and MacNaughton reserve report, Dilhan Ilk, is a Registered Professional Engineer (No.139334) in the State of Texas and a Senior Vice President of the firm. Dr.
The design suction pressure at the Auburn compression facility was reduced further from 550 psig to 450 psig in January 2025. Operating at the lower design suction pressure has the benefit of reducing hydrate occurrences in the system which can pose an operational hazard.
The design suction pressure at the Auburn compression facility was reduced further from 550 psig to 450 psig in January 2025 and from 450 psig to 400 psig in December 2025. Operating at the lower design suction pressure has the benefit of reducing hydrate occurrences in the system which can pose an operational hazard.
In 2024, we paid $2.4 million (after elimination) to the Auburn GGS to gather and treat our 5.7 Bcf of natural gas production in Pennsylvania ($2.5 million after elimination was paid to the Auburn GGS to gather and treat our 7.9 Bcf in 2023), including the fees paid to our subsidiary, Epsilon Midstream.
In 2025, we paid $3.5 million (after elimination) to the Auburn GGS to gather and treat our 9.4 Bcf of natural gas production in Pennsylvania ($2.4 million after elimination was paid to the Auburn GGS to gather and treat our 5.7 Bcf in 2024), including the fees paid to our subsidiary, Epsilon Midstream.
Substantially all the Pennsylvania acreage (4,807 net) is dedicated to the Auburn Gas Gathering System, or the Auburn GGS, located in Susquehanna County, Pennsylvania for a 10-year term expiring in 2033 under an operating agreement whereby the Auburn GGS owners charge a fixed gathering and compression rate which is adjusted annually by the CPI-U All Urban Consumer Price Index published by the US Bureau of Labor Statistics.
Substantially all the Pennsylvania acreage (4,878 net) is dedicated to the Auburn Gas Gathering System (“Auburn GGS”) located in Susquehanna County, Pennsylvania for a 10-year term expiring in 2033 under an operating agreement whereby the Auburn GGS owners charge a fixed gathering and compression rate which is adjusted annually by the CPI-U All Urban Consumer Price Index published by the US Bureau of Labor Statistics.
In November 2016, the Bureau of Land Management (“BLM”) published a final rule to reduce methane emissions 13 ​ ​ by regulating venting, flaring, and leaking from oil and natural gas operations on public lands. A federal district court vacated much of that rule in October 2020 and that decision is now subject to an appeal.
In November 2016, the BLM published a final rule to reduce methane emissions by regulating venting, flaring, and leaking from oil and natural gas operations on public lands. A federal district court vacated much of that rule in October 2020 and that decision is now subject to an appeal.
Gathering system revenues derived from Epsilon’s production, which have been eliminated from total gathering system revenues (“elimination entry”), amounted to $1.1 million and $1.4 million, respectively, for the years ended December 31, 2024 and 2023.
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 for the years ended December 31, 2025 and 2024, respectively.
For the year ended December 31, 2023, we sold natural gas through ARM to 33 unique customers. Direct Energy Business Marketing, LLC and EQT Energy, LLC each accounted for 10% or more of our total revenue.
SWN Energy Services Company, LLC accounted for 10% or more of our total revenue. For the year ended December 31, 2024, we sold natural gas through ARM to 33 unique customers. Direct Energy Business Marketing, LLC and EQT Energy, LLC each accounted for 10% or more of our total revenue.
The reserve information in this report is based on estimates prepared by DeGolyer and MacNaughton, our independent petroleum consultants.
The reserve information in this report is based on estimates prepared by DeGolyer and MacNaughton and Cawley, Gillespie & Associates, our independent petroleum consultants.
Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company’s Overall Reserve Estimation Process Our policies regarding internal controls over reserve estimates require reserves to be prepared by an independent engineering firm under the supervision of our Chief Operating Officer, and to be in compliance with generally accepted geologic, petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.
The Company sold all of its assets in Oklahoma in December 2025. ​ Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company’s Overall Reserve Estimation Process Our policies regarding internal controls over reserve estimates require reserves to be prepared by an independent engineering firm under the supervision of our Chief Operating Officer, and to be in compliance with generally accepted geologic, petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.
The following tables set out the number of common shares available to be issued upon exercise of outstanding securities and the changes to the securities outstanding for the year pursuant to our equity compensation plans and the weighted average exercise price of outstanding securities for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Number of Shares to be ​ ​ Weighted Average ​ Number of Shares Remaining ​ ​ Issued Upon Exercise ​ ​ Exercise Price of ​ Available for Future Issuance ​ ​ of Outstanding Options, ​ ​ Outstanding Options, ​ Under Equity Compensation Plans Plan Category ​ Warrants and Rights ​ ​ Warrants and Rights ​ (excluding shares in column (a)) Common shares under 2020 Equity Incentive Plan 560,970 ​ $ 5.77 676,337 ​ At December 31, 2024, under the 2020 Equity Incentive Plan (the “2020 Plan”) (See Note 7, “Shareholders’ Equity” of the Notes to the Consolidated Financial Statements), we are authorized to issue 2,000,000 common shares to employees and directors of the Company.
The following tables set out the number of common shares available to be issued upon exercise of outstanding securities and the changes to the securities outstanding for the year pursuant to our equity compensation plans and the weighted average exercise price of outstanding securities for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Number of Shares to be ​ ​ Weighted Average ​ Number of Shares Remaining ​ ​ Issued Upon Exercise ​ ​ Exercise Price of ​ Available for Future Issuance ​ ​ of Outstanding Options, ​ ​ Outstanding Options, ​ Under Equity Compensation Plans Plan Category ​ Warrants and Rights ​ ​ Warrants and Rights ​ (excluding shares in column (a)) Common shares under 2020 Equity Incentive Plan 781,792 ​ $ 5.15 140,637 ​ At December 31, 2025, under the 2020 Equity Incentive Plan (the “2020 Plan”) (See Note 7, “Shareholders’ Equity” of the Notes to the Consolidated Financial Statements), we are authorized to issue 2,000,000 common shares to employees and directors of the Company.
Approximately 40% and 6% of our revenue during fiscal years 2024 and 2023, respectively, was derived from oil, natural gas, and natural gas liquids revenues in the state of Texas.
Approximately 19% and 40% of our revenue during fiscal years 2025 and 2024, respectively, was derived from oil, natural gas, and natural gas liquids revenues in the state of Texas.
As a result of the 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.
However, the Company is still subject to geographic concentration, and 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.
We are exposed to the risk of industry competition for drilling rigs, completion rigs and availability of related equipment and services, among other goods and services required in our business. Employees As of December 31, 2024, we had ten full-time employees (including executive officers) in Houston, Texas.
We are exposed to the risk of industry competition for drilling rigs, completion rigs and availability of related equipment and services, among other goods and services required in our business. Employees As of December 31, 2025, we had twenty-seven full-time employees (including executive officers) in Texas, Colorado, and Wyoming.
Environmental Protection Agency, or the EPA, issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that 12 ​ ​ carry substantial administrative, civil and criminal penalties or that may result in injunctive relief for failure to comply.
Environmental Protection Agency (“EPA”), or the Bureau of Land Management (“BLM”) issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or that may result in injunctive relief for failure to comply.
Price ($/Bbl) ​ $ — ​ $ — Total Canada Revenues ​ $ 116,163 ​ $ — Total Company Revenues ​ $ 31,522,775 ​ $ 30,729,752 ​ Gathering System Operations Epsilon Energy USA is the 100% owner of Epsilon Midstream, which owns a 35% undivided interest in the Auburn GGS, located in Susquehanna County, Pennsylvania, with partners Appalachia Midstream Services, LLC (43.875%) and Equinor Pipelines, LLC (21.125%).
Price ($/Bbl) ​ $ 55.84 ​ $ 46.04 Total Canada Revenues ​ $ 987,276 ​ $ 116,163 Total Company Revenues ​ $ 51,587,556 ​ $ 31,522,775 ​ Gathering System Operations Epsilon Energy USA is the 100% owner of Epsilon Midstream, which owns a 35% undivided interest in the Auburn GGS, located in Susquehanna County, Pennsylvania, with partners Appalachia Midstream Services, LLC (43.875%) and Equinor Pipelines, LLC (21.125%).
Our development capital spending to convert proved undeveloped reserves to proved developed reserves for the periods indicated is as follows: ● In 2024 in Pennsylvania, we drilled 3 gross (0.04 net) wells and participated in the completion of 10 gross (0.82 net) wells.
Our development capital spending to convert Proved Undeveloped Reserves to Proved Developed Reserves for the periods indicated is as follows: ● In 2025 in Pennsylvania, 4 gross (0.24) wells were turned on line in January 2025 and 3 gross (0.04) wells were turned on line in March 2025. ​ ● In 2024 in Pennsylvania, we drilled 3 gross (0.04 net) wells and participated in the completion of 10 gross (0.82 net) wells.
These laws and regulations may: ● require the acquisition of various permits before drilling commences; ● restrict the types, quantities and concentrations of various substances, including water and waste, that can be released into the environment; ● limit or prohibit activities on lands lying within wilderness, wetlands and other protected areas; and ● require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
These laws and regulations may: ● require the acquisition of various permits before drilling commences; ● restrict the types, quantities and concentrations of various substances, including water and waste, that can be released into the environment; ● limit or prohibit activities on lands lying within wilderness, wetlands and other protected areas; and ● require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells. 13 ​ ​ Compliance with environmental laws and regulations increases Epsilon’s overall cost of business, but has not had, to date, a material adverse effect on Epsilon’s operations, financial condition or results of operations.
These wells went into production in Texas in May 2024 and July 2024. ​ ● In 2023 in the Permian Basin, The Company participated in the drilling and completion of 4 gross (0.7 net) wells.
This well went into production in Texas in July 2025. ● In 2024 in the Permian Basin, the Company participated in the drilling and completion of 2 gross (0.5 net) wells. These wells went into production in May 2024 and July 2024. ● In 2025 in Canada, we participated in the completion of 2 gross (0.5 net) wells.
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.” At December 31, 2024, Epsilon’s total estimated net proved reserves were 69,401 million cubic feet of natural gas reserves, 876,808 barrels of NGL reserves, and 1,572,465 barrels of oil and other liquids.
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.” At December 31, 2025, Epsilon’s 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.
During the years ended December 31, 2024 and 2023, the Auburn GGS delivered 36.9 Bcf and 66.2 Bcf respectively, of natural gas, or 101 and 181 MMcf per day.
During the years ended December 31, 2025 and 2024, the Auburn GGS delivered 40.5 Bcf and 36.9 Bcf respectively, of natural gas, or 111,000 Mcf per day and 101,000 Mcf per day.
Proved Reserves Per our reserve report prepared by independent petroleum consultants, DeGolyer and MacNaughton, our estimated proved reserves as of December 31, 2024, are summarized in the table below.
Proved Reserves Per our reserve reports prepared by independent petroleum consultants, DeGolyer and MacNaughton and Cawley, Gillespie & Associates (Powder River Basin assets only), our estimated proved reserves as of December 31, 2025, are summarized in the table below.
For information about our segment’s revenues, profits and losses, total assets, and total liabilities, see Note 14 “Operating Segments” in the Notes to Consolidated Financial Statements. ​ 7 ​ ​ Oil and Natural Gas Production and Revenues and Gathering System Revenues A summary of our net oil and natural gas production, average oil and natural gas prices and related revenues and our gathering system revenues for the years ended December 31, 2024 and 2023, respectively, follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ 2024 2023 Production Volumes ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 5,699 ​ ​ 7,906 Total (Mmcfe) ​ ​ 5,699 ​ ​ 7,906 Permian Basin ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 205 ​ ​ 80 Natural gas liquids (MBOE) ​ ​ 52 ​ ​ 18 Oil & other liquids (MBbl) ​ ​ 173 ​ ​ 44 Total (Mmcfe) ​ ​ 1,554 ​ ​ 454 Oklahoma ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 237 ​ ​ 354 Natural gas liquids (MBOE) ​ ​ 17 ​ ​ 21 Oil & other liquids (MBbl) ​ ​ 11 ​ ​ 21 Total (Mmcfe) ​ ​ 408 ​ ​ 605 Canada ​ ​ ​ ​ ​ ​ Oil & other liquids (MBbl) ​ ​ 3 ​ ​ - Total (Mmcfe) ​ ​ 15 ​ ​ - Company Total ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 6,142 ​ ​ 8,340 Natural gas liquids (MBOE) ​ ​ 69 ​ ​ 39 Oil & other liquids (MBbl) ​ ​ 187 ​ ​ 65 Total (Mmcfe) ​ ​ 7,676 ​ ​ 8,965 ​ 8 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ 2024 2023 Revenues ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 10,247,834 ​ $ 13,733,052 Avg.
For information about our segment’s revenues, profits and losses, total capital expenditures, and total assets, see Note 14 “Operating Segments” in the Notes to Consolidated Financial Statements. 7 ​ ​ Oil and Natural Gas Production and Revenues and Gathering System Revenues A summary of our net oil and natural gas production, average oil and natural gas prices and related revenues and our gathering system revenues for the years ended December 31, 2025 and 2024, respectively, follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 Production Volumes ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 9,402 ​ ​ 5,699 Total (MMcfe) ​ ​ 9,402 ​ ​ 5,699 Permian Basin ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 161 ​ ​ 205 Natural gas liquids (MBoe) ​ ​ 36 ​ ​ 52 Oil (MBbl) ​ ​ 149 ​ ​ 173 Total (MMcfe) ​ ​ 1,271 ​ ​ 1,554 Oklahoma ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 197 ​ ​ 237 Natural gas liquids (MBoe) ​ ​ 14 ​ ​ 17 Oil (MBbl) ​ ​ 9 ​ ​ 11 Total (MMcfe) ​ ​ 335 ​ ​ 408 Wyoming ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 189 ​ ​ — Natural gas liquids (MBoe) ​ ​ 27 ​ ​ — Oil (MBbl) ​ ​ 50 ​ ​ — Total (MMcfe) ​ ​ 651 ​ ​ — Canada ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 52 ​ ​ — Natural gas liquids (MBoe) ​ ​ 4 ​ ​ — Oil (MBbl) ​ ​ 15 ​ ​ 3 Total (MMcfe) ​ ​ 166 ​ ​ 15 Company Total ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 10,001 ​ ​ 6,142 Natural gas liquids (MBoe) ​ ​ 81 ​ ​ 69 Oil (MBbl) ​ ​ 223 ​ ​ 187 Total (MMcfe) ​ ​ 11,825 ​ ​ 7,676 ​ 8 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 Revenues ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 28,012,040 ​ $ 10,247,834 Avg.
Geographic Locations of Operations Approximately 50% and 77% of our revenue during fiscal years 2024 and 2023, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania.
In Wyoming, for our operated oil and gas production, two customers accounted for 95.7% of our total revenues. 12 ​ ​ 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.
We conduct operations in the United States through our wholly owned subsidiaries Epsilon Energy USA Inc., an Ohio corporation, or Epsilon Energy USA; Epsilon Midstream, LLC, a Pennsylvania limited liability company, or Epsilon Midstream; Epsilon Operating, LLC, a Delaware limited liability company; Dewey Energy GP LLC, a Delaware limited liability company; Dewey Energy Holdings LLC, a Delaware limited liability company; and Altolisa Holdings, LLC, a Delaware limited liability company.
We conduct operations in the United States through our wholly owned subsidiaries Epsilon Energy USA Inc., an Ohio corporation, or Epsilon Energy USA; Epsilon Midstream, LLC, a Pennsylvania limited liability company, or Epsilon Midstream; Epsilon Operating, LLC, a Delaware limited liability company; Dewey Energy GP LLC, a Delaware limited liability company; Peak Exploration & Production LLC, a Delaware limited liability company; Peak BLM Lease LLC, a Delaware limited liability company; Peak Powder River Resources, LLC, a Wyoming limited liability company (the licensed operator in the state of Wyoming); Peak Energy Operating #2, LLC, a Colorado limited liability company; Willow Springs Development, LLC, a Colorado limited liability company; Peak Powder River Acquisition, LLC, a Delaware limited liability company; and Altolisa Holdings, LLC, a Delaware limited liability company.
Epsilon holds leasehold rights to approximately 102,506 gross (23,602 net) acres. The Company has natural gas production in the Marcellus Shale in Pennsylvania; oil, natural gas liquids and natural gas production in the Permian Basin in Texas and New Mexico, the NW Anadarko Basin in Oklahoma; and oil production in the Western Canadian Sedimentary Basin in Alberta, Canada.
Epsilon holds leasehold rights to approximately 101,265 gross (54,044 net) acres. The Company has natural gas production in the Appalachian Basin Pennsylvania and oil, natural gas liquids and natural gas production in the Powder River Basin in Wyoming, the Permian Basin in Texas and New Mexico, and the Western Canadian Sedimentary Basin in Alberta, Canada.
Commencing on February 19, 2019, the common shares of the Company trade on the NASDAQ Global Market with the ticker symbol ‘‘EPSN.’’ The last reported sales price of our common shares on the NASDAQ Global Market on March 18, 2025 was $7.21 per share. Shareholders. We had approximately 2,000 shareholders of record as of March 1, 2025. Dividends.
Commencing on February 19, 2019, the common shares of the Company trade on the NASDAQ Global Market with the ticker symbol ‘‘EPSN.’’ The last reported sales price of our common shares on the NASDAQ Global Market on March 23, 2026 was $6.00 per share. Shareholders.
In this capacity, ARM is responsible for carrying out marketing activities such as submission of nominations, receipt of payments, and submission of invoices. For the year ended December 31, 2024, we sold natural gas through ARM to 34 unique customers. SWN Energy Services Company, LLC accounted for 10% or more of our total revenue.
Epsilon uses a third-party service, ARM Energy Management LLC (“ARM”) for its Pennsylvania natural gas marketing. In this capacity, ARM is responsible for carrying out marketing activities such as submission of nominations, receipt of payments, and submission of invoices. For the year ended December 31, 2025, we sold natural gas through ARM to 34 unique customers.
Price ($/Mcf) ​ $ 0.16 ​ $ 1.47 Natural gas liquids revenue ​ $ 1,060,967 ​ $ 353,612 Avg. Price ($/Bbl) ​ $ 20.48 ​ $ 19.78 Oil and condensate revenue ​ $ 12,770,258 ​ $ 3,501,098 Avg.
Price ($/Mcf) ​ $ 0.70 ​ $ 0.16 Natural gas liquids revenue ​ $ 706,010 ​ $ 1,060,967 Avg. Price ($/Bbl) ​ $ 19.51 ​ $ 20.48 Oil and condensate revenue ​ $ 9,614,603 ​ $ 12,770,258 Avg.
Price ($/Mcf) ​ $ 1.80 ​ $ 1.74 Gathering system revenue (net of elimination) ​ $ 5,524,063 ​ $ 9,790,531 Total PA Revenues ​ $ 15,771,897 ​ $ 23,523,583 Permian Basin ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 32,930 ​ $ 117,112 Avg.
Price ($/Mcf) ​ $ 2.98 ​ $ 1.80 Gathering system revenue (net of elimination) ​ $ 6,683,735 ​ $ 5,524,063 Total PA Revenues ​ $ 34,695,775 ​ $ 15,771,897 Permian Basin ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 113,038 ​ $ 32,930 Avg.
Price ($/Bbl) ​ $ 73.81 ​ $ 78.71 Total Permian Basin Revenues ​ $ 13,864,155 ​ $ 3,971,822 Oklahoma ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 505,304 ​ $ 1,014,050 Avg. Price ($/Mcf) ​ $ 2.13 ​ $ 2.87 Natural gas liquids revenue ​ $ 420,991 ​ $ 630,806 Avg.
Price ($/Bbl) ​ $ 64.50 ​ $ 73.81 Total Permian Basin Revenues ​ $ 10,433,651 ​ $ 13,864,155 Oklahoma ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 640,607 ​ $ 505,304 Avg. Price ($/Mcf) ​ $ 3.25 ​ $ 2.13 Natural gas liquids revenue ​ $ 318,108 ​ $ 420,991 Avg.
Business highlights of 2024 Operational Highlights Marcellus Shale—Pennsylvania ● During the year ended December 31, 2024, Epsilon’s realized natural gas price was $1.80 per Mcf, excluding the impact of hedges, a 4% increase from $1.74 for the year ended December 31, 2023. ● Total natural gas sales for the year ended December 31, 2024 were 5.7 Bcf, a 28% decrease from the 7.9 Bcf for the year ended December 31, 2023, driven by curtailed production volumes. ● Gathered and delivered 36.9 Bcf gross (12.9 Bcf net to Epsilon’s interest) during the year, or 101 MMcf/d through the Auburn GGS. ● We participated in the drilling of 3 gross (0.04 net) and the completion of 10 gross (0.82 net) Marcellus wells in 2024.
Operational Highlights of 2025 Appalachian Basin—Pennsylvania ● During the year ended December 31, 2025, Epsilon’s realized natural gas price was $2.98 per Mcf, 5 ​ ​ excluding the impact of hedges, a 66% increase from $1.80 for the year ended December 31, 2024. ● Total natural gas sales for the year ended December 31, 2025 were 9.4 Bcf, a 65% increase from the 5.7 Bcf sold for the year ended December 31, 2024, driven by new wells and curtailed wells returning to production. ● Gathered and delivered 40.5 Bcf gross (14.2 Bcf net to Epsilon’s interest) during the year, or 111 MMcf/d through the Auburn GGS. ● In 2025, 4 gross (0.24 net) wells were turned on line in January 2025 and 3 gross (0.04) wells were turned on line in March 2025. ​ Permian Basin—Texas and New Mexico ● During the year ended December 31, 2025, Epsilon’s realized price for all Permian Basin production was $49.19 per Boe, excluding the impact of hedges, an 8% decrease from the $53.52 per Boe for the year ended December 31, 2024 . ● Total sales for the year ended December 31, 2025, including oil, natural gas, and natural gas liquids, were 212 Mboe, an 18% decrease from the 259 MBoe sold for the year ended December 31, 2024. ● In 2025, the Company participated in the drilling and completion of 1 gross (0.25 net) wells in Texas.
These wells went into production in May 2024 and July 2024. ​ Anadarko, NW STACK Trend—Oklahoma ● During the year ended December 31, 2024, Epsilon’s realized price for all Oklahoma production was $4.34 per Mcfe, excluding the impact of hedges, a 19% decrease from $5.35 for the year ended December 31, 2023. ● Total sales for the year ended December 31, 2024, including natural gas, oil, and other liquids, were 0.41 Bcfe, a 32% decrease from 0.60 Bcfe for the year ended December 31, 2023. ​ Western Canadian Sedimentary Basin—Alberta, Canada ● During the year ended December 31, 2024, Epsilon’s realized price for Canada oil production was $46.04 per Bbl. ● Total oil sales for the year ended December 31, 2024 were 2.5 M Bbl. ● In 2024, the Company participated in the drilling of 4 gross (1.5 net) wells in Canada.
This well went into production in July 2025. ​ Anadarko Basin—Oklahoma ● During the year ended December 31, 2025, Epsilon’s realized price for all Oklahoma production was $4.33 per Mcfe, excluding the impact of hedges, a 0.2% decrease from $4.34 realized for the year ended December 31, 2024. ● Total sales for the year ended December 31, 2025, including oil, natural gas, and natural gas liquids, were 0.34 Bcfe, a 17% decrease from 0.41 Bcfe sold for the year ended December 31, 2024. ● In 2025, there was no development activity in Oklahoma.
Epsilon made aggregate quarterly distributions of $5.5 million ($0.25 per share) during the year ended December 31, 2024. The dividend is well supported and the Company intends to maintain it going forward. Securities Authorized for Issuance under Equity Incentive Plans.
We had approximately 2,000 shareholders of record as of March 1, 2026. 15 ​ ​ Dividends. Epsilon made aggregate quarterly distributions of $6.0 million ($0.25 per share) during the year ended December 31, 2025. The dividend is well supported and the Company intends to maintain it going forward, subject to quarterly approval by the Board.
Marketing and Major Customers Natural gas marketing is competitive in northeast Pennsylvania because of the limited interstate transportation 11 ​ ​ capacity and ample natural gas supply. We do not currently own any firm transportation on interstate pipelines that would enable us to diversify our natural gas sales to downstream locations.
We do not currently own any firm transportation on interstate pipelines that would enable us to diversify our natural gas sales to downstream locations. As a result, all of our Pennsylvania gas sales occur in Zone 4 of the Tennessee Gas Pipeline at the Shoemaker Dehy meter, which is the receipt point from the Auburn CF.
See Risk Factors for information relating to the uncertainties surrounding these reserve categories. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural Gas ​ Natural Gas ​ Oil and Other ​ Total ​ MMcf Liquids MBbl Liquids MBbl MMcfe Proved developed reserves ​ 56,851 ​ 490 ​ 847 64,872 Proved undeveloped reserves ​ 12,550 ​ 387 ​ 725 19,225 Total Proved Reserves at December 31, 2024 ​ 69,401 ​ 877 ​ 1,572 84,097 ​ ​ ​ ​ ​ ​ ​ ​ Changes in Total Proved Undeveloped Reserves Proved undeveloped reserves at December 31, 2023 ​ 18,361 ​ 134 ​ 69 19,581 Revisions of previous estimates ​ 10,029 ​ — ​ (4) ​ 10,001 Acquisitions ​ 785 ​ 253 ​ 660 ​ 6,268 Transfers to proved developed ​ (16,625) ​ — ​ — (16,625) Proved undeveloped reserves at December 31, 2024 12,550 387 725 19,225 ​ Revisions to previous estimates for total proved undeveloped reserves for 2024 include additions of 10,244 MMcfe related to changes to the previously adopted development plan and reductions of 182 MMcfe related to well performance and reductions of 61 MMcfe related to commodity pricing.
See Risk Factors for information relating to the uncertainties surrounding these reserve categories. 10 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural Gas ​ Natural Gas ​ Oil and Other ​ Total ​ ​ ​ ​ MMcf ​ ​ ​ Liquids MBbl ​ ​ ​ Liquids MBbl ​ ​ ​ MMcfe Proved developed reserves ​ 75,849 ​ 1,599 ​ 4,000 109,444 Proved undeveloped reserves ​ 10,523 ​ 753 ​ 5,259 46,593 Total Proved Reserves at December 31, 2025 ​ 86,372 ​ 2,352 ​ 9,259 156,037 ​ ​ ​ ​ ​ ​ ​ ​ Changes in Total Proved Undeveloped Reserves ​ ​ ​ ​ Proved undeveloped reserves at December 31, 2024 ​ 12,550 ​ 387 ​ 725 19,225 Revisions of previous estimates ​ (4,949) ​ (85) ​ (194) ​ (6,628) Acquisitions ​ 4,609 ​ 639 ​ 4,933 ​ 38,041 Divestitures ​ (1,521) ​ (134) ​ (65) ​ (2,715) Transfers to proved developed ​ (166) ​ (54) ​ (140) (1,330) Proved undeveloped reserves at December 31, 2025 10,523 753 5,259 46,593 ​ Revisions to previous estimates for total proved undeveloped reserves for 2025 include reductions of 6,340 MMcfe related to changes to the previously adopted development plan and reductions of 269 MMcfe related to technical revisions and reductions of 19 MMcfe related to commodity pricing.
The three wells turned online in October 2024. 10 ​ ​ ● In 2023 in Pennsylvania, we drilled 7 gross (0.74 net) wells and completed 2 gross (0.02 net) wells. The two wells turned online in January 2023. ● In 2024 in the Permian Basin, the Company participated in the drilling and completion of 2 gross (0.5 net) wells.
The three wells turned on line in October 2024. ● In 2025 in the Permian Basin, the Company participated in the drilling and completion of 1 gross (.25 net) well.
Price ($/Bbl) ​ $ 24.16 ​ $ 29.96 Oil and condensate revenue ​ $ 844,265 ​ $ 1,589,491 Avg. Price ($/Bbl) ​ $ 76.75 ​ $ 76.37 Total OK Revenues ​ $ 1,770,560 ​ $ 3,234,347 Canada ​ ​ ​ ​ ​ ​ Oil and condensate revenue ​ $ 116,163 ​ $ — Avg.
Price ($/Bbl) ​ $ 22.56 ​ $ 24.16 Oil and condensate revenue ​ $ 507,406 ​ $ 844,265 Avg. Price ($/Bbl) ​ $ 54.11 ​ $ 76.75 Total OK Revenues ​ $ 1,466,121 ​ $ 1,770,560 Wyoming ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 291,933 ​ $ — Avg.
Three completed wells went into production in October 2024. ● At year end, the Company had 7 gross (0.27 net) wells waiting to turn on line. 5 ​ ​ ​ Permian Basin—Texas and New Mexico ● During the year ended December 31, 2024, Epsilon’s realized price for all Permian Basin production was $53.52 per BOE, excluding the impact of hedges, a 2% increase from the $52.49 for the year ended December 31, 2023 . ● Total sales for the year ended December 31, 2024, including oil, natural gas, and other liquids, were 259 MBOE, a 242% increase from the 75.7 MBOE for the year ended December 31, 2023. ● In 2024, the Company acquired a 25% working interest in three producing wells and 3,246 gross undeveloped acres in Ector County, Texas. ● In 2024, the Company participated in the drilling and completion of 2 gross (0.5 net) wells in Texas.
The Company sold all of its assets in the Anadarko Basin in December 2025. ​ Powder River Basin—Wyoming ● The Powder River Basin assets were acquired on November 14, 2025. ● During the period ended December 31, 2025, Epsilon’s realized price for all Wyoming production was $36.91 per Boe, excluding the impact of hedges. ● Total sales for the period ended December 31, 2025, including oil, natural gas, and natural gas liquids, were 108.5 MBoe. ​ Western Canadian Sedimentary Basin—Alberta, Canada ● During the year ended December 31, 2025, Epsilon’s realized price for all Canada production was $36.07 per Boe, excluding the impact of hedges, a 22% decrease from the $46.07 per Boe realized for the year ended December 31, 2024. ● Total sales for the year ended December 31, 2025, including oil, natural gas, and natural gas liquids, were 27.4 MBoe , a 996% increase from 2.5 MBoe sold for the year ended December 31, 2024. ● In 2025, the Company participated in the completion of 2 gross (0.5 net) wells in Canada.
Acquisitions of 6,268 MMcfe relates to acreage acquired in Texas. Transfers to proved developed of 16,625 MMcfe relates to the development of wells in Pennsylvania and the Permian Basin.
Acquisitions of 38,041 MMcfe relate to reserves acquired in Wyoming from the Peak acquisition. Divestitures of 2,715 MMcfe relate to the selling of all interests in Oklahoma. Transfers to Proved Developed Reserves of 1,330 MMcfe relates to the development of wells in the Permian Basin.
These wells went into production in April 2023 (1 – New Mexico), May 2023 (1 – New Mexico) and October 2023 (2 – Texas). ● In 2024 in Oklahoma, there was no development activity. ● In 2023 in Oklahoma, we completed 1 gross (0.11 net) well. (Net development capital $0.7 million). The well turned online in May 2023.
The two wells turned on line in March 2025. ● In 2024 in Canada, we 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. ​ ● In 2025 and 2024 in Oklahoma, there was no development activity.
As of December 31, 2024, one well was deemed non-commercial, one well was still being drilled, and one well was waiting on completion. ​ Properties Wells As of December 31, 2024, Epsilon’s 102,506 gross (23,602 net) acres are located in the United States and Canada and include 368 gross (37.90 net) wells. ​ ​ ​ ​ ​ ​ Gross (1) Net (2) Producing Wells Gas 274 29.87 Oil 39 5.58 Total Producing Wells ​ 313 ​ 35.45 Non-Producing Wells ​ 55 ​ 2.45 Total Wells ​ 368 ​ 37.90 ​ Acreage As of December 31, 2024, our leasehold inventory consisted of the following acreage amounts, rounded to the 6 ​ ​ nearest acre: ​ ​ ​ ​ ​ ​ Gross (1) Net (2) (3) Developed Acres Pennsylvania 11,270 4,807 Texas 2,763 691 Oklahoma 5,113 991 Canada 640 320 ​ 19,786 6,809 Undeveloped Acres Pennsylvania 335 327 Texas 13,829 3,455 Oklahoma 54,953 6,209 Canada 13,603 6,802 ​ 82,720 16,793 Total Acres Pennsylvania 11,605 5,134 Texas 16,592 4,146 Oklahoma 60,066 7,200 Canada 14,243 7,122 Total acres 102,506 23,602 ​ (1) “Gross” means one-hundred percent of the working interest ownership in each leasehold tract of land.
Of these wells, 105 gross (45 net) wells are operated. ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross (1) ​ ​ ​ Net (2) Producing Wells ​ ​ Gas 274 33.63 Oil 194 55.42 Total Producing Wells ​ 468 ​ 89.05 Non-Producing Wells ​ 72 ​ 1.64 Total Wells ​ 540 ​ 90.69 ​ Acreage As of December 31, 2025, our leasehold inventory consisted of the following acreage amounts, rounded to the nearest acre: ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross (1) ​ ​ ​ Net (2) (3) Developed Acres ​ ​ Pennsylvania 11,398 4,878 Wyoming 10,428 6,781 Texas 3,086 771 Canada 4,138 1,273 ​ 29,050 13,703 Undeveloped Acres ​ ​ Pennsylvania 250 250 Wyoming 50,517 32,785 Texas 13,548 3,354 Canada 7,900 3,950 ​ 72,215 40,339 Total Acres ​ ​ Pennsylvania 11,648 5,129 Wyoming 60,945 39,566 Texas 16,634 4,126 Canada 12,038 5,223 Total acres 101,265 54,044 (1) “Gross” means one hundred percent of the working interest ownership in each leasehold tract of land.
Removed
One well went into production in September 2024.
Added
On November 14, 2025, Epsilon acquired 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.
Removed
As a result, all of our Pennsylvania gas sales occur in Zone 4 of the Tennessee Gas Pipeline at the Shoemaker Dehy meter, which is the receipt point from the Auburn CF. Epsilon uses a third-party service, ARM Energy Management LLC (“ARM”) for its Pennsylvania natural gas marketing.
Added
The contingent consideration was settled on November 19, 2025, through the issuance of 2,234,847 common shares for $10.6 million. The acquired assets primarily include operated and non-operated production and leasehold interests in the core of the Powder River Basin in Wyoming.
Removed
Epsilon’s management expects to continue to seek opportunities in other North American basins to provide the Company the flexibility to respond to market conditions by allocating capital across multiple basins and commodities.
Added
As part of the acquisition, the Company added 17 full-time employees from Peak. ​ The results of operations attributable to the Peak acquisition have been included in the Company’s consolidated financial statements as of the closing date of the acquisition.
Removed
Compliance with environmental laws and regulations increases Epsilon’s overall cost of business, but has not had, to date, a material adverse effect on Epsilon’s operations, financial condition or results of operations.
Added
The two wells turned on line in March 2025. ​ Properties Wells As of December 31, 2025, Epsilon’s 101,265 gross (54,044 net) acres are located in the United States and Canada 6 ​ ​ and include 540 gross (90.69 net) wells.
Added
Price ($/Mcf) ​ $ 1.54 ​ $ — Natural gas liquids revenue ​ $ 872,263 ​ $ — Avg. Price ($/Bbl) ​ $ 32.48 ​ $ — Oil and condensate revenue ​ $ 2,840,537 ​ $ — Avg.
Added
Price ($/Bbl) ​ $ 56.66 ​ $ — Total WY Revenues ​ $ 4,004,733 ​ $ — Canada ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 63,828 ​ $ — Avg. Price ($/Mcf) ​ $ 1.22 ​ $ — Natural gas liquids revenue ​ $ 82,479 ​ $ — Avg.
Added
Price ($/Bbl) ​ $ 23.01 ​ $ — Oil and condensate revenue ​ $ 840,969 ​ $ 116,163 Avg.
Added
Cawley Gillespie & Associates is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. The lead evaluator that prepared the reserve report was Zane Meekins, P.E., Executive Vice President at Cawley Gillespie. ​ Mr.
Added
Meekins has been with Cawley Gillespie since 1989 and graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins is a State of Texas registered professional engineer (License #71055) and a member of the Society of Petroleum Evaluation Engineers and the Society of Petroleum Engineers. Mr.
Added
Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Mr.
Added
Meekins is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. ​ Marketing and Major Customers Natural gas marketing is competitive in northeast Pennsylvania because of the limited interstate transportation capacity and ample natural gas supply.
Added
In November 2025, the Company completed the acquisition of oil and gas assets in the Powder River Basin, Wyoming which will materially increase the geographic diversification of our revenues going forward and could provide enhanced flexibility to respond to market conditions by allocating capital across multiple basins and commodities.
Added
Securities Authorized for Issuance under Equity Incentive Plans.
Added
As of that date, we had 1,859,363 common shares granted under the 2020 Plan.
Added
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.
Added
The acquired Proved Reserves include 16.8 Bcf of natural gas, 8.2 MMBbls of oil, and 2.0 MMBbls of natural gas liquids, according to the report by Cawley Gillespie & Associates as of December 31, 2025.
Added
As part of the acquisition, the Company added 17 full-time employees from Peak. ​ The results of operations attributable to the Peak acquisition have been included in the Company’s consolidated financial statements as of the closing date of the acquisition. 16 ​ ​ ​ ​ Asset Sale ​ On December 11, 2025, Epsilon divested Dewey Energy Holdings, LLC, a wholly owned subsidiary of the Company to an undisclosed private buyer for $2.5 million.
Added
The assets sold included approximately 964 Mcfe/d (60% natural gas) of production (Q4 2025 figure) and approximately 6,400 net deep acres and 2,200 net shallow acres of leasehold, all located in Dewey County, Oklahoma. ​ Credit Facility ​ On October 10, 2025, the Company closed a new senior secured reserve based revolving credit facility with Frost Bank as administrative agent and Frost Bank and Texas Capital Bank as lenders.
Added
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.
Added
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. ​ ​ ​ ​

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

53 edited+17 added−5 removed120 unchanged
Biggest changeDifferential 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, natural gas is significantly discounted to Henry Hub pricing and the size of the differential can be volatile.
Biggest changeBecause of the large supply of gas, and limited availability of transportation out of 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.
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.
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 and dilution to shareholders.
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 24 ​ ​ 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-term stockholder value.
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 term stockholder value.
There are operational risks associated with gathering and compression of natural gas, including: ● Hurricanes, tornadoes, floods, extreme weather conditions and other natural disasters; ● Aging infrastructure and mechanical problems; ● Damages to pipelines and pipeline blockages or other pipeline interruptions; ● Uncontrolled releases of natural gas, brine, or industrial chemicals; ● Operator error; ● Damage caused by third-party activity, such as operation of construction equipment; ● Pollution and other environmental risks; ● Fires, explosions, craterings, and blowouts; and ● Terrorist attacks on our facilities or those of other energy companies.
There are operational risks associated with gathering and compression of natural gas, including: ● Hurricanes, tornadoes, floods, extreme weather conditions and other natural disasters; ● Aging infrastructure and mechanical problems; 28 ​ ​ ● Damages to pipelines and pipeline blockages or other pipeline interruptions; ● Uncontrolled releases of natural gas, brine, or industrial chemicals; ● Operator error; ● Damage caused by third-party activity, such as operation of construction equipment; ● Pollution and other environmental risks; ● Fires, explosions, craterings, and blowouts; and ● Terrorist attacks on our facilities or those of other energy companies.
If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt, equity financing or the proceeds from the sale of 18 ​ ​ a portion or all of our interest in one or more projects will be available to meet these requirements or available on terms acceptable to us.
If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt, equity financing or the proceeds from the sale of a portion or all of our interest in one or more projects will be available to meet these requirements or available on terms acceptable to us.
If we fail to adequately assess the creditworthiness of existing or future customers and counterparties or otherwise 26 ​ ​ 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.
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.
Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial financial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe 27 ​ ​ to be appropriate.
Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial financial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate.
Any substantial and extended decline in the price of oil and natural gas would have an adverse 22 ​ ​ effect on the carrying value of our proved reserves, borrowing capacity, revenues, profitability and cash flows from operations. There can be no assurance that recent commodity prices can be sustained over the life of our operations.
Any substantial and extended decline in the price of oil and natural gas would have an adverse effect on the carrying value of our proved reserves, borrowing capacity, revenues, profitability and cash flows from operations. There can be no assurance that recent commodity prices can be sustained over the life of our operations.
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 25 ​ ​ have an adverse effect on our business, results of operations, financial position and cash flows.
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.
There can be no assurance that any of the obligations required to maintain each leasehold interest will be met. The termination or expiration of a particular leasehold interest may have a material adverse effect on our financial condition and results of operations. We may incur losses as a result of title deficiencies.
There can be no assurance that any of the obligations required to maintain each 22 ​ ​ leasehold interest will be met. The termination or expiration of a particular leasehold interest may have a material adverse effect on our financial condition and results of operations. We may incur losses as a result of title deficiencies.
A sustained material decline in prices from historical average prices could reduce our borrowing base, thereby reducing the bank credit available to us, which could require that a portion, or all, of our bank debt be repaid. Hedging transactions may limit our potential gains or cause us to lose money.
A sustained material decline in prices from historical average prices could reduce our borrowing base, thereby reducing the bank credit available to us, which could require that a portion, or all, of our bank debt be repaid. 23 ​ ​ Hedging transactions may limit our potential gains or cause us to lose money.
For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom and prepared by different engineers, or by the same engineers at different times, 17 ​ ​ may vary.
For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom and prepared by different engineers, or by the same engineers at different times, may vary.
We may be unable to obtain additional capital required to implement our business plan, which could restrict our ability to grow. Operations could also be adversely affected by general economic downturns or limitations on spending. An economic downturn and uncertainty may have a negative impact on our business.
We may be unable to obtain additional capital required to implement our business plan, which could restrict our ability to sustain or grow our business. Operations could also be adversely affected by general economic downturns or limitations on spending. An economic downturn and uncertainty may have a negative impact on our business.
As a result, the Foreign Investment in Real Property Tax Act, or “FIRPTA,” would require Epsilon Energy Ltd. to pay U.S. federal income tax at the corporate income tax rates on capital gain distributions made by Epsilon Energy USA Inc. to 20 ​ ​ Epsilon Energy Ltd.
As a result, the Foreign Investment in Real Property Tax Act, or “FIRPTA,” would require Epsilon Energy Ltd. to pay U.S. federal income tax at the corporate income tax rates on capital gain distributions made by Epsilon Energy USA Inc. to Epsilon Energy Ltd.
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.
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 17 ​ ​ prospects.
The contract 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-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.
The agreement 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 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.
Additionally, members of the investment community may screen companies such as ours for sustainability performance before investing in our shares. 23 ​ ​ We are subject to complex laws and regulations, including environmental regulations that can have a material adverse effect on the cost, manner and feasibility of doing business.
Additionally, members of the investment community may screen companies such as ours for sustainability performance before investing in our shares. 24 ​ ​ We are subject to complex laws and regulations, including environmental regulations that can have a material adverse effect on the cost, manner and feasibility of doing business.
During 2024 and 2023, there was tremendous volatility in prices and available financing for oil and gas projects. There can be no assurance that we will be able to access capital markets to provide funding for future operations that would require additional capital beyond our current existing available capital on terms acceptable to us.
During 2025 and 2024, there was tremendous volatility in prices and available financing for oil and gas projects. There can be no assurance that we will be able to access capital markets to provide funding for future operations that would require additional capital beyond our current existing available capital on terms acceptable to us.
Approximately 99% of our oil and natural gas properties are operated by third-party operators. As such, we will be dependent on such operators for the timing of activities related to such properties and will largely be unable to direct or control the activities of the operators.
Approximately 50% of our oil and natural gas properties are operated by third-party operators. As such, we will be dependent on such operators for the timing of activities related to such properties and will largely be unable to direct or control the activities of the operators.
Additionally, we may, due to circumstances beyond our control, be put in a position of over-hedging. If this occurs, our revenue could be adversely affected due to the necessity of buying gas at the current market rate in order to fulfill hedging sales obligations.
Additionally, we may, due to circumstances beyond our control, be put in a position of 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.
Actual production and revenues derived therefrom will vary from the estimates contained in the DeGolyer Reserve Report, and such variations could be material. The DeGolyer Reserve Report is based in part on the assumed success of activities that we intend to undertake in future years.
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 and the CGA Reserve Report are based in part on the assumed success of activities that we intend to undertake in future years.
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, property damage, personal injury or other hazards.
Our involvement in the exploration for and development of oil and natural gas properties may result in our becoming subject to liability for pollution, blowouts, property damage, personal injury or other hazards.
Our ability to market our 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 by our 35% ownership of a gathering system in the Marcellus Shale in Pennsylvania.
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 northeast Pennsylvania.
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, or 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.
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 and our annual revenue is more than $100 million.
The borrowing base under our credit facility may be reduced in light of commodity price declines, which could limit us in the future.
The borrowing base under our credit facility may be reduced in light of commodity price declines or reserve changes, which could limit us in the future.
We may issue debt to acquire assets or for working capital. From time to time, we may enter into transactions to acquire assets or shares of other companies. These transactions may be financed partially or wholly with debt, which may increase our debt levels.
From time to time, we may enter into transactions to acquire assets or shares of other companies. These transactions may be financed partially or wholly with debt, which may increase our debt levels.
The loss of the services of such key personnel could have a material adverse effect on us. We do not have key-person insurance in effect for management. The contributions of these individuals to our immediate operations are likely to be of central importance.
Our 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 person insurance in effect for management. The contributions of these individuals to our immediate operations are likely to be of central importance.
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, 2024 and 2023, or the DeGolyer 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.
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, 2025 and 2024 (“DeGolyer Reserve 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.
Approximately 50% and 77% of our revenue during fiscal years 2024 and 2023, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania. Approximately 40% and 6% of our revenue during fiscal years 2024 and 2023, respectively, was derived from oil, natural gas, and natural gas liquids revenues in the state of Texas.
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 years 2025 and 2024, respectively, was derived from oil, natural gas, and natural gas liquids revenues in the state of Texas.
It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and natural gas companies of similar size. Environmental and health and safety risks may adversely affect our business.
It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and natural gas companies of similar size.
The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues from our assets or could increase costs or create liability for the operator’s failure to properly maintain the well and facilities and to adhere to applicable safety and environmental standards. 21 ​ ​ In addition to the operator, our success will depend in large measure on certain key personnel.
The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues from our assets or could increase costs or create liability for the operator’s failure to properly maintain the well and facilities and to adhere to applicable safety and environmental standards.
We may make future acquisitions or enter into financing or other transactions involving the issuance of securities, which may be dilutive to existing security holders.
Future equity transactions could result in dilution to existing stockholders. We may make future acquisitions or enter into financing or other transactions involving the issuance of securities, which may be dilutive to existing security holders.
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 based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to twice yearly redeterminations, as well as special redeterminations described in the credit agreement.
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 Proved Developed Reserves that have been mortgaged to the lenders, and is subject to semiannual redeterminations.
The age and condition of our assets could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our gathering rate and competitive position. We are exposed to the credit risk of our customers and counterparties, and our credit risk management will not be able to completely eliminate such risk.
Any significant increase in these expenditures could adversely affect our gathering rate and competitive position. 27 ​ ​ We are exposed to the credit risk of our customers and counterparties, and our credit risk management will not be able to completely eliminate such risk.
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.
However, the Company is still subject to geographic concentration and we may be disproportionately exposed to the effect of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by 21 ​ ​ governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of crude oil or natural gas.
On the oil and natural gas properties that we do not operate, we will be dependent on such operators for the timing of activities related to such properties and may be largely unable to direct or control the activities of the operators. Results of our drilling are uncertain, and we may not be able to generate high returns.
On the oil and natural gas properties that we do not operate, we will be 20 ​ ​ dependent on such operators for the timing of activities related to such properties and may be largely unable to direct or control the activities of the operators.
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 related debt. In the event our lenders accelerate the repayment of our borrowings, we may not have sufficient assets to repay that indebtedness.
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 repayment of the outstanding indebtedness.
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 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.
If the oil and natural gas industry continues to experience low prices, we may, among other things, be unable to meet all our financial obligations or make planned expenditures. 16 ​ ​ Substantial and extended declines in oil and natural gas prices may result in impairments of proved natural gas and oil properties or undeveloped acreage and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures.
Substantial and extended declines in oil and natural gas prices may result in impairments of proved natural gas and oil properties or undeveloped acreage and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures.
A future increase in our reserves will depend not only on our ability to develop any properties we may have from time to time, but also on our ability to select and acquire suitable producing properties or prospects.
Without the continual addition of new reserves, any of our existing reserves and their production will decline as such reserves are exploited. A future increase in our reserves will depend not only on our ability to develop any properties we may have from time to time, but also on our ability to select and acquire suitable producing properties or prospects.
Our operations involve utilizing the latest drilling and completion techniques in order to maximize cumulative recoveries and generate high returns.
Results of our drilling are uncertain, and we may not be able to generate high returns. Our operations involve utilizing the latest drilling and completion techniques in order to maximize cumulative recoveries and generate high returns.
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.
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.
The oil and natural gas reserves and estimated cash flows to be derived therefrom contained in the DeGolyer Reserve Report will be reduced to the extent that such activities do not achieve the level of success assumed in the DeGolyer Reserve Report.
The oil and natural gas reserves and estimated cash flows to be derived therefrom contained in these reserve reports will be reduced to the extent that such activities do not achieve the level of success assumed in these reserve reports. 18 ​ ​ Our future oil and natural gas reserves, production, and derived cash flows are highly dependent on our successfully acquiring or discovering and developing new reserves.
If we become unable to pay our debt service charges or otherwise commit an event of default, such as bankruptcy, these lenders may foreclose on or sell our properties.
If we become unable to pay our debt service charges or otherwise commit an event of default, such as bankruptcy, these lenders may foreclose on or sell our properties. The proceeds of any such sale would be applied to satisfy amounts owed to our lenders and other creditors, and only the remainder, if any, would be available to us.
In addition, our ability to carry out operations may depend upon the decisions of other working interest owners in our properties. Accordingly, while we anticipate that we will have the ability to spend the funds available to us, there may be circumstances where, for sound business reasons, a reallocation of funds may be prudent.
Accordingly, while we anticipate that we will have the ability to spend the funds available to us, there may be circumstances where, for sound business reasons, a reallocation of funds may be prudent. We may issue debt to acquire assets or for working capital.
Any of these systems are susceptible to outages due to fire, floods, power loss, telecommunications failures, usage errors by employees, computer viruses, cyberattacks or other security breaches or similar events. The failure of any of our information technology systems may cause disruptions in our operations, which could adversely affect our revenue and profitability. We are subject to cybersecurity risks.
Any of these systems are susceptible to outages due to fire, floods, power loss, telecommunications failures, usage errors by employees, computer viruses, cyberattacks or other security breaches or similar events.
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. Investor sentiment towards climate change, fossil fuels, and sustainability could adversely affect our business and our share price.
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 upon two significant purchasers for the sale of most of our oil and natural gas production in Wyoming.
If we fail to maintain effective controls, investors may lose confidence in our operating results, the price of our common shares could decline and we may be subject to litigation or regulatory enforcement actions.
If we fail to maintain effective controls, investors may lose confidence in our operating results, the price of our common shares could decline and we may be subject to litigation or regulatory enforcement actions. 26 ​ ​ Risks Related to Gathering System Because of the natural decline in production from existing wells, our success depends on the Anchor Shippers’ economically developing the remaining Marcellus Shale reserves in Pennsylvania.
Depending on forces outside our control, we may need to allocate our available capital in ways that we did not anticipate. Because of the volatile nature of the oil and natural gas industry, we regularly review our budgets in light of past results and future opportunities that may become available to us.
Because of the volatile nature of the oil and natural gas industry, we regularly review our budgets in light of past results and future opportunities that may become available to us. In addition, our ability to carry out operations may depend upon the decisions of other working interest owners in our properties.
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.
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. 19 ​ ​ The terms of our revolving credit facility may restrict our operations, particularly our ability to respond to changes or to take certain actions.
Accidents or other operating risks could further result in loss of service available to our customers. ​
Accidents or other operating risks could further result in loss of service available to our customers. Risks Related to Our Business Combination We may be unable to successfully integrate acquired businesses, which could adversely affect our operations and financial results.
A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
The failure of any of our information technology systems may cause disruptions in our operations, which could adversely affect our revenue and profitability. 25 ​ ​ We are subject to cybersecurity risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
Epsilon’s management expects to continue to seek opportunities in other North American basins to provide the Company the flexibility to respond to market conditions by allocating capital across multiple basins and commodities.
In November 2025, the Company completed the acquisition of oil and gas assets in the Powder River Basin, Wyoming which could provide the Company the enhanced flexibility to respond to market conditions by allocating capital across multiple basins and commodities.
Removed
Our future oil and natural gas reserves, production, and derived cash flows are highly dependent on our successfully acquiring or discovering and developing new reserves. Without the continual addition of new reserves, any of our existing reserves and their production will decline as such reserves are exploited.
Added
If the oil and natural gas industry experiences low prices, we may, among other things, be unable to meet all our financial obligations or make planned expenditures.
Removed
The terms of our revolving credit facility may restrict our operations, particularly our ability to respond to changes or to take certain actions.
Added
In the event our lenders accelerate the repayment of our borrowings, we may not have sufficient resources to repay that indebtedness. Depending on forces outside our control, we may need to allocate our available capital in ways that we did not anticipate.
Removed
The proceeds of any such sale would be applied to satisfy amounts owed to our lenders and other creditors, and only the remainder, if any, would be available to us. 19 ​ ​ Future equity transactions could result in dilution to existing stockholders.
Added
The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce. ​ For year ended December 31, 2025, HF Sinclair Refining & Marketing LLC and WGR Operating, LP accounted for approximately 68.4% and 27.3% of our total revenues in Wyoming, respectively, excluding the impact of our commodity derivatives.
Removed
Risks Related to Gathering System Because of the natural decline in production from existing wells, our success depends on the Anchor Shippers’ economically developing the remaining Marcellus Shale reserves. Our natural gas gathering system is dependent upon the level of production from natural gas wells, from which production will naturally decline over time.
Added
No other purchaser accounted for more than 10% of our revenue during such periods. We do not have long term contracts with our purchasers but rather we sell the substantial majority of our production under arm’s length contracts with terms of 12 months or less, potentially including on a month-to-month basis, to a relatively small number of purchasers.
Removed
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, our gas is subject to a price differential.
Added
We do not believe that the loss of a single purchaser would materially affect our business because there are numerous other potential purchasers in the area in which we sell our production.
Added
However, the loss of any one of these significant purchasers, our ability to sell our production to other purchasers on terms we consider acceptable, the inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation could have a short term impact on our financial condition and results of operations.
Added
We cannot assure you that any of our purchasers will continue to do business with us or that we will continue to have ready access to suitable markets for our future production. ​ Investor sentiment towards climate change, fossil fuels, and sustainability could adversely affect our business and our share price.
Added
In Wyoming, we conduct oil and natural gas exploration, development and production activities on federal lands, including lands administered by the BLM and in some cases, United States Forest Service. Operations on federal lands are frequently subject to permitting delays.
Added
Operations on these lands are also subject to the National Environmental Policy Act ("NEPA”) which requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment.
Added
In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment.
Added
While the Company currently has exploration, development and production activities on federal lands, our proposed exploration, development and production activities are expected to include federal mineral interests, which will require the acquisition of governmental permits or authorizations that are subject to the procedural requirements of NEPA.
Added
This process has the potential to delay, limit, or increase the cost of the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.
Added
Moreover, depending on the mitigation strategies recommended in Environmental Assessments or Environmental Impact Statements, they could incur added costs, which may be substantial. Environmental and health and safety risks may adversely affect our business.
Added
The age and condition of our assets could result in increased maintenance or repair expenditures in the future.
Added
The success of the acquisition depends, in part, on our ability to realize anticipated synergies and integrate the acquired assets, personnel and systems with those of the Company. Integration efforts may be complex, time-consuming, and costly, and may include consolidating systems, aligning accounting processes, retaining key personnel, and harmonizing corporate cultures.
Added
We may encounter difficulties in integrating information technology systems, internal controls over financial reporting, and operational processes, which could result in delays, increased expenses, or disruptions to our business. In addition, we may fail to retain key employees, customers, or suppliers of the acquired business.
Added
If we are unable to successfully integrate acquired businesses or achieve expected synergies within anticipated timeframes, our financial condition, results of operations, and cash flows could be materially adversely affected. ​

Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

2 edited+1 added−0 removed1 unchanged
Biggest changeMore specifically, they review the Company’s annual IT audits and discuss any potential threats in quarterly meetings. ​ The Chief Financial Officer, Chief Operating Officer, Controller, and Director – Finance are all involved in communications with our IT consultants and auditors. The Chief Financial Officer notifies the Audit Committee and Chief Executive Officer of any cybersecurity threats. ​
Biggest changeMore specifically, they review the Company’s annual IT audits and discuss any potential threats in quarterly meetings. ​ The Chief Financial Officer, Chief Operating Officer, Controller, Senior Vice Presidents and Director – Finance are all involved in communications with our IT consultants and auditors.
The management team works closely with our IT consultants and IT auditors to ensure potential risks are mitigated within our systems. ​ The Company engages a third-party IT consulting firm and conducts an annual IT audit to test our risk management processes. ​ The Company, together with our IT consultants and auditors, has processes that thoroughly vet third-party service providers, continuously monitoring to ensure compliance with our cybersecurity standards. ​ The Company has not encountered cybersecurity threats that have materially impacted our business or operations. ​ Governance ​ The Company’s Board of Directors is aware of the impact of potential cybersecurity threats and stays in close contact with management in case a threat is identified. ​ The Audit Committee of the Board of Directors is the primary governing body that is tasked with the evaluation and confirmation of the Company’s cybersecurity threat mitigation processes.
The management team works closely with our IT consultants and IT auditors to ensure potential risks are mitigated within our systems. ​ The Company engages a third-party IT consulting firm and conducts an annual IT audit to test our risk management processes. ​ The Company, together with our IT consultants and auditors, has processes that thoroughly vet third-party service providers, continuously monitoring to ensure compliance with our cybersecurity standards. ​ 29 ​ ​ The Company has not encountered cybersecurity threats that have materially impacted our business or operations. ​ Governance ​ The Company’s Board of Directors is aware of the impact of potential cybersecurity threats and stays in close contact with management in case a threat is identified. ​ The Audit Committee of the Board of Directors is the primary governing body that is tasked with the evaluation and confirmation of the Company’s cybersecurity threat mitigation processes.
Added
The Chief Financial Officer notifies the Audit Committee and Chief Executive Officer of any cybersecurity threats. ​

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

7 edited+2 added−2 removed1 unchanged
Biggest changeThe awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act. The Company funds the purchases out of available cash and does not incur debt to fund the share repurchase program. The shares are accounted for as treasury shares until such a time as they are retired.
Biggest changeAdditionally, 47,417 common shares were issued as dividend equivalent rights. The awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act. The Company funds the purchases of its shares out of available cash and does not incur debt to fund the share repurchase program.
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 is set to expire February 11, 2026, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination.
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 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 December 31, 2024, our Board made grants to our management, employees, and directors entitling them to receive an aggregate of 236,072 common shares which shall not be issued to the award recipients unless certain time based vesting criteria are met, in which case the vesting will occur in three equal parts on the succeeding periods ending on December 31.
On December 31, 2025, our Board made grants to our management, employees, and directors entitling them to receive an aggregate of 488,283 common shares which shall not be issued to the award recipients unless certain time based vesting criteria are met, in which case the vesting will occur in three equal parts on the succeeding periods ending on December 31.
On February 12, 2025, the Board terminated and revoked authority under this share repurchase program. 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.
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.
On March 19, 2024, the Board authorized a new share repurchase program of up to 2,191,320 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 $12.0 million.
Business .’’ 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.
There were no common share purchases made by the Company during the three months ended December 31, 2024. ​ ​ ​
The shares are accounted for as treasury shares until such a time as they are retired. There were no common share purchases made by the Company during the three months ended December 31, 2025. ​ ​ ​
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 March 26, 2025, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination.
The program was 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.
Removed
Business .’’ On January 1, 2024, the Board of Directors made grants to our directors entitling them to an aggregate of 63,980 common shares which shall not be issued to the award recipients unless certain time based vesting criteria are met, in which case the vesting will occur in three equal parts on the succeeding periods ending on December 31.
Added
On November 14, 2025, after receiving shareholder approval following a special meeting, the Company closed on the acquisition of Peak Exploration and Production LLC and Peak BLM Lease LLC and their subsidiaries (together, “Peak”).
Removed
The awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act.
Added
As consideration, 7,916,336 common shares were issued to the shareholders of Peak after the satisfaction of the conditions of the contingent share consideration and all closing purchase price adjustments.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

68 edited+25 added−16 removed28 unchanged
Biggest changeGeneral and Administrative (“G&A”) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2024 2023 General and administrative ​ $ 6,933,130 ​ $ 7,311,496 ​ 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.
Biggest changeThe Company had no asset sales in 2024. ​ Transaction Costs ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 Transaction Costs ​ $ 2,947,907 ​ $ — ​ 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. ​ 36 ​ ​ General and Administrative (“G&A”) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 General and administrative expenses ​ ​ ​ ​ ​ ​ Stock based compensation expense ​ $ 1,744,917 ​ $ 1,244,416 Other general and administrative expense ​ ​ 7,168,235 ​ ​ 5,688,714 Total general and administrative expenses ​ $ 8,913,152 ​ $ 6,933,130 ​ 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.
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.
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.
Repurchase Transactions 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.
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.
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 38 ​ ​ re-assessments.
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.
Adjusted EBITDA is not a measure of financial performance as determined under U.S. GAAP and 34 ​ ​ 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.
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.
Such indicators include changes in our business plans, changes in commodity prices leading to unprofitable performance, and, for natural 37 ​ ​ 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.
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; and the inflation rate.
The initial recognition of an ARO fair value requires that management make numerous assumptions regarding such factors as the amounts and timing 42 ​ ​ of settlements; the credit-adjusted risk-free discount rate; and the inflation rate.
This section should be read in conjunction with the audited consolidated financial statements as of December 31, 2024 and 2023 and for the years then ended together with accompanying notes. Overview Epsilon Energy Ltd.
This section should be read in conjunction with the audited consolidated financial statements as of December 31, 2025 and 2024 and for the years then ended together with accompanying notes. Overview Epsilon Energy Ltd.
Impairment ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2024 2023 Impairment ​ $ 1,450,076 ​ $ — ​ We perform a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable, over proved properties using the market forward prices, timing, methods and other assumptions consistent with historical periods.
Impairment ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 Impairment ​ $ 3,936,669 ​ $ 1,450,076 ​ We perform a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable, over proved properties using the market forward prices, timing, methods and other assumptions consistent with historical periods.
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.
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.
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.
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.
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. The amounts recorded represent the fair value changes on our derivative instruments during the year.
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.
Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues, amounted to $1.1 million and $1.4 million, respectively, for the years ended December 31, 2024 and 2023.
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.
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.
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.
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 year ended December 31, 2024, gathering system operating costs decreased by $0.2 million, or 7.9% from the same period in 2023.
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 year ended December 31, 2025, gathering system operating costs decreased by $0.1 million, or 4% from the same period in 2024.
Depletion, Depreciation, Amortization and Accretion (DD&A) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2024 2023 Depletion, depreciation, amortization and accretion ​ $ 10,185,119 ​ $ 7,685,084 ​ Natural gas and oil and gathering system assets are depleted and depreciated using the units of production method aggregating properties on a field basis.
Depletion, Depreciation, Amortization and Accretion (DD&A) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 Depletion, depreciation, amortization and accretion ​ $ 12,170,320 ​ $ 10,185,119 ​ Natural gas and oil and gathering system assets are depleted and depreciated using the units of production method aggregating properties on a field basis.
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 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.
The increase is primarily due to the acquired and developed wells in the Permian Basin. The higher unit operating cost is primarily due to the higher liquids (oil and natural gas liquids) proportion of total sales (Mcfe).
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).
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.
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.
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. For the year ended December 31, 2024, upstream operating costs increased by $0.9 million, or 13.4% from the same period in 2023.
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.
Results of Operations The following review of operations for the periods presented below should be read in conjunction with our consolidated financial statements and the notes thereto. 30 ​ ​ Revenues During the year ended December 31, 2024, revenues increased $0.8 million, or 3%, to $31.5 million from $30.7 million during the year ended December 31, 2023.
Results of Operations The following review of operations for the periods presented below should be read in conjunction with our consolidated financial statements and the notes thereto. Revenues During the year ended December 31, 2025, revenues increased $20.1 million, or 64%, to $51.6 million from $31.5 million during the year ended December 31, 2024.
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. We are committed to disciplined capital allocation which could include shareholder returns in the form of dividends and/or share buybacks.
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.
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. A reserve report is prepared as of December 31, each year.
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 35 ​ ​ development and gathering system costs, the reserve base used to calculate depletion and depreciation is proved developed reserves.
Capital Resources and Liquidity Cash Flow 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.
GAAP and should be reviewed carefully. 38 ​ ​ Capital Resources and Liquidity Cash Flow 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.
We plan to maintain a strong balance sheet and liquidity position to allow us to opportunistically invest in both our existing project areas and potential new projects. Our Pennsylvania (“PA”) assets are supported by our 35% ownership in the Auburn GGS.
We plan to maintain a strong balance sheet and liquidity position to allow us to opportunistically invest in both our existing project areas and potential new projects.
Operating Costs The following table presents total cost and cost per unit of production (Mcfe), including ad valorem, severance, and production taxes for the years ended December 31, 2024 and 2023: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2024 2023 Lease operating costs (net of elimination) ​ $ 7,264,824 ​ $ 6,405,281 Gathering system operating costs ​ ​ 2,265,190 ​ ​ 2,459,694 ​ ​ $ 9,530,014 ​ $ 8,864,975 ​ ​ ​ ​ ​ ​ ​ Upstream operating costs—Total $/Mcfe ​ $ 0.95 ​ $ 0.71 Gathering system operating costs $/Mcf ​ $ 0.30 ​ $ 0.15 ​ Operating costs include the effects of elimination entries to remove the gathering fees paid to Epsilon’s ownership in the gathering system.
Operating Costs The following table presents total cost and cost per unit of production (Mcfe), including ad valorem, severance, and production taxes for the years ended December 31, 2025 and 2024: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 Lease operating costs (net of elimination) ​ $ 12,518,325 ​ $ 7,264,824 Gathering system operating costs ​ ​ 2,362,036 ​ ​ 2,265,190 ​ ​ $ 14,880,361 ​ $ 9,530,014 ​ ​ ​ ​ ​ ​ ​ Upstream operating costs—Total $/Mcfe ​ $ 1.06 ​ $ 0.95 Gathering system operating costs $/Mcf ​ $ 0.16 ​ $ 0.17 ​ Operating costs include the effects of elimination entries to remove the gathering fees paid to Epsilon’s ownership in the gathering system.
Revenue and volume statistics for the years ended December 31, 2024 and 2023 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ 2024 2023 Revenues ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 10,247,834 ​ $ 13,733,052 Volume (MMcf) ​ 5,699 ​ 7,906 Avg.
Revenue and volume statistics for the years ended December 31, 2025 and 2024 were as follows: ​ 33 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 Revenues ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 28,012,040 ​ $ 10,247,834 Volume (MMcf) ​ 9,402 ​ 5,699 Avg.
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, 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.
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.
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.
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. 31 ​ ​ Upstream oil and condensate revenue for the year ended December 31, 2024 increased by $8.6 million, or 170% over 2023.
Upstream natural gas liquids revenue for the year ended December 31, 2025 increased by $0.5 million, or 34% from 2024. An increase of $0.2 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.
Depreciation expense includes amounts pertaining to our office furniture and fixtures, leasehold improvements and computer hardware. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 7 years. Also included in depreciation expense is an amount pertaining to buildings owned by the Company.
A reserve report is prepared as of December 31, each year. Depreciation expense includes amounts pertaining to our office furniture and fixtures, leasehold improvements and computer hardware. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 7 years.
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. 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.
The process of estimating future production volumes of proved natural gas and oil reserves is complex, requiring significant subjective 41 ​ ​ decisions in the evaluation of all available geological, engineering and economic data for each reservoir.
Interest expense decreased by $0.03 million, or 42%, during the year ended December 31, 2024 from 2023.
Interest expense increased by $0.6 million, or 1245%, during the year ended December 31, 2025 from 2024.
Under the terms of the facility, the Company must adhere to the following financial covenants: 35 ​ ​ ● Current ratio of 1.0 to 1.0 (current assets / current liabilities) ● 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.
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: ● Current ratio of 1.0 to 1.0 (current assets / current liabilities) ● Leverage ratio of less than 2.5 to 1.0 (total debt / income adjusted for interest, taxes and non-cash amounts) Additionally, the Company is required to hedge 50% of its forecasted Proved Developed Producing production over a rolling 18-month period.
Year ended December 31, 2024 compared to 2023 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.
Year ended December 31, 2025 compared to 2024 During the year ended December 31, 2025, $20.6 million was provided by our operating activities, compared to $16.8 million in 2024, a $3.8 million, or 23%, increase.
Price ($/Mcf) ​ $ 0.16 ​ $ 1.47 Natural gas liquids revenue ​ $ 1,060,967 ​ $ 353,612 Volume (MBOE) ​ 51.8 ​ 17.9 Avg. Price ($/Bbl) ​ $ 20.48 ​ $ 19.78 Oil and condensate revenue ​ $ 12,770,258 ​ $ 3,501,098 Volume (MBbl) ​ 173.0 ​ 44.5 Avg.
Price ($/Mcf) ​ $ 0.70 ​ $ 0.16 Natural gas liquids revenue ​ $ 706,010 ​ $ 1,060,967 Volume (MBoe) ​ 36.2 ​ 51.8 Avg. Price ($/Bbl) ​ $ 19.51 ​ $ 20.48 Oil and condensate revenue ​ $ 9,614,603 ​ $ 12,770,258 Volume (MBbl) ​ 149.1 ​ 173.0 Avg.
Net Income Compared to Adjusted EBITDA ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2024 2023 Net income ​ $ 1,927,800 ​ $ 6,945,153 Add Back: ​ ​ ​ ​ ​ ​ Interest income, net ​ ​ (446,877) ​ ​ (1,592,862) Income tax expense ​ ​ 1,629,093 ​ ​ 3,200,447 Depreciation, depletion, amortization, and accretion ​ ​ 10,185,119 ​ ​ 7,685,084 Impairment expense ​ ​ 1,450,076 ​ ​ — Stock based compensation expense ​ ​ 1,244,416 ​ ​ 1,018,262 Loss on sale of assets ​ ​ — ​ ​ 1,449,871 Loss on derivative contracts net of cash received or paid on settlement ​ ​ 1,587,803 ​ ​ 121,835 Foreign currency translation loss ​ ​ 570 ​ ​ (278) Adjusted EBITDA ​ $ 17,578,000 ​ $ 18,827,512 ​ 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.
Net (Loss) Income Compared to Adjusted EBITDA ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2025 2024 Net (loss) income ​ $ (5,798,863) ​ $ 1,927,800 Add Back: ​ ​ ​ ​ ​ ​ Interest expense (income), net ​ ​ 435,791 ​ ​ (446,877) Income tax (benefit) expense ​ ​ 362,731 ​ ​ 1,629,093 Depreciation, depletion, amortization, and accretion ​ ​ 12,170,320 ​ ​ 10,185,119 Impairment expense ​ ​ 3,936,669 ​ ​ 1,450,076 Stock based compensation expense ​ ​ 1,744,917 ​ ​ 1,244,416 Loss on sale of assets ​ ​ 19,256,530 ​ ​ — Transaction costs ​ ​ 2,947,907 ​ ​ ​ (Gain) loss on derivative contracts net of cash received or paid on settlement ​ ​ (4,336,824) ​ ​ 1,587,803 Foreign currency translation loss ​ ​ 24,805 ​ ​ 570 Adjusted EBITDA ​ $ 30,743,983 ​ $ 17,578,000 ​ 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, (8) transaction costs and (9) gain or loss on foreign currency translation.
Interest Income ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2024 2023 Interest income ​ $ 493,277 ​ $ 1,673,241 ​ During the year ended December 31, 2024, interest income decreased by $1.2 million, or 71%, from the same period in 2023.
Interest Income ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 Interest income ​ $ 188,369 ​ $ 493,277 ​ During the year ended December 31, 2025, interest income decreased by $0.3 million, or 62%, from the same period in 2024.
Price ($/Mcf) ​ $ 1.80 ​ $ 1.74 Gathering system revenue (net of elimination) ​ $ 5,524,063 ​ $ 9,790,531 Total PA Revenues ​ $ 15,771,897 ​ $ 23,523,583 Permian Basin ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 32,930 ​ $ 117,112 Volume (MMcf) ​ 205 ​ 80 Avg.
Price ($/Mcf) ​ $ 2.98 ​ $ 1.80 Gathering system revenue (net of elimination) ​ $ 6,683,735 ​ $ 5,524,063 Total PA Revenues ​ $ 34,695,775 ​ $ 15,771,897 Permian Basin ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 113,038 ​ $ 32,930 Volume (MMcf) ​ 161 ​ 205 Avg.
This measure of discounted future net cash flows does not include any estimate for future cash flows generated by our gathering system assets.
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. This measure of discounted future net cash flows does not include any estimate for future cash flows generated by our gathering system assets.
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.
Upstream oil and condensate revenue for the year ended December 31, 2025 increased by $0.1 million, or 1% over 2024. 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 $2.6 million due to lower oil prices.
Price ($/Mcf) ​ $ 2.13 ​ $ 2.87 Natural gas liquids revenue ​ $ 420,991 ​ $ 630,806 Volume (MBOE) ​ 17.4 ​ 21.1 Avg. Price ($/Bbl) ​ $ 24.16 ​ $ 29.96 Oil and condensate revenue ​ $ 844,265 ​ $ 1,589,491 Volume (MBbl) ​ 11.0 ​ 20.8 Avg.
Price ($/Mcf) ​ $ 3.25 ​ $ 2.13 Natural gas liquids revenue ​ $ 318,108 ​ $ 420,991 Volume (MBoe) ​ 14.1 ​ 17.4 Avg. Price ($/Bbl) ​ $ 22.56 ​ $ 24.16 Oil and condensate revenue ​ $ 507,406 ​ $ 844,265 Volume (MBbl) ​ 9.4 ​ 11.0 Avg.
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.
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.
The decrease is due to higher fees in 2023 associated with our new credit facility. 33 ​ ​ Net (loss) gain on commodity contracts ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2024 2023 (Loss) gain on derivative contracts ​ $ (391,147) ​ $ 3,130,055 ​ 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.
Gain (Loss) on Derivative Contracts, net ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 Gain (loss) on derivative contracts, net ​ $ 5,500,486 ​ $ (391,147) ​ 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.
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.
For the year ended December 31, 2025, the Company received net cash settlements of $1,163,662.
Price ($/Bbl) ​ $ 46.04 ​ $ — Total Canada Revenues ​ $ 116,163 ​ $ — Total Revenues ​ $ 31,522,775 ​ $ 30,729,752 ​ Upstream natural gas revenue for the year ended December 31, 2024 decreased by $4.1 million, or 27%, from 2023.
Price ($/Bbl) ​ $ 55.84 ​ $ 46.04 Total Canada Revenues ​ $ 987,276 ​ $ 116,163 Total Revenues ​ $ 51,587,556 ​ $ 31,522,775 ​ 34 ​ ​ Upstream natural gas revenue for the year ended December 31, 2025 increased by $18.3 million, or 170%, from 2024.
Price ($/Bbl) ​ $ 73.81 ​ $ 78.71 Total Permian Basin Revenues ​ $ 13,864,155 ​ $ 3,971,822 Oklahoma ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 505,304 ​ $ 1,014,050 Volume (MMcf) ​ 237 ​ 354 Avg.
Price ($/Bbl) ​ $ 64.50 ​ $ 73.81 Total Permian Basin Revenues ​ $ 10,433,651 ​ $ 13,864,155 Oklahoma ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 640,607 ​ $ 505,304 Volume (MMcf) ​ 197 ​ 237 Avg.
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 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.
This decrease was primarily due to the reduction in the balance of cash and short term investments. Interest Expense ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2024 2023 Interest expense ​ $ 46,400 ​ $ 80,379 ​ Interest expense relates to the interest and commitment fees paid on the revolving line of credit.
Interest Expense ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 Interest expense ​ $ 624,160 ​ $ 46,400 ​ Interest expense relates to the interest and commitment fees paid on the revolving line of credit.
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 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 expired on February 12, 2025, when the Board terminated and revoked authority under the program.
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 ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2024 2023 Income tax expense ​ $ 1,629,093 ​ $ 3,200,447 ​ During the year ended December 31, 2024, income tax expense decreased by $1.6 million, or 49%, from the same period in 2023.
For the year ended December 31, 2024, the Company received net cash settlements of $1,196,656. 37 ​ ​ 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, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 Income tax expense ​ $ 362,731 ​ $ 1,629,093 ​ During the year ended December 31, 2025, income tax expense decreased by $1.3 million, or 78%, from the same period in 2024.
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.
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.
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.
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.
Depreciation for the buildings is calculated using the straight-line method over an estimated useful life of 30 years. 32 ​ ​ Accretion expense is related to the asset retirement costs. During the year ended December 31, 2024, DD&A expense increased by $2.5 million, or 33%, compared to the same period in 2023.
Also included in depreciation expense is an amount pertaining to buildings owned by the Company. Depreciation for the buildings is calculated using the straight-line method over an estimated useful life of 30 years. Accretion expense is related to the asset retirement costs.
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. 29 ​ ​ 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.
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. 32 ​ ​ 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.
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.
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.
Changes in facts, circumstances, and interpretations of the standards may result in a material increase or decrease in our provision for income taxes. Recently Issued Accounting Standards See Note 3, “Summary of Significant Accounting Policies” in Notes to the Consolidated Financial Statements. ​
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.
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%.
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 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 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 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 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.
At December 31, 2024, our total estimated net proved developed reserves were 64,872 MMcfe, a 28% increase from December 31, 2023. The increase is mainly attributable to transfers from proved undeveloped reserves in Pennsylvania and acquisitions in Texas. At December 31, 2024, our total estimated net proved reserves were 84,097 MMcfe, a 20% increase from December 31, 2023.
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. The increase is mainly attributable to Wyoming reserves acquired from the Peak acquisition.
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.
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.
The decrease was due to fewer repurchases of our common shares. 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 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 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, 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.
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.
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.
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 facility is secured by the assets of the Company’s Epsilon Energy USA subsidiary. During March 2026, the Company made a $5 million repayment on the outstanding credit facility.
Price ($/Bbl) ​ $ 76.75 ​ $ 76.37 Total OK Revenues ​ $ 1,770,560 ​ $ 3,234,347 Canada ​ ​ ​ ​ ​ ​ Oil and condensate revenue ​ $ 116,163 ​ $ — Volume (MBbl) ​ 2.5 ​ — Avg.
Price ($/Mcf) ​ $ 1.22 ​ $ — Natural gas liquids revenue ​ $ 82,479 ​ $ — Volume (MBoe) ​ 3.6 ​ — Avg. Price ($/Bbl) ​ $ 23.01 ​ $ — Oil and condensate revenue ​ $ 840,969 ​ $ 116,163 Volume (MBbl) ​ 15.1 ​ 2.5 Avg.
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.
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.
Removed
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.
Added
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, 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.
Removed
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.
Added
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.
Removed
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.
Added
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.
Removed
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.
Added
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.
Removed
The Company will provide a $7 million drilling carry during 2025 in favor of the operator in exchange for a 25% working interest in the leasehold. To date, the Company participated in the drilling and completion of 2 gross (0.5 net) wells.
Added
Price ($/Bbl) ​ $ 54.11 ​ $ 76.75 Total OK Revenues ​ $ 1,466,121 ​ $ 1,770,560 Wyoming ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 291,933 ​ $ — Volume (MMcf) ​ 189 ​ — Avg.
Removed
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 $6.9 million for 2023.
Added
Price ($/Mcf) ​ $ 1.54 ​ $ — Natural gas liquids revenue ​ $ 872,263 ​ $ — Volume (MBoe) ​ 27 ​ — Avg. Price ($/Bbl) ​ $ 32.48 ​ $ — Oil and condensate revenue ​ $ 2,840,537 ​ $ — Volume (MBbl) ​ 50.1 ​ — Avg.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeGathering System Revenue Risk The Auburn Gas Gathering System lies within the Marcellus Shale with historically high levels of recoverable reserves and low cost of production. We believe that a short-term low commodity price environment will not significantly impact the reserves produced and thus the revenue of our gas gathering system.
Biggest changeWe believe that a short term low commodity price environment will not significantly impact the reserves produced and thus the revenue of our gas gathering system. Derivative Contracts The Company’s financial results and condition depend on the prices received for natural gas and oil production.
Derivative Contracts The Company’s financial results and condition depend on the prices received for natural gas production. Natural gas prices have fluctuated widely and are determined by economic and political factors. Supply and demand factors, including weather, general economic conditions, the ability to transport the gas to other regions, as well as conditions in other natural gas regions, impact prices.
Natural gas and oil prices have fluctuated widely and are determined by economic and political factors. Supply and demand factors, including weather, general economic conditions, the ability to transport the gas to other regions, as well as conditions in other natural gas and oil regions, impact prices.
In addition, our operations are exposed to market risks in the ordinary course of our business, including interest rate and certain exposure as well as risks relating to changes in the general economic conditions in the United States.
In addition, our operations are exposed to market risks in the ordinary course of our business, including interest rate and certain exposure as well as risks relating to changes in the general economic conditions in the United States. 43 ​ ​ Gathering System Revenue Risk The Auburn GGS gather gas produced from the Marcellus Shale with historically high levels of recoverable reserves and low cost of production.

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