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What changed in Epsilon Energy Ltd.'s 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of Epsilon Energy Ltd.'s 2023 and 2024 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 2024 report.

+179 added−192 removedSource: 10-K (2025-03-19) vs 10-K (2024-03-21)

Top changes in Epsilon Energy Ltd.'s 2024 10-K

179 paragraphs added · 192 removed · 140 edited across 4 sections

Item 1. Business

Business — how the company describes what it does

47 edited+9 added−21 removed48 unchanged
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: 15 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of ​ As of ​ ​ December 31, 2023 ​ December 31, 2022 ​ ​ ​ 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 298,210 ​ $ 6.00 166,002 ​ $ 3.96 Granted 358,546 ​ ​ 5.42 ​ 289,231 ​ ​ 6.28 Vested (165,220) ​ ​ 5.95 (157,023) ​ 4.34 Forfeited — ​ ​ — — ​ — Balance non-vested Restricted Stock at end of period ​ 491,536 ​ $ 5.59 298,210 ​ $ 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, 2023 ​ December 31, 2022 ​ ​ ​ 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 ​ $ 3.71 151,500 ​ $ 3.84 Granted — ​ ​ — ​ — ​ ​ — Vested (15,833) ​ ​ 3.71 (135,667) ​ 3.48 Balance non-vested Performance Shares at end of period ​ — ​ $ — 15,833 ​ $ 3.71 ​ ​ Recent Developments On January 30, 2024, the Company repurchased 248,700 shares at $4.82 per share (excluding commissions) under the existing share repurchase plan. ​ ​ ​
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. ​ ​ ​
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 natural gas marketing.
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.
In November 2016, the Bureau of Land Management (“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.
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.
None 11 ​ ​ of our employees are subject to a collective bargaining agreement or represented by a union. The foundation of our Company is our employees and our success begins with a values-driven culture and commitment to developing a skilled, agile, diverse and engaged workforce where every employee understands that they can and do make a difference.
None of our employees are subject to a collective bargaining agreement or represented by a union. The foundation of our Company is our employees and our success begins with a values-driven culture and commitment to developing a skilled, agile, diverse and engaged workforce where every employee understands that they can and do make a difference.
In addition, it is not anticipated, based on current laws and regulations, that Epsilon will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to its total exploration and 12 ​ ​ development expenditure program in order to comply with such laws and regulations.
In addition, it is not anticipated, based on current laws and regulations, that Epsilon will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations.
We are currently unable to calculate or predict the direct and indirect costs of GHG or climate change related laws, regulations and treaties, and accordingly, we cannot assure you that any such 13 ​ ​ efforts will not have a material impact on our operations, financial condition and results.
We are currently unable to calculate or predict the direct and indirect costs of GHG or climate change related laws, regulations and treaties, and accordingly, we cannot assure you that any such efforts will not have a material impact on our operations, financial condition and results.
Marketing and Major Customers Natural gas marketing is competitive in northeast Pennsylvania because of the limited interstate transportation 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.
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.
Environmental Protection Agency, or the EPA, 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.
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.
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 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.
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 13 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 14 years of experience in oil and gas reservoir studies and reserves evaluations.
Proved Reserves Per our reserve report prepared by independent petroleum consultants, DeGolyer and MacNaughton, our estimated proved reserves as of December 31, 2023, are summarized in the table below.
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.
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. Mr.
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.
Epsilon made aggregate quarterly distributions of $5.6 million ($0.25 per share) during the year ended December 31, 2023. The dividend is well supported and the Company intends to maintain it going forward. 14 ​ ​ Securities Authorized for Issuance under Equity Incentive Plans.
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.
Gathering system revenues derived from Epsilon’s production, which have been eliminated from total gathering system revenues (“elimination entry”), amounted to $1.4 million and $1.5 million, respectively, for the years ended December 31, 2023 and 2022.
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.
Geographic Locations of Operations Approximately 77% and 88% of our revenue during fiscal years 2023 and 2022, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania.
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 2023, we paid $2.5 million (after elimination) to the Auburn GGS to gather and treat our 7.9 Bcf of natural gas production in Pennsylvania ($2.8 million after elimination was paid to the Auburn GGS to gather and treat our 9.0 Bcf in 2022), including the fees paid to our subsidiary, Epsilon Midstream.
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.
Direct Energy Business Marketing, LLC and EQT Energy, LLC each accounted for 10% or more of our total revenue. For the year ended December 31, 2022, we sold natural gas through ARM to 26 unique customers. Direct Energy Business Marketing, LLC and SWN Energy Services Company, LLC each accounted for 10% or more of our total revenue.
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.
The relative mix of Anchor Shipper gas and third-party gas is critical to the revenue and earnings of the Auburn GGS because the third-party gathering rate is only 25% of the Anchor Shipper rate. Third-party shippers must pay 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 9 ​ ​ the gathering rate of the originating gathering system plus 25% of the Auburn GGS gathering rate.
The Anchor Shippers, consisting of Epsilon Energy USA, Equinor USA Onshore Properties, Inc., and Chesapeake Energy Corporation, dedicated approximately 18,000 mineral acres to the Auburn GGS for an initial term of 15 years under an operating agreement 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 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.
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 19, 2024 was $5.01 per share. Shareholders. We had approximately 975 shareholders of record as of March 1, 2024. 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 18, 2025 was $7.21 per share. Shareholders. We had approximately 2,000 shareholders of record as of March 1, 2025. Dividends.
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, 2023, Epsilon’s total estimated net proved reserves were 65,916 million cubic feet of natural gas reserves, 383,174 barrels of NGL reserves, and 341,286 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, 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.
During the years ended December 31, 2023 and 2022, the Auburn GGS delivered 66.2 Bcf and 66.3 Bcf respectively, of natural gas, or 181 and 182 MMcf per day.
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.
Epsilon’s management expects to continue to seek opportunities outside of the Marcellus Shale in order to provide the Company the flexibility to respond to market conditions by allocating capital across multiple basins and commodities.
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 this capacity, ARM is responsible for carrying out marketing activities such as submission of nominations, receipt of payments, and submission of invoices. 10 ​ ​ For the year ended December 31, 2023, we sold natural gas through ARM to 33 unique customers.
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.
Price ($/Bbl) ​ $ 76.37 ​ $ 99.24 Total OK Revenues ​ $ 3,234,347 ​ $ 8,117,843 Total Company Revenues ​ $ 30,729,752 ​ $ 69,962,709 ​ 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) ​ $ — ​ $ — 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 ($/Mcf) ​ $ 1.47 ​ $ — Natural gas liquids revenue ​ $ 353,612 ​ $ — Avg. Price ($/Bbl) ​ $ 19.78 ​ $ — Oil and condensate revenue ​ $ 3,501,098 ​ $ — Avg.
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.
Business highlights of 2023 Operational Highlights Marcellus Shale—Pennsylvania ● During the year ended December 31, 2023, Epsilon’s realized natural gas price was $1.74 per Mcf, excluding the impact of hedges, a 71% decrease from $5.96 for the year ended December 31, 2022. ● Total year ended December 31, 2023, natural gas sales were 7.9 Bcf, as compared to 9.0 Bcf during 2022. ● Gathered and delivered 66.2 Bcf gross (23.2 Bcf net to Epsilon’s interest) during the year, or 181 MMcf/d through the Auburn GGS. ● We participated in the drilling of 7 gross (0.74 net) and completion of 2 gross (0.02 net) Marcellus wells in 2023.
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.
The completed wells went into production in January 2023. ● At year end, the Company had 1 gross (0.01 net) well being drilled and 6 gross (0.73 net) wells waiting on completion. ​ Permian Basin—New Mexico and Texas ● During the year ended December 31, 2023, Epsilon’s realized price for all Permian Basin production was 5 ​ ​ $52.49 per BOE, excluding the impact of hedges . ● Total sales for 2023 including oil, natural gas, and other liquids was 75.7 MBOE . ● In 2023, the Company acquired 12,373 gross (3,093 net) of undeveloped leasehold acres in Ector County, Texas. ● In 2023, the Company participated in the drilling and completion of 4 gross (0.7 net) wells.
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 $52.49 for the year ended December 31, 2023 . ● Total sales for the year ended December 31, 2024, including oil, natural gas, and other liquids, were 259 MBOE, a 242% increase from the 75.7 MBOE for the year ended December 31, 2023. ● In 2024, the Company acquired a 25% working interest in three producing wells and 3,246 gross undeveloped acres in Ector County, Texas. ● In 2024, the Company participated in the drilling and completion of 2 gross (0.5 net) wells in Texas.
Price ($/Mcf) ​ $ 1.74 ​ $ 5.96 Gathering system revenue (net of elimination) ​ $ 9,790,531 ​ $ 8,085,512 Total PA Revenues ​ $ 23,523,583 ​ $ 61,844,866 Permian Basin ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 117,112 ​ $ — 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.
The purpose of the reduced rate is to attract additional volumes that require delivery to Tennessee Gas Pipeline when there is spare capacity at the Auburn compression facility, or the “Auburn CF”. Throughput at the Auburn CF has declined from 100.1 Bcf in 2018 to 66.2 Bcf in 2023, a decrease of 34%.
The purpose of the reduced rate is to attract additional volumes that require delivery to Tennessee Gas Pipeline when there is spare capacity at the Auburn compression facility, or the “Auburn CF”.
Price ($/Bbl) ​ $ 78.71 ​ $ — Total Permian Basin Revenues ​ $ 3,971,822 ​ $ — Oklahoma ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 1,014,050 ​ $ 3,189,380 Avg. Price ($/Mcf) ​ $ 2.87 ​ $ 6.68 Natural gas liquids revenue ​ $ 630,806 ​ $ 1,733,129 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.
Our development capital spending to convert proved undeveloped reserves to proved developed reserves for the periods indicated is as follows: ● In 2023 in Pennsylvania, we drilled 7 gross (0.74 net) wells and completed 2 gross (0.02 net) wells. (Net development capital $2.5 million).
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.
These wells went into production in April 2023 (1 – New Mexico), May 2023 (1 – New Mexico) and October 2023 (2 – Texas). ​ Anadarko, NW STACK Trend—Oklahoma ● During the year ended December 31, 2023, Epsilon’s realized price for all Oklahoma production was $5.35 per Mcfe, excluding the impact of hedges, a 38% decrease from $8.68 for the year ended December 31, 2022. ● Total sales for 2023 including natural gas, oil, and other liquids was 0.60 Bcfe, as compared to 0.93 Bcfe during 2022. ● In 2023, the Company participated in the completion of 1 gross (0.11 net) well.
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.
Epsilon holds leasehold rights to approximately 84,684 gross (15,463 net) acres, excluding the Texas acreage acquired in February 2024. The Company has natural gas production in the Marcellus Shale in Pennsylvania and oil, natural gas liquids and natural gas production in the Permian Basin in Texas and New Mexico and in the Anadarko Basin in Oklahoma.
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.
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, 2023 and 2022, respectively, follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ 2023 2022 Production Volumes ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 7,906 ​ ​ 9,026 Total (Mmcfe) ​ ​ 7,906 ​ ​ 9,026 Permian Basin ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 80 ​ ​ - Natural gas liquids (MBOE) ​ ​ 18 ​ ​ - Oil & other liquids (MBbl) ​ ​ 44 ​ ​ - Total (Mmcfe) ​ ​ 454 ​ ​ - Oklahoma ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 354 ​ ​ 477 Natural gas liquids (MBOE) ​ ​ 21 ​ ​ 44 Oil & other liquids (MBbl) ​ ​ 21 ​ ​ 32 Total (Mmcfe) ​ ​ 605 ​ ​ 933 Company Total ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 8,340 ​ ​ 9,503 Natural gas liquids (MBOE) ​ ​ 39 ​ ​ 44 Oil & other liquids (MBbl) ​ ​ 65 ​ ​ 32 Total (Mmcfe) ​ ​ 8,965 ​ ​ 9,959 ​ 7 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ 2023 2022 Revenues ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 13,733,052 ​ $ 53,759,354 Avg.
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.
This request served to minimize throughput decline during a period of low pricing in which the drilling of new wells was undesirable. Operating at the lower design suction pressure also has the benefit of reducing hydrate occurrences in the system which can pose an operational hazard.
The design suction pressure was subsequently reduced to 550 psig in June 2020 at the request of the Anchor Shippers. This request served to minimize throughput decline during a period of low pricing in which the drilling of new wells was undesirable.
Substantially all the production from our Pennsylvania acreage (4,807 net) is dedicated to the Auburn Gas Gathering System, or the Auburn GGS, located in Susquehanna County, Pennsylvania for a 15-year term expiring in 2026 under an operating agreement whereby the Auburn GGS owners receive a fixed percentage rate of return on the total capital invested in the construction and maintenance of the system.
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.
All of Epsilon’s Oklahoma undeveloped properties are deep rights acreage which is held by production of developed properties. Business Segments Our operations are conducted by three operating segments for which information is provided in our consolidated financial statements for the years ended December 31, 2023 and 2022.
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.
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. Our Status as an Emerging Growth Company We are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012, or the “JOBS Act”.
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.
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 ​ 47,555 ​ 249 ​ 272 50,681 Proved undeveloped reserves ​ 18,361 ​ 134 ​ 69 19,581 Total Proved Reserves at December 31, 2023 ​ 65,916 ​ 383 ​ 341 70,262 ​ ​ ​ ​ ​ ​ ​ ​ Changes in Total Proved Undeveloped Reserves Proved undeveloped reserves at December 31, 2022 ​ 11,074 ​ 293 ​ 104 13,459 Revisions of previous estimates ​ 7,549 ​ (132) ​ (25) ​ 6,602 Transfers to proved developed ​ (262) ​ (27) ​ (10) (480) Proved undeveloped reserves at December 31, 2023 18,361 134 69 19,581 ​ Revisions to previous estimates for total proved undeveloped reserves for 2023 include additions of 14,867 MMcfe related to changes to the previously adopted development plan and reductions of 8,265 MMcfe related to commodity pricing.
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.
The 9 ​ ​ well turned online in May 2023. ● In 2022 in Oklahoma, we drilled 2 gross (0.26 net) wells and completed 3 gross (0.7 net) wells. (Net development capital $5.4 million).
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 well went into production in May 2023. ​ Properties Wells As of December 31, 2023, Epsilon’s 84,684 gross (15,463 net) acres are all located in the United States and include 362 gross (37.47 net) wells. ​ ​ ​ ​ ​ ​ Gross (1) Net (2) Producing Wells Gas 289 31.42 Oil 29 2.68 Total Producing Wells ​ 318 ​ 34.10 Non-Producing Wells ​ 44 ​ 3.37 Total Wells ​ 362 ​ 37.47 ​ Acreage As of December 31, 2023, our leasehold inventory consisted of the following acreage amounts, rounded to the nearest acre: ​ ​ ​ ​ ​ ​ Gross (1) Net (2) (3) Developed Acres Pennsylvania 11,270 4,807 Texas 800 200 Oklahoma 5,113 991 ​ 17,183 5,998 Undeveloped Acres Pennsylvania 335 335 Texas 11,573 2,893 Oklahoma 55,593 6,237 ​ 67,501 9,465 Total Acres Pennsylvania 11,605 5,142 Texas 12,373 3,093 Oklahoma 60,706 7,228 Total acres 84,684 15,463 ​ 6 ​ ​ (1) “Gross” means one-hundred percent of the working interest ownership in each leasehold tract of land.
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.
At inception, the capacity of the Auburn CF was approximately 330,000 Mcf per day at a design suction pressure of 800 psig. The design suction pressure was subsequently reduced to 550 psig in June 2020 at the request of the Anchor Shippers.
The Auburn GGS consists of approximately 44 miles of gathering pipelines, a small auxiliary compression facility and a main compression facility with three dehydration units and three Caterpillar 3612 compression units. At inception, the capacity of the Auburn CF was approximately 330,000 Mcf per day at a design suction pressure of 800 psig.
At December 31, 2023, 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. As of that date, we had 1,042,511 common shares granted under the 2020 Plan.
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.
Revenues are also earned from third-party customers of the system to transport gas from the wellhead to the compression facility, and then to the delivery meter at Tennessee Gas Pipeline.
Revenues from the Auburn GGS are earned primarily from the Anchor Shippers with well pads located within the Auburn GGS system boundary. Revenues are also earned when natural gas originating in adjacent gathering systems flow into the Auburn GGS (“cross-flow gas”) to the compression facility, and then to the delivery meter at Tennessee Gas Pipeline.
Price ($/Bbl) ​ $ 29.96 ​ $ 39.31 Oil and condensate revenue ​ $ 1,589,491 ​ $ 3,195,334 Avg.
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.
Additionally, 2 gross (0.02 net) wells were drilled in 2022, but not completed (development capital $0.1 million). They were completed and turned online in January 2023. ● In 2023 in Oklahoma, we completed 1 gross (0.11 net) well. (Net development capital $0.7 million).
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.
Removed
The three segments are as follows: Upstream: Activities include acquisition, exploration, development and production of oil and natural gas reserves on properties within the United States. Gathering System: We partner with two other companies to operate a natural gas gathering system. Corporate: Activities include our corporate and governance functions.
Added
One well went into production in September 2024.
Removed
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.
Added
Gathering System: Interest in a natural gas gathering system.
Removed
During 2023, the gathering rate of the Auburn GGS was determined by a cost of service model whereby the Anchor Shippers dedicate acreage and reserves to the gas gathering system in exchange for the Auburn GGS owners agreeing to an 18% contractual rate of return on invested capital.
Added
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.
Removed
The term of this arrangement is 15 years commencing January 1, 2012 and expiring December 31, 2026. Each year, the Auburn GGS historical and forecast throughput, revenue, operating expenses and capital expenditures are entered into the cost of service model.
Added
The new ASGGA establishes fixed gathering, compression and cross-flow rates for all shippers on each system into which Epsilon produces natural gas. These rates will be adjusted annually by the Consumer Price Index for All Urban Consumers (“CPI-U”) commencing January 2025.
Removed
The model then computes the new gathering rate that will yield the contractual rate of return to the Auburn GGS owners. In January 2027, the Auburn GGS will transition to a fixed gathering rate. Revenues from the Auburn GGS are earned primarily from the Anchor Shippers.
Added
Notably, the gathering rates in Auburn GGS, Rome GGS & Overfield GGS will no longer be subject to a cost-of-service redetermination annually; however, acreage dedications, service priority levels, required shipper approvals and shipper voting procedures are all substantially consistent with the prior agreement.
Removed
However, Anchor Shipper gas as a percentage of total throughput has increased from 57% in 2018 to 74% in 2023.
Added
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.
Removed
As a result of this shift toward a higher percentage of Anchor Shipper gas, as well as higher gathering rates charged, revenues for the gathering system have only declined 2% from 2018 to 2023. 8 ​ ​ The Auburn GGS consists of approximately 44 miles of gathering pipelines, a small auxiliary compression facility and a main compression facility with three dehydration units and three Caterpillar 3612 compression units.
Added
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.
Removed
Transfers to proved developed relates to the development of one well in Oklahoma. We did not engage in any exploration capital spending in 2023 or 2022.
Added
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.
Removed
The two wells turned online in January 2023. ● In 2022 in Pennsylvania, we drilled 5 gross (0.05 net) wells and completed 4 gross (0.21 net) wells. (Net development capital $2.5 million). Reserves of 5.4 Bcf for the 1 well with proved undeveloped reserves were reclassified as proved developed producing as this well was turned online in August 2022.
Added
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.
Removed
Reserves of 2.9 Bcfe for the 3 wells were reclassified as proved developed producing as these wells were turned online at various times beginning in March 2022 and going through October 2022. One gross (0.11 net) well was drilled in 2022, but not completed. It was completed in May 2023.
Removed
As a result of prolonged weak pricing in Zone 4 of the Tennessee Gas Pipeline and, therefore, a reduced pace of development, Epsilon’s management is striving to allocate capital to additional upstream opportunities outside of the Marcellus Shale. More specifically, the Company has allocated capital to the Permian Basin through its investments in New Mexico and Texas.
Removed
Certain specified reduced reporting and other regulatory requirements are available to public companies that are emerging growth companies.
Removed
These provisions include: ● an exemption from the auditor attestation requirement in the assessment of our internal controls over financial reporting required by Section 404 of the Sarbanes—Oxley Act of 2002 (provided that this exemption will continue for such time as we are a “non-accelerated filer”); ● an exemption from the adoption of new or revised financial accounting standards until they would apply to private companies; ● an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board, or the PCAOB, requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about our audit and our financial statements; and ● reduced disclosure about our executive compensation arrangements.
Removed
We have elected to take advantage of the exemption from the adoption of new or revised financial accounting standards until they would apply to private companies. We will continue to be an emerging growth company not later than December 31, 2024. Employees As of December 31, 2023, we had ten full-time employees (including executive officers) in Houston, Texas.
Removed
Legal Proceedings On March 10, 2021, Epsilon filed a complaint against Chesapeake Appalachia, LLC (“Chesapeake”) in the United States District Court for the Middle District of Pennsylvania, Scranton, Pennsylvania (“Middle District”). Epsilon claimed that Chesapeake had breached a settlement agreement and several operating agreements (“JOAs”) to which Epsilon and Chesapeake are parties.
Removed
Epsilon asserted that Chesapeake had failed to cooperate with Epsilon’s efforts to develop resources in the Auburn Development, located in North-Central Pennsylvania, as required under both the settlement agreement and JOAs. Epsilon requested a preliminary injunction but was unsuccessful in obtaining that injunction. Epsilon filed a motion to amend its original Complaint. Chesapeake opposed.
Removed
The Court ruled in Epsilon’s favor and allowed Epsilon’s amendment. Chesapeake moved to dismiss the amended Complaint. The Court granted the motion to dismiss on a narrow issue without prejudice to Epsilon’s right to file a new lawsuit based on new proposals made after the Court’s decision.
Removed
Epsilon filed a motion for reconsideration of that decision, but the court denied the motion for reconsideration on January 18, 2022. Epsilon filed a notice of appeal on February 15, 2022 challenging the District Court's rulings in the case.
Removed
Following the Third Circuit's ruling to remand the case back to District court, Epsilon sought and was granted a dismissal of the case without prejudice in September 2023.
Removed
The following tables set out the number of common shares available to be issued upon exercise of outstanding options issued and the changes to the options outstanding for the year pursuant to our equity compensation plans and the weighted average exercise price of outstanding options for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Number of Shares to be ​ ​ Weighted Average ​ ​ ​ ​ Issued Upon Exercise or ​ ​ Exercise or Vesting Price ​ Number of Shares Remaining ​ ​ Vesting of Outstanding ​ ​ of Outstanding Options ​ Available for Future Issuance Plan Category ​ Options or Shares ​ ​ or Shares ​ Under Equity Compensation Plans Equity share options under Amended and Restated 2017 Stock Option Plan 57,500 $ 5.03 — Common shares under 2020 Equity Incentive Plan 491,536 ​ $ 5.59 957,489 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of ​ As of ​ ​ December 31, 2023 ​ December 31, 2022 ​ ​ ​ Weighted ​ Weighted ​ ​ Number of ​ Average ​ Number of ​ Average ​ ​ Options ​ Exercise ​ Options ​ Exercise ​ Outstanding Price Outstanding Price Balance at beginning of period 70,000 ​ $ 5.03 218,750 ​ $ 5.28 Exercised (12,500) ​ ​ 5.03 (138,750) ​ 5.38 Expired/Forfeited — ​ ​ — (10,000) ​ 5.51 Balance at period-end 57,500 ​ $ 5.03 70,000 ​ $ 5.03 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Exercisable at period-end 57,500 ​ $ 5.03 70,000 ​ $ 5.03 ​ For the years ended December 31, 2023 and 2022, we had no warrants or other common share-related rights outstanding.
Removed
No more shares are authorized to be issued under our predecessor plan.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

29 edited+8 added−15 removed141 unchanged
Biggest changeIf we fail to establish and maintain proper disclosure or internal controls, our ability to produce accurate financial statements and supplemental information or comply with applicable regulations could be impaired. As we grow, we may be subject to growth-related risks including capacity constraints and pressure on our internal systems and controls.
Biggest changeIf some investors find our common shares less attractive as a result, there may be a less active trading market for our common shares and our share price may be more volatile. ​ If we fail to establish and maintain proper disclosure or internal controls, our ability to produce accurate financial statements and supplemental information or comply with applicable regulations could be impaired.
We must also maintain effective internal controls over financial reporting or, at the appropriate time, our independent auditors will be unwilling or unable to provide us with an unqualified report on the effectiveness of our internal controls over financial reporting as required by Section 404(b) of 25 ​ ​ the Sarbanes-Oxley Act, once we become subject to those requirements.
We must also maintain effective internal controls over financial reporting or, at the appropriate time, our independent auditors will be unwilling or unable to provide us with an unqualified report on the effectiveness of our internal controls over financial reporting as required by Section 404(b) of the Sarbanes-Oxley Act, once we become subject to those requirements.
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.
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.
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 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.
There is no guarantee that future demand or pipeline transportation projects will eliminate this differential, and it will therefore remain a significant risk to demand for transportation service on the Auburn GGS, and therefore Epsilon’s revenues and cash flows. 26 ​ ​ We compete with other operators in our gas gathering energy businesses.
There is no guarantee that future demand or pipeline transportation projects will eliminate this differential, and it will therefore remain a significant risk to demand for transportation service on the Auburn GGS, and therefore Epsilon’s revenues and cash flows. We compete with other operators in our gas gathering energy businesses.
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.
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.
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.
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.
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.
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.
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.
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.
There 22 ​ ​ is substantial risk that commodity prices may decline in the future, although it is not possible to predict the time or extent of such decline.
There is substantial risk that commodity prices may decline in the future, although it is not possible to predict the time or extent of such decline.
During 2023 and 2022, 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 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.
Distributions made out of earnings and profits are not expected to be subject to the FIRPTA tax but would be subject to U.S. withholding tax. 20 ​ ​ Our operations are currently geographically concentrated and therefore subject to regional economic, regulatory and capacity risks.
Distributions made out of earnings and profits are not expected to be subject to the FIRPTA tax but are subject to U.S. withholding tax. Our operations are currently geographically concentrated and therefore subject to regional economic, regulatory and capacity risks.
Demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy could reduce demand for natural gas in our markets and have an adverse effect on our business.
Alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy could reduce demand for natural gas in our markets and have an adverse effect on our business.
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.
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 contributions of these individuals to our immediate operations are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is intense, and there can be no assurance that we will be able to continue to attract and retain all personnel necessary for the development and operation of our business.
In addition, the competition for qualified personnel in the oil and natural gas industry is intense, and there can be no assurance that we will be able to continue to attract and retain all personnel necessary for the development and operation of our business.
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. 18 ​ ​ The borrowing base under our credit facility may be reduced in light of commodity price declines, which could limit us in the future.
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.
Epsilon’s management expects to continue to seek opportunities outside of the Marcellus Shale in order to provide the Company the flexibility to respond to market conditions by allocating capital across multiple basins and commodities.
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.
Approximately 77% and 88% of our revenue during fiscal years 2023 and 2022, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania.
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.
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, 16 ​ ​ cash flows, results of operations, liquidity or ability to finance planned capital expenditures.
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.
Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves will vary from estimates thereof and such variations could be material. 17 ​ ​ 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, 2023 and 2022, 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, 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.
Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to train and manage our employee base. We must maintain effective disclosure controls and procedures.
As we grow, we may be subject to growth-related risks including capacity constraints and pressure on our internal systems and controls. Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to train and manage our employee base. We must maintain effective disclosure controls and procedures.
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. 19 ​ ​ Competition in the natural gas and oil industry is intense, which may hinder our ability, and the ability of our third-party operating partners, to contract for drilling equipment, and we may not be able to control the scheduling and activities of contracted drilling equipment.
Competition in the natural gas and oil industry is intense, which may hinder our ability, and the ability of our third-party operating partners, to contract for drilling equipment, and we may not be able to control the scheduling and activities of contracted drilling equipment.
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.
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.
In addition to the operator, 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 21 ​ ​ for management.
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.
The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of the third-party natural gas reserves flowing into our systems and compression facilities.
Production from existing wells with access to our gathering systems will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated.
Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.
Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks. Risks Related to Internal Controls We are a “smaller reporting company” and as a result of the reduced disclosure requirement applicable to smaller reporting companies, our common shares may be less attractive to investors.
Although the Anchor Shippers have dedicated their reserves to the Auburn GGS, they are under no obligation to develop the reserves. 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.
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.
A slowing pace of or complete halt to the development of Anchor Shipper reserves will impact our financial results, cash flows, and access to capital. 27 ​ ​ The financial condition of our natural gas gathering businesses is dependent on the continued availability of natural gas supplies and demand for those supplies in the markets we serve.
The financial condition of our natural gas gathering businesses is dependent on the continued availability of natural gas supplies and demand for those supplies in the markets we serve. Our ability to expand our natural gas gathering business primarily depends on the level of drilling and production by the Anchor Shippers.
This volatility and discount has adversely impacted reserve development in the past, and could do so again in the future.
This volatility and discount has adversely impacted reserve development in the past, and could do so again in the future. A slowing pace of or complete halt to the development of Anchor Shipper reserves will impact our financial results, cash flows, and access to capital.
Removed
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.
Added
Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves will vary from estimates thereof and such variations could be material.
Removed
Future equity transactions could result in dilution to existing stockholders.
Added
The borrowing base under our credit facility may be reduced in light of commodity price declines, which could limit us in the future.
Removed
As a result of prolonged weak pricing in Zone 4 of the Tennessee Gas Pipeline and, therefore, a reduced pace of development, Epsilon’s management is striving to allocate capital to additional upstream opportunities outside of the Marcellus Shale. More specifically, the Company has allocated capital to the Permian Basin through its investments in New Mexico and Texas.
Added
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.
Removed
Risks Related to Internal Controls For as long as we are an “emerging growth company,” we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to some other public companies.
Added
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.
Removed
As an “emerging growth company” as defined in the JOBS Act, we are permitted to, and intend to, rely on exemptions from certain disclosure requirements. We will cease being an emerging growth company not later than December 31, 2024.
Added
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.
Removed
For so long as we remain an “emerging growth company,” we will not be required to: ● have an auditor report on our internal control over financial reporting pursuant to the Sarbanes-Oxley Act of 2002 (provided that this exemption will continue to apply for so long as we are a “non-accelerated filer”); ● comply with any requirement that may be adopted by the Public Company Accounting Oversight Board regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements (auditor discussion and analysis); ● submit certain executive compensation matters to shareholder approval (requiring a non-binding shareholder vote to approve golden parachute arrangements in connection with mergers and certain other business combinations, and advisory votes on executive compensation pursuant to the “say on frequency” and “say on pay” provisions under the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010; and ● include detailed compensation discussion and analysis in our filings under the Securities Exchange Act of 1934 (the “Exchange Act”) and instead may provide a reduced level of disclosure concerning executive compensation.
Added
Smaller reporting companies are able to provide simplified executive compensation disclosure and have certain other reduced disclosure obligations, including, among other things, being required to provide only two years of audited financial statements and not being required to provide selected financial data, supplemental financial information or risk factors.
Removed
In addition, the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period for complying with new or revised accounting standards. We have elected to take advantage of the extended transition period, which allows us to delay the adoption of new or revised accounting standards until those standards apply to private companies.
Added
We have chosen to take advantage of some, but not all, of the available exemptions for smaller reporting companies. We cannot predict whether investors will find our common shares less attractive if we rely on these exemptions.
Removed
As a result of this election, our financial statements may not be comparable to public companies that comply with new or revised accounting standards. Because of these exemptions, some investors may find our common shares less attractive, which may result in a less active trading market for our common shares, and our shares price may be more volatile.
Added
We do not obtain independent evaluations of the third-party natural gas reserves flowing into our systems and compression facilities. Demand for our services is dependent on the demand for gas in the markets we serve.
Removed
Although gross throughput at the Auburn CF has declined from 2018-2023, the share of Anchor Shipper gas has increased. The gathering rate on the Auburn GGS is subject to a cost-of-service model which could result in a non-competitive gathering rate and reduced throughput.
Removed
The gathering rate charged by the Auburn GGS is determined by a cost-of-service model whereby the Anchor Shippers in the system, of which Epsilon is one, dedicate acreage and reserves to the gas gathering system in exchange for the Auburn GGS owners agreeing to a contractual rate of return on invested capital.
Removed
The term of this arrangement is 15 years commencing in 2012 and expiring in 2026 with an 18% rate of return. Each year, the Auburn GGS historical and forecast throughput, revenue, operating expenses and capital expenditures are entered into the cost-of-service model.
Removed
The model then computes the new gathering rate that will yield the contractual rate of return to the Auburn GGS owners. In January 2027, the Auburn GGS will transition to a fixed gathering rate. Under the cost-of-service model, if total throughput on the system is lower than forecasted in the prior year, the gathering rate will increase.
Removed
The 2022 model forecasts 276 Bcf throughput from 2022-2026 (approximately 69% of current capacity at the 550 psig design suction pressure) which resulted in a $0.40 gathering rate. If the gathering rate on the Auburn GGS increases, it could result in reduced or deferred development in the Auburn GGS.
Removed
In one unlikely scenario, if no further development activity beyond work in progress occurs in the Auburn GGS, forecast throughput from 2022-2026 is expected to decline to 205 Bcf (approximately 52% of current capacity at the 550 psig design suction pressure) resulting in a still acceptable $0.62 gathering rate.
Removed
Our ability to expand our natural gas gathering business primarily depends on the level of drilling and production by the Anchor Shippers. Production from existing wells with access to our gathering systems will naturally decline over time.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

5 edited+3 added−4 removed2 unchanged
Biggest changeThe awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act.
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.
On December 31, 2023, our Board made grants to our management and employees entitling them to receive an aggregate of 213,982 common shares which shall not be issued to the award recipients unless certain time or performance based vesting criteria, as applicable, are met, in which case the vesting will occur in three equal parts on the succeeding periods ending on December 31.
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 July 3, 2023, our Board made grants to our directors entitling them to receive an aggregate of 64,975 common shares which shall not be issued to the award recipients unless certain time or performance based vesting criteria, as applicable, are met, in which case the vesting will occur in three equal parts on the succeeding periods ending on December 31.
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.
On March 9, 2023, the Board of Directors authorized a new share repurchase program of up to 2,292,644 common shares, representing 10% of the outstanding common shares of Epsilon at that time, for an aggregate purchase price of not more than US $15.0 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.
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 commenced on March 27, 2023 and will end on March 26, 2024. The Company funded the purchases out of available cash and did not incur debt to fund the share repurchase program.
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.
Removed
Business .’’ On July 1, 2023, our Board made grants to our CEO and CFO, entitling them to receive an aggregate of 79,589 common shares which shall not be issued to the award recipients unless certain time or performance based vesting criteria, as applicable, are met, in which case the vesting will occur in three equal parts on the succeeding periods ending on July 1.
Added
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.
Removed
The awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act.
Added
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.
Removed
The shares are accounted for as treasury shares until such a time as they are retired.
Added
There were no common share purchases made by the Company during the three months ended December 31, 2024. ​ ​ ​
Removed
The following table provides information with respect to the common share purchases made by the Company during the three months ended December 31, 2023. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total number of ​ Maximum number ​ ​ ​ ​ ​ ​ shares purchased ​ of shares that ​ ​ ​ ​ ​ ​ as part of ​ may yet be ​ ​ Total number ​ Average price ​ publicly ​ purchased under ​ ​ of shares ​ paid per ​ announced plans ​ the plans or Period purchased ​ share or programs programs December 2023 ​ 70,874 ​ $ 5.06 ​ ​ ​ ​ ​ Total ​ 70,874 ​ $ 5.06 ​ 968,149 ​ ​ 1,324,495 ​ ​ ​

Item 7. Management's Discussion & Analysis

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

59 edited+19 added−12 removed34 unchanged
Biggest changeAt December 31, 2023, Epsilon’s outstanding natural gas commodity swap contracts consisted of the following: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average ​ ​ ​ ​ ​ Volume ​ Price ($/MMbtu) ​ Fair Value of Asset Derivative Type (MMbtu) Swaps December 31, 2023 2024 ​ ​ ​ ​ ​ ​ ​ ​ NYMEX Henry Hub swap 1,905,000 ​ $ 3.25 $ 1,353,668 Tennessee Z4 basis swap 1,905,000 ​ $ (1.10) $ (253,413) ​ 3,810,000 ​ ​ ​ ​ $ 1,100,255 ​ Contractual Obligations We enter into commitments for capital expenditures in advance of the expenditures being made.
Biggest changeAt December 31, 2024, Epsilon’s outstanding natural gas and crude oil commodity contracts consisted of the following: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average ​ ​ ​ ​ ​ Volume ​ Price ($/MMbtu) ​ Fair Value of Asset Derivative Type (MMbtu) Swaps December 31, 2024 2025 ​ ​ ​ ​ ​ ​ ​ ​ NYMEX Henry Hub swap 2,261,500 ​ $ 3.26 $ (297,579) Tennessee Z4 basis swap 2,261,500 ​ $ (0.91) $ (246,516) ​ 4,523,000 ​ ​ ​ ​ $ (544,095) ​ 36 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value ​ ​ Volume ​ Weighted Average ​ December 31, Derivative Type (Bbl) Price ($/Bbl) 2024 2025 ​ ​ ​ ​ ​ ​ ​ ​ Crude Oil NYMEX WTI CMA 20,662 ​ $ 73.49 $ 56,547 ​ 20,662 ​ ​ ​ ​ $ 56,547 ​ Contractual Obligations We enter into commitments for capital expenditures in advance of the expenditures being made.
Significant 39 ​ ​ inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices and (iv) a market-based weighted average cost of capital rate. We evaluate impairment of proved natural gas and oil properties on an area basis.
Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices and (iv) a market-based weighted average cost of capital rate. We evaluate impairment of proved natural gas and oil properties on an area basis.
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.
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.
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. ​ 40 ​ ​
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. ​
Such indicators include changes in our business plans, changes in commodity prices leading to unprofitable performance, and, for natural gas and oil properties, significant downward revisions of estimated proved reserve quantities or significant increases in the estimated development costs.
Such indicators include changes in our business plans, changes in commodity prices leading to unprofitable performance, and, for natural 37 ​ ​ gas and oil properties, significant downward revisions of estimated proved reserve quantities or significant increases in the estimated development costs.
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) 37 ​ ​ ● 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.
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.
This section should be read in conjunction with the audited consolidated financial statements as of December 31, 2023 and 2022 and for the years then ended together with accompanying notes. 31 ​ ​ Overview Epsilon Energy Ltd.
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.
We have natural gas production from our non-operated wells in Pennsylvania, and natural gas, oil and other liquids production from our non-operated wells in the Permian Basin and Oklahoma. 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; 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.
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.
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.
Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues, amounted to $1.4 million and $1.5 million, respectively, for the years ended December 31, 2023 and 2022.
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.
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 current outstanding common shares of Epsilon, for an aggregate purchase price of not more than US $12.0 million.
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.
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, 2023, gathering system operating costs increased by $0.2 million, or 7.5% from the same period in 2022.
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.
GAAP or as a measure of profitability or liquidity. 36 ​ ​ 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 EBITDA provides useful information regarding our ability to service debt and to fund capital expenditures.
We must have confirmation from the operator on near-term development to designate an undeveloped well location as proved. Our standardized measure of discounted future net cash flows as of December 31, 2023 and 2022 was $33.0 million and $145.8 million, respectively.
We must have confirmation from the operator on near-term development to designate an undeveloped well location as proved. Our standardized measure of discounted future net cash flows as of December 31, 2024 and 2023 was $50.7 million and $33.0 million, respectively.
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. During the year ended December 31, 2023, DD&A expense increased by $1.2 million, or 19%, compared to the same period in 2022.
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.
As of December 31, 2023, our commitments for capital expenditures were nil. ​ Summary of Critical Accounting Estimates The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements and accompanying notes, which have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP, and SEC rules which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes.
Summary of Critical Accounting Estimates The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements and accompanying notes, which have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP, and SEC rules which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes.
General and Administrative (“G&A”) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 General and administrative ​ $ 7,311,496 ​ $ 7,346,438 ​ 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 stock options granted and restricted shares of stock granted and the related non-cash compensation.
General 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.
Depletion, Depreciation, Amortization and Accretion (DD&A) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 Depletion, depreciation, amortization and accretion ​ $ 7,685,084 ​ $ 6,438,511 ​ 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, ​ 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.
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, 2023, upstream operating costs decreased by $0.7 million, or 10.1% from the same period in 2022.
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.
The initial commitment and borrowing base is $35 million (redetermined as of December 6, 2023), supported by the Company’s upstream assets in Pennsylvania and subject to semi-annual redeterminations with a maturity date of the earlier of June 28, 2027. Interest will be charged at the Daily Simple SOFR rate plus a margin of 3.25%.
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%.
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, 2023 and 2022: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 Lease operating costs (net of elimination) ​ $ 6,405,281 ​ $ 7,128,631 Gathering system operating costs ​ ​ 2,459,694 ​ ​ 2,287,763 ​ ​ $ 8,864,975 ​ $ 9,416,394 ​ ​ ​ ​ ​ ​ ​ Upstream operating costs—Total $/Mcfe ​ ​ 0.71 ​ ​ 0.72 Gathering system operating costs $/Mcf ​ ​ 0.15 ​ ​ 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, 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.
For the year ended December 31, 2023 the primary uses of cash were the acquisition and development of upstream properties, investment in U.S. Treasury bills, the repurchase of shares of common stock, and the distribution of dividends.
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.
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. Historically, our investments have been focused on our position in the prolific Marcellus unconventional reservoir in Pennsylvania (“PA”). Our 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. Our Pennsylvania (“PA”) assets are supported by our 35% ownership in the Auburn GGS.
The surplus decreased from December 31, 2022 due to lower cash and short term investment balances. We anticipate that our current cash balance, short term investments, available borrowings, and cash flows from operations to be sufficient to meet our cash requirements for at least the next twelve months.
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.
Total leasehold capital expenditures (net to Epsilon) to date are $6.2 million. ​ We continue to evaluate new opportunities in numerous onshore North American natural gas and oil basins. ​ During 2023, we realized net income of $7.9 million as compared to net income of $35.4 million for 2022.
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.
An increase of $3.3 million was due to increased production from new wells in the Permian Basin offset by a reduction of $1.4 million due to lower oil prices. Gathering system revenue for the year ended December 31, 2023 increased by $1.7 million, or 21% over 2022.
An increase of $9.4 million was due to increased production from new wells in the Permian Basin offset by a reduction of $0.8 million due to lower oil prices. Gathering system revenue (net of elimination) for the year ended December 31, 2024 decreased by $4.3 million, or 44% over 2023.
The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act. The program commenced on March 27, 2023, and will end on March 26, 2024, unless the maximum amount of common shares is purchased before then or Epsilon provides earlier notice of termination.
The program was pursuant to a normal course issuer bid and was conducted in accordance with Rule 10b-18 under the Exchange Act. The program commenced on March 27, 2024 and was set to expire on March 26, 2025, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination.
The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act. The program will commence on March 27, 2024 and end on March 26, 2025, unless the maximum amount of common shares is purchased before then or Epsilon provides earlier notice of termination.
The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act. The program will commence on February 12, 2025 and end on February 11, 2026, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination.
Price ($/Mcf) ​ $ 1.47 ​ $ — Natural gas liquids revenue ​ $ 353,612 ​ $ — Volume (MBOE) ​ 17.9 ​ — Avg. Price ($/Bbl) ​ $ 19.78 ​ $ — Oil and condensate revenue ​ $ 3,501,098 ​ $ — Volume (MBbl) ​ 44.5 ​ — Avg.
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.
The Company also added NYMEX HH swaps totaling 0.535 Bcf with a strike price of $3.29 and Tennessee Z4 basis swaps totaling 0.535 Bcf with a strike price of ($1.20) to hedge a portion of the expected volumes for the contract period of April 2024 to October 2024. ​ 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, ​ 2023 2022 Income tax expense ​ $ 3,200,447 ​ $ 12,157,487 ​ During the year ended December 31, 2023, income tax expense decreased by $9.0 million, or 74%, from the same period in 2022.
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.
Revenue and volume statistics for the years ended December 31, 2023 and 2022 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ 2023 2022 Revenues ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 13,733,052 ​ $ 53,759,354 Volume (MMcf) ​ 7,906 ​ 9,026 Avg.
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.
During the year ended December 31, 2022, the Company had NYMEX HH two-way collars and Tennessee Gas Pipeline Zone 4 basis swap derivative contracts for the same hedging purpose. The amounts recorded represent the fair value changes on our derivative instruments during the year. For the year ended December 31, 2023, the Company received net cash settlements of $3,251,890.
During the year ended December 31, 2023, the Company had NYMEX HH Natural Gas Futures swaps and Tennessee Gas Pipeline Zone 4 basis swaps derivative contracts for the same hedging purpose. The amounts recorded represent the fair value changes on our derivative instruments during the year.
Price ($/Mcf) ​ $ 1.74 ​ $ 5.96 Gathering system revenue (net of elimination) ​ $ 9,790,531 ​ $ 8,085,512 Total PA Revenues ​ $ 23,523,583 ​ $ 61,844,866 Permian Basin ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 117,112 ​ $ — Volume (MMcf) ​ 80 ​ — 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 Volume (MMcf) ​ 205 ​ 80 Avg.
Price ($/Bbl) ​ $ 78.71 ​ $ — Total Permian Basin Revenues ​ $ 3,971,822 ​ $ — Oklahoma ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 1,014,050 ​ $ 3,189,380 Volume (MMcf) ​ 354 ​ 477 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 Volume (MMcf) ​ 237 ​ 354 Avg.
Interest Income ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 Interest income ​ $ 1,673,241 ​ $ 452,877 ​ During the year ended December 31, 2023, interest income increased by $1.2 million, or 269%, from the same period in 2022.
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.
Net gain (loss) on commodity contracts ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 Gain on derivative contracts ​ $ 3,130,055 ​ $ 236,077 ​ During the year ended December 31, 2023, the Company had NYMEX Henry Hub (“HH”) Natural Gas Futures swaps and Tennessee Gas Pipeline Zone 4 basis swap derivative contracts for the purpose of hedging a portion of its physical natural gas sales revenue.
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.
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 new facility replaced the Company’s previous facility.
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.
Repurchase Transactions On March 9, 2023, the Board of Directors authorized a new share repurchase program of up to 2,292,644 common shares, representing 10% of our outstanding common shares, for an aggregate purchase price of not more than US $15.0 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 current outstanding common shares of Epsilon, for an aggregate purchase price of not more than US $13.0 million.
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. Capital Resources and Liquidity Cash Flow The primary source of cash during the years ended December 31, 2023 and 2022 was funds generated from operations.
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.
A decrease of $0.5 million was due to lower natural gas liquids prices and a reduction of $0.2 million was due to lower produced volumes. Upstream oil and condensate revenue for the year ended December 31, 2023 increased by $1.9 million, or 59% over 2022.
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.
During the year ended December 31, 2023, we repurchased 968,149 common shares and spent $4,940,295 at an average price of $5.08 per share (excluding commissions) under the new plan. The previous share repurchase program commenced on March 8, 2022.
During the year ended December 31, 2023, we repurchased 968,149 common shares of the maximum of 2,292,644 authorized for repurchase and spent $4,940,295 under the plan. The repurchased stock had an average price of $5.08 per share (excluding commissions) and 897,275 common shares were retired during the year ended December 31, 2023.
This decrease was primarily due to a decrease in taxable income as a result of lower realized commodity prices. ​ Net Income Compared to Adjusted EBITDA ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 Net income ​ $ 6,945,153 ​ $ 35,354,679 Add Back: ​ ​ ​ ​ ​ ​ Interest (income) expense, net ​ ​ (1,592,862) ​ ​ (402,095) Income tax expense ​ ​ 3,200,447 ​ ​ 12,157,487 Depreciation, depletion, amortization, and accretion ​ ​ 7,685,084 ​ ​ 6,438,511 Stock based compensation expense ​ ​ 1,018,262 ​ ​ 1,021,026 Gain (loss) on sale of assets ​ ​ 1,449,871 ​ ​ (221,642) Loss (gain) on derivative contracts net of cash received or paid on settlement ​ ​ 121,835 ​ ​ (1,461,914) Foreign currency translation loss ​ ​ (278) ​ ​ (850) Adjusted EBITDA ​ $ 18,827,512 ​ $ 52,885,202 ​ 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 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.
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. 32 ​ ​ Revenues During the year ended December 31, 2023, revenues decreased $39.3 million, or 56%, to $30.7 million from $70.0 million during the year ended December 31, 2022 primarily due to lower realized natural gas prices in PA (down 71%), partially offset by new oil revenues from the Permian Basin.
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.
In 2023, we repurchased and retired 190,700 common shares and spent $1,115,306 at an average price of $5.82 per share (excluding commissions) before the plan terminated on March 7, 2023. In 2023, the Company repurchased 1,158,849 shares and spent $6,055,601 at an average price of $5.20 per share (excluding commissions) under the two consecutive repurchase programs.
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 $4.88 per share (excluding commissions) under the two consecutive repurchase programs.
(the “Company”) is a North American onshore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves. Our areas of operations are the Marcellus Shale section of the Appalachian Basin in Pennsylvania, the Permian Basin in Texas and New Mexico, and the NW Anadarko Basin in Oklahoma.
(the “Company”) is a North American onshore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves.
Price ($/Mcf) ​ $ 2.87 ​ $ 6.68 Natural gas liquids revenue ​ $ 630,806 ​ $ 1,733,129 Volume (MBOE) ​ 21.1 ​ 44.1 Avg. Price ($/Bbl) ​ $ 29.96 ​ $ 39.31 Oil and condensate revenue ​ $ 1,589,491 ​ $ 3,195,334 Volume (MBbl) ​ 20.8 ​ 32.2 Avg.
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.
For the year ended December 31, 2022, cash was primarily used for the development of upstream properties, the repurchase of common stock, and the distribution of dividends. At December 31, 2023, we had a working capital surplus of $33.2 million, a decrease of $16.0 million from the $49.2 million surplus at December 31, 2022.
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.
Total capital expenditure (net to Epsilon) was $2.2 million. ​ On May 16, 2023, Epsilon acquired a 25% working interest in 1,297 gross acres on the Central Basin Platform in Ector County, Texas from a private operator. The Company participated in the drilling and completion of 2 gross (0.5 net) wells which were put on production in October 2023.
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.
Year ended December 31, 2023 compared to 2022 During the year ended December 31, 2023, $17.5 million was provided by our operating activities, compared to $38.0 million in 2022, a $20.5 million, or 54%, decrease. The decrease was mainly due to the decrease in realized prices resulting in decreased revenue.
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 $1.4 million, or 7%, decrease.
Price ($/Bbl) ​ $ 76.37 ​ $ 99.24 Total OK Revenues ​ $ 3,234,347 ​ $ 8,117,843 Total Revenues ​ $ 30,729,752 ​ $ 69,962,709 ​ Upstream natural gas revenue for the year ended December 31, 2023 decreased by $42.1 million, or 74%, from 2022.
Price ($/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.
The primarily price-related decrease in our total proved developed reserves was partially offset by increases in proved undeveloped reserves in PA from wells currently in progress. As a non-operating working interest owner, we often do not have direct control or visibility over the pace of investment in our assets by the operator.
This increase is primarily due to revisions in previous estimates related to changes to previously adopted development plans and well performance and acquisitions in Texas As a non-operating working interest owner, we often do not have direct control or visibility over the pace of investment in our assets by the operator.
Interest Expense ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 Interest expense ​ $ 80,379 ​ $ 50,782 ​ Interest expense relates to the interest and commitment fees paid on the revolving line of credit. Interest expense increased by $0.03 million, or 58%, during the year ended December 31, 2023 from 2022.
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.
A decrease of $35.1 million was due to lower realized natural gas prices and a reduction of $7.0 million was due to lower produced volumes due to natural decline of the wells. Upstream natural gas liquids revenue for the year ended December 31, 2023 decreased by $0.7 million, or 43% from 2022.
Upstream natural gas liquids revenue for the year ended December 31, 2024 increased by $0.5 million, or 51% from 2023.
We have a substantial remaining drillable location inventory within our existing leasehold. ​ On May 9, 2023, Epsilon acquired a 10% interest in two wellbores located in Eddy County, New Mexico from a private operator. The wells are currently in production.
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.
At December 31, 2023, our total estimated net proved developed reserves were 50,681 MMcfe, a decrease of 37% from December 31, 2022. The decrease is mainly attributable to revisions to previous estimates related to commodity pricing. At December 31, 2023, our total estimated net proved reserves were 70,262 MMcfe, a 25% decrease from December 31, 2022.
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.
During the year ended December 31, 2022, we repurchased 982,500 common shares of the maximum of 1,183,410 authorized for repurchase and spent $6,234,879 under the plan. The repurchased stock had an average price of $6.32 per share (excluding commissions) and was subsequently retired during the year ended December 31, 2022.
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.
The company used $37.7 million for investing activities during the year ended December 31, 2023, compared to $7.9 million in 2022, a $29.8 million, or 379%, increase. The Company made a $17.9 million investment in U.S. Treasury bills and $19.8 million in capital investment in the upstream properties.
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.
At December 31, 2023 our total estimated net proved reserves were 65,916 MMcf of natural gas reserves, 383,174 Bbls of NGL reserves, and 341,286 Bbls of oil and condensate, and we held leasehold rights to approximately 84,684 gross (15,463 net) acres.
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.
G&A expenses were generally consistent compared to the same period in 2022, decreasing by $0.03 million, or 0%.
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.
Removed
Total capital expenditures (net to Epsilon) to date are $9.3 million, including leasehold and drilling and completion costs. ​ On June 20, 2023, Epsilon acquired a 25% working interest in 11,067 gross acres on the Central Basin Platform in Ector County, Texas from a private operator.
Added
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.
Removed
This was the result of anchor shipper volumes, which pay the full gathering rate, increasing from 69% to 78% of total 33 ​ ​ throughput in addition to a one-time compressor fee adjustment as a result of the operator’s internal audit of the gathering system.
Added
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.
Removed
Operating costs in 2022 were higher due to higher produced volumes and extraordinary plugging and abandonment costs related to atypical wellbore conditions in two older vintage wells in Pennsylvania, which is not representative of the other wells.
Added
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.
Removed
This increase was a result of the lower reserves causing an increased depletion rate in addition to four new producing wells in the Permian Basin. 34 ​ ​ Loss (gain) on Sale of Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 Loss (gain) on sale of assets ​ $ 1,449,871 ​ $ (221,642) ​ For the year ended December 31, 2023, the Company had a loss on sale of assets of $1.4 million, compared to a gain of $0.2 million in 2022 due to the assets sold in 2023 having a larger net book value than the asset sold in 2022.
Added
Price ($/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.
Removed
Epsilon sold two Oklahoma assets in April 2023 and one Oklahoma asset in April 2022.
Added
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.
Removed
This increase was primarily due to the utilization of additional financial instruments with higher prevailing interest rates in 2023.
Added
The decrease was primarily due to lower anchor shipper volumes as a result of natural decline in the wells and operator elected well shut-ins due to poor natural gas pricing in Pennsylvania partially offset by an increase in the Auburn gathering rate.
Removed
The increase is due to the front-end fees on our new credit facility put in place during 2023.
Added
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).
Removed
For the year ended December 31, 2022, the Company paid net cash settlements of $1,225,837. 35 ​ ​ At December 31, 2022, the Company had outstanding NYMEX HH swaps totaling 1.07 Bcf with a strike price of $5.212 and Tennessee Z4 basis swaps totaling 1.07 Bcf with a strike price of ($1.25) to hedge a portion of expected volumes for the contract period of April 2023 to October 2023. ​ In September 2023, the Company added NYMEX HH swaps totaling 0.38 Bcf with a strike price of $3.315 and Tennessee Z4 basis swaps totaling 0.38 Bcf with a strike price of ($0.73) to hedge a portion of the expected volumes for the contract period of November 2023 to March 2024.
Added
This increase was a result of the lower third-party reserves causing an increased depletion rate in addition to higher production from the Permian Basin.
Removed
The Company also added NYMEX HH swaps totaling 1.07 Bcf with a strike price of $3.1975 and Tennessee Z4 basis swaps totaling 1.07 Bcf with a strike price of ($1.145) to hedge a portion of the expected volumes for the contract period of April 2024 to October 2024. ​ In October 2023, the Company added NYMEX HH swaps totaling 0.38 Bcf with a strike price of $3.455 and Tennessee Z4 basis swaps totaling 0.38 Bcf with a strike price of ($0.81) to hedge a portion of the expected volumes for the contract period of November 2023 to March 2024.
Added
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.
Removed
During the year ended December 31, 2023, $11.7 million of cash used for financing activity was primarily related to the repurchase of our common shares and the payment of quarterly dividends.
Added
When indicators of impairment are present, GAAP requires that the Company first compare expected future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required.
Removed
During the year ended December 31, 2022, $12.0 million of cash used for financing activity was primarily related to the repurchase of our common shares and the payment of quarterly dividends. This was offset by $0.7 million of proceeds from the exercise of stock options.

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