# Epsilon Energy Ltd. (EPSN) Informational only - not investment advice. CIK: 0001726126 SIC: 1311 Crude Petroleum & Natural Gas SIC breadcrumb: [Mining](/division/B/) > [SIC Major Group 13](/major-group/13/) > [SIC 1311 Crude Petroleum & Natural Gas](/industry/1311/) Latest 10-K filed: 2026-03-27 SEC page: https://www.sec.gov/edgar/browse/?CIK=1726126 Filing source: https://www.sec.gov/Archives/edgar/data/1726126/000110465926035794/epsn-20251231x10k.htm ## Selected Fundamentals | Metric | Value | Unit | FY | Filed | | --- | ---: | --- | ---: | --- | | Revenue | 51587556 | USD | 2025 | 2026-03-27 | | Net income | -5798863 | USD | 2025 | 2026-03-27 | | Assets | 228239417 | USD | 2025 | 2026-03-27 | ## Financials Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-03-27. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001726126.json. Derived margins, ratios, and free cash flow are computed from the extracted annual SEC facts. | Metric | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Revenue | | 29,684,205 | 26,690,336 | 24,425,280 | 42,403,992 | 69,962,709 | 30,729,752 | 31,522,775 | 51,587,556 | | Net income | | 6,662,060 | 8,697,999 | 875,171 | 11,627,517 | 35,354,679 | 6,945,153 | 1,927,800 | -5,798,863 | | Operating income | | 9,431,895 | 8,185,104 | -977,704 | 20,612,321 | 46,973,463 | 5,418,326 | 3,424,436 | -10,517,383 | | Diluted EPS | | 0.24 | 0.32 | 0.03 | 0.49 | 1.51 | 0.31 | 0.09 | -0.25 | | Operating cash flow | | 10,305,998 | 12,985,014 | 14,816,366 | 20,006,377 | 38,005,360 | 18,188,299 | 16,830,279 | 20,619,683 | | Share buybacks | | 663,944 | 2,856,350 | 9,078,522 | 2,423,007 | 6,234,879 | 6,055,601 | 1,831,208 | 0.00 | | Assets | | 87,897,709 | 97,669,203 | 86,676,184 | 99,462,594 | 123,862,243 | 124,042,613 | 120,454,785 | 228,239,417 | | Liabilities | | 17,953,622 | 21,306,209 | 17,656,741 | 20,199,261 | 19,617,038 | 23,429,648 | 23,726,656 | 103,507,063 | | Stockholders' equity | 63,731,045 | 69,944,087 | 76,362,994 | 69,019,443 | 79,263,333 | 104,245,205 | 100,612,965 | 96,728,129 | 124,732,354 | | Cash and cash equivalents | | 14,401,257 | 14,052,417 | 13,270,913 | 26,497,305 | 45,236,584 | 13,403,628 | 6,519,793 | 8,959,954 | ### Ratios ROE and ROA use period-end equity/assets. Liabilities / equity uses total liabilities divided by stockholders' equity. Current ratio uses current assets divided by current liabilities when both are reported. | Metric | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Net margin | | 22.44% | 32.59% | 3.58% | 27.42% | 50.53% | 22.60% | 6.12% | -11.24% | | Operating margin | | 31.77% | 30.67% | -4.00% | 48.61% | 67.14% | 17.63% | 10.86% | -20.39% | | Return on equity | | 9.52% | 11.39% | 1.27% | 14.67% | 33.91% | 6.90% | 1.99% | -4.65% | | Return on assets | | 7.58% | 8.91% | 1.01% | 11.69% | 28.54% | 5.60% | 1.60% | -2.54% | | Liabilities / equity | | 0.26 | 0.28 | 0.26 | 0.25 | 0.19 | 0.23 | 0.25 | 0.83 | | Current ratio | | 3.14 | 2.99 | 3.94 | 4.20 | 8.92 | 5.21 | 2.02 | 1.31 | ## Quarterly Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-13. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001726126.json. Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived. | Quarter | End date | Revenue | Net income | Diluted EPS | Method | | --- | --- | ---: | ---: | ---: | --- | | 2022-Q2 | 2022-03-31 | | 5,805,888 | | reported discrete quarter | | 2022-Q2 | 2022-06-30 | | | 0.44 | reported discrete quarter | | 2022-Q3 | 2022-06-30 | | 10,582,988 | | reported discrete quarter | | 2022-Q3 | 2022-09-30 | | | 0.41 | reported discrete quarter | | 2023-Q1 | 2023-03-31 | | 3,529,827 | 0.15 | reported discrete quarter | | 2023-Q2 | 2023-03-31 | | 3,529,827 | | reported discrete quarter | | 2023-Q2 | 2023-06-30 | 6,500,136 | | 0.02 | reported discrete quarter | | 2023-Q3 | 2023-06-30 | | 430,589 | | reported discrete quarter | | 2023-Q3 | 2023-09-30 | 6,310,527 | | 0.02 | reported discrete quarter | | 2023-Q4 | 2023-12-31 | 8,562,813 | | | derived Q4 = FY annual - nine-month YTD | | 2024-Q1 | 2024-03-31 | 7,986,743 | 1,506,896 | 0.07 | reported discrete quarter | | 2024-Q2 | 2024-03-31 | | 1,506,896 | | reported discrete quarter | | 2024-Q2 | 2024-06-30 | 7,307,818 | | 0.04 | reported discrete quarter | | 2024-Q3 | 2024-06-30 | | 815,660 | | reported discrete quarter | | 2024-Q3 | 2024-09-30 | 7,287,941 | | 0.02 | reported discrete quarter | | 2024-Q4 | 2024-12-31 | 8,940,273 | | | derived Q4 = FY annual - nine-month YTD | | 2025-Q1 | 2025-03-31 | 16,163,140 | 4,016,034 | 0.18 | reported discrete quarter | | 2025-Q2 | 2025-03-31 | | 4,016,034 | | reported discrete quarter | | 2025-Q2 | 2025-06-30 | 11,624,733 | | 0.07 | reported discrete quarter | | 2025-Q3 | 2025-06-30 | | 1,551,461 | | reported discrete quarter | | 2025-Q3 | 2025-09-30 | 8,981,459 | | 0.05 | reported discrete quarter | | 2025-Q4 | 2025-12-31 | 14,818,224 | | | derived Q4 = FY annual - nine-month YTD | | 2026-Q1 | 2026-03-31 | 25,595,787 | 729,425 | 0.02 | reported discrete quarter | ## Macro Cross-References - [CPIAUCSL](/indicator/CPIAUCSL/): Consumer Price Index for All Urban Consumers: All Items in U.S. City Average - [UNRATE](/indicator/UNRATE/): Unemployment Rate - [FEDFUNDS](/indicator/FEDFUNDS/): Federal Funds Effective Rate - [CES0500000003](/indicator/CES0500000003/): Average Hourly Earnings of All Employees, Total Private - [DFEDTARU](/indicator/DFEDTARU/): Federal Funds Target Range - Upper Limit - [DFEDTARL](/indicator/DFEDTARL/): Federal Funds Target Range - Lower Limit - [DGS3MO](/indicator/DGS3MO/): Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity - [DGS2](/indicator/DGS2/): Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity - [DGS10](/indicator/DGS10/): Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity - [DGS30](/indicator/DGS30/): Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity - [T10Y2Y](/indicator/T10Y2Y/): 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity - [CPILFESL](/indicator/CPILFESL/): Consumer Price Index for All Urban Consumers: All Items Less Food and Energy - [CPIUFDSL](/indicator/CPIUFDSL/): Consumer Price Index for All Urban Consumers: Food - [CPIENGSL](/indicator/CPIENGSL/): Consumer Price Index for All Urban Consumers: Energy - [CUSR0000SAH1](/indicator/CUSR0000SAH1/): Consumer Price Index for All Urban Consumers: Shelter - [PCEPI](/indicator/PCEPI/): Personal Consumption Expenditures: Chain-type Price Index - [PCEPILFE](/indicator/PCEPILFE/): Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index - [PPIACO](/indicator/PPIACO/): Producer Price Index by Commodity: All Commodities - [T10YIE](/indicator/T10YIE/): 10-Year Breakeven Inflation Rate - [U6RATE](/indicator/U6RATE/): Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons - [PAYEMS](/indicator/PAYEMS/): All Employees, Total Nonfarm - [CIVPART](/indicator/CIVPART/): Labor Force Participation Rate - [EMRATIO](/indicator/EMRATIO/): Employment-Population Ratio - [UNEMPLOY](/indicator/UNEMPLOY/): Unemployed - [CE16OV](/indicator/CE16OV/): Employment Level - [ICSA](/indicator/ICSA/): Initial Claims - [JTSJOL](/indicator/JTSJOL/): Job Openings: Total Nonfarm - [JTSQUR](/indicator/JTSQUR/): Quits: Total Nonfarm - [GDPC1](/indicator/GDPC1/): Real Gross Domestic Product - [A191RL1Q225SBEA](/indicator/A191RL1Q225SBEA/): Real Gross Domestic Product: Percent Change from Preceding Period - [INDPRO](/indicator/INDPRO/): Industrial Production: Total Index - [TCU](/indicator/TCU/): Capacity Utilization: Total Index - [HOUST](/indicator/HOUST/): New Privately-Owned Housing Units Started: Total Units - [PERMIT](/indicator/PERMIT/): New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units - [RSAFS](/indicator/RSAFS/): Advance Retail Sales: Retail Trade - [PCE](/indicator/PCE/): Personal Consumption Expenditures - [DSPIC96](/indicator/DSPIC96/): Real Disposable Personal Income - [PSAVERT](/indicator/PSAVERT/): Personal Saving Rate - [M2SL](/indicator/M2SL/): M2 - [BOPGSTB](/indicator/BOPGSTB/): U.S. International Trade in Goods and Services: Balance - [MSPUS](/indicator/MSPUS/): Median Sales Price of Houses Sold for the United States - [HSN1F](/indicator/HSN1F/): New One Family Houses Sold: United States - [RHORUSQ156N](/indicator/RHORUSQ156N/): Homeownership Rate in the United States - [TTLCONS](/indicator/TTLCONS/): Total Construction Spending: Total Construction in the United States - [RRVRUSQ156N](/indicator/RRVRUSQ156N/): Rental Vacancy Rate in the United States - [TOTALSL](/indicator/TOTALSL/): Total Consumer Credit Owned and Securitized - [REVOLSL](/indicator/REVOLSL/): Revolving Consumer Credit Owned and Securitized - [DRCCLACBS](/indicator/DRCCLACBS/): Delinquency Rate on Credit Card Loans, All Commercial Banks - [GDP](/indicator/GDP/): Gross Domestic Product - [GPDI](/indicator/GPDI/): Gross Private Domestic Investment - [GCE](/indicator/GCE/): Government Consumption Expenditures and Gross Investment - [PCEC](/indicator/PCEC/): Personal Consumption Expenditures - [NETEXP](/indicator/NETEXP/): Net Exports of Goods and Services - [GFDEBTN](/indicator/GFDEBTN/): Federal Debt: Total Public Debt - [GFDEGDQ188S](/indicator/GFDEGDQ188S/): Federal Debt: Total Public Debt as Percent of Gross Domestic Product - [FYFSD](/indicator/FYFSD/): Federal Surplus or Deficit - [FGRECPT](/indicator/FGRECPT/): Federal Government Current Receipts - [FGEXPND](/indicator/FGEXPND/): Federal Government: Current Expenditures - [MANEMP](/indicator/MANEMP/): All Employees, Manufacturing - [USCONS](/indicator/USCONS/): All Employees, Construction - [USTRADE](/indicator/USTRADE/): All Employees, Retail Trade - [USFIRE](/indicator/USFIRE/): All Employees, Financial Activities - [USGOVT](/indicator/USGOVT/): All Employees, Government - [AWHAETP](/indicator/AWHAETP/): Average Weekly Hours of All Employees, Total Private - [DGORDER](/indicator/DGORDER/): Manufacturers' New Orders: Durable Goods - [NEWORDER](/indicator/NEWORDER/): Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft - [BUSINV](/indicator/BUSINV/): Total Business Inventories - [EXPGS](/indicator/EXPGS/): Exports of Goods and Services - [IMPGS](/indicator/IMPGS/): Imports of Goods and Services - [IR](/indicator/IR/): Import Price Index (End Use): All Commodities - [PPIFIS](/indicator/PPIFIS/): Producer Price Index by Commodity: Final Demand ## Latest quarter (10-Q) Latest 10-Q source: https://www.sec.gov/Archives/edgar/data/1726126/000110465926060245/epsn-20260331x10q.htm Extracted structurally from real Item 2 body heading to real Item 3/4 boundary. Confidence: high Filing date: 2026-05-13 Report date: 2026-03-31 ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist in the understanding of trends and significant changes in our results of operations and the financial condition of Epsilon Energy Ltd. and its subsidiaries for the periods presented. The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this report, including the unaudited condensed consolidated financial statements as of March 31, 2026 and 2025 together with accompanying notes, as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2025. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward- looking statements due to a number of factors. See “Part II. Item 1A. Risk Factors” and “Forward-Looking Statements.” Overview Epsilon Energy Ltd. (the “Company”) is a North American onshore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves. Our areas of operations are the Appalachian Basin in Pennsylvania, the Powder River Basin in Wyoming, the Permian Basin in Texas and New Mexico, and the Western Canadian Sedimentary Basin in Alberta, Canada. At March 31, 2026 we held leasehold rights to 52,149 net acres. We have natural gas production from our non-operated wells in Pennsylvania and natural gas, natural gas liquids, and oil production from our operated and non-operated wells in the Permian, Powder River, and Western Canadian Sedimentary Basins. At December 31, 2025 our total estimated net proved reserves were 86.4 Bcf of natural gas reserves, 9.3 MMBbls of oil reserves, and 2.4 MMBbls of NGL reserves. Our Pennsylvania (“PA”) assets are supported by our 35% ownership in the Auburn GGS. Our common shares trade on the NASDAQ Global Market under the ticker symbol “EPSN.” Business Strategy We are committed to disciplined capital allocation which could include shareholder returns in the form of dividends and/or share buybacks. 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. On November 14, 2025, Epsilon acquired Peak Exploration and Production LLC and Peak BLM Lease LLC and their subsidiaries (together, "Peak") through a business combination. The acquisition added 284 gross (60 net) wells, including 105 gross (45 net) operated wells, and 60,945 gross (39,566 net) acres located in Campbell, Converse and Johnson Counties, Wyoming.   ​ On December 11, 2025, Epsilon divested Dewey Energy Holdings, LLC, a wholly owned subsidiary of the Company to an undisclosed private buyer. The assets sold included approximately 964 Mcfe/d (60% natural gas) of production and approximately 6,400 net deep acres and 2,200 net shallow acres of leasehold, all located in Dewey County, Oklahoma. ​ We have a substantial remaining drillable location inventory within our existing leaseholds in Pennsylvania, Wyoming, and Texas. ​ 23 Table of Contents Three months ended March 31, 2026 Highlights Operational Highlights Marcellus Shale – Pennsylvania ● During the three months ended March 31, 2026, Epsilon's realized natural gas price was $5.77 per Mcf, a 47% increase over the three months ended March 31, 2025. ● During the three months ended March 31, 2026, Epsilon’s net revenue interest natural gas production was 2.1 Bcf, a 19% increase over the three months ended March 31, 2025. ● Gathered and delivered 9.6 Bcf gross (3.3 net to Epsilon's interest) during the three months ended March 31, 2026, or 107 MMcf/d through the Auburn Gas Gathering System. Powder River Basin – Wyoming ● During the three months ended March 31, 2026, Epsilon's realized price for all Powder River Basin production was $49.84 per Boe (74% liquids). ● Total net revenue interest production for the three months ended March 31, 2026, which included oil, natural gas liquids, and natural gas, was 179.6 Mboe Permian Basin – Texas and New Mexico ● During the three months ended March 31, 2026, Epsilon's realized price for all Permian Basin production was $48.29 per Boe (85% liquids), a 12% decrease over the three months ended March 31, 2025. ● Total net revenue interest production for the three months ended March 31, 2026, which included oil, natural gas liquids, and natural gas, was 51.7 Mboe compared to 61.9 Mboe during the same period in 2025, a 16% decrease. ● During the three months ended March 31, 2026, the Company had 1 gross (.25 net) well drilled. Western Canadian Sedimentary Basin—Alberta, Canada ● During the three months ended March 31, 2026, Epsilon's realized price for all Canada production was $27.99 per Boe (49% liquids). ● Total net revenue interest production for the three months ended March 31, 2026, which included oil, natural gas liquids, and natural gas, was 5.7 Mboe. 24 Table of Contents Non-GAAP Financial Measures-Adjusted EBITDA Epsilon defines Adjusted EBITDA as earnings before (1) net interest expense, (2) taxes, (3) depreciation, depletion, amortization and accretion expense, (4) impairments of natural gas and oil properties, (5) non-cash stock compensation expense, (6) transaction costs, (7) gain or loss on derivative contracts net of cash received or paid on settlement, and (8) net other income (expense). Adjusted EBITDA is not a measure of financial performance as determined under U.S. GAAP and should not be considered in isolation from or as a substitute for net income or cash flow measures prepared in accordance with U.S. GAAP or as a measure of profitability or liquidity. Additionally, Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. Epsilon has included Adjusted EBITDA as a supplemental disclosure because its management believes that Adjusted EBITDA provides useful information regarding its ability to service debt and to fund capital expenditures. It further provides investors a helpful measure for comparing operating performance on a normalized or recurring basis with the performance of other companies, without giving effect to certain non-cash expenses and other items. This provides management, investors and analysts with comparative information for evaluating the Company in relation to other natural gas and oil companies providing corresponding non-U.S. GAAP financial measures or that have different financing and capital structures or tax rates. These non-U.S. GAAP financial measures should be considered in addition to, but not as a substitute for, measures for financial performance prepared in accordance with U.S. GAAP. The table below sets forth a reconciliation of net income to Adjusted EBITDA for the three months ended March 31, 2026 and 2025, which is the most directly comparable measure of financial performance calculated under U.S. GAAP and should be reviewed carefully. ​ ​ ​ ​ ​ ​ ​ ​ ​ Three months ended March 31,  ​ 2026 2025 Net income ​ $ 729,425 ​ $ 4,016,034 Add Back: ​ ​ ​ ​ ​ ​ Interest expense (income), net ​ ​ 896,038 ​ ​ (3,088) Income tax (benefit) expense ​ ​ 267,736 ​ ​ 1,670,194 Depreciation, depletion, amortization, and accretion ​ ​ 3,002,339 ​ ​ 3,475,857 Impairment expense ​ ​ — ​ ​ 6,669 Stock based compensation expense ​ ​ 547,527 ​ ​ 385,838 Transaction costs ​ ​ 71,420 ​ ​ — Loss on derivative contracts net of cash received or paid on settlement ​ ​ 7,881,993 ​ ​ 1,047,127 Foreign currency translation loss ​ ​ (1,875) ​ ​ 10,289 Adjusted EBITDA ​ $ 13,394,603 ​ $ 10,608,920 ​ ​ 25 Table of Contents Results of Operations ​ Net Operating Revenues For the three months ended March 31, 2026, revenues increased $9.4 million, or 58%, to $25.6 million from $16.2 million during the same period of 2025. Revenue and volume statistics for the three months ended March 31, 2026 and 2025 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ Three months ended ​ ​ March 31,  ​   ​ ​ ​ 2026   ​ ​ ​ 2025 Revenues ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 12,312,568 ​ $ 10,327,894 Volume (MMcf) ​ 2,133 ​ 2,637 Avg. Price ($/Mcf) ​ $ 5.77 ​ $ 3.92 Gathering system revenue (net of elimination) ​ $ 1,657,777 ​ $ 1,892,350 Total PA Revenues ​ $ 13,970,345 ​ $ 12,220,244 Permian Basin ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ (19,619) ​ $ 78,339 Volume (MMcf) ​ 47 ​ 50 Avg. Price ($/Mcf) ​ $ (0.41) ​ $ 1.57 Natural gas liquids revenue ​ $ 185,332 ​ $ 284,961 Volume (MBoe) ​ 10.8 ​ 12.1 Avg. Price ($/Bbl) ​ $ 17.22 ​ $ 23.56 Oil and condensate revenue ​ $ 2,332,637 ​ $ 3,019,495 Volume (MBbl) ​ 33.1 ​ 41.5 Avg. Price ($/Bbl) ​ $ 70.54 ​ $ 72.72 Total Permian Basin Revenues ​ $ 2,498,350 ​ $ 3,382,795 Oklahoma ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 10,075 ​ $ 207,340 Volume (MMcf) ​ 1 ​ 53 Avg. Price ($/Mcf) ​ $ 10.41 ​ $ 3.94 Natural gas liquids revenue ​ $ 2,754 ​ $ 102,289 Volume (MBoe) ​ 0.1 ​ 3.7 Avg. Price ($/Bbl) ​ $ 32.60 ​ $ 27.68 Oil and condensate revenue ​ $ 384 ​ $ 157,937 Volume (MBbl) ​ (0.5) ​ 2.2 Avg. Price ($/Bbl) ​ $ (0.82) ​ $ 70.35 Total OK Revenues ​ $ 13,213 ​ $ 467,566 Wyoming ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 1,068,303 ​ $ — Volume (MMcf) ​ 283 ​ — Avg. Price ($/Mcf) ​ $ 3.77 ​ $ — Natural gas liquids revenue ​ $ 859,968 ​ $ — Volume (MBoe) ​ 30 ​ — Avg. Price ($/Bbl) ​ $ 28.32 ​ $ — Oil and condensate revenue ​ $ 7,025,297 ​ $ — Volume (MBbl) ​ 102.1 ​ — Avg. Price ($/Bbl) ​ $ 68.81 ​ $ — Total WY Revenues ​ $ 8,953,568 ​ $ — Canada ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 31,195 ​ $ — Volume (MMcf) ​ 17 ​ — Avg. Price ($/Mcf) ​ $ 1.79 ​ $ — Natural gas liquids revenue ​ $ 25,247 ​ $ — Volume (MBoe) ​ 1.2 ​ — Avg. Price ($/Bbl) ​ $ 21.37 ​ $ — Oil and condensate revenue ​ $ 103,869 ​ $ 92,535 Volume (MBbl) ​ 1.6 ​ 1.8 Avg. Price ($/Bbl) ​ $ 62.99 ​ $ 51.27 Total Canada Revenues ​ $ 160,311 ​ $ 92,535 Total Revenues ​ $ 25,595,787 ​ $ 16,163,140 ​ Upstream natural gas revenue for the three months ended March 31, 2026 increased by $2.8 million, or 26%, over the same period in 2025. An increase of $3.8 million was due to higher natural gas prices and a decrease of $1.0 million was a result of decrease in volume due to the natural decline in the producing wells partially offset due to increased volumes as a result of the Peak acquisition.. 26 Table of Contents Upstream natural gas liquids revenue for the three months ended March 31, 2026 increased by $0.7 million, or 177%, over the same period in 2025. This increase was primarily due to increased volumes as a result of the Peak acquisition. Upstream oil and condensate revenue for the three months ended March 31, 2026 increased by $6.2 million, or 189% over the same period in 2025.  An increase of $6.5 million was due to higher volumes as a result of the Peak acquisition and a decrease of $0.3 million was due to a decrease in prices for oil in the Permian Basin. Gathering system revenue for the three months ended March 31, 2026 decreased by $0.2 million, or 12%, compared with the same period in 2025 due to lower thoughput volumes partially offset due to higher contractual rates for gathering and compression. Revenues derived from transporting and compressing our production, which have bee [Excerpt truncated for page length; source filing is linked above.] ## Latest 10-K MD&A Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Confidence: high ITEM 7.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The following discussion is intended to assist in the understanding of trends and significant changes in our results of operations and the financial condition of Epsilon Energy Ltd. and its subsidiaries for the periods presented. This section should be read in conjunction with the audited consolidated financial statements as of December 31, 2025 and 2024 and for the years then ended together with accompanying notes. Overview Epsilon Energy Ltd. (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 Appalachian Basin in Pennsylvania, the Powder River Basin in Wyoming, the Permian Basin in Texas and New Mexico, and the Western Canadian Sedimentary Basin in Alberta, Canada. 32 ​ ​ At December 31, 2025 our total estimated net proved reserves were 86.4 Bcf of natural gas reserves, 9.3 MMBbls of oil reserves, and 2.4 MMBbls of NGL reserves, and we held leasehold rights to approximately 101,265 gross (54,044 net) acres. We have natural gas production from our non-operated wells in Pennsylvania and natural gas, natural gas liquids, and oil production from our operated and non-operated wells in the Permian, Powder River, and Western Canadian Sedimentary Basins. We are committed to disciplined capital allocation which could include shareholder returns in the form of dividends and/or share buybacks. We plan to maintain a strong balance sheet and liquidity position to allow us to opportunistically invest in both our existing project areas and potential new projects. Our Pennsylvania (“PA”) assets are supported by our 35% ownership in the Auburn GGS. ​ We have a substantial remaining drillable location inventory within our existing leaseholds in Pennsylvania, Wyoming, and Texas. ​ On November 14, 2025, Epsilon acquired Peak Exploration and Production LLC and Peak BLM Lease LLC and their subsidiaries (together, "Peak") through a business combination. The acquisition added 284 gross (60 net) wells, including 105 gross (45 net) operated wells, and 60,945 gross (39,566 net) acres located in Campbell, Converse and Johnson Counties, Wyoming.   ​ On December 11, 2025, Epsilon divested Dewey Energy Holdings, LLC, a wholly owned subsidiary of the Company to an undisclosed private buyer. The assets sold included approximately 964 Mcfe/d (60% natural gas) of production and approximately 6,400 net deep acres and 2,200 net shallow acres of leasehold, all located in Dewey County, Oklahoma. ​ During 2025, we realized net loss of $5.8 million as compared to net income of $1.9 million for 2024. This included a $19.3 million loss in Q4 2025 on the sale of our Anadarko Basin assets in Oklahoma, which provides potential tax benefits that may be utilized going forward. At December 31, 2025, our total estimated net proved developed reserves were 109,444 MMcfe, a 69% increase from December 31, 2024. The increase is mainly attributable to Wyoming reserves acquired from the Peak acquisition.  At December 31, 2025, our total estimated net proved reserves were 156,037 MMcfe, a 86% increase from December 31, 2024. The increase is mainly attributable to Wyoming reserves acquired from the Peak acquisition. Our standardized measure of discounted future net cash flows as of December 31, 2025 and 2024 was $156.1 million and $50.7 million, respectively. This measure of discounted future net cash flows does not include any estimate for future cash flows generated by our gathering system assets. Results of Operations The following review of operations for the periods presented below should be read in conjunction with our consolidated financial statements and the notes thereto. Revenues During the year ended December 31, 2025, revenues increased $20.1 million, or 64%, to $51.6 million from $31.5 million during the year ended December 31, 2024. Revenue and volume statistics for the years ended December 31, 2025 and 2024 were as follows: ​ 33 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31,  ​   ​ ​ ​ 2025   ​ ​ ​ 2024 Revenues ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 28,012,040 ​ $ 10,247,834 Volume (MMcf) ​ 9,402 ​ 5,699 Avg. Price ($/Mcf) ​ $ 2.98 ​ $ 1.80 Gathering system revenue (net of elimination) ​ $ 6,683,735 ​ $ 5,524,063 Total PA Revenues ​ $ 34,695,775 ​ $ 15,771,897 Permian Basin ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 113,038 ​ $ 32,930 Volume (MMcf) ​ 161 ​ 205 Avg. Price ($/Mcf) ​ $ 0.70 ​ $ 0.16 Natural gas liquids revenue ​ $ 706,010 ​ $ 1,060,967 Volume (MBoe) ​ 36.2 ​ 51.8 Avg. Price ($/Bbl) ​ $ 19.51 ​ $ 20.48 Oil and condensate revenue ​ $ 9,614,603 ​ $ 12,770,258 Volume (MBbl) ​ 149.1 ​ 173.0 Avg. Price ($/Bbl) ​ $ 64.50 ​ $ 73.81 Total Permian Basin Revenues ​ $ 10,433,651 ​ $ 13,864,155 Oklahoma ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 640,607 ​ $ 505,304 Volume (MMcf) ​ 197 ​ 237 Avg. Price ($/Mcf) ​ $ 3.25 ​ $ 2.13 Natural gas liquids revenue ​ $ 318,108 ​ $ 420,991 Volume (MBoe) ​ 14.1 ​ 17.4 Avg. Price ($/Bbl) ​ $ 22.56 ​ $ 24.16 Oil and condensate revenue ​ $ 507,406 ​ $ 844,265 Volume (MBbl) ​ 9.4 ​ 11.0 Avg. Price ($/Bbl) ​ $ 54.11 ​ $ 76.75 Total OK Revenues ​ $ 1,466,121 ​ $ 1,770,560 Wyoming ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 291,933 ​ $ — Volume (MMcf) ​ 189 ​ — Avg. Price ($/Mcf) ​ $ 1.54 ​ $ — Natural gas liquids revenue ​ $ 872,263 ​ $ — Volume (MBoe) ​ 27 ​ — Avg. Price ($/Bbl) ​ $ 32.48 ​ $ — Oil and condensate revenue ​ $ 2,840,537 ​ $ — Volume (MBbl) ​ 50.1 ​ — Avg. Price ($/Bbl) ​ $ 56.66 ​ $ — Total WY Revenues ​ $ 4,004,733 ​ $ — Canada ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 63,828 ​ $ — Volume (MMcf) ​ 52 ​ — Avg. Price ($/Mcf) ​ $ 1.22 ​ $ — Natural gas liquids revenue ​ $ 82,479 ​ $ — Volume (MBoe) ​ 3.6 ​ — Avg. Price ($/Bbl) ​ $ 23.01 ​ $ — Oil and condensate revenue ​ $ 840,969 ​ $ 116,163 Volume (MBbl) ​ 15.1 ​ 2.5 Avg. Price ($/Bbl) ​ $ 55.84 ​ $ 46.04 Total Canada Revenues ​ $ 987,276 ​ $ 116,163 Total Revenues ​ $ 51,587,556 ​ $ 31,522,775 ​ 34 ​ ​ Upstream natural gas revenue for the year ended December 31, 2025 increased by $18.3 million, or 170%, from 2024. An increase of $11.6 million was due to higher natural gas prices and an increase of $6.8 million was due to higher produced volumes as a result of previously delayed wells coming on line and the end of operator-elected well shut-ins in Pennsylvania. Upstream natural gas liquids revenue for the year ended December 31, 2025 increased by $0.5 million, or 34% from 2024.  An increase of $0.2 million was due to higher produced volumes from new wells in the Permian and Powder River Basins and an increase of $0.3 million was due to higher natural gas liquids prices. Upstream oil and condensate revenue for the year ended December 31, 2025 increased by $0.1 million, or 1% over 2024.  An increase of $2.7 million was due to increased production from new wells in the Permian and Powder River Basins offset by a reduction of $2.6 million due to lower oil prices. Gathering system revenue (net of elimination) for the year ended December 31, 2025 increased by $1.2 million, or 21% over 2024. The increase was primarily due to slightly higher throughput, but more importantly, crossflow gas being displaced with Anchor Shipper gas which is charged a higher gathering fee. Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues, amounted to $1.9 million and $1.1 million, respectively, for the years ended December 31, 2025 and 2024. Operating Costs The following table presents total cost and cost per unit of production (Mcfe), including ad valorem, severance, and production taxes for the years ended December 31, 2025 and 2024: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31,  ​   ​ ​ ​ 2025   ​ ​ ​ 2024 Lease operating costs (net of elimination) ​ $ 12,518,325 ​ $ 7,264,824 Gathering system operating costs ​ ​ 2,362,036 ​ ​ 2,265,190 ​ ​ $ 14,880,361 ​ $ 9,530,014 ​ ​ ​ ​ ​ ​ ​ Upstream operating costs—Total $/Mcfe ​ $ 1.06 ​ $ 0.95 Gathering system operating costs $/Mcf ​ $ 0.16 ​ $ 0.17 ​ Operating costs include the effects of elimination entries to remove the gathering fees paid to Epsilon’s ownership in the gathering system. Upstream operating costs consist of lease operating expenses necessary to extract natural gas and oil, including gathering and treating the natural gas and oil to prepare it for sale. For the year ended December 31, 2025, upstream operating costs increased by $5.3 million, or 72% from the same period in 2024. The increase is primarily due to the increase in gas production in Pennsylvania and the acquired production in the Powder River Basin. The higher unit operating cost is primarily due to the higher liquids (oil and natural gas liquids) proportion of total sales (Mcfe). Gathering system operating costs consist primarily of rental payments for the natural gas fueled compression units and overhead fees due to the system’s operator. For the year ended December 31, 2025, gathering system operating costs decreased by $0.1 million, or 4% from the same period in 2024. Depletion, Depreciation, Amortization and Accretion (DD&A) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31,  ​   ​ ​ ​ 2025   ​ ​ ​ 2024 Depletion, depreciation, amortization and accretion ​ $ 12,170,320 ​ $ 10,185,119 ​ Natural gas and oil and gathering system assets are depleted and depreciated using the units of production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved and unproved properties, the reserve base used to calculate depreciation and depletion is total proved reserves. For natural gas and oil 35 ​ ​ development and gathering system costs, the reserve base used to calculate depletion and depreciation is proved developed reserves. A reserve report is prepared as of December 31, each year. Depreciation expense includes amounts pertaining to our office furniture and fixtures, leasehold improvements and computer hardware. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 7 years. Also included in depreciation expense is an amount pertaining to buildings owned by the Company. Depreciation for the buildings is calculated using the straight-line method over an estimated useful life of 30 years. Accretion expense is related to the asset retirement costs. During the year ended December 31, 2025, DD&A expense increased by $2 million, or 19%, compared to the same period in 2024. This increase was primarily a result of higher produced volumes in Pennsylvania and acquired properties in Wyoming. Impairment ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31,  ​   ​ ​ ​ 2025   ​ ​ ​ 2024 Impairment ​ $ 3,936,669 ​ $ 1,450,076 ​ We perform a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable, over proved properties using the market forward prices, timing, methods and other assumptions consistent with historical periods. 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. Additionally, GAAP requires that if an exploratory well is determined not to have found proved reserves, the costs incurred, net of any salvage value, should be charged to expense. For the year ended December 31, 2025, the Company recorded an impairment of $3.2 million on the Canadian wells (2 gross, 0.5 net) and $0.7 million on the New Mexico wells (2 gross, 0.2 net) due to low forward oil prices on December 31, 2025 (which are required to be used in impairment testing) and an offset frac hit impacting production and reserves in New Mexico. During the year ended December 31, 2024, Epsilon recorded an impairment of $1.45 million on the Killam project (interest acquired in April 2024) in Alberta, Canada as a result of a decrease in forecasted reserves. Loss on Sale of Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31,  ​   ​ ​ ​ 2025   ​ ​ ​ 2024 Loss on sale of assets ​ $ 19,256,530 ​ $ — ​ For the year ended December 31, 2025, the Company sold all of its interests in Oklahoma for $2.5 million. This resulted in a loss on the sale of $19.3 million, primarily on undeveloped leasehold. The Company had no asset sales in 2024. ​ Transaction Costs ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31,  ​   ​ ​ ​ 2025   ​ ​ ​ 2024 Transaction Costs ​ $ 2,947,907 ​ $ — ​ For the year ended December 31,2025, the Company had transaction costs related to the Peak acquisition of $2.9 million for advisory and legal services incurred by the Company. ​ 36 ​ ​ General and Administrative (“G&A”) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31,  ​   ​ ​ ​ 2025   ​ ​ ​ 2024 General and administrative expenses ​ ​ ​ ​ ​ ​ Stock based compensation expense ​ $ 1,744,917 ​ $ 1,244,416 Other general and administrative expense ​ ​ 7,168,235 ​ ​ 5,688,714 Total general and administrative expenses ​ $ 8,913,152 ​ $ 6,933,130 ​ G&A expenses consist of general corporate expenses such as compensation, legal, accounting and professional fees, consulting services, travel and other related corporate costs such as restricted shares of stock granted and the related non-cash compensation. G&A expenses for the year ended December 31, 2025 increased by $2 million, or 29%, compared to the same period in 2024. An increase of $1.2 million is related to higher compensation expense, an increase of $0.5 million in stock based compensation, and an increase of $0.1 million in audit and tax fees. Interest Income ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31,  ​   ​ ​ ​ 2025   ​ ​ ​ 2024 Interest income ​ $ 188,369 ​ $ 493,277 ​ During the year ended December 31, 2025, interest income decreased by $0.3 million, or 62%, from the same period in 2024. This decrease was primarily due to the reduction in the balance of cash equivalents associated with the maturation of all short term investments in June 2024. Interest Expense ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31,  ​   ​ ​ ​ 2025   ​ ​ ​ 2024 Interest expense ​ $ 624,160 ​ $ 46,400 ​ Interest expense relates to the interest and commitment fees paid on the revolving line of credit. Interest expense increased by $0.6 million, or 1245%, during the year ended December 31, 2025 from 2024. The increase is due to interest charged on the outstanding debt balance from the closing of the Peak acquisition on November 14, 2025, commitment fees on unused debt capacity, and the amortization of front-end fees related to the new credit facility entered into in October 2025. Gain (Loss) on Derivative Contracts, net ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31,  ​   ​ ​ ​ 2025   ​ ​ ​ 2024 Gain (loss) on derivative contracts, net ​ $ 5,500,486 ​ $ (391,147) ​ During the year ended December 31, 2025, the Company had NYMEX Henry Hub (“HH”) Natural Gas Futures swaps, NYMEX HH options, and crude oil NYMEX WTI CMA swaps derivative contracts for the purpose of hedging a portion of its physical natural gas and oil sales revenue. During the year ended December 31, 2024, the Company had NYMEX HH Natural Gas Futures swaps, Tennessee Gas Pipeline Zone 4 basis swaps, and crude oil NYMEX HH CMA swaps derivative contracts for the same hedging purpose. The amounts recorded represent the fair value changes on our derivative instruments during the year. For the year ended December 31, 2025, the Company received net cash settlements of $1,163,662. For the year ended December 31, 2024, the Company received net cash settlements of $1,196,656. 37 ​ ​ At December 31, 2025, the Company had outstanding NYMEX HH swaps totaling 1.68 Bcf, NYMEX HH options totaling 4.51 Bcf, NYMEX WTI CMA swaps totaling 340,916 Bbls, and NYMEX WTI CMA options totaling 181,634 Bbls for the contract period of January 2026 to January 2028. ​ At December 31, 2024, the Company had outstanding NYMEX HH swaps totaling 2.2615 Bcf and Tennessee Z4 basis swaps totaling 2.2615 Bcf for the contract period of January 2025 to October 2025, and NYMEX WTI CMA swaps totaling 20,662 Bbls for the contract period of January 2025 to June 2025. ​ Income Tax (Benefit) Expense ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31,  ​   ​ ​ ​ 2025   ​ ​ ​ 2024 Income tax expense ​ $ 362,731 ​ $ 1,629,093 ​ During the year ended December 31, 2025, income tax expense decreased by $1.3 million, or 78%, from the same period in 2024. This decrease was primarily due to a decrease in taxable income as a result of loss on the asset sale, as well as increased expenses related to the Peak acquisition. Net (Loss) Income Compared to Adjusted EBITDA ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31,  ​ 2025 2024 Net (loss) income ​ $ (5,798,863) ​ $ 1,927,800 Add Back: ​ ​ ​ ​ ​ ​ Interest expense (income), net ​ ​ 435,791 ​ ​ (446,877) Income tax (benefit) expense ​ ​ 362,731 ​ ​ 1,629,093 Depreciation, depletion, amortization, and accretion ​ ​ 12,170,320 ​ ​ 10,185,119 Impairment expense ​ ​ 3,936,669 ​ ​ 1,450,076 Stock based compensation expense ​ ​ 1,744,917 ​ ​ 1,244,416 Loss on sale of assets ​ ​ 19,256,530 ​ ​ — Transaction costs ​ ​ 2,947,907 ​ ​ ​ (Gain) loss on derivative contracts net of cash received or paid on settlement ​ ​ (4,336,824) ​ ​ 1,587,803 Foreign currency translation loss ​ ​ 24,805 ​ ​ 570 Adjusted EBITDA ​ $ 30,743,983 ​ $ 17,578,000 ​ We define Adjusted EBITDA as earnings before (1) net interest expense, (2) taxes, (3) depreciation, depletion, amortization and accretion expense, (4) impairments of natural gas and oil properties, (5) non-cash stock compensation expense, (6) gain or loss on sale of assets, (7) gain or loss on derivative contracts net of cash received or paid on settlement, (8) transaction costs and (9) gain or loss on foreign currency translation. Adjusted EBITDA is not a measure of financial performance as determined under U.S. GAAP and should not be considered in isolation from or as a substitute for net income or cash flow measures prepared in accordance with U.S. GAAP or as a measure of profitability or liquidity. Additionally, Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We have included Adjusted EBITDA as a supplemental disclosure because its management believes that Adjusted EBITDA provides useful information regarding our ability to service debt and to fund capital expenditures. It further provides investors a helpful measure for comparing operating performance on a "normalized" or recurring basis with the performance of other companies, without giving effect to certain non-cash expenses and other items. This provides management, investors and analysts with comparative information for evaluating us in relation to other natural gas and oil companies providing corresponding non-U.S. GAAP financial measures or that have different financing and capital structures or tax rates. These non-U.S. GAAP financial measures should be considered in addition to, but not as a substitute for, measures for financial performance prepared in accordance with U.S. GAAP. The table above sets forth a reconciliation of net income to Adjusted EBITDA, which is the most directly comparable measure of financial performance calculated under U.S. GAAP and should be reviewed carefully. 38 ​ ​ Capital Resources and Liquidity Cash Flow The primary source of cash during the year ended December 31, 2025 was funds generated from operations and financing activities. The primary source of cash during the year ended December 31, 2024 was funds generated from operations and proceeds from short term investments. For the year ended December 31, 2025 the primary uses of cash were development of upstream properties, the distribution of dividends, and costs related to the Peak acquisition. For the year ended December 31, 2024 the primary uses of cash were the acquisition and development of upstream properties and the distribution of dividends. At December 31, 2025, we had a working capital surplus of $7.6 million, an increase of $0.5 million from the $7.1 million surplus at December 31, 2024. The surplus increased from December 31, 2024 due to an increase in current assets. We anticipate that our current cash balance, available borrowings, and cash flows from operations to be sufficient to meet our cash requirements for at least the next twelve months. Year ended December 31, 2025 compared to 2024 During the year ended December 31, 2025, $20.6 million was provided by our operating activities, compared to $16.8 million in 2024, a $3.8 million, or 23%, increase. The increase was primarily due to higher production and throughput volumes in Pennsylvania due to new wells turned on line as well as curtailed wells returning to production. The Company used $61.6 million for investing activities during the year ended December 31, 2025, compared to $16.7 million in 2024, a $44.9 million, or 270%, increase. The increase was primarily due to $49.8 million paid for the Peak acquisition. During the year ended December 31, 2025, $43.7 million was provided by financing activities compared to $7.3 million used in 2024, a $51 million, or 697% decrease. The decrease was primarily due to the $50.5 million draw on the Company’s credit facility to repay the outstanding debt of Peak related to the acquisition. Credit Agreement The Company closed a new senior secured reserve based revolving credit facility on October 10, 2025 with Frost Bank as administrative agent and Frost Bank and Texas Capital Bank as lenders. This replaced the Company’s previous credit facility. As of December 31, 2025, the borrowing base was $80 million, supported by the Company’s producing reserves and is subject to semi-annual redeterminations with a maturity date of October 10, 2029. Interest will be charged at the 3-month Term SOFR rate plus a margin of 3-4% (depending on facility utilization), payable quarterly. The facility is secured by the assets of the Company’s Epsilon Energy USA subsidiary. During March 2026, the Company made a $5 million repayment on the outstanding credit facility. The current balance as of March 25, 2026 is $45.5 million. ​ Under the terms of the facility, the Company must adhere to the following financial covenants: ● Current ratio of 1.0 to 1.0 (current assets / current liabilities) ● Leverage ratio of less than 2.5 to 1.0 (total debt / income adjusted for interest, taxes and non-cash amounts) Additionally, the Company is required to hedge 50% of its forecasted Proved Developed Producing production over a rolling 18-month period. If the facility utilization drops below 50%, then the required hedging drops to 25% of Proved Developed Producing production for the last 6 months of the 18-month period. Repurchase Transactions On February 18, 2026, the Board authorized a new share repurchase program of up to 3,014,986 common shares, representing 10% of the current outstanding common shares of Epsilon, for an aggregate purchase price of not more than 39 ​ ​ US $15.0 million. The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act. The program will commence on February 19, 2026 and end on February 18, 2027, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination. On February 12, 2025, the Board authorized a new share repurchase program of up to 2,200,876 common shares, representing 10% of the outstanding common shares of the Company at such time, for an aggregate purchase price of not more than US $13.0 million. The program is pursuant to a normal course issuer bid and conducted in accordance with Rule 10b-18 under the Exchange Act. The program commenced on February 12, 2025 and expired on February 11, 2026. No shares were repurchased under this program. On March 19, 2024, the Board of Directors authorized a new share repurchase program of up to 2,191,320 common shares, representing 10% of the outstanding common shares of Epsilon at such time, for an aggregate purchase price of not more than US $12.0 million. The program was pursuant to a normal course issuer bid and was conducted in accordance with Rule 10b-18 under the Exchange Act. The program commenced on March 27, 2024 and expired on February 12, 2025, when the Board terminated and revoked authority under the program. During the year ended December 31, 2024, we repurchased 125,000 common shares and spent $627,500 at an average price of $5.00 per share (excluding commissions) under the plan. In 2024, the Company also repurchased 248,700 common shares and spent $1,203,708 at an average price of $4.82 per share (excluding commissions) and retired 319,574 common shares under the 2023-2024 repurchase program before the plan terminated on March 26, 2024. During the year ended December 31, 2024, the Company repurchased a total of 373,700 shares and spent $1,831,208 at an average price of $4.88 per share (excluding commissions) under the two previous repurchase programs. Derivative Transactions The Company has entered into hedging arrangements to reduce the impact of natural gas and oil price volatility on operations. By removing the price volatility from a significant portion of natural gas and oil production, the potential effects of changing prices on operating cash flows have been mitigated, but not eliminated. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we might otherwise receive from increases in commodity prices. At December 31, 2025, Epsilon’s outstanding natural gas and crude oil commodity contracts consisted of the following: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average Price ($/Mmbtu) ​ ​ ​ ​ ​ Volume ​ ​ ​ ​ Ceiling ​ Floor ​ Fair Value of Asset Derivative Type   ​ ​ ​ (MMbtu)   ​ ​ ​  Swaps    ​ ​ ​ Price   ​ ​ ​ Price   ​ ​ ​ December 31, 2025 2026 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NYMEX Henry Hub (LD) Options Call 2,360,801 ​ $ — ​ $ 5.05 ​ $ — $ (295,384) NYMEX Henry Hub (LD) Options Put — ​ $ — ​ $ — ​ $ 3.35 $ 709,792 NYMEX Henry Hub (LD) Swaps 1,339,777 ​ $ 4.00 ​ $ — ​ $ — $ 632,140 2027 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NYMEX Henry Hub (LD) Options Call 2,126,016 ​ $ — ​ $ 4.87 ​ $ — $ (631,696) NYMEX Henry Hub (LD) Options Put — ​ $ — ​ $ — ​ $ 3.29 $ 639,282 NYMEX Henry Hub (LD) Swaps 312,297 ​ $ 3.76 ​ $ — ​ $ — $ (32,489) 2028 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NYMEX Henry Hub (LD) Options Call 27,978 ​ $ — ​ $ 4.70 ​ $ — $ (22,920) NYMEX Henry Hub (LD) Options Put — ​ $ — ​ $ — ​ $ 3.65 $ 8,513 NYMEX Henry Hub (LD) Swaps 27,978 ​ $ 4.46 ​ $ — ​ $ — $ (7,910) ​ 6,194,847 ​ ​ ​ ​ ​ ​ ​ ​ ​ $ 999,328 ​ 40 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average Price ($/Mmbtu) ​ ​ ​ ​ Volume ​ ​ ​ ​ Ceiling ​ Floor ​ Fair Value of Asset Derivative Type   ​ ​ ​ (Bbl)   ​ ​ ​  Swaps    ​ ​ ​ Price   ​ ​ ​ Price   ​ ​ ​ December 31, 2025 2026 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NYMEX WTI CMA Options Call ​ 55,230 ​ $ — ​ $ 69.23 ​ $ — $ (63,877) NYMEX WTI CMA Options Put ​ — ​ $ — ​ $ — ​ $ 59.37 $ 313,499 NYMEX WTI CMA Swaps ​ 226,622 ​ $ 63.21 ​ $ — ​ $ — $ 1,398,170 2027 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NYMEX WTI CMA Options Call ​ 118,096 ​ $ — ​ $ 67.82 ​ $ — $ (384,927) NYMEX WTI CMA Options Put ​ — ​ $ — ​ $ — ​ $ 57.60 $ 839,353 NYMEX WTI CMA Swaps ​ 105,986 ​ $ 63.76 ​ $ — ​ $ — $ 679,105 2028 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NYMEX WTI CMA Options Call ​ 8,308 ​ $ — ​ $ 67.96 ​ $ — $ (33,685) NYMEX WTI CMA Options Put ​ — ​ $ — ​ $ — ​ $ 57.57 $ 61,503 NYMEX WTI CMA Swaps ​ 8,308 ​ $ 62.97 ​ $ — ​ $ — $ 40,807 ​ 522,550 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ 2,849,948 ​ Contractual Obligations The following table summarizes our contractual obligations at December 31, 2025. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Payments Due by Period ​ ​ ​ ​ ​ Less than ​ 1 – 3 ​ Greater than ​   ​ ​ ​ Total   ​ ​ ​ 1 Year   ​ ​ ​ Years   ​ ​ ​ 3 Years Derivative liabilities ​ $ 1,552,027 ​ $ 410,342 ​ $ 1,141,685 ​ $ — Asset retirement obligations, undiscounted ​ ​ 18,765,954 ​ ​ — ​ ​ — ​ ​ 18,765,954 Capital expenditure commitments ​ 3,828,678 ​ 3,828,678 ​ — ​ — Total future commitments ​ $ 24,146,659 ​ $ 4,239,020 ​ $ 1,141,685 ​ $ 18,765,954 ​ We enter into commitments for capital expenditures in advance of the expenditures being made. As of December 31, 2025, our commitments for capital expenditures were $3.8 million related to the drilling of 1 gross (0.25 net) well in Texas. 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. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting estimates cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting estimates. Described below are the most significant accounting policies we apply in preparing our consolidated financial statements. We also describe the most significant estimates and assumptions we make in applying these policies. Proved Natural Gas and Oil Reserves Our engineers estimate proved natural gas and oil reserves in accordance with SEC regulations, which directly impact financial accounting estimates, including depreciation, depletion and amortization and impairments of proved properties and related assets. Proved reserves represent estimated quantities of crude oil and condensate, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating future production volumes of proved natural gas and oil reserves is complex, requiring significant subjective 41 ​ ​ decisions in the evaluation of all available geological, engineering and economic data for each reservoir. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Accordingly, there can be no assurance that ultimately, the reserves will be produced, nor can there be assurance that the proved undeveloped reserves will be developed within the period anticipated. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. We cannot predict the types of reserve revisions that will be required in future periods. For related discussion, see the sections titled “Risk Factors” and “Supplemental Information to Consolidated Financial Statements.” Impairments The carrying value of unproved and proved oil and natural gas properties and gathering system assets are reviewed for impairment whenever events indicate that the carrying amounts for those assets may not be recoverable. Such indicators include changes in our business plans, changes in commodity prices leading to unprofitable performance, and, for natural gas and oil properties, significant downward revisions of estimated proved reserve quantities or significant increases in the estimated development costs. We compare expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the carrying value of the asset. If the expected undiscounted future cash flows, based on our estimates of (and assumptions regarding) future oil and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the carrying value of the asset, the carrying value is reduced to fair value. Fair value is generally calculated using the “Income Approach” based on estimated discounted net cash flows. Estimates of future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. In addition, such assumptions and estimates are reasonably likely to change in the future. 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. On this basis, certain fields may be impaired because they are not expected to recover their entire carrying value from future net cash flows. The basis for future depletion, depreciation, amortization, and accretion will take into account the reduction in the value of the asset as a result of any accumulated impairment losses. Unproved natural gas and oil properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and other relevant factors. When circumstances indicate that the gathering system properties may be impaired, Epsilon compares expected undiscounted future cash flows related to the gathering system to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach, which considers estimated discounted future cash flows. Asset Retirement Obligations (“ARO”) We recognize asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. For our upstream properties, these obligations consist of estimated future costs associated with the plugging and abandonment of natural gas and oil wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. For our gathering system, these obligations consist of estimated future costs associated with the removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the natural gas and oil or gathering system asset. The initial recognition of an ARO fair value requires that management make numerous assumptions regarding such factors as the amounts and timing 42 ​ ​ of settlements; the credit-adjusted risk-free discount rate; and the inflation rate. In periods subsequent to the initial measurement of an ARO, period-to-period changes are recognized in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the natural gas and oil property or gathering system asset. Income Taxes Tax regulations and legislation in the U.S. and Canada are subject to change and differing interpretations requiring judgment. We compute income taxes using the asset-and-liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities, as well as loss and tax credit carryforwards. Changes in tax rates and laws are recognized in income in the period such changes are enacted. We establish a valuation allowance if, based on available evidence, it is more likely than not that some or all of the deferred tax assets will not be realized. 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. Changes in facts, circumstances, and interpretations of the standards may result in a material increase or decrease in our provision for income taxes. Business Combinations We account for acquisitions that have been determined to be business combinations using the acquisition method of accounting. Accordingly, identifiable assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair values. We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in these acquisitions. The most significant assumptions relate to the estimated fair values of proved and unproved oil and gas properties. The fair value of identifiable assets acquired and liabilities assumed is determined based on various valuation techniques, including market prices, discounted cash flow analysis, and independent appraisals. Significant judgments and assumptions are inherent in these valuation techniques and include, among other things, estimates of reserves, estimates of future production volumes, estimates of future commodity prices, expected development costs, lease operating costs and the discount rate that reflects the risk of the underlying cash flow estimates. Estimated fair values assigned to assets acquired can have a significant impact on future results of operations presented in the Company's financial statements. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net income. In the event that future commodity prices or reserve quantities are lower than those used as inputs to determine estimates of acquisition date fair values, the likelihood increases that certain costs may be determined to not be recoverable. ​ Recently Issued Accounting Standards See Note 3, “Summary of Significant Accounting Policies” in Notes to the Consolidated Financial Statements. ​