UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☒

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2024~~2025.

☐

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 001-38770

EPSILON ENERGY LTD.

(Exact name of registrant as specified in its charter)


Alberta, Canada	98-1476367
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

500 Dallas Street, Suite 1250

Houston, Texas 77002

(281) 670-0002

(Address of principal executive offices including zip code and

telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol	Name of each exchange on which registered
Common Shares, no par value	EPSN	NASDAQ Global Market

Securities registered pursuant to Section 12(g) of the Act:

NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.


Yes ☐	No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.


Yes ☐	No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.


Yes ☒	No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).


Yes ☒	No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ☐	Accelerated filer ☐	Non-accelerated filer ☒	Smaller reporting company ☒	Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to § 240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).


Yes ☐	No ☒

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $90133.97 million. There were 2230,~~008~~239,~~766~~980 Common Shares (no par value) outstanding as of March 1826, ~~2025~~2026.

PART I

FORWARD LOOKING STATEMENTS.

Certain statements contained in this report constitute forward-looking statements. The use of any of the words ‘‘anticipate,’’ ‘‘continue,’’ ‘‘estimate,’’ ‘‘expect,’’ ‘‘may,’’ ‘‘will,’’ ‘‘project,’’ ‘‘should,’’ ‘‘believe,’’ and similar expressions and statements relating to matters that are not historical facts constitute ‘‘forward looking statements’’ within the meaning of applicable securities laws. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated. Such forward-looking statements are based on reasonable assumptions, but no assurance can be given that these expectations will prove to be correct and the forward-looking statements included in this report should not be unduly relied upon. These statements are made only as of the date of this report. All statements that address operating performance, events or developments that we expect or anticipate will occur in the future — including statements relating to oil and natural gas production rates, commodity prices for crude oil or natural gas, supply and demand for oil and natural gas; the estimated quantity of oil and natural gas reserves, including reserve life; future development and production costs, and statements expressing general views about future operating results — are forward-looking statements. Management believes that these forward-looking statements are reasonable as and when made. However, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date when made. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. In addition, forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from our present expectations or projections. These risks and uncertainties include, but are not limited to, those described in this Annual Report on Form 10-K, and those described from time to time in our future reports filed with the Securities and Exchange Commission.

DEFINED TERMS

We have included below the definitions for certain terms used in this document:

‘‘3-D seismic’’ Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

‘‘ABCA’’ Business Corporations Act (Alberta).

‘‘Anchor shippers’’ Parties listed in the Anchor Shipper Gas Gathering Agreement for Northern Pennsylvania, including Epsilon Energy USA, Inc., Equinor USA Onshore Properties, Inc., and Expand Energy Corporation. for the Auburn Gas Gathering System.

‘‘ASC’’ Accounting Standards Codification.

‘‘Bbl’’ One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil, NGLs and other liquid hydrocarbons.

‘‘Bcf’’ One billion cubic feet, used in reference to natural gas.

‘‘~~BOE~~Boe’’ One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals one Bbl of natural gas liquids.

‘‘Completion’’ The process of preparing a natural gas and oil wellbore for production through the installation of permanent production equipment, as well as perforation and fracture stimulation to optimize production.

‘‘Delay rental’’ Consideration paid to the lessor by a lessee to extend the terms of an oil and natural gas lease in the absence of drilling operations and/or production that is contractually required to hold the lease. This consideration is generally required to be paid on or before the anniversary date of the natural gas and oil lease during its primary term, and typically extends the lease for an additional year.

‘‘Development well’’ A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

‘‘Differential’’ The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot price, and the wellhead price received.

‘‘Dry hole’’ A well found to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well.

‘‘Exit rate’’ Upstream term referring to the rate of production of oil and/or gas as of a specified date.

‘‘Exploratory well’’ A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

‘‘FASB’’ Financial Accounting Standards Board.

‘‘Field’’ An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms ‘‘structural feature’’ and ‘‘stratigraphic condition’’ are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.

‘‘Free cash flow’’ A measure of a company’s financial performance, calculated as operating cash flow minus capital expenditures. Free cash flow represents the cash that a company is able to generate after spending the money required to maintain or expand its asset base.

‘‘GAAP’’ Generally accepted accounting principles in the United States of America.

“GGS” A natural gas gathering system.

‘‘Gross acres’’ or ‘‘gross wells’’ The total acres or wells, as the case may be, in which a working interest is owned.

“Henry Hub” A natural gas pipeline located in Erath, Louisiana, that serves as the official delivery location for futures contracts on the NYMEX. The hub is owned by Sabine Pipe Line LLC and has access to many of the major gas markets in the United States.

‘‘ISDA’’ International Swaps and Derivatives Association, Inc.

‘‘Lease operating expense’’ or ‘‘LOE’’ The expenses of lifting oil or gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

‘‘LIBOR’’ London interbank offered rate.

‘‘MBbl’’ One thousand barrels of oil, NGLs or other liquid hydrocarbons.

‘‘MBbl/d’’ One MBbl per day.

‘‘~~MBOE~~MBoe’’ One thousand BOE.

‘‘~~MBOE~~MBoe/d’’ One MBOE per day.

‘‘Mcf’’ One thousand cubic feet, used in reference to natural gas.

“Mcfe” One thousand cubic feet equivalent, used in reference to natural gas. One Mcf of natural gas equivalent, converting one Bbl of oil or natural gas liquids at the ratio of one Bbl of oil or natural gas liquids to 6 Mcf of natural gas.

‘‘MMBbl’’ One million Bbl.

‘‘~~MMBOE~~MMBoe’’ One million ~~BOE~~Boe.

‘‘MMBtu’’ One million British Thermal Units, used in reference to natural gas.

‘‘MMcf’’ One million cubic feet, used in reference to natural gas.

‘‘MMcf/d’’ One MMcf per day.

“MMcfe” One million Mcfe.

‘‘Net acres’’ or ‘‘net wells’’ The sum of the fractional working interests owned in gross acres or wells, as the case may be.

‘‘Net production’’ The total production attributable to the fractional working interest owned.

‘‘NGL’’ Natural gas liquid.

‘‘NYMEX’’ The New York Mercantile Exchange.

‘‘PDNP’’ Proved developed nonproducing reserves.

‘‘PDP’’ Proved developed producing reserves.

‘‘Plugging and abandonment’’ Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of most states legally require plugging of abandoned wells.

‘‘Prospect’’ A property on which indications of oil or gas have been identified based on available seismic and geological information.

‘‘Proved developed reserves’’ Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

‘‘Proved reserves’’ Those reserves that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

The area of the reservoir considered as proved includes all of the following:

The area identified by drilling and limited by fluid contacts, if any, and

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and

The project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

‘‘Proved undeveloped reserves’’ or ‘‘PUDs’’ Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

‘‘PV-10’’ The present value, discounted at 10% per annum, of future net revenues (estimated future gross revenues less estimated future costs of production, development, and asset retirement costs) associated with reserves and is not necessarily the same as market value. PV-10 does not include estimated future income taxes. Unless otherwise noted, PV-10 is calculated using the pricing scheme as required by the Securities and Exchange Commission (‘‘SEC’’). PV-10 of proved reserves is calculated the same as the standardized measure of discounted future net cash flows, except that the

~~of proved reserves is calculated the same as the~~ standardized measure of discounted future net cash flows, ~~except that the standardized measure of discounted future net cash flows~~ includes future estimated income taxes discounted at 10% per annum. See the definition of standardized measure of discounted future net cash flows.

‘‘Reasonable certainty’’ If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

‘‘Reserves’’ Estimated remaining quantities of natural gas and oil and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering natural gas and oil or related substances to market, and all permits and financing required to implement the project.

‘‘Reservoir’’ A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

‘‘Royalty’’ The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil or natural gas produced and sold, unencumbered by expenses relating to the drilling, completing or operating of the affected well.

‘‘Royalty interest’’ An interest in an oil or natural gas property entitling the owner to shares of the crude oil or natural gas production free of costs of exploration, development and production operations.

‘‘Section’’ An area of one square mile of land, 640 acres, with 36 sections making up one survey township on a rectangular grid.

‘‘SOFR’’ The Secured Overnight Financing Rate that is generally published by the Federal Reserve Bank of New York.

‘‘Standardized Measure’’ or ‘‘SMOG’’ The standardized measure of discounted future net cash flows (the ‘‘Standardized Measure’’) is an estimate of future net cash flows associated with proved reserves, discounted at 10% per annum. Future net cash flows is calculated by reducing future net revenues by estimated future income tax expenses and discounting at 10% per annum. The Standardized Measure and the PV-10 of proved reserves is calculated in the same exact fashion, except that the Standardized Measure includes future estimated income taxes discounted at 10% per annum. The Standardized Measure is in accordance with U.S. GAAP.

‘‘Working interest’’ The interest in a crude oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

‘‘Workover’’ Operations on a producing well to restore or increase production.

ITEM 1. BUSINESS.

Summary

Epsilon Energy Ltd. (the “Company” or “Epsilon” or “we”) was incorporated under the laws of the Province of Alberta, Canada on March 14, 2005, pursuant to the ABCA. The Company is extra-provincially registered in Ontario pursuant to the Business Corporations Act (Ontario). Epsilon is a North American on-shore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves. 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~~2025, Epsilon’s total estimated net proved reserves were ~~69,401~~86.4 ~~million~~Bcf ~~cubic feet~~ of natural gas reserves, ~~876,808~~9.3 ~~barrels~~MMBbls of ~~NGL~~oil reserves, and ~~1,572,465~~2.4 ~~barrels~~MMBbls of ~~oil~~NGL ~~and other liquids~~reserves. Epsilon holds leasehold rights to approximately ~~102~~101,~~506~~265 gross (2354,~~602~~044 net) acres. The Company has natural gas production in the ~~Marcellus~~Appalachian ~~Shale~~Basin in Pennsylvania; and oil, natural gas liquids and natural gas production in the ~~Permian~~Powder River Basin in ~~Texas and New Mexico~~Wyoming, the NWPermian ~~Anadarko~~ Basin in ~~Oklahoma;~~Texas and ~~oil~~New ~~production~~Mexico, inand the Western Canadian Sedimentary Basin in Alberta, Canada.

WeOn ~~conduct~~November ~~operations~~14, in2025, ~~the~~Epsilon ~~United~~acquired ~~States~~Peak ~~through~~Exploration ~~our~~& ~~wholly~~Production ~~owned~~LLC and Peak BLM Lease LLC and their subsidiaries ~~Epsilon~~(together, ~~Energy~~“Peak”) ~~USA Inc~~for total consideration of $88.5 million consisting of 1) issuance of 5,681,489 ancommon ~~Ohio~~shares ~~corporation~~valued at $27.6 million, or2) ~~Epsilon~~contingent ~~Energy~~consideration ~~USA;~~of ~~Epsilon~~up ~~Midstream~~to 2, ~~LLC~~500,000 acommon ~~Pennsylvania~~shares ~~limited~~valued ~~liability~~at ~~company~~$10.6 million, orand ~~Epsilon~~the ~~Midstream;~~settlement ~~Epsilon~~of ~~Operating, LLC,~~$50.3 amillion ~~Delaware~~of ~~limited~~debt. ~~liability~~The ~~company;~~contingent ~~Dewey~~consideration ~~Energy GP LLC,~~was asettled ~~Delaware~~on ~~limited~~November ~~liability~~19, ~~company;~~2025, ~~Dewey~~through ~~Energy~~the ~~Holdings LLC~~issuance of 2,234,847 acommon ~~Delaware~~shares ~~limited~~for ~~liability~~$10.6 ~~company;~~million. The acquired assets primarily include operated and ~~Altolisa~~non-operated ~~Holdings,~~production ~~LLC~~and leasehold interests in the core of the Powder River Basin in Wyoming. As part of the acquisition, athe ~~Delaware~~Company ~~limited~~added ~~liability~~17 ~~company~~full-time employees from Peak.

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. We own a 35% interest in the Auburn GGS which is operated by a subsidiary of Williams Partners, LP. 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.

The results of operations attributable to the Peak acquisition have been included in the Company’s consolidated financial statements as of the closing date of the acquisition.

We conduct operations in the United States through our wholly owned subsidiaries Epsilon Energy USA Inc., an Ohio corporation, or Epsilon Energy USA; Epsilon Midstream, LLC, a Pennsylvania limited liability company, or Epsilon Midstream; Epsilon Operating, LLC, a Delaware limited liability company; Dewey Energy GP LLC, a Delaware limited liability company; Peak Exploration & Production LLC, a Delaware limited liability company; Peak BLM Lease LLC, a Delaware limited liability company; Peak Powder River Resources, LLC, a Wyoming limited liability company (the licensed operator in the state of Wyoming); Peak Energy Operating #2, LLC, a Colorado limited liability company; Willow Springs Development, LLC, a Colorado limited liability company; Peak Powder River Acquisition, LLC, a Delaware limited liability company; and Altolisa Holdings, LLC, a Delaware limited liability company.

Substantially all the Pennsylvania acreage (4,878 net) is dedicated to the Auburn Gas Gathering System (“Auburn GGS”) located in Susquehanna County, Pennsylvania for a 10-year term expiring in 2033 under an operating agreement whereby the Auburn GGS owners charge a fixed gathering and compression rate which is adjusted annually by the CPI-U All Urban Consumer Price Index published by the US Bureau of Labor Statistics. We own a 35% interest in the Auburn GGS which is operated by a subsidiary of Williams Partners, LP. In 2025, we paid $3.5 million (after elimination) to the Auburn GGS to gather and treat our 9.4 Bcf of natural gas production in Pennsylvania ($2.4 million after elimination was paid to the Auburn GGS to gather and treat our 5.7 Bcf in 2024), including the fees paid to our subsidiary, Epsilon Midstream.

Our principal executive office is located at 500 Dallas Street, Suite 1250, Houston, Texas 77002, and our telephone number at that address is (281) 670-0002. Our registered office in Alberta, Canada is located at 14505 Bannister Road SE, Suite 300, Calgary, AB, Canada T2X 3J3.

~~Business~~Operational ~~highlights~~Highlights of ~~2024~~2025

~~Operational~~Appalachian ~~Highlights~~Basin—Pennsylvania

~~Marcellus~~● ~~Shale—Pennsylvania~~During the year ended December 31, 2025, Epsilon’s realized natural gas price was $2.98 per Mcf,

● 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. 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.

excluding the impact of hedges, a 66% increase from $1.80 for the year ended December 31, 2024.

●

Total natural gas sales for the year ended December 31, 2025 were 9.4 Bcf, a 65% increase from the 5.7 Bcf sold for the year ended December 31, 2024, driven by new wells and curtailed wells returning to production.

●

Gathered and delivered 40.5 Bcf gross (14.2 Bcf net to Epsilon’s interest) during the year, or 111 MMcf/d through the Auburn GGS.

●

In 2025, 4 gross (0.24 net) wells were turned on line in January 2025 and 3 gross (0.04) wells were turned on line in March 2025.

Permian Basin—Texas and New Mexico

● During the year ended December 31, ~~2024~~2025, Epsilon’s realized price for all Permian Basin production was $5349.5219 per ~~BOE~~Boe, excluding the impact of hedges, aan 28% ~~increase~~decrease from the $5253.4952 per Boe for the year ended December 31, ~~2023~~2024.

● Total sales for the year ended December 31, ~~2024~~2025, including oil, natural gas, and ~~other~~natural gas liquids, were ~~259~~212 ~~MBOE~~Mboe, aan ~~242~~18% ~~increase~~decrease from the ~~75.7~~259 ~~MBOE~~MBoe sold for the year ended December 31, ~~2023~~2024.

● In ~~2024~~2025, the Company ~~acquired~~participated ain ~~25%~~the ~~working~~drilling ~~interest~~and incompletion ~~three~~of ~~producing~~1 gross (0.25 net) wells ~~and~~in ~~3,246~~Texas. ~~gross~~This ~~undeveloped~~well ~~acres~~went ininto ~~Ector~~production ~~County,~~in ~~Texas~~July 2025.

● In 2024, the Company participated in the drilling and completion of 2 gross (0.5 net) wells in Texas. These wells went into production in May 2024 and July 2024.

Anadarko, ~~NW STACK Trend~~Basin—Oklahoma

● During the year ended December 31, ~~2024~~2025, Epsilon’s realized price for all Oklahoma production was $4.3433 per Mcfe, excluding the impact of hedges, a 190.2% decrease from $54.3534 realized for the year ended December 31, ~~2023~~2024.

● Total sales for the year ended December 31, ~~2024~~2025, including oil, natural gas, ~~oil,~~ and ~~other~~natural gas liquids, were 0.4134 Bcfe, a 3217% decrease from 0.6041 Bcfe sold for the year ended December 31, ~~2023~~2024.

●

In 2025, there was no development activity in Oklahoma. The Company sold all of its assets in the Anadarko Basin in December 2025.

Powder River Basin—Wyoming

●

The Powder River Basin assets were acquired on November 14, 2025.

●

During the period ended December 31, 2025, Epsilon’s realized price for all Wyoming production was $36.91 per Boe, excluding the impact of hedges.

●

Total sales for the period ended December 31, 2025, including oil, natural gas, and natural gas liquids, were 108.5 MBoe.

Western Canadian Sedimentary Basin—Alberta, Canada

● During the year ended December 31, ~~2024~~2025, Epsilon’s realized price for all Canada ~~oil~~ production was $36.07 per Boe, excluding the impact of hedges, a 22% decrease from the $46.0407 per ~~Bbl~~Boe realized for the year ended December 31, 2024.

● Total ~~oil~~ sales for the year ended December 31, ~~2024~~2025, including oil, natural gas, and natural gas liquids, were 27.4 MBoe, a 996% increase from 2.5 ~~MBbl~~MBoe sold for the year ended December 31, 2024.

● In ~~2024~~2025, the Company participated in the ~~drilling~~completion of 42 gross (10.5 net) wells in Canada. ~~One~~The ~~well~~two ~~went~~wells ~~into~~turned ~~production~~on line in ~~September~~March ~~2024~~2025. ~~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~~2025, Epsilon’s ~~102~~101,~~506~~265 gross (2354,~~602~~044 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

~~nearest~~and ~~acre:~~include 540 gross (90.69 net) wells. Of these wells, 105 gross (45 net) wells are operated.


	Gross(1)	Net(2) ~~(3)~~
Developed Acres
Producing Wells
Pennsylvania	11,270	4,807
Gas	274	33.63
Texas	2,763	691
Oil	194	55.42
Oklahoma	5,113	991
Total Producing Wells	468	89.05
Canada	640	320
Non-Producing Wells	72	1.64
	19,786	6,809
Total Wells	540	90.69
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.~~Acreage

As of December 31, 2025, our leasehold inventory consisted of the following acreage amounts, rounded to the nearest acre:


		Gross⁽¹⁾		Net^{(2) (3)}
Developed Acres
Pennsylvania		11,398		4,878
Wyoming		10,428		6,781
Texas		3,086		771
Canada		4,138		1,273
		29,050		13,703
Undeveloped Acres
Pennsylvania		250		250
Wyoming		50,517		32,785
Texas		13,548		3,354
Canada		7,900		3,950
		72,215		40,339
Total Acres
Pennsylvania		11,648		5,129
Wyoming		60,945		39,566
Texas		16,634		4,126
Canada		12,038		5,223
Total acres		101,265		54,044

(1)“Gross” means one hundred percent of the working interest ownership in each leasehold tract of land.

(2)

“Net” means the Company’s fractional working interest share in each leasehold tract of land on which productive wells have been drilled.

(3)

“Net Undeveloped” means the Company’s fractional working interest share in each leasehold tract of land where productive wells have yet to be drilled.

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~~2025 and ~~2023~~2024.

The two segments are as follows:

Upstream: Activities include interest in the acquisition, exploration, development and production of oil and natural gas reserves.

Gathering System: Interest in a natural gas gathering system.

For information about our segment’s revenues, profits and losses, total ~~assets~~capital expenditures, and total ~~liabilities~~assets, see Note 14 “Operating Segments” in the Notes to Consolidated Financial Statements.

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~~2025 and ~~2023~~2024, respectively, follows:


	Year ended
	December 31,
	~~2024~~2025		~~2023~~2024
Production Volumes
Pennsylvania
Natural gas (MMcf)		59,~~699~~402		75,~~906~~699
Total (Mmcfe)		5,699		7,906
Total (MMcfe)		9,402		5,699
Permian Basin
Natural gas (MMcf)		~~205~~161		80205
Natural gas liquids (MBOE)		52		18
Natural gas liquids (MBoe)		36		52
Oil & other liquids (MBbl)		173		44
Oil (MBbl)		149		173
Total (Mmcfe)		1,554		454
Total (MMcfe)		1,271		1,554
Oklahoma
Natural gas (MMcf)		~~237~~197		~~354~~237
Natural gas liquids (MBOE)		17		21
Natural gas liquids (MBoe)		14		17
Oil & other liquids (MBbl)		11		21
Oil (MBbl)		9		11
Total (Mmcfe)		408		605
Total (MMcfe)		335		408
Wyoming
Natural gas (MMcf)		189		—
Natural gas liquids (MBoe)		27		—
Oil (MBbl)		50		—
Total (MMcfe)		651		—
Canada
Oil & other liquids (MBbl)		3		-
Natural gas (MMcf)		52		—
Total (Mmcfe)		15		-
Natural gas liquids (MBoe)		4		—
Oil (MBbl)		15		3
Total (MMcfe)		166		15
Company Total
Natural gas (MMcf)		610,~~142~~001		86,~~340~~142
Natural gas liquids (MBOE)		69		39
Natural gas liquids (MBoe)		81		69
Oil & other liquids (MBbl)		187		65
Oil (MBbl)		223		187
Total (Mmcfe)		7,676		8,965
Total (MMcfe)		11,825		7,676


	Year ended
	December 31,
	~~2024~~2025		~~2023~~2024
Revenues
Pennsylvania
Natural gas revenue	$	1028,~~247~~012,~~834~~040	$	1310,~~733~~247,~~052~~834
Avg. Price ($/Mcf)	$	12.8098	$	1.7480
Gathering system revenue (net of elimination)	$	56,~~524~~683,~~063~~735	$	95,~~790~~524,~~531~~063
Total PA Revenues	$	1534,~~771~~695,~~897~~775	$	2315,~~523~~771,~~583~~897
Permian Basin
Natural gas revenue	$	32113,~~930~~038	$	~~117~~32,~~112~~930
Avg. Price ($/Mcf)	$	0.1670	$	10.4716
Natural gas liquids revenue	$	1706,~~060,967~~010	$	~~353~~1,~~612~~060,967
Avg. Price ($/Bbl)	$	2019.4851	$	1920.7848
Oil and condensate revenue	$	129,~~770~~614,~~258~~603	$	312,~~501~~770,~~098~~258
Avg. Price ($/Bbl)	$	7364.8150	$	7873.7181
Total Permian Basin Revenues	$	1310,~~864~~433,~~155~~651	$	313,~~971~~864,~~822~~155
Oklahoma
Natural gas revenue	$	~~505~~640,~~304~~607	$	1505,~~014,050~~304
Avg. Price ($/Mcf)	$	23.1325	$	2.8713
Natural gas liquids revenue	$	~~420~~318,~~991~~108	$	~~630~~420,~~806~~991
Avg. Price ($/Bbl)	$	2422.1656	$	2924.9616
Oil and condensate revenue	$	~~844~~507,~~265~~406	$	1844,~~589,491~~265
Avg. Price ($/Bbl)	$	7654.7511	$	76.3775
Total OK Revenues	$	1,~~770~~466,~~560~~121	$	31,~~234~~770,~~347~~560
Wyoming
Natural gas revenue	$	291,933	$	—
Avg. Price ($/Mcf)	$	1.54	$	—
Natural gas liquids revenue	$	872,263	$	—
Avg. Price ($/Bbl)	$	32.48	$	—
Oil and condensate revenue	$	2,840,537	$	—
Avg. Price ($/Bbl)	$	56.66	$	—
Total WY Revenues	$	4,004,733	$	—
Canada
Oil and condensate revenue	$	116,163	$	—
Natural gas revenue	$	63,828	$	—
Avg. Price ($/Bbl)	$	—	$	—
Avg. Price ($/Mcf)	$	1.22	$	—
Total Canada Revenues	$	116,163	$	—
Natural gas liquids revenue	$	82,479	$	—
Total Company Revenues	$	31,522,775	$	30,729,752
Avg. Price ($/Bbl)	$	23.01	$	—
Oil and condensate revenue	$	840,969	$	116,163
Avg. Price ($/Bbl)	$	55.84	$	46.04
Total Canada Revenues	$	987,276	$	116,163
Total Company Revenues	$	51,587,556	$	31,522,775

Gathering System Operations

Epsilon Energy USA is the 100% owner of Epsilon Midstream, which owns a 35% undivided interest in the Auburn GGS, located in Susquehanna County, Pennsylvania, with partners Appalachia Midstream Services, LLC (43.875%) and Equinor Pipelines, LLC (21.125%). 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~~Shipper Gas Gathering Agreement for ~~Northern~~northern Pennsylvania whereby the Auburn GGS owners ~~receive~~received a fixed percentage rate of return on the total capital invested in the construction of the system.

On May 17, 2024, Epsilon Energy USA, ~~Inc. (“Epsilon”)~~ executed a new Anchor Shipper Gas Gathering Agreement for ~~Northern~~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. 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. 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.

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. The relative mix of Anchor Shipper gas and cross-flow gas is critical to the revenue and earnings of the Auburn GGS because the cross-flow gathering rate is only 25% of the Anchor Shipper rate. Shippers cross-flowing gas must pay

~~the~~effective ~~gathering~~date ~~rate~~ of January 1, 2024. Epsilon Energy USA simultaneously terminated the ~~originating~~prior agreement. The new ASGGA establishes fixed gathering, compression and cross-flow rates for all shippers on each system ~~plus~~into ~~25%~~which ofEpsilon produces natural gas. These rates will be adjusted annually by the Consumer Price Index for All Urban Consumers (“CPI-U”) commencing January 2025. Notably, the gathering rates in Auburn GGS, ~~gathering~~Rome ~~rate.~~GGS ~~The~~& ~~purpose~~Overfield ofGGS ~~the~~will ~~reduced~~no ~~rate~~longer isbe subject to ~~attract~~a ~~additional~~cost-of-service ~~volumes~~redetermination ~~that~~annually; ~~require~~however, ~~delivery~~acreage todedications, ~~Tennessee~~service ~~Gas~~priority ~~Pipeline~~levels, ~~when~~required ~~there~~shipper isapprovals ~~spare~~and ~~capacity~~shipper atvoting ~~the~~procedures ~~Auburn~~are ~~compression~~all ~~facility,~~substantially orconsistent with the ~~“Auburn~~prior ~~CF”~~agreement.

~~The~~Revenues from the Auburn GGS ~~consists~~are ofearned ~~approximately~~primarily 44from ~~miles~~the ofAnchor ~~gathering~~Shippers ~~pipelines,~~with awell ~~small~~pads ~~auxiliary~~located ~~compression~~within ~~facility~~the ~~and~~Auburn aGGS ~~main~~system ~~compression~~boundary. ~~facility~~Revenues ~~with~~are ~~three~~also ~~dehydration~~earned ~~units~~when ~~and~~natural ~~three~~gas ~~Caterpillar~~originating ~~3612~~in ~~compression~~adjacent ~~units.~~gathering Atsystems ~~inception,~~flow into the ~~capacity~~Auburn ofGGS ~~the~~(“cross-flow ~~Auburn~~gas”) CFto ~~was~~the ~~approximately~~compression ~~330~~facility,~~000~~ ~~Mcf~~and ~~per~~then ~~day~~to atthe adelivery ~~design~~meter ~~suction~~at ~~pressure~~Tennessee ofGas ~~800 psig~~Pipeline. The ~~design~~relative ~~suction~~mix ~~pressure~~of ~~was~~Anchor ~~subsequently~~Shipper ~~reduced~~gas toand ~~550~~cross-flow ~~psig~~gas inis ~~June~~critical ~~2020~~to at the ~~request~~revenue and earnings of the ~~Anchor~~Auburn ~~Shippers.~~GGS ~~This~~because ~~request~~the ~~served~~cross-flow togathering ~~minimize~~rate ~~throughput~~is ~~decline~~only ~~during~~25% ~~a period~~ of ~~low pricing in which~~ the ~~drilling~~Anchor ofShipper ~~new wells was undesirable~~rate. ~~The~~Shippers ~~design~~cross-flowing ~~suction~~gas ~~pressure~~must atpay the ~~Auburn~~gathering ~~compression~~rate ~~facility~~of ~~was reduced further from 550 psig to 450 psig in January 2025. Operating at~~ the ~~lower~~originating ~~design~~gathering ~~suction~~system ~~pressure~~plus ~~has~~25% ~~the benefit~~ of ~~reducing hydrate occurrences in~~ the ~~system~~Auburn ~~which~~GGS ~~can~~gathering ~~pose an operational hazard~~rate. The ~~current~~purpose ~~system capacity~~ of the ~~Auburn~~reduced CFrate atis ~~this~~to ~~lower~~attract ~~design~~additional ~~pressure~~volumes isthat ~~approximately~~require ~~220,000~~delivery ~~Mcf~~to ~~per~~Tennessee ~~day.~~Gas ~~The~~Pipeline ~~facility~~when ~~capacity~~there ~~could~~is bespare ~~increased~~capacity ~~again,~~at ifthe ~~required,~~Auburn ~~by either adding~~ compression ~~units~~facility, or ~~increasing~~ the ~~design~~“Auburn ~~suction pressure~~CF”.

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. 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. The design suction pressure at the Auburn compression facility was reduced further from 550 psig to 450 psig in January 2025 and from 450 psig to 400 psig in December 2025. Operating at the lower design suction pressure has the benefit of reducing hydrate occurrences in the system which can pose an operational hazard. The current system capacity of the Auburn CF at this lower design pressure is approximately 127,000 Mcf per day. The facility capacity could be increased again, if required, by either adding compression units or increasing the design suction pressure.

The Auburn CF delivers processed natural gas into the Tennessee Gas Pipeline at the Shoemaker Dehy receipt meter. The Auburn GGS is connected with the adjacent Rome GGS, which allows for the receipt of additional natural gas to maximize utilization of the Auburn CF and Tennessee Gas Pipeline meter capacity.

During the years ended December 31, ~~2024~~2025 and ~~2023~~2024, the Auburn GGS delivered 3640.95 Bcf and 6636.29 Bcf respectively, of natural gas, or ~~101~~111,000 Mcf per day and ~~181~~101,000 ~~MMcf~~Mcf per day.

Gathering system revenues derived from Epsilon’s production, which have been eliminated from total gathering system revenues (“elimination entry”), amounted to $1.19 million and $1.41 million, ~~respectively,~~ for the years ended December 31, ~~2024~~2025 and ~~2023~~2024, respectively.

Proved Reserves

Per our reserve ~~report~~reports prepared by independent petroleum consultants, DeGolyer and MacNaughton and Cawley, Gillespie & Associates (Powder River Basin assets only), our estimated proved reserves as of December 31, ~~2024~~2025, are summarized in the table below. 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. 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.

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. The three wells turned online in October 2024.

● 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.


		Natural Gas		Natural Gas		Oil and Other		Total
		MMcf		Liquids MBbl		Liquids MBbl		MMcfe
Proved developed reserves		75,849		1,599		4,000		109,444
Proved undeveloped reserves		10,523		753		5,259		46,593
Total Proved Reserves at December 31, 2025		86,372		2,352		9,259		156,037

Changes in Total Proved Undeveloped Reserves
Proved undeveloped reserves at December 31, 2024		12,550		387		725		19,225
Revisions of previous estimates		(4,949)		(85)		(194)		(6,628)
Acquisitions		4,609		639		4,933		38,041
Divestitures		(1,521)		(134)		(65)		(2,715)
Transfers to proved developed		(166)		(54)		(140)		(1,330)
Proved undeveloped reserves at December 31, 2025		10,523		753		5,259		46,593

● In 2024 in the Permian Basin, the Company participated in the drilling and completion of 2 gross (0.5 net) wells. These wells went into production in Texas in May 2024 and July 2024.

●Revisions Into ~~2023~~previous inestimates ~~the~~for ~~Permian~~total ~~Basin~~proved undeveloped reserves for 2025 include reductions of 6,340 ~~The~~MMcfe ~~Company~~related ~~participated~~to inchanges to the ~~drilling~~previously adopted development plan and ~~completion~~reductions of 4269 ~~gross~~MMcfe ~~(0.7~~related ~~net)~~to ~~wells~~technical revisions and reductions of 19 MMcfe related to commodity pricing. ~~These~~Acquisitions ~~wells~~of ~~went~~38,041 ~~into~~MMcfe ~~production~~relate to reserves acquired in ~~April~~Wyoming ~~2023~~from (1the –Peak ~~New~~acquisition. ~~Mexico)~~Divestitures of 2,715 ~~May~~MMcfe ~~2023~~relate (to the selling of all interests in Oklahoma. Transfers to Proved Developed Reserves of 1,330 –MMcfe ~~New~~relates ~~Mexico)~~to ~~and~~the ~~October~~development ~~2023~~of (2wells –in ~~Texas)~~the Permian Basin.

●Our Indevelopment ~~2024~~capital inspending ~~Oklahoma,~~to ~~there~~convert ~~was~~Proved noUndeveloped ~~development~~Reserves ~~activity.~~to Proved Developed Reserves for the periods indicated is as follows:

● In ~~2023~~2025 in ~~Oklahoma~~Pennsylvania, we4 ~~completed 1~~ gross (0.~~11 net~~24) ~~well.~~wells ~~(Net~~were ~~development~~turned ~~capital~~on $line in January 2025 and 3 gross (0.~~7 million~~04). ~~The~~wells ~~well~~were turned ~~online~~on line in ~~May~~March ~~2023~~2025.

●

In 2024 in Pennsylvania, we drilled 3 gross (0.04 net) wells and participated in the completion of 10 gross (0.82 net) wells. The three wells turned on line in October 2024.

●

In 2025 in the Permian Basin, the Company participated in the drilling and completion of 1 gross (.25 net) well. This well went into production in Texas in July 2025.

●

In 2024 in the Permian Basin, the Company participated in the drilling and completion of 2 gross (0.5 net) wells. These wells went into production in May 2024 and July 2024.

●

In 2025 in Canada, we participated in the completion of 2 gross (0.5 net) wells. The two wells turned on line in March 2025.

●

In 2024 in Canada, we participated in the drilling and completion of 2 gross (0.5 net) wells. One well was put on production in September 2024. One well was deemed non-commercial.

●

In 2025 and 2024 in Oklahoma, there was no development activity. The Company sold all of its assets in Oklahoma in December 2025.

Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company’s Overall Reserve Estimation Process

Our policies regarding internal controls over reserve estimates require reserves to be prepared by an independent engineering firm under the supervision of our Chief Operating Officer, and to be in compliance with generally accepted geologic, petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The corporate staff interacts with our internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data for the reserves estimation process. We provide our engineering firm with property interests, production, capital budgets, current operating costs, current production prices and other information. This information is reviewed by our Chief Operating Officer to ensure accuracy and completeness of the data prior to submission to our independent engineering firm. Reserves are reviewed and approved internally by our Chief Operating Officer on a semi-annual basis. Our Chief Operating Officer holds a Bachelor of Science degree in Petroleum Engineering and received a Master’s Degree of Business Administration. He has over 30 years of ~~experience in upstream exploration and production, and has managed all phases of drilling, completions, production and field operations.~~

The reserve information in this report is based on estimates prepared by DeGolyer and MacNaughton, our independent petroleum consultants. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas).

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. 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.

Marketing and Major Customers

Natural gas marketing is competitive in northeast Pennsylvania because of the limited interstate transportation

~~capacity~~experience ~~and~~in ~~ample~~upstream ~~natural~~exploration ~~gas~~and ~~supply.~~production, Weand dohas ~~not~~managed ~~currently own any firm transportation on interstate pipelines that would enable us to diversify our natural gas sales to downstream locations. As a result,~~ all ofphases ~~our Pennsylvania gas sales occur in Zone 4~~ of ~~the~~drilling, ~~Tennessee Gas Pipeline at the Shoemaker Dehy meter~~completions, ~~which~~production isand ~~the~~field ~~receipt point from the Auburn CF~~operations.

The reserve information in this report is based on estimates prepared by DeGolyer and MacNaughton and Cawley, Gillespie & Associates, our independent petroleum consultants. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

The person responsible for preparing the DeGolyer and MacNaughton reserve report, Dilhan Ilk, is a Registered Professional Engineer (No.139334) in the State of Texas and a Senior Vice President of the firm. Dr. Ilk graduated from Texas A&M University with a Doctor in Philosophy degree in Petroleum Engineering, is a member of the Society of Petroleum Engineers, and has in excess of 15 years of experience in oil and gas reservoir studies and reserves evaluations.

Cawley Gillespie & Associates is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. The lead evaluator that prepared the reserve report was Zane Meekins, P.E., Executive Vice President at Cawley Gillespie.

Mr. Meekins has been with Cawley Gillespie since 1989 and graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins is a State of Texas registered professional engineer (License #71055) and a member of the Society of Petroleum Evaluation Engineers and the Society of Petroleum Engineers. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Mr. Meekins is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Marketing and Major Customers

Natural gas marketing is competitive in northeast Pennsylvania because of the limited interstate transportation capacity and ample natural gas supply. We do not currently own any firm transportation on interstate pipelines that would enable us to diversify our natural gas sales to downstream locations. As a result, all of our Pennsylvania gas sales occur in Zone 4 of the Tennessee Gas Pipeline at the Shoemaker Dehy meter, which is the receipt point from the Auburn CF.

Epsilon uses a third-party service, ARM Energy Management LLC (“ARM”) for its Pennsylvania natural gas marketing. In this capacity, ARM is responsible for carrying out marketing activities such as submission of nominations, receipt of payments, and submission of invoices.

For the year ended December 31, ~~2024~~2025, we sold natural gas through ARM to 34 unique customers. SWN Energy Services Company, LLC accounted for 10% or more of our total revenue. For the year ended December 31, ~~2023~~2024, we sold natural gas through ARM to 33 unique customers. Direct Energy Business Marketing, LLC and EQT Energy, LLC each accounted for 10% or more of our total revenue.

In Wyoming, for our operated oil and gas production, two customers accounted for 95.7% of our total revenues.

Geographic Locations of Operations

Approximately 5067% and 7750% of our revenue during fiscal years ~~2024~~2025 and ~~2023~~2024, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania. Approximately 4019% and 640% of our revenue during fiscal years ~~2024~~2025 and ~~2023~~2024, respectively, was derived from oil, natural gas, and natural gas liquids revenues in the state of Texas. ~~Epsilon’s~~In ~~management~~November ~~expects~~2025, tothe ~~continue~~Company tocompleted ~~seek~~the ~~opportunities~~acquisition of oil and gas assets in ~~other~~the ~~North~~Powder ~~American~~River ~~basins~~Basin, toWyoming ~~provide~~which ~~the~~will ~~Company~~materially increase the geographic diversification of our revenues going forward and could provide enhanced flexibility to respond to market conditions by allocating capital across multiple basins and commodities.

AsHowever, athe ~~result~~Company ofis ~~the~~still subject to geographic concentration, and we may be disproportionately exposed to the effect of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of crude oil or natural gas.

Competition

It is not uncommon in the oil and natural gas industry to experience shortages of drilling and completion rigs, equipment, pipe, services, and personnel, which can cause both delays in development drilling activities and significant cost increases. 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~~2025, we had ~~ten~~twenty-seven full-time employees (including executive officers) in ~~Houston~~Texas, ~~Texas~~Colorado, and Wyoming. 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. Advancing a safe, ethical, inclusive and diverse culture creates an environment that attracts and retains the high-performing workforce needed to successfully execute our strategy.

We continue to foster a culture that embraces inclusion and diversity and encourages collaboration. Our core values include inclusion and diversity, and we believe in equity and the value and voice of every employee.

Regulation

Environmental Regulation

Epsilon is subject to various federal, state and local laws and regulations governing the handling, management, disposal and discharge of materials into the environment or otherwise relating to the protection of human health, safety and the environment. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), or the ~~EPA,~~Bureau of Land Management (“BLM”) issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or that may result in injunctive relief for failure to comply. These laws and regulations may:

carry substantial administrative, civil and criminal penalties or that may result in injunctive relief for failure to comply. These laws and regulations may:

●

require the acquisition of various permits before drilling commences;

●

restrict the types, quantities and concentrations of various substances, including water and waste, that can be released into the environment;

●

limit or prohibit activities on lands lying within wilderness, wetlands and other protected areas; and

●

require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

Compliance with environmental laws and regulations increases Epsilon’s overall cost of business, but has not had, to date, a material adverse effect on Epsilon’s operations, financial condition or results of operations. 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. However, given that such laws and regulations are subject to change, Epsilon is unable to predict the ultimate cost of compliance or the ultimate effect on Epsilon’s operations, financial condition and results of operations.

Climate Change

There is consensus in the international scientific community that increasing concentrations of greenhouse gas emissions (“GHG”) in the atmosphere will produce changes to global, as well as local, climate. Scientists project that increased concentrations of GHGs will cause more frequent, and more powerful storms, droughts, floods and other climatic events. If such effects were to occur, our development and production operations, as well as operations of our third -party providers and customers, could be adversely affected. To date, we have not developed a comprehensive plan to address potential impacts of climate change on our operations and there can be no assurance that any such impacts would not have an adverse effect on our financial condition and results of operations.

Attempts to address GHGs, as well as climate change more generally, have taken the form of local, state, national and international proposals. Broadly speaking, examples include cap-and-trade programs, carbon tax proposals, GHG reporting and tracking programs, and regulations that directly limit GHGs from certain sources.

In the United States, federal proposals are rooted in the EPA’s “endangerment finding,” that was upheld by the Supreme Court. Simply, the EPA has concluded that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment. For example, the EPA adopted regulations that require Prevention of Significant Deterioration (“PSD”) construction under Title V operating permit reviews for GHG emissions from certain large stationary sources that constitute major sources of emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards.

Rules requiring the monitoring and reporting of GHG emissions from designated sources in the United States on an annual basis, including, oil and natural gas production facilities and processing, transmission, storage and distribution facilities, which include certain of our operations, have been adopted. The EPA has expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities.

Federal agencies also have begun directly regulating emissions of methane from natural gas operations. In 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain facilities to reduce methane gas and volatile organic compound emissions. EPA published amendments to those regulations effective September 15, 2020. However, on January 20, 2021, President Biden issued an Executive Order directing EPA to consider suspending, revising or rescinding the September 15, 2020 amendments and also to consider proposing new regulations governing methane and volatile organic compound emissions from existing oil and gas sector operations.

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.

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.

Internationally, in April 2016, the United States joined other countries in entering into a non-binding agreement in France for nations to limit their GHG emissions through country-determined reduction goals every five years beginning in 2020 (the “Paris Agreement”). Although the Trump Administration subsequently announced plans to withdraw from the Paris Agreement, on January 20, 2021, President Biden issued an Executive Order providing that he was accepting the Paris Agreement on behalf of the United States.

In addition, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations on certain sources of funding for the energy sector. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities.

Epsilon is unable to predict the timing, scope and effect of any currently proposed or future, laws, regulations or treaties regarding climate change and GHG emissions. Any limits on GHG emissions, however, could adversely affect demand for the oil and natural gas that production operators produce, some of whom are our customers, which could thereby reduce demand for our gas gathering services. 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.

treaties regarding climate change and GHG emissions. Any limits on GHG emissions, however, could adversely affect demand for the oil and natural gas that production operators produce, some of whom are our customers, which could thereby reduce demand for our gas gathering services. 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.

Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices and has finalized a study of the potential environmental impacts of hydraulic fracturing activities. In 2014, the EPA issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act of 1976 requesting comments related to disclosure for hydraulic fracturing chemicals. The Department of the Interior had released final regulations governing hydraulic fracturing on federal and Native American oil and natural gas leases which require lessees to file for approval of well stimulation work before commencement of operations and require well operators to disclose the trade names and purposes of additives used in the fracturing fluids. However, in December 2017, the ~~Bureau~~BLM ~~of Land Management~~ published a final rule rescinding the March 26, 2015 rule (“BLM 2015 Rule”), entitled “Natural gas and oil; Hydraulic Fracturing on Federal and Indian Lands.” The primary purposes of the BLM 2015 Rule were to ensure that wells were constructed so as to protect water supplies, to ensure environmentally responsible management of fluids displaced by fracturing, and to provide public disclosure of chemicals used in fracturing operations. The net effect of the December 2017 rule making is to return the affected sections of the Code of Federal Regulations to the language that existed before the BLM’s 2015 Rule. In addition, legislation has from time to time been introduced, but not adopted, in Congress to provide for additional federal regulation of hydraulic fracturing and to require additional disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances.

Epsilon is unable to predict the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing in the United States, but there can be no assurance that the direct and indirect costs of such laws and regulations (if enacted) would not materially and adversely affect Epsilon’s operations, financial condition and results of operations.

Gathering System Regulation

Regulation of gathering facilities may affect certain aspects of Epsilon’s business and the market for Epsilon’s services. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily the Federal Energy Regulatory Commission, or the FERC. The FERC regulates interstate natural gas transportation rates, terms and conditions of service, which affects the marketing of natural gas produced by Epsilon, as well as the revenues received for sales of Epsilon’s natural gas.

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. In certain limited circumstances, intrastate transportation, gathering, and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the U.S. Congress and by FERC regulations.

Market for Our Common Equity and Related Stockholder Matters

Market Information. Commencing on February 19, 2019, the common shares of the Company trade on the NASDAQ Global Market with the ticker symbol ‘‘EPSN.’’ The last reported sales price of our common shares on the NASDAQ Global Market on March 23, 2026 was $6.00 per share.

Shareholders. We had approximately 2,000 shareholders of record as of March 1, 2026.

Natural Gas Act, or the NGA, and by regulations and orders promulgated under the NGA by the FERC. In certain limited circumstances, intrastate transportation, gathering, and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the U.S. Congress and by FERC regulations.

~~Market~~Dividends. ~~for~~Epsilon ~~Our~~made ~~Common~~aggregate ~~Equity~~quarterly distributions of $6.0 million ($0.25 per share) during the year ended December 31, 2025. The dividend is well supported and ~~Related~~the ~~Stockholder~~Company ~~Matters~~intends to maintain it going forward, subject to quarterly approval by the Board.

Market Information. 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. 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.

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~~781,~~970~~792	$	5.7715	~~676~~140,~~337~~637

At December 31, ~~2024~~2025, under the 2020 Equity Incentive Plan (the “2020 Plan”) (See Note 7, “Shareholders’ Equity” of the Notes to the Consolidated Financial Statements), we are authorized to issue 2,000,000 common shares to employees and directors of the Company. As of that date, we had 1,~~323~~859,~~663~~363 common shares granted under the 2020 Plan.

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, 2025					December 31, 2024
				Weighted					Weighted
		Number of		Average			Number of		Average
		Shares		Grant Date			Shares		Grant Date
		Outstanding		Market Price			Outstanding		Market Price
Balance non-vested Restricted Stock at beginning of period		560,970		$	5.77		491,536		$	6.00
Granted		488,283			4.77		300,052			5.97
Vested		(267,461)			5.60		(230,618)			5.65
Balance non-vested Restricted Stock at end of period		781,792		$	5.15		560,970		$	5.77


	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

Recent ~~For the years ended December 31, 2024 and 2023, we had no warrants or other common share related rights outstanding.~~Developments

15Business Combination

On November 14, 2025, Epsilon acquired Peak Exploration & Production LLC and Peak BLM Lease LLC and their subsidiaries (together, “Peak”) for total consideration of $88.5 million consisting of 1) issuance of 5,681,489 common shares valued at $27.6 million, 2) contingent consideration of up to 2,500,000 common shares valued at $10.6 million, and the settlement of $50.3 million of debt. The contingent consideration was settled on November 19, 2025, through the issuance of 2,234,847 common shares for $10.6 million. The acquired assets primarily include operated and non-operated production and leasehold interests in the core of the Powder River Basin in Wyoming. The acquired Proved Reserves include 16.8 Bcf of natural gas, 8.2 MMBbls of oil, and 2.0 MMBbls of natural gas liquids, according to the report by Cawley Gillespie & Associates as of December 31, 2025. As part of the acquisition, the Company added 17 full-time employees from Peak.

The ~~following~~results ~~table sets out the number~~ of ~~time~~operations ~~restricted~~attributable ~~common shares available~~ to ~~be issued upon vesting over~~ the ~~next~~Peak ~~three~~acquisition ~~years~~have ~~and~~been ~~the~~included ~~changes~~in ~~during~~ the ~~year~~Company’s ~~pursuant~~consolidated tofinancial ~~our~~statements ~~share~~as ~~compensation~~of ~~plans and~~ the ~~weighted~~closing ~~average market price at~~ date of ~~issue for outstanding shares for~~ the ~~periods indicated:~~acquisition.


	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~~Asset ~~Developments~~Sale

None.

On December 11, 2025, Epsilon divested Dewey Energy Holdings, LLC, a wholly owned subsidiary of the Company to an undisclosed private buyer for $2.5 million. The assets sold included approximately 964 Mcfe/d (60% natural gas) of production (Q4 2025 figure) and approximately 6,400 net deep acres and 2,200 net shallow acres of leasehold, all located in Dewey County, Oklahoma.

Credit Facility

On October 10, 2025, the Company closed a new senior secured reserve based revolving credit facility with Frost Bank as administrative agent and Frost Bank and Texas Capital Bank as lenders. 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.

ITEM 1A. RISK FACTORS.

You should carefully consider the risks and uncertainties described below, together with all of the other information and risks included in, or incorporated by reference into this report, including our consolidated financial statements and the related notes thereto, before making any financial decisions relating to Epsilon.

Risks Related to Oil and Natural Gas Reserves

Our business is dependent on oil and natural gas prices, and any fluctuations or decreases in such prices could adversely affect our results of operations and financial condition.

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

16Substantial 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. To the extent commodity prices received from production are insufficient to fund planned capital expenditures, spending will be required to be reduced, assets could be sold or funds may be borrowed to fund any such shortfall.

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

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Our long term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, any existing reserves that we may have at any particular time and the production from those reserves will decline over time as those reserves are exploited. A future increase in our reserves will depend not only on our ability to explore and develop any properties we may have from time to time, but also on our ability to select and acquire suitable producing properties or

~~Substantial~~prospects. ~~and~~We ~~extended~~cannot ~~declines~~assure inyou ~~oil~~that ~~and~~we ~~natural~~will ~~gas~~be ~~prices~~able ~~may~~to ~~result~~locate inand ~~impairments~~continue ofto ~~proved~~locate ~~natural~~satisfactory ~~gas~~properties ~~and~~for ~~oil~~acquisition ~~properties~~ or ~~undeveloped~~participation. ~~acreage~~Moreover, ~~and~~if ~~may~~we ~~materially~~do ~~and~~identify ~~adversely~~such ~~affect~~acquisitions ~~our~~or ~~future business~~participations, ~~financial~~we ~~condition,~~may ~~cash~~determine ~~flows,~~that ~~results~~current ~~of operations~~markets, ~~liquidity~~terms orof ~~ability~~acquisition toand ~~finance~~participation ~~planned~~or ~~capital~~pricing ~~expenditures.~~conditions Tomake ~~the~~such ~~extent~~acquisitions ~~commodity~~or ~~prices~~participations ~~received~~uneconomic. ~~from~~We ~~production~~cannot ~~are~~assure ~~insufficient~~you tothat ~~fund~~we ~~planned capital expenditures, spending~~ will bediscover ~~required to be reduced, assets could be sold~~ or ~~funds~~acquire ~~may~~further becommercial ~~borrowed~~quantities toof ~~fund~~oil ~~any~~and ~~such~~natural ~~shortfall~~gas.

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

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

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not ensure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or in personal injury. In accordance with industry practice, we are not fully insured against all of these risks, nor are all such risks insurable. Although we maintain liability insurance in an amount that we consider consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect upon our financial condition. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations, and the loss of the ability to use hydraulic fracturing (see risk factor regarding government legislation). Losses resulting from the occurrence of any of these risks could have a material adverse effect on our future results of operations, liquidity and financial condition.

Our reserve estimates may be inaccurate, and future net cash flows as well as our ability to replace any reserves are uncertain.

There are numerous uncertainties inherent in estimating quantities of oil and natural gas reserves and cash flows to be derived therefrom, including many factors beyond our control. The reserve and associated cash flow information set forth herein represents estimates only. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions such as historical oil and natural gas prices, production levels, capital expenditures, operating and development costs, the effects of regulation, the accuracy and reliability of the underlying engineering and geologic data, and the availability of funds; all of which may vary from actual results. 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. 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.

17In accordance with applicable securities laws, the technical report on our oil and natural gas reserves prepared by DeGolyer and MacNaughton, independent petroleum consultants, as of December 31, 2025 and 2024 (“DeGolyer Reserve Report”), and the report by Cawley, Gillespie & Associates as of December 31, 2025 (“CGA Reserve Report”), used SEC guideline prices and cost estimates in calculating net cash flows from oil and natural gas reserve quantities included within the report. Actual future net revenue will be affected by other factors such as actual commodity prices, production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs. Actual production and revenues derived therefrom will vary from the estimates contained in the DeGolyer Reserve Report and CGA Reserve Report, and such variations could be material. The DeGolyer Reserve Report and the CGA Reserve Report are based in part on the assumed success of activities that we intend to undertake in future years. The oil and natural gas reserves and estimated cash flows to be derived therefrom contained in these reserve reports will be reduced to the extent that such activities do not achieve the level of success assumed in these reserve reports.

may vary. 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.

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. Actual future net revenue will be affected by other factors such as actual commodity prices, production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs. Actual production and revenues derived therefrom will vary from the estimates contained in the DeGolyer Reserve Report, and such variations could be material. The DeGolyer Reserve Report is based in part on the assumed success of activities that we intend to undertake in future years. The oil and natural gas reserves and estimated cash flows to be derived therefrom contained in the DeGolyer Reserve Report will be reduced to the extent that such activities do not achieve the level of success assumed in the DeGolyer Reserve Report.

Our future oil and natural gas reserves, production, and derived cash flows are highly dependent on our successfully acquiring or discovering and developing new reserves. Without the continual addition of new reserves, any of our existing reserves and their production will decline as such reserves are exploited. A future increase in our reserves will depend not only on our ability to develop any properties we may have from time to time, but also on our ability to select and acquire suitable producing properties or prospects. There can be no assurance that our future exploration and development efforts will result in the discovery and development of additional commercial accumulations of oil and natural gas.

Risks Related to Stage of Development, Structure and Capital Resources

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

Operations could also be adversely affected by general economic downturns or limitations on spending. An economic downturn and uncertainty may have a negative impact on our business. During ~~2024~~2025 and ~~2023~~2024, there was tremendous volatility in prices and available financing for oil and gas projects. There can be no assurance that we will be able to access capital markets to provide funding for future operations that would require additional capital beyond our current existing available capital on terms acceptable to us.

Substantial capital, which may not be available to us in the future, is required to replace and grow reserves.

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

Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times. From time to time, we may require additional financing in order to carry out our oil and natural gas acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause us to forfeit our interest in certain properties, miss certain acquisition opportunities, or reduce or terminate our operations. If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our production. 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.

18The borrowing base under our credit facility may be reduced in light of commodity price declines or reserve changes, which could limit us in the future.

Lower commodity volumes and prices may reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of our lenders primarily based on the collateral value of our Proved Developed Reserves that have been mortgaged to the lenders, and is subject to semiannual redeterminations. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding.

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.

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

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

The terms of our revolving credit facility may restrict our operations, particularly our ability to respond to changes or to take certain actions.

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

In addition, the restrictive covenants in our revolving credit facility require us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we may be unable to meet them.

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

Depending on forces outside our control, we may need to allocate our available capital in ways that we did not anticipate.

Because of the volatile nature of the oil and natural gas industry, we regularly review our budgets in light of past results and future opportunities that may become available to us. In addition, our ability to carry out operations may depend upon the decisions of other working interest owners in our properties. Accordingly, while we anticipate that we will have the ability to spend the funds available to us, there may be circumstances where, for sound business reasons, a reallocation of funds may be prudent.

We may issue debt to acquire assets or for working capital.

From time to time, we may enter into transactions to acquire assets or shares of other companies. These transactions may be financed partially or wholly with debt, which may increase our debt levels. Depending on future exploration and development plans, we may require additional equity and/or debt financing that may not be available or, if available, may not be available on favorable terms. Neither our articles of incorporation nor our by-laws limit the amount of indebtedness that we may incur. The level of our indebtedness, from time to time, could impair our ability to obtain additional financing in the future on a timely basis to take advantage of business opportunities that may arise.

Our potential lenders will likely require security over substantially all of our assets. 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.

Future equity transactions could result in dilution to existing stockholders.

We may make future acquisitions or enter into financing or other transactions involving the issuance of securities, which may be dilutive to existing security holders.

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.

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to us and our third-party operating partners and may delay exploration and development activities. Past industry conditions have led to periods of extreme shortages of drilling equipment in certain areas of the United States. On the oil and natural gas properties that we do not operate, we will be ~~dependent on such operators for the timing of activities related to such properties and may be largely unable to direct or control the activities of the operators.~~

dependent on such operators for the timing of activities related to such properties and may be largely unable to direct or control the activities of the operators.

Results of our drilling are uncertain, and we may not be able to generate high returns.

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

Extensive government legislation and regulatory initiatives could increase costs and impose burdensome operating restrictions that may cause operational delays.

Hydraulic fracturing, which involves the injection of water, sand and chemicals under pressure into deep rock formations to stimulate oil or natural gas production, is often used in the completion of unconventional oil and natural gas wells. Currently, hydraulic fracturing is primarily regulated in the United States at the state level, which generally focuses on regulation of well design, pressure testing, and other operating practices.

However, some states and local jurisdictions across the United States, such as the State of New York, have begun adopting more restrictive regulation. Some members of the U.S. Congress and the EPA are studying environmental contamination related to hydraulic fracturing and the impact of fracturing on public health. In March 2015, the U.S. Congress introduced legislation to regulate hydraulic fracturing and require disclosure of the chemicals used in the hydraulic fracturing process, and may implement more stringent regulations in the future. Additionally, some states, such as the State of New York, have adopted, and others are considering, regulations that could restrict hydraulic fracturing. The ultimate status of such regulation is currently unknown. Any federal or state legislative or regulatory changes with respect to hydraulic fracturing could cause us to incur substantial compliance costs or result in operational delays, and the consequences of any failure to comply by us or our third-party operating partners could have a material adverse effect on our financial condition and results of operations.

Our corporate structure could result in incremental tax burden in certain circumstances.

Epsilon Energy Ltd. is an Alberta company. Epsilon Energy USA Inc. (Ohio corporation) may be a U.S. real property holding corporation (a “USRPHC”) for U.S. federal income tax purposes if it is determined, at any time, that the fair market value of its assets that consist of “United States real property interests,” as defined in the Internal Revenue Code, and applicable Treasury regulations, constitute at least 50% of the combined fair market value of our real property interests and other business assets. If Epsilon Energy USA Inc. were a USRPHC, then Epsilon Energy Ltd.’s investment in Epsilon Energy USA Inc. would be a United States Real Property Interest (USRPI) for US federal tax purposes. 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. 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.

20Our operations are currently geographically concentrated and therefore subject to regional economic, regulatory and capacity risks.

Approximately 67% and 50% of our revenue during fiscal years 2025 and 2024, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania. Approximately 19% and 40% of our revenue during fiscal years 2025 and 2024, respectively, was derived from oil, natural gas, and natural gas liquids revenues in the state of Texas. In November 2025, the Company completed the acquisition of oil and gas assets in the Powder River Basin, Wyoming which could provide the Company the enhanced flexibility to respond to market conditions by allocating capital across multiple basins and commodities.

However, the Company is still subject to geographic concentration and we may be disproportionately exposed to the effect of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by

~~Epsilon~~governmental ~~Energy~~regulation, ~~Ltd.~~processing ~~Distributions~~or ~~made~~transportation ~~out~~capacity ofconstraints, ~~earnings~~market ~~and~~limitations, ~~profits~~weather ~~are~~events ~~not~~or ~~expected~~interruption toof ~~be subject to~~ the ~~FIRPTA~~processing ~~tax~~or ~~but~~transportation ~~are~~of ~~subject~~crude tooil ~~U.S.~~or ~~withholding~~natural ~~tax~~gas.

Our operations are currently geographically concentrated and therefore subject to regional economic, regulatory and capacity risks.

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. 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.

As a result of this geographic concentration, we may be disproportionately exposed to the effect of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of crude oil or natural gas.

Delays in business operations may reduce cash flows and subject us to credit risks.

In addition to the usual delays in payments by purchasers of oil and natural gas to us or to the operators, and the delays by operators in remitting payment to us, payments from these parties may be delayed by restrictions imposed by lenders, accounting delays, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, adjustment for prior periods, or recovery by the operator of expenses incurred in the operation of the properties. In addition, the transition of one operator to another as the result of an operator being bought or sold could cause additional operational delays beyond our control. Any of these delays could reduce the amount of cash flow available for our business in a given period and expose us to additional third-party credit risks.

We depend on the successful acquisition, exploration and development of oil and natural gas properties to develop any future reserves and grow production and revenue in the future, and assessments of our assets may be subject to uncertainty.

Acquisitions of oil and natural gas companies and oil and natural gas assets are typically based on engineering and economic assessments made by independent engineers and our own assessments. These assessments will include a series of assumptions regarding such factors as recoverability and marketability of oil and natural gas, future prices of oil and natural gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. In particular, the prices of, and markets for, oil and natural gas products may change from those anticipated at the time of making such assessment. In addition, all such assessments involve a measure of geologic and engineering uncertainty which could result in lower production and reserves than anticipated. Initial assessments of acquisitions may be based on analysis by our internal engineers or reports by a firm of independent engineers that are not the same as the firm that we use for our year-end reserve evaluations. Because each of these firms may have different evaluation methods and approaches, these initial assessments may differ significantly from the assessments of the firm that we use.

We depend on third-party operators and our key personnel, and competition for experienced technical personnel may negatively affect our operations.

Approximately 9950% of our oil and natural gas properties are operated by third-party operators. As such, we will be dependent on such operators for the timing of activities related to such properties and will largely be unable to direct or control the activities of the operators. The objectives and strategy of those operators may not always be consistent with ours, and we have a limited ability to exercise influence over, and control the risks associated with, operations of these properties. 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.

21Our success will depend in large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse effect on us. We do not have key person insurance in effect for management. The contributions of these individuals to our immediate operations are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is intense, and there can be no assurance that we will be able to continue to attract and retain all personnel necessary for the development and operation of our business. Certain of our directors are also directors of other companies and as such may, in certain circumstances, have a conflict of interest requiring them to abstain from certain decisions. Conflicts, if any, will be subject to the procedures and remedies of the Conflicts Committee of our board of directors.

Our leasehold interests are subject to termination or expiration under certain conditions.

Our properties are held in the form of leases and working interests in leases, collectively referred to as “leasehold interests.” If we or our joint venture partner fails to meet the specific requirement(s) of a particular leasehold interest, the leasehold interest may terminate or expire. There can be no assurance that any of the obligations required to maintain each

Inleasehold ~~addition~~interest ~~to the operator, our success~~ will ~~depend~~be ~~in large measure on certain key personnel~~met. The ~~loss~~termination ofor ~~the~~expiration ~~services~~ of ~~such~~a ~~key~~particular ~~personnel~~leasehold ~~could~~interest may 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~~financial ~~operations~~condition ~~are likely to be of central importance. In addition, the competition for qualified personnel in the oil~~ and ~~natural~~results ~~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~~operations. Certain of our directors are also directors of other companies and as such may, in certain circumstances, have a conflict of interest requiring them to abstain from certain decisions. Conflicts, if any, will be subject to the procedures and remedies of the Conflicts Committee of our board of directors.

Our leasehold interests are subject to termination or expiration under certain conditions.

Our properties are held in the form of leases and working interests in leases, collectively referred to as “leasehold interests.” If we or our joint venture partner fails to meet the specific requirement(s) of a particular leasehold interest, the leasehold interest may terminate or expire. There can be no assurance that any of the obligations required to maintain each leasehold interest will be met. The termination or expiration of a particular leasehold interest may have a material adverse effect on our financial condition and results of operations.

We may incur losses as a result of title deficiencies.

Although title reviews will be done according to industry standards before the purchase of most oil and natural gas-producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat our claim, which could result in a reduction in our ownership interest or of the revenue that we receive.

We may be exposed to third-party credit risk, and defaults by third parties could adversely affect us.

We are or may be exposed to third-party credit risk through our contractual arrangements with current or future joint venture partners, marketers of our petroleum and natural gas production, derivative counterparties and other parties. In the event such entities fail to meet their contractual obligations to us, such failures could have a material adverse effect on us and our cash flow from operations.

We may not be insured against all of the operating risks to which we are exposed.

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

Risks Related to Commodity Prices, Hedging and Marketing

Natural gas and oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse effect on our business.

Our revenues, profitability and future growth and the carrying value of our oil and natural gas properties are substantially dependent on prevailing prices of oil and natural gas. Our ability to borrow and to obtain additional capital on attractive terms is also substantially dependent upon oil and natural gas prices. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control. These factors include economic conditions in the United States, the Middle East and elsewhere in the world; the actions of OPEC; governmental regulation; political stability in the Middle East and elsewhere; the foreign supply of oil and natural gas; the price of foreign imports; and the availability of alternative fuel sources. 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. 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.

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. 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.

Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

In addition, bank borrowings that may be available to us are in part determined by our borrowing base. A sustained material decline in prices from historical average prices could reduce our borrowing base, thereby reducing the bank credit available to us, which could require that a portion, or all, of our bank debt be repaid.

Hedging transactions may limit our potential gains or cause us to lose money.

From time to time, we may enter into agreements to receive fixed prices on our oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, we will not benefit from such increases.

We are exposed to risks of loss in the event of nonperformance by our counterparties to our hedging arrangements. Some of our counterparties may be highly leveraged and subject to their own operating and regulatory risks. Despite our analysis, we may experience financial losses in our dealings with these and other parties with whom we enter into transactions as a normal part of our business activities. Any nonpayment or nonperformance by our counterparties could have a material adverse effect on our business, financial condition and results of operations.

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

Market conditions or operation impediments may hinder our access to natural gas and oil markets or delay our production.

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

We depend upon two significant purchasers for the sale of most of our oil and natural gas production in Wyoming. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.

For year ended December 31, 2025, HF Sinclair Refining & Marketing LLC and WGR Operating, LP accounted for approximately 68.4% and 27.3% of our total revenues in Wyoming, respectively, excluding the impact of our commodity derivatives. No other purchaser accounted for more than 10% of our revenue during such periods. We do not have long term contracts with our purchasers but rather we sell the substantial majority of our production under arm’s length contracts with terms of 12 months or less, potentially including on a month-to-month basis, to a relatively small number of purchasers. We do not believe that the loss of a single purchaser would materially affect our business because there are numerous other potential purchasers in the area in which we sell our production. However, the loss of any one of these significant purchasers, our ability to sell our production to other purchasers on terms we consider acceptable, the inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation could have a short term impact on our financial condition and results of operations. We cannot assure you that any of our purchasers will continue to do business with us or that we will continue to have ready access to suitable markets for our future production.

Investor sentiment towards climate change, fossil fuels, and sustainability could adversely affect our business and our share price.

There have been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to promote the divestment of shares of energy companies, as well as to pressure lenders and other financial services companies to limit or curtail activities with energy companies. If these efforts are successful, our stock price and our ability to access capital markets may be negatively impacted.

Members of the investment community are also increasing their focus on sustainability practices, including practices related to GHGs and climate change, in the energy industry. As a result, we may face increasing pressure regarding our sustainability disclosures and practices. Additionally, members of the investment community may screen companies such as ours for sustainability performance before investing in our shares.

2324

We are subject to complex laws and regulations, including environmental regulations that can have a material adverse effect on the cost, manner and feasibility of doing business.

Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels of government that may be amended from time to time. Our operations may require licenses and permits from various governmental authorities. There can be no assurance that we will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development at our projects. It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and natural gas companies of similar size.

In Wyoming, we conduct oil and natural gas exploration, development and production activities on federal lands, including lands administered by the BLM and in some cases, United States Forest Service. Operations on federal lands are frequently subject to permitting delays. Operations on these lands are also subject to the National Environmental Policy Act ("NEPA”) which requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. While the Company currently has exploration, development and production activities on federal lands, our proposed exploration, development and production activities are expected to include federal mineral interests, which will require the acquisition of governmental permits or authorizations that are subject to the procedural requirements of NEPA. This process has the potential to delay, limit, or increase the cost of the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in Environmental Assessments or Environmental Impact Statements, they could incur added costs, which may be substantial.

Environmental and health and safety risks may adversely affect our business.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills and releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. Although we believe that we are in material compliance with current applicable environmental regulations, we cannot assure you that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect our financial condition, results of operations or prospects.

We must also conduct our operations in accordance with various laws and regulations concerning occupational safety and health. Currently, we do not foresee expending material amounts to comply with these occupational safety and health laws and regulations. However, since such laws and regulations are frequently changed, we are unable to predict the future effect of these laws and regulations.

Risks Related to Cybersecurity

We may be subject to interruptions or failures in our information technology systems.

We rely on sophisticated information technology systems and infrastructure to support our business, including process control technology. Any of these systems are susceptible to outages due to fire, floods, power loss, telecommunications failures, usage errors by employees, computer viruses, cyberattacks or other security breaches or similar events. The failure of any of our information technology systems may cause disruptions in our operations, which could adversely affect our revenue and profitability.

~~We are subject to cybersecurity risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.~~25

~~damage~~We ~~that~~are ~~adversely~~subject affects customer or investor confidence; (vii) the loss, theft, corruption or unauthorized release of intellectual property, proprietary information, customer and vendor data or other critical data and (viii) damage to ~~the~~cybersecurity ~~Company’s competitiveness, stock price, and long-term stockholder value~~risks. ~~Certain~~A cyber ~~incidents,~~incident ~~such~~could asoccur ~~surveillance,~~and ~~may~~result ~~remain~~in ~~undetected~~information ~~for~~theft, andata ~~extended period of time. As the sophistication of cyber incidents continues to evolve~~corruption, weoperational ~~will~~disruption ~~likely be required to expend additional resources to continue to modify~~ and/or ~~enhance~~financial ~~our protective measures or to investigate and remediate any vulnerability to cyber incidents~~loss. ~~Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.~~

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

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.

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, orand our annual revenue is more than $100 million during the most recently completed fiscal year and our voting and non-voting common shares held by non-affiliates is more than $700 million measured on the last business day of our second fiscal quarter. 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.

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. If 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.

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 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 maintain effective controls, investors may lose confidence in our operating results, the price of our common shares could decline and we may be subject to litigation or regulatory enforcement actions.

~~Risks Related to Gathering System~~26

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

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

~~have~~Risks anRelated ~~adverse~~to ~~effect~~Gathering ~~on our business, results of operations, financial position and cash flows. Although gross throughput at the Auburn CF has declined from 2018-2024, the share of Anchor Shipper gas has increased.~~System

Because of the ~~large~~natural ~~supply~~decline ofin ~~gas,~~production ~~and~~from ~~limited~~existing ~~availability~~wells, ofour ~~transportation~~success ~~out~~depends ofon the ~~Marcellus~~Anchor ~~Shale~~Shippers’ ~~area,~~economically ~~our~~developing ~~gas~~the isremaining ~~subject~~Marcellus toShale areserves ~~price~~in ~~differential~~Pennsylvania.

~~Differential~~Our isnatural angas ~~energy~~gathering ~~industry~~system ~~term~~is ~~that~~dependent ~~refers~~upon to the ~~discount~~level orof ~~premium~~production ~~received~~from ~~for~~natural ~~the~~gas ~~sale~~wells, offrom awhich ~~petroleum~~production ~~product~~will atnaturally adecline ~~specific~~over ~~location~~time. ~~relative~~In order to amaintain ~~nationally~~or ~~recognized~~increase ~~sales~~throughput ~~hub.~~levels Inon ~~the~~our ~~Marcellus~~gathering ~~Shale~~system and compression facility, ~~natural~~we ~~gas~~must iscontinually ~~significantly~~develop ~~discounted~~reserves towithin ~~Henry~~the ~~Hub~~Auburn ~~pricing~~GGS ~~and~~boundary ~~the~~or ~~size~~obtain ofnew ~~the~~supplies ~~differential~~external ~~can~~to bethe ~~volatile~~Auburn GGS boundary. ~~Many~~Developing ~~factors~~reserves ~~influence~~within the ~~size~~system ~~and~~boundary ~~duration~~is ofthe ~~differentials~~priority ~~including~~as ~~local~~external ~~supply~~natural /gas ~~demand~~volumes ~~imbalances,~~have ~~seasonal~~a ~~fluctuations~~contractual ingathering ~~demand,~~rate ~~transportation~~that ~~availability~~is ~~and~~25% ~~cost,~~of asthe ~~well~~Anchor asShipper ~~the~~rate. ~~regulatory~~The ~~environment~~primary asfactors itaffecting ~~pertains~~our ability to ~~constructing~~obtain new ~~transportation~~supplies ~~pipelines.~~of Innatural ~~Northeast~~gas ~~Pennsylvania,~~is ~~negative~~the ~~differentials~~level ~~have~~of ~~persisted~~successful ~~for~~drilling ~~many years~~activity ~~due~~from tothe ~~rapid~~Anchor ~~increases~~Shippers, inof ~~supply~~which asEpsilon ais ~~result~~one, ofas ~~advances~~well inas ~~well~~our ~~completion~~ability ~~techniques.~~to ~~Despite~~compete ~~substantial~~for ~~increases~~volumes infrom ~~local~~successful ~~demand~~new ~~for~~wells ~~natural~~drilled ~~gas~~by ~~coupled~~third ~~with~~parties ~~pipeline~~proximate ~~expansions,~~to ~~optimizations,~~our ~~and~~system. ~~new~~If ~~pipelines~~we ~~that~~are ~~have~~not ~~been~~able ~~brought~~to ~~into~~obtain ~~service,~~new ~~the~~supplies of natural gas ~~differential~~to inreplace ~~Northeast~~the ~~Pennsylvania~~natural ~~remains~~decline ~~significant.~~in ~~There~~volumes isfrom noexisting ~~guarantee~~wells, ~~that~~throughput ~~future~~on ~~demand~~our orpipelines ~~pipeline~~and ~~transportation~~the ~~projects~~utilization ~~will~~rates ~~eliminate~~of ~~this~~our ~~differential,~~compression ~~and~~facility itwould ~~will~~decline, ~~therefore~~which ~~remain~~could ahave ~~significant~~an ~~risk~~adverse toeffect ~~demand for transportation service~~ on ~~the~~our ~~Auburn GGS~~business, ~~and~~results ~~therefore~~of ~~Epsilon’s~~operations, ~~revenues~~financial position and cash flows.

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

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

We compete with other operators in our gas gathering energy businesses.

Although the Anchor Shippers have dedicated their acreage and reserves to the Auburn GGS, the Auburn GGS may not be chosen by other producers in these areas to gather and compress the natural gas extracted. We compete with other companies, including co-owners of the Auburn GGS who operate other systems, for any such production from non-Anchor Shippers on the basis of many factors, including but not limited to geographic proximity to the production, costs of connection, available capacity, rates and access to markets. Competition in natural gas gathering is based in large part on existing assets, reputation, efficiency, system reliability, gathering system capacity and pricing arrangements. Our key competitors in the natural gas gathering business include independent gas gatherers and major integrated energy companies. Alternate gathering facilities are available to non-Anchor Shippers we serve, and those producers may also elect to construct proprietary gas gathering systems. A significant increase in competition in the gas gathering industry could have a material adverse effect on our financial position, results of operations and cash flows.

Several of our assets that have been in service for many years may require significant expenditures to maintain them. As a result, our maintenance or repair costs may increase in the future.

Our gathering lines and compression facility are generally long-lived assets, and many of such assets have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our gathering rate and competitive position.

~~We are exposed to the credit risk of our customers and counterparties, and our credit risk management will not be able to completely eliminate such risk.~~27

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

doWe ~~not take or~~ are ~~unable~~exposed to ~~take~~the ~~sufficient~~credit ~~mitigating~~risk ~~actions,~~of ~~including~~our ~~obtaining~~customers ~~sufficient~~and ~~collateral~~counterparties, ~~deterioration in their creditworthiness,~~ and ~~any~~our ~~resulting~~credit ~~increase~~risk inmanagement ~~nonpayment~~will ~~and/or~~not ~~nonperformance~~be byable ~~them could cause us~~ to ~~write~~completely ~~down~~eliminate orsuch ~~write off accounts receivable~~risk. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows, and financial condition.

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

~~Our~~Prices ~~revenues,~~for ~~operating results, and future rate of growth depend primarily upon the price of~~ natural gas in ~~Northeast~~northeast Pennsylvania ~~which~~are ~~is currently~~ volatile and ~~significantly~~are ~~discounted~~subject to ~~natural~~significant ~~gas~~discounts from pricing at Henry Hub ~~due to insufficient interstate pipeline capacity out of the region~~. This ~~volatility~~discount and ~~discount~~volatility has ~~adversely impacted reserve development in the past,~~ and could docontinue ~~so again in the future. A slowing pace of or complete halt~~ to ~~the~~adversely ~~development~~affect ~~of Anchor Shipper reserves will impact~~ our financial results, cash flows, ~~and~~ access to capital and ability to maintain our existing businesses.

Our revenues, operating results, and future rate of growth depend primarily upon the price of natural gas in northeast Pennsylvania which is currently volatile and significantly discounted to natural gas at Henry Hub due to insufficient interstate pipeline capacity out of the region. 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.

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. 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. 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. 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. A failure to obtain access to sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Our operations are subject to operational hazards and unforeseen interruptions.

There are operational risks associated with gathering and compression of natural gas, including:

●

Hurricanes, tornadoes, floods, extreme weather conditions and other natural disasters;

●

Aging infrastructure and mechanical problems;

●

Damages to pipelines and pipeline blockages or other pipeline interruptions;

●

Uncontrolled releases of natural gas, brine, or industrial chemicals;

●

Operator error;

●

Damage caused by third-party activity, such as operation of construction equipment;

●

Pollution and other environmental risks;

●

Fires, explosions, craterings, and blowouts; and

●

Terrorist attacks on our facilities or those of other energy companies.

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. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of our precautions, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers.

27Risks Related to Our Business Combination

We may be unable to successfully integrate acquired businesses, which could adversely affect our operations and financial results. The success of the acquisition depends, in part, on our ability to realize anticipated synergies and integrate the acquired assets, personnel and systems with those of the Company. Integration efforts may be complex, time-consuming, and costly, and may include consolidating systems, aligning accounting processes, retaining key personnel, and harmonizing corporate cultures.

We may encounter difficulties in integrating information technology systems, internal controls over financial reporting, and operational processes, which could result in delays, increased expenses, or disruptions to our business. In addition, we may fail to retain key employees, customers, or suppliers of the acquired business. If we are unable to successfully integrate acquired businesses or achieve expected synergies within anticipated timeframes, our financial condition, results of operations, and cash flows could be materially adversely affected.

to be appropriate. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of our precautions, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 1C. CYBERSECURITY

Risk Management and Strategy

The Company considers cybersecurity risks as part of our overall risk management process. The management team works closely with our IT consultants and IT auditors to ensure potential risks are mitigated within our systems.

The Company engages a third-party IT consulting firm and conducts an annual IT audit to test our risk management processes.

The Company, together with our IT consultants and auditors, has processes that thoroughly vet third-party service providers, continuously monitoring to ensure compliance with our cybersecurity standards.

The Company has not encountered cybersecurity threats that have materially impacted our business or operations.

Governance

The Company’s Board of Directors is aware of the impact of potential cybersecurity threats and stays in close contact with management in case a threat is identified.

The Audit Committee of the Board of Directors is the primary governing body that is tasked with the evaluation and confirmation of the Company’s cybersecurity threat mitigation processes. More specifically, they review the Company’s annual IT audits and discuss any potential threats in quarterly meetings.

The Chief Financial Officer, Chief Operating Officer, Controller, Senior Vice Presidents and Director – Finance are all involved in communications with our IT consultants and auditors. The Chief Financial Officer notifies the Audit Committee and Chief Executive Officer of any cybersecurity threats.

ITEM 2. PROPERTIES.

The information required by Item 2 is contained in ‘‘Item 1. Business – Properties.’’

ITEM 3. LEGAL PROCEEDINGS.

~~Not~~In ~~applicable~~2025, Peak Powder River Resources LLC (“PPRR”), a Subsidiary of Peak Exploration & Production LLC (“Peak E&P”) filed a lawsuit against a contractor regarding alleged non-performance while running casing in a well in Wyoming. The Company is seeking damages due to its inability to complete the Leavitt Fed 2-9-4MH well. PPRR is in the process of scheduling arbitration

PPRR and Peak Powder River Acquisitions (“PPRA”), a subsidiary of Peak BLM Lease LLC (Peak BLM”), has intervened as a defendant-intervenor in litigation challenging BLM’s issuance of federal oil and gas leases acquired by the Company in 2017, 2018, and 2020. Plaintiffs allege deficiencies in BLM’s environmental review under NEPA. The Company intervened to protect its leasehold interests. Management does not believe the outcome will have a material adverse effect on the Company’s financial position.

Between September 30, 2025 and October 28, 2025, we received multiple demand letters on behalf of purported Epsilon stockholders (the “Demands”). The Demands primarily alleged that the Preliminary Proxy Statement filed on September 19, 2025 or the Definitive Proxy Statement filed on October 10, 2025, as applicable, failed to disclose certain material information with respect to the acquisition of Peak Exploration and Production, LLC, and Peak BLM Lease LLC.

On October 16, 2025, we received a copy of a complaint filed against Epsilon and certain members of Epsilon’s Board of Directors in the Supreme Court of the State of New York, County of New York, on behalf of purported Epsilon stockholder Anthony Morgan (the “Morgan Complaint”). On October 17, 2025, we received a copy of a complaint filed against Epsilon and certain members of Epsilon’s Board of Directors in the Supreme Court of the State of New York, County of New York, on behalf of purported Epsilon stockholder Richard Lawrence (the “Lawrence Complaint,” and together with the Morgan Complaint, the “Complaints”).

The Complaints allege, among other things, that Epsilon and the other named defendants (the “Epsilon Defendants”) violated New York common law based on claims of negligence, negligent misrepresentation and concealment. Specifically, the Complaints allege that the Preliminary Proxy Statement or the Definitive Proxy Statement, as applicable, failed to disclose, among other things, certain details regarding the background of the Transactions. Among other remedies, the Complaints sought an injunction against consummating the Transactions, rescission or actual and punitive damages if the Transactions are consummated, costs and attorneys’ fees. To date, we have not been served with the Complaints, and the Plaintiffs have not taken any additional steps in furtherance of prosecuting the Complaints.

While we believe that the disclosures set forth in the Preliminary Proxy Statement and the Definitive Proxy Statement comply fully with applicable law, to moot certain of the claims made in the Demands and Complaints, to avoid nuisance and potential expense and delay, we voluntarily supplemented the Definitive Proxy Statement with certain disclosures in our Supplemental Disclosures to Definitive Proxy Statement filed on October 31, 2025. Nothing in our Supplemental Disclosures was an admission of the legal necessity or materiality under applicable law of any of the disclosures set forth in the Preliminary Proxy Statement or the Definitive Proxy Statement. To the contrary, we deny all allegations in the Demands and Complaints that any additional disclosure was required.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

2831

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

The information required by Item 201 of Regulation S-K is contained in ‘‘Item 1. Business.’’

On ~~January~~February 118, ~~2024~~2026, the Board ofauthorized ~~Directors~~a ~~made~~new ~~grants~~share torepurchase ~~our~~program ~~directors~~of ~~entitling~~up ~~them~~ to an3,014,986 ~~aggregate~~common shares, representing 10% of ~~63,980~~the outstanding common shares ~~which~~of ~~shall~~the ~~not~~Company beat ~~issued~~such totime, ~~the~~for ~~award~~an ~~recipients~~aggregate ~~unless~~purchase ~~certain~~price ~~time~~of ~~based~~not ~~vesting~~more ~~criteria~~than ~~are~~US ~~met,~~$15.0 inmillion. ~~which~~The ~~case~~program ~~the~~is ~~vesting~~pursuant ~~will~~to ~~occur~~a normal course issuer bid and conducted in ~~three~~accordance ~~equal~~with ~~parts~~Rule on10b-18 under the ~~succeeding~~Exchange ~~periods~~Act. ~~ending~~The program commenced on ~~December~~February ~~31.~~19, ~~The~~2026 ~~awards~~and ~~were~~is ~~made~~set ~~under~~to ~~the~~expire ~~2020~~February ~~Equity~~18, ~~Incentive~~2027, ~~plan~~unless inthe ~~accordance~~maximum ~~with~~amount ~~Rule~~of ~~701~~common ~~promulgated~~shares ~~under~~is purchased before then or the ~~Securities~~Board ~~Act~~approves earlier termination.

On ~~March~~February 1912, ~~2024~~2025, the Board authorized a new share repurchase program of up to 2,~~191~~200,~~320~~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 $1213.0 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~~February 2712, ~~2024~~2025 and ~~was~~expired ~~set~~on toFebruary ~~expire March 26~~11, ~~2025,~~2026. ~~unless~~No ~~the maximum amount of common~~ shares iswere ~~purchased~~repurchased ~~before then or the Board approves earlier termination. On February 12, 2025, the Board terminated and revoked authority~~ under this ~~share repurchase~~ program.

On ~~February~~November 1214, 2025, ~~the~~after ~~Board~~receiving ~~authorized~~shareholder aapproval ~~new~~following ~~share~~a ~~repurchase~~special ~~program of up to 2~~meeting,~~200,876~~ ~~common shares, representing 10% of~~ the ~~outstanding~~Company ~~common~~closed ~~shares~~on of the ~~Company~~acquisition ~~at such time, for an aggregate purchase price~~ of ~~not~~Peak ~~more~~Exploration ~~than~~and USProduction ~~$13.0~~LLC ~~million.~~and ~~The~~Peak ~~program~~BLM isLease ~~pursuant~~LLC ~~to a normal course issuer bid~~ and ~~conducted~~their insubsidiaries ~~accordance~~(together, ~~with Rule 10b-18 under the Exchange Act~~“Peak”). ~~The~~As ~~program~~consideration, ~~commenced on February 12~~7,916,336 ~~2025~~common ~~and~~shares iswere ~~set~~issued to ~~expire~~the ~~February~~shareholders ~~11,~~of ~~2026,~~Peak ~~unless~~after the ~~maximum~~satisfaction ~~amount~~ of ~~common~~the ~~shares~~conditions isof ~~purchased~~the ~~before~~contingent ~~then~~share orconsideration ~~the~~and ~~Board~~all ~~approves~~closing ~~earlier~~purchase ~~termination~~price adjustments.

On December 31, ~~2024~~2025, our Board made grants to our management, employees, and directors entitling them to receive an aggregate of ~~236~~488,~~072~~283 common shares which shall not be issued to the award recipients unless certain time based vesting criteria are met, in which case the vesting will occur in three equal parts on the succeeding periods ending on December 31. Additionally, 47,417 common shares were issued as dividend equivalent rights. The awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act.

The Company funds the purchases of its shares out of available cash and does not incur debt to fund the share repurchase program. The shares are accounted for as treasury shares until such a time as they are retired. There were no common share purchases made by the Company during the three months ended December 31, ~~2024~~2025.

ITEM 6. [RESERVED.]

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, ~~2024~~2025 and ~~2023~~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 ~~Marcellus~~Appalachian ~~Shale~~Basin ~~section~~in ofPennsylvania, the ~~Appalachian~~Powder River Basin in ~~Pennsylvania~~Wyoming, the Permian Basin in Texas and New Mexico, ~~the NW Anadarko Basin in Oklahoma,~~ and the Western Canadian Sedimentary Basin in Alberta, Canada.

2932

At December 31, ~~2024~~2025 our total estimated net proved reserves were ~~69,401~~86.4 ~~MMcf~~Bcf of natural gas reserves, ~~876,808~~9.3 ~~Bbls~~MMBbls of ~~NGL~~oil reserves, and ~~1,572,465~~2.4 ~~Bbls~~MMBbls of ~~oil~~NGL ~~and condensate~~reserves, and we held leasehold rights to approximately ~~102~~101,~~506~~265 gross (2354,~~602~~044 net) acres. We have natural gas production from our non-operated wells in Pennsylvania; and natural gas, ~~oil~~natural ~~and~~gas ~~other~~ liquids, and oil production from our operated and non-operated wells in the Permian ~~Basin~~, ~~Oklahoma;~~Powder River, and ~~oil~~Western ~~production~~Canadian ~~from~~Sedimentary ~~our non-operated well in Alberta, Canada~~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 and Texas.~~

OnWe ~~February~~have ~~26, 2024, Epsilon acquired~~ a ~~25%~~substantial ~~interest~~remaining indrillable ~~three~~location ~~producing~~inventory ~~wells~~within ~~and~~our ~~3,620~~existing ~~gross~~leaseholds ~~undeveloped acres~~ in ~~Ector County~~Pennsylvania, Texas from a private operator. The Company participated in the drilling and completion of 2 gross (0.5 net) wells during 2024 which were put on production in May 2024 and July 2024. Together with the transaction completed in 2023Wyoming, ~~the Company holds a 25% working interest in 16,592 gross acres~~ and ~~7 producing wells in~~ Texas. ~~Total capital expenditures (net to Epsilon) through year-end 2024 in the project (including undeveloped leasehold) are $38.6 million.~~

On ~~April~~November 1114, ~~2024~~2025, Epsilon acquired aPeak ~~50%~~Exploration ~~working~~and ~~interest~~Production inLLC ~~14,243~~and ~~gross~~Peak ~~undeveloped~~BLM ~~acres~~Lease inLLC ~~Alberta,~~and ~~Canada.~~their ~~The~~subsidiaries ~~Company~~(together, ~~participated~~"Peak") inthrough ~~the~~a ~~drilling~~business ~~and~~combination. ~~completion~~The ofacquisition 2added 284 gross (~~0.5~~60 net) wells., ~~One~~including ~~well~~105 ~~was~~gross ~~put~~(45 onnet) ~~production~~operated inwells, ~~September~~and ~~2024.~~60,945 ~~One~~gross ~~well was deemed non-commercial. Total capital expenditures~~ (~~net~~39,566 ~~to Epsilon~~net) ~~through~~acres ~~year-end~~located ~~2024~~ in ~~the~~Campbell, ~~project~~Converse ~~(including~~and ~~undeveloped~~Johnson ~~leasehold)~~Counties, ~~are $2~~Wyoming.~~9 million.~~

InOn ~~October~~December ~~2024~~11, 2025, Epsilon ~~formed~~divested aDewey ~~joint~~Energy ~~venture~~Holdings, ~~with~~LLC, a ~~private~~wholly ~~operator~~owned ~~covering~~subsidiary ~~approximately~~of ~~130,000~~the ~~gross~~Company ~~acres~~to inan ~~Garrington~~undisclosed ~~and~~private ~~Harmattan areas in Alberta, Canada~~buyer. The ~~Company~~assets ~~will~~sold ~~provide~~included aapproximately $7964 ~~million~~Mcfe/d ~~drilling~~(60% ~~carry~~natural ~~during~~gas) ~~2025 in favor~~ of ~~the~~production ~~operator~~and inapproximately ~~exchange for a 25% working interest in the leasehold. To date~~6,400 ~~the~~net ~~Company~~deep ~~participated~~acres ~~in the drilling~~ and ~~completion of~~ 2,200 ~~gross (0.5~~ net) ~~wells.~~shallow ~~Total~~acres ~~capital~~of ~~expenditures~~leasehold, ~~(net~~all tolocated ~~Epsilon)~~in ~~through~~Dewey ~~year-end~~County, ~~2024 are $1~~Oklahoma.~~4 million.~~

WeDuring ~~continue~~2025, we realized net loss of $5.8 million as compared to ~~evaluate~~net ~~new~~income ~~opportunities~~of $1.9 million for 2024. This included a $19.3 million loss in ~~numerous~~Q4 ~~onshore~~2025 ~~North~~on ~~American~~the ~~natural~~sale ~~gas~~of ~~and~~our ~~oil~~Anadarko ~~basins~~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.

~~During~~At ~~2024~~December 31, we2025, ~~realized~~our total estimated net ~~income~~proved ofreserves $1were 156,037 MMcfe, a 86% increase from December 31, 2024.9 ~~million~~The asincrease ~~compared~~is mainly attributable to ~~net~~Wyoming ~~income~~reserves ofacquired ~~$6.9 million~~from ~~for~~the ~~2023~~Peak acquisition.

AtOur ~~December 31,~~standardized ~~2024,~~measure ~~our~~of ~~total~~discounted ~~estimated~~future net ~~proved~~cash ~~developed~~flows ~~reserves~~as ~~were~~of ~~64,872~~December ~~MMcfe~~31, a2025 ~~28%~~and ~~increase~~2024 ~~from~~was ~~December~~$156.1 million and $50.7 31million, ~~2023~~respectively. ~~The~~This ~~increase~~measure isof ~~mainly~~discounted ~~attributable~~future tonet ~~transfers~~cash ~~from~~flows ~~proved~~does ~~undeveloped~~not ~~reserves~~include inany ~~Pennsylvania~~estimate ~~and~~for ~~acquisitions~~future incash ~~Texas~~flows generated by our gathering system assets.

At December 31, 2024, our total estimated net proved reserves were 84,097 MMcfe, a 20% increase from December 31, 2023. This increase is primarily due to revisions in previous estimates related to changes to previously adopted development plans and well performance and acquisitions in Texas As a non-operating working interest owner, we often do not have direct control or visibility over the pace of investment in our assets by the operator. We must have confirmation from the operator on near-term development to designate an undeveloped well location as proved.

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. 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.

30Revenues

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:

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.

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. Price ($/Mcf)	$	1.80	$	1.74
Gathering system revenue (net of elimination)	$	5,524,063	$	9,790,531
Total PA Revenues	$	15,771,897	$	23,523,583
Permian Basin
Natural gas revenue	$	32,930	$	117,112
Volume (MMcf)		205		80
Avg. Price ($/Mcf)	$	0.16	$	1.47
Natural gas liquids revenue	$	1,060,967	$	353,612
Volume (MBOE)		51.8		17.9
Avg. Price ($/Bbl)	$	20.48	$	19.78
Oil and condensate revenue	$	12,770,258	$	3,501,098
Volume (MBbl)		173.0		44.5
Avg. Price ($/Bbl)	$	73.81	$	78.71
Total Permian Basin Revenues	$	13,864,155	$	3,971,822
Oklahoma
Natural gas revenue	$	505,304	$	1,014,050
Volume (MMcf)		237		354
Avg. Price ($/Mcf)	$	2.13	$	2.87
Natural gas liquids revenue	$	420,991	$	630,806
Volume (MBOE)		17.4		21.1
Avg. Price ($/Bbl)	$	24.16	$	29.96
Oil and condensate revenue	$	844,265	$	1,589,491
Volume (MBbl)		11.0		20.8
Avg. Price ($/Bbl)	$	76.75	$	76.37
Total OK Revenues	$	1,770,560	$	3,234,347
Canada
Oil and condensate revenue	$	116,163	$	—
Volume (MBbl)		2.5		—
Avg. Price ($/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. 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.


		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

Upstream natural gas liquids revenue for the year ended December 31, 2024 increased by $0.5 million, or 51% from 2023. 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.

Upstream oil and condensate revenue for the year ended December 31, 2024 increased by $8.6 million, or 170% over 2023. 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~~Upstream ~~system~~natural gas revenue ~~(net of elimination)~~ for the year ended December 31, ~~2024~~2025 ~~decreased~~increased by $418.3 million, or 44170%, ~~over~~from ~~2023~~2024. ~~The~~An ~~decrease~~increase ~~was primarily due to lower anchor shipper volumes as a result~~ of ~~natural~~$11.6 ~~decline~~million inwas ~~the wells and operator elected well shut-ins~~ due to ~~poor~~higher natural gas ~~pricing~~prices inand ~~Pennsylvania partially offset by~~ an increase inof ~~the Auburn gathering rate~~$6.8 ~~Revenues~~million ~~derived~~was ~~from~~due ~~transporting~~to ~~and~~higher ~~compressing~~produced ~~our~~volumes ~~production,~~as ~~which~~a ~~have~~result ~~been~~of ~~eliminated~~previously ~~from~~delayed ~~gathering~~wells ~~system~~coming ~~revenues,~~on ~~amounted~~line ~~to $1.1 million~~ and ~~$1.4 million, respectively, for~~ the ~~years~~end ~~ended~~of ~~December~~operator-elected ~~31,~~well ~~2024~~shut-ins ~~and~~in ~~2023~~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, ~~2024~~2025 and ~~2023~~2024:


	Year ended December 31,
	~~2024~~2025		~~2023~~2024
Lease operating costs (net of elimination)	$	712,~~264~~518,~~824~~325	$	67,~~405~~264,~~281~~824
Gathering system operating costs		2,~~265~~362,~~190~~036		2,~~459~~265,~~694~~190
	$	914,~~530~~880,~~014~~361	$	89,~~864~~530,~~975~~014

Upstream operating costs—Total $/Mcfe	$	01.9506	$	0.7195
Gathering system operating costs $/Mcf	$	0.3016	$	0.1517

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

Upstream operating costs consist of lease operating expenses necessary to extract natural gas and oil, including gathering and treating the natural gas and oil to ~~ready~~prepare it for sale. For the year ended December 31, ~~2024~~2025, upstream operating costs increased by $05.93 million, or ~~13.4~~72% from the same period in ~~2023~~2024. The increase is primarily due to the ~~acquired~~increase in gas production in Pennsylvania and ~~developed~~the ~~wells~~acquired production in the ~~Permian~~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, ~~2024~~2025, gathering system operating costs decreased by $0.21 million, or ~~7.9~~4% from the same period in ~~2023~~2024.

Depletion, Depreciation, Amortization and Accretion (DD&A)

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 ~~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.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.

Accretion expense is related to the asset retirement costs.

During the year ended December 31, ~~2024~~2025, DD&A expense increased by $2.5 million, or 3319%, compared to the same period in ~~2023~~2024. This increase was primarily a result of ~~the~~higher ~~lower~~produced ~~third-party~~volumes ~~reserves~~in ~~causing~~Pennsylvania anand ~~increased~~acquired ~~depletion~~properties ~~rate~~ in ~~addition to higher production from the Permian Basin~~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, ~~2024~~2025, the Company recorded an impairment of $13.452 million on the ~~Killam~~Canadian ~~project~~wells (~~interest~~2 ~~acquired~~gross, in0.5 ~~April 2024~~net) inand ~~Alberta~~$0.7 million on the New Mexico wells (2 gross, ~~Canada~~0.2 ~~One~~net) ~~well~~due ~~was~~to ~~impaired~~low asforward aoil ~~result~~prices ofon aDecember ~~decrease~~31, in2025 ~~reserves~~ (~~$0.53~~which ~~million~~are required to be used in impairment testing) and ~~one~~an ~~well~~offset ~~drilled~~frac ~~during~~hit ~~the~~impacting ~~year~~production ~~was~~and ~~deemed~~reserves ~~non-commercial~~in ~~($0.92~~New ~~million)~~Mexico. ~~For~~During the year ended December 31, ~~2023~~2024, ~~there~~Epsilon ~~was~~recorded noan 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.

General and Administrative (“G&A”)


	Year ended December 31,
	~~2024~~2025		~~2023~~2024
General and administrative	$	6,933,130	$	7,311,496
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, ~~2024~~2025 ~~decreased~~increased by $~~0.3~~2 million, or 529%, compared to the same period in ~~2023~~2024. ~~This~~An ~~decrease~~increase ~~was~~of ~~primarily~~$1.2 ~~due~~million is related to ahigher ~~reduction~~compensation expense, an increase of $0.5 million in ~~legal~~stock ~~expenses~~based compensation, and an increase of $0.1 million in audit and tax fees.

Interest Income

During the year ended December 31, ~~2024~~2025, interest income decreased by $10.23 million, or 7162%, from the same period in ~~2023~~2024. This decrease was primarily due to the reduction in the balance of cash ~~and~~equivalents associated with the maturation of all short term investments in June 2024.

Interest Expense

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

Interest expense ~~decreased~~increased by $0.036 million, or 421245%, during the year ended December 31, ~~2024~~2025 from ~~2023~~2024. The ~~decrease~~increase is due to ~~higher~~interest charged on the outstanding debt balance from the closing of the Peak acquisition on November 14, 2025, commitment fees inon ~~2023~~unused ~~associated~~debt ~~with~~capacity, ~~our~~and the amortization of front-end fees related to the new credit facility entered into in October 2025.

33Gain (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.

Net (loss) gain on commodity contracts

~~During~~At ~~the year ended~~ December 31, ~~2024~~2025, the Company had outstanding NYMEX ~~Henry Hub (“~~HH”) ~~Natural~~swaps ~~Gas~~totaling ~~Futures~~1.68 ~~swaps~~Bcf, ~~Tennessee~~NYMEX ~~Gas~~HH ~~Pipeline~~options ~~Zone~~totaling 4.51 ~~basis swaps~~Bcf, ~~and crude oil~~ NYMEX WTI CMA swaps ~~derivative~~totaling ~~contracts for the purpose of hedging a portion of its physical natural gas and oil sales revenue. During the year ended December 31~~340,916 ~~2023~~Bbls, ~~the~~and ~~Company had~~ NYMEX HHWTI ~~Natural~~CMA ~~Gas~~options ~~Futures~~totaling ~~swaps~~181,634 ~~and~~Bbls ~~Tennessee Gas Pipeline Zone 4 basis swaps derivative contracts~~ for the ~~same~~contract ~~hedging~~period ~~purpose. The amounts recorded represent the fair value changes on our derivative instruments during the year. For the year ended December 31, 2024, the Company received net cash settlements~~ of ~~$1,196,656.~~January ~~For~~2026 ~~the~~to ~~year~~January ~~ended December 31, 2023, the Company received net cash settlements of $3,251,890~~2028.

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~~2024, the Company had outstanding NYMEX HH swaps totaling 12.~~905~~2615 Bcf ~~with a weighted average strike price of $3.25~~ and Tennessee Z4 basis swaps totaling 12.~~905~~2615 Bcf ~~with~~for athe ~~weighted~~contract ~~average~~period ~~strike price~~ of ~~($1.10)~~January 2025 to ~~hedge~~October a2025, ~~portion~~and ofNYMEX ~~expected~~WTI ~~volumes~~CMA swaps totaling 20,662 Bbls for the contract period of January ~~2024~~2025 to ~~October~~June ~~2024~~2025.

Income Tax (Benefit) Expense

During the year ended December 31, ~~2024~~2025, income tax expense decreased by $1.63 million, or 4978%, from the same period in ~~2023~~2024. This decrease was primarily due to a decrease in taxable income as a result of ~~losses~~loss on ~~derivative~~the ~~contracts~~asset ~~and~~sale, ~~higher~~as ~~intangible~~well ~~drilling~~as ~~cost~~increased ~~deductions~~expenses related to the Peak acquisition.

Net (Loss) Income Compared to Adjusted EBITDA


	Year ended December 31,
	~~2024~~2025		~~2023~~2024
Net income	$	1,927,800	$	6,945,153
Net (loss) income	$	(5,798,863)	$	1,927,800
Add Back:
Interest income, net		(446,877)		(1,592,862)
Interest expense (income), net		435,791		(446,877)
Income tax expense		1,629,093		3,200,447
Income tax (benefit) expense		362,731		1,629,093
Depreciation, depletion, amortization, and accretion		1012,~~185~~170,~~119~~320		710,~~685~~185,~~084~~119
Impairment expense		13,~~450~~936,~~076~~669		—1,450,076
Stock based compensation expense		1,~~244~~744,~~416~~917		1,~~018~~244,~~262~~416
Loss on sale of assets		—19,256,530		~~1,449,871~~—
Loss on derivative contracts net of cash received or paid on settlement		1,587,803		121,835
Transaction costs		2,947,907
Foreign currency translation loss		570		(278)
(Gain) loss on derivative contracts net of cash received or paid on settlement		(4,336,824)		1,587,803
Adjusted EBITDA	$	17,578,000	$	18,827,512
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 (89) ~~other~~gain ~~income~~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.

34Additionally, 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.

should not be considered in isolation from or as a substitute for net income or cash flow measures prepared in accordance with U.S. GAAP or as a measure of profitability or liquidity.

Additionally, Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We have included Adjusted EBITDA as a supplemental disclosure because its management believes that EBITDA provides useful information regarding our ability to service debt and to fund capital expenditures. 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.

Capital Resources and Liquidity

Cash Flow

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

At December 31, ~~2024~~2025, we had a working capital surplus of $7.06 million, aan ~~decrease~~increase of $260.25 million from the $337.21 million surplus at December 31, ~~2023~~2024. The surplus ~~decreased~~increased from December 31, ~~2023~~2024 due to ~~lower~~an ~~cash~~increase ~~and~~in ~~short~~current ~~term investment balances~~assets. We anticipate that our current cash balance, ~~short term investments,~~ available borrowings, and cash flows from operations to be sufficient to meet our cash requirements for at least the next twelve months.

Year ended December 31, ~~2024~~2025 compared to ~~2023~~2024

During the year ended December 31, ~~2024~~2025, $1620.86 million was provided by our operating activities, compared to $1816.28 million in ~~2023~~2024, a $13.48 million, or 723%, ~~decrease~~increase. The ~~decrease~~increase was primarily due to ~~lower~~higher production and throughput volumes in ~~the~~Pennsylvania ~~Marcellus~~ due to ~~operator~~new ~~elected~~wells ~~shut-ins,~~turned ~~offset~~on byline ~~higher~~as ~~production~~well ~~volumes~~as incurtailed ~~Texas~~wells returning to production.

The ~~company~~Company used $1661.76 million for investing activities during the year ended December 31, ~~2024~~2025, compared to $3816.47 million in ~~2023~~2024, a $2144.79 million, or 57270%, ~~decrease~~increase. The ~~decrease~~increase was primarily due to a $4049.8 million ~~decrease~~paid infor ~~purchases~~the ofPeak ~~short-term investments, offset by a $15~~acquisition.2 ~~million increase in capital investments in upstream properties.~~

During the year ended December 31, ~~2024~~2025, ~~the Company used~~ $743.37 million ~~for~~was provided by financing ~~activity~~activities compared to $~~11.~~7.3 million used in ~~2023~~2024, a $~~4.4~~51 million, or 38697% decrease. The decrease was primarily due to ~~fewer~~the ~~repurchases~~$50.5 million draw on the Company’s credit facility to repay the outstanding debt of ~~our~~Peak ~~common~~related ~~shares~~to the acquisition.

Credit Agreement

The Company closed a new senior secured reserve based revolving credit facility on ~~June~~October 2810, ~~2023~~2025 with Frost Bank as ~~issuing~~administrative ~~bank~~agent and ~~sole~~Frost ~~lender.~~Bank ~~The~~and ~~current~~Texas ~~borrowing~~Capital ~~base~~Bank isas ~~$45~~lenders. ~~million~~This ~~(redetermined~~replaced asthe Company’s previous credit facility. As of ~~February~~December 1031, 2025), the borrowing base was $80 million, supported by the Company’s ~~upstream~~producing ~~assets~~reserves ~~in Pennsylvania~~ and is subject to semi-annual redeterminations with a maturity date of ~~June~~October 2810, ~~2027~~2029. Interest will be charged at the ~~Daily~~3-month ~~Simple~~Term SOFR rate plus a margin of 3~~.25~~-4% (depending on facility utilization), payable quarterly. The facility is secured by the assets of the Company’s Epsilon Energy USA subsidiary ~~(Borrower)~~. ~~There~~During ~~are~~March ~~currently~~2026, nothe ~~borrowings~~Company ~~under~~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, if the ~~leverage~~Company ~~ratio~~ is ~~greater~~required ~~than~~to ~~1.0~~hedge to50% 1of its forecasted Proved Developed Producing production over a rolling 18-month period.0, orIf the ~~borrowing~~facility ~~base~~ utilization isdrops ~~greater~~below ~~than~~ 50%, then the ~~Company~~required ishedging ~~required~~drops to ~~hedge 50~~25% of ~~the~~Proved ~~anticipated~~Developed Producing production ~~from~~for ~~PDP~~the ~~reserves~~last ~~for~~6 amonths ~~rolling~~of 24the 18-month period.

Repurchase Transactions

On ~~March~~February 1918, ~~2024~~2026, the Board ~~of Directors~~ authorized a new share repurchase program of up to 23,~~191~~014,~~320~~986 common shares, representing 10% of the current outstanding common shares of Epsilon ~~at such time~~, for an aggregate purchase price of not more than US $12.0 million. The program was pursuant to a normal course issuer bid and was conducted in accordance with Rule 10b-18 under the Exchange Act. The program commenced on March 27, 2024 and was set to expire on March 26, 2025, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination. During the year ended December 31, 2024, we repurchased 125,000 common shares and spent $627,500 at an average price of $5.00 per share (excluding commissions) under the plan. On February 12, 2025, the Board terminated and revoked authority under the program.

The previous share repurchase program commenced on March 9, 2023. During the year ended December 31, 2023, we repurchased 968,149 common shares of the maximum of 2,292,644 authorized for repurchase and spent $4,940,295 under the plan. The repurchased stock had an average price of $5.08 per share (excluding commissions) and 897,275 common shares were retired during the year ended December 31, 2023. In 2024, we repurchased 248,700 common shares and spent $1,203,708 at an average price of $4.82 per share (excluding commissions) and retired 319,574 common shares before the plan terminated on March 26, 2024.39

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

On February 12, 2025, the Board authorized a new share repurchase program of up to 2,200,876 common shares, representing 10% of the current outstanding common shares of Epsilon, for an aggregate purchase price of not more than US $13.0 million. The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act. The program will commence on February 12, 2025 and end on February 11, 2026, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination.

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, ~~2024~~2025, Epsilon’s outstanding natural gas and crude oil commodity contracts consisted of the following:


		Weighted Average Price ($/Mmbtu)
	Volume	~~Price ($/MMbtu)~~		~~Fair Value of Asset~~Ceiling		Floor		Fair Value of Asset
Derivative Type	(MMbtu)	Swaps		~~December 31, 2024~~Price		Price		December 31, 2025
2025
2026
NYMEX Henry Hub swap	2,261,500	$	3.26	$	(297,579)
NYMEX Henry Hub (LD) Options Call	2,360,801	$	—	$	5.05	$	—	$	(295,384)
Tennessee Z4 basis swap	2,261,500	$	(0.91)	$	(246,516)
NYMEX Henry Hub (LD) Options Put	—	$	—	$	—	$	3.35	$	709,792
	4,523,000			$	(544,095)
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

3640


		Weighted Average Price ($/Mmbtu)		~~Fair Value~~
	Volume	~~Weighted Average~~		~~December 31,~~Ceiling		Floor		Fair Value of Asset
Derivative Type	(Bbl)	~~Price ($/Bbl)~~Swaps		~~2024~~Price		Price		December 31, 2025
2025
2026
Crude Oil NYMEX WTI CMA	20,662	$	73.49	$	56,547
NYMEX WTI CMA Options Call	55,230	$	—	$	69.23	$	—	$	(63,877)
	20,662			$	56,547
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

WeThe ~~enter~~following ~~into~~table ~~commitments~~summarizes ~~for~~our ~~capital~~contractual ~~expenditures~~obligations inat ~~advance of the expenditures being made. As of~~ December 31, ~~2024, our commitments for capital expenditures were $7~~2025.8 million. All of the capital commitments are related to the first two wells of the joint venture in Alberta entered into in October 2024. Of the total commitment, $3.4 million is drilling carry in favor of the operator, the remaining amount is our working interest share of outstanding authorizations for future expenditures.


	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 ~~quantities~~future production volumes of proved natural gas and oil reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. 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~~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 ~~properties,~~that ~~significant~~cannot ~~downward~~be ~~revisions~~measured in an exact way. The accuracy of ~~estimated~~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 ~~reserve~~undeveloped ~~quantities~~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 ~~significant~~downward) ~~increases~~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 ~~estimated~~sections ~~development~~titled ~~costs~~“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 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.

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.

38Business 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.

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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Our earnings and cash flow are significantly affected by changes in the market price of commodities. The prices of oil and natural gas can fluctuate widely and are influenced by numerous factors such as demand, production levels, and world political and economic events and the strength of the U.S. dollar relative to other currencies. Should the price of oil or natural gas decline substantially, the value of our assets could fall dramatically, impacting our future options and exploration and development activities, along with our gas gathering system revenues. In addition, our operations are exposed to market risks in the ordinary course of our business, including interest rate and certain exposure as well as risks relating to changes in the general economic conditions in the United States.

Gathering System Revenue Risk

The Auburn ~~Gas~~GGS ~~Gathering~~gather ~~System~~gas ~~lies~~produced ~~within~~from the Marcellus Shale with historically high levels of recoverable reserves and low cost of production. We believe that a short- term low commodity price environment will not significantly impact the reserves produced and thus the revenue of our gas gathering system.

Derivative Contracts

The Company’s financial results and condition depend on the prices received for natural gas and oil production. Natural gas and oil prices have fluctuated widely and are determined by economic and political factors. Supply and demand factors, including weather, general economic conditions, the ability to transport the gas to other regions, as well as conditions in other natural gas and oil regions, impact prices. Epsilon has established a hedging strategy and may manage the risk associated with changes in commodity prices by entering into various derivative financial instrument agreements and physical contracts. Although these commodity price risk management activities could expose the Company to losses or gains, entering into these contracts helps to stabilize cash flows and support the Company’s capital spending program.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Our consolidated balance sheets as of December 31, ~~2024~~2025 and ~~2023~~2024, and the consolidated statements of operations and comprehensive income, changes in shareholders’ equity and cash flows for years ended December 31, ~~2024~~2025 and ~~2023~~2024 included in this annual report have been prepared in accordance with U.S. GAAP.

3944

Report of Independent Registered Public Accounting Firm

Shareholders and Board of Directors

Epsilon Energy Ltd.

Houston, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Epsilon Energy Ltd. (the “Company”) as of December 31, ~~2024~~2025 and ~~2023~~2024, the related consolidated statements of operations and comprehensive income, changes in shareholders’ equity, and cash flows for each of the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, ~~2024~~2025 and ~~2023~~2024, and the results of its operations and its cash flows for ~~each of~~ the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit ~~Matter~~Matters

The critical audit ~~matter~~matters communicated below isare amatters ~~matter~~ arising from the current period audit of the consolidated financial statements that ~~was~~were communicated or required to be communicated to the audit committee and that: (1) ~~relates~~relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit ~~matter~~matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit ~~matter~~matters below, providing a separate ~~opinion~~opinions on the critical audit ~~matter~~matters or on the accounts or disclosures to which itthey ~~relates~~relate.

Estimation of Future Production Volumes Used to Estimate Proved Oil and Natural Gas Reserves and the Associated Effect on Depreciation, Depletion and Amortization (“DD&A”) Expense Related to Proved Oil and Natural Gas Properties

As described in Note 3 to the consolidated financial statements, the Company uses the successful efforts method of accounting for its oil and natural gas producing activities which involves management making significant estimates, including estimating the future production volumes of proved oil and natural gas reserves. As disclosed in Note 5, the Company’s oil and natural gas properties, net balance as of December 31, ~~2024~~2025 was $~~97.0~~181 million, which includes proved

4045

oil and natural gas properties of $~~191~~233.3 million and accumulated depletion, amortization and impairment of $~~122~~131.86 million. ~~DD&A~~Depletion, depreciation, amortization, and accretion expense was $1012.2 million for the year ended December 31, ~~2024~~2025.

We have identified the estimation of future production volumes used to estimate proved oil and natural gas reserves and the associated effect on DD&A expense related to proved oil and natural gas properties as a critical audit matter. Estimating future production volumes involves a high degree of subjectivity from management and their independent petroleum ~~engineer~~engineers. Changes in this estimate could have a significant effect on the measurement of DD&A expense. Auditing the estimation of future production volumes required subjective and complex auditor judgment.

The primary procedures we performed to address this critical audit matter included:

•● Evaluating the professional qualifications and objectivity of the independent petroleum ~~engineer~~engineers, including their relationship to the Company.

•● Assessing the reasonableness of the future production volumes by comparing estimates of future production volumes against historical results of production volumes on a summary basis for all wells.

•● Performing a retrospective review over management estimates of future production volumes made in prior periods as compared to actual results.

Estimation of Future Production Volumes Used to Estimate Fair Value of the Acquired Proved Oil and Gas Properties in the Peak Acquisition

As described in Note 4 to the consolidated financial statements, on November 14, 2025, the Company completed an acquisition of Peak E&P, LLC and Peak BLM, LLC (“Peak Acquisition”) for a total consideration of $88.5 million. In connection with the Peak Acquisition, the Company recognized proved oil and gas properties of $47.9 million. To determine the acquisition date fair value of the oil and gas properties, management used internal engineers to make significant estimates, including estimating the future production volumes of the acquired oil and gas reserves.

We have identified the estimation of future production volumes used to estimate the fair value of the acquired proved oil and gas properties in the Peak Acquisition as a critical audit matter. Estimating future production volumes involves a high degree of subjectivity from management and their internal petroleum engineers. Changes in this estimate could have a significant effect on the fair value of the acquired oil and natural gas properties. Auditing the estimation of future production volumes requires subjective and complex auditor judgement.

The primary procedures we performed to address this critical audit matter included:

●

Assessing the reasonableness of the future production volumes by comparing estimates of future production volumes against historical results of production volumes on a summary basis for all wells and on a detailed basis for certain wells.

●

Performing a retrospective review over management estimates of future production volumes made in the acquisition date fair value forecast as compared to actual results.

/s/ BDO USA, P.C.

We have served as the Company’s auditor since 2017.

Houston, Texas

March 1927, ~~2025~~2026

4146

EPSILON ENERGY LTD.

Consolidated Balance Sheets


	December 31,		December 31,
	~~2024~~2025		~~2023~~2024
ASSETS
Current assets
Cash and cash equivalents	$	68,~~519~~959,~~793~~954	$	136,~~403~~519,~~628~~793
Accounts receivable		516,~~843~~132,~~722~~501		65,~~015~~843,~~448~~722
Short term investments		—		18,775,106
Fair value of derivatives		2,694,340		—
Fair value of derivatives		—		1,219,025
Prepaid income taxes		2,949,311		975,963
Prepaid income taxes		975,963		952,301
Other current assets		1,847,672		792,041
Other current assets		792,041		763,288
Total current assets		32,583,778		14,131,519
Total current assets		14,131,519		41,128,796
Non-current assets
Property and equipment:
Oil and gas properties, successful efforts method
Proved properties		~~191~~233,~~349~~334,~~210~~212		~~160~~191,~~263~~879,~~511~~210
Unproved properties		2879,~~364~~307,~~186~~169		2528,~~504~~364,~~873~~186
Accumulated depletion, depreciation, amortization and impairment		(~~122~~131,~~751~~636,~~395~~141)		(~~113~~123,~~708~~281,~~210~~395)
Total oil and gas properties, net		96181,~~962~~005,~~001~~240		7296,~~060~~962,~~174~~001
Gathering system		43,~~116~~540,~~371~~389		4243,~~738~~116,~~273~~371
Accumulated depletion, depreciation, amortization and impairment		(3637,~~449~~472,~~511~~139)		(3536,~~539~~449,~~996~~511)
Total gathering system, net		6,~~666~~068,~~860~~250		76,~~198~~666,~~277~~860
Land		~~637~~1,~~764~~231,965		637,764
Buildings and other property and equipment, net		~~259~~4,~~335~~132,732		~~291~~259,~~807~~335
Total property and equipment, net		~~104~~192,~~525~~438,~~960~~187		80104,~~188~~525,~~022~~960
Other assets:
Operating lease right-of-use assets, long term		~~344~~488,~~589~~949		~~441~~344,~~987~~589
Restricted cash		~~470~~553,000		470,000
Prepaid drilling costs		982,717		1,813,808
Fair value of derivatives, long term		1,154,936		—
Total non-current assets		106,323,266		82,913,817
Deferred financing costs		774,347		—
Total assets	$	120,454,785	$	124,042,613
Prepaid drilling costs		246,220		982,717
Total non-current assets		195,655,639		106,323,266
Total assets	$	228,239,417	$	120,454,785

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable trade	$	211,~~334~~148,~~732~~050	$	32,~~149~~334,~~371~~732
Gathering fees payable		~~997~~1,~~016~~076,143		1997,~~136,237~~016
Royalties payable		18,~~400~~702,~~976~~526		1,~~422~~400,~~898~~976
Accrued capital expenditures		~~572~~24,~~079~~888		~~696~~572,~~761~~079
Accrued compensation		~~695~~1,~~018~~056,304		~~636~~695,~~295~~018
Other accrued liabilities		~~371~~2,~~503~~682,090		~~649~~371,~~037~~503
Fair value of derivatives		~~487,548~~—		~~118~~487,~~770~~548
Operating lease liabilities		~~121~~271,~~135~~494		86121,~~473~~135
Total current liabilities		624,~~980~~961,~~007~~495		76,~~895~~980,~~842~~007
Non-current liabilities
Asset retirement obligations		3,652,296		3,502,952
Credit facility payable		50,500,000		—
Deferred income taxes		12,738,577		11,553,943
Ad valorem taxes, long term		7,411,971		—
Operating lease liabilities, long term		355,776		476,911
Asset retirement obligations		7,437,960		3,652,296
Total non-current liabilities		16,746,649		15,533,806
Deferred income taxes		12,855,585		12,738,577
Total liabilities		23,726,656		23,429,648
Operating lease liabilities, long term		340,052		355,776
Total non-current liabilities		78,545,568		16,746,649
Total liabilities		103,507,063		23,726,656
Commitments and contingencies (Note 11)
Shareholders' equity
Preferred shares, no par value, unlimited shares authorized, none issued or outstanding		—		—
Common shares, no par value, unlimited shares authorized and 22,008,766 shares issued and outstanding at December 31, 2024 and 22,222,722 issued and 22,151,848 shares outstanding at December 31, 2023		116,081,031		118,272,565
Common shares, no par value, unlimited shares authorized and 30,239,980 shares issued and outstanding at December 31, 2025 and 22,008,766 issued and outstanding at December 31, 2024		154,274,125		116,081,031
Treasury shares, at cost, 0 at December 31, 2024 and 70,874 at December 31, 2023		—		(360,326)
Additional paid-in capital		13,863,824		12,118,907
Additional paid-in capital		12,118,907		10,874,491
Accumulated deficit		(53,302,162)		(41,505,076)
Accumulated deficit		(41,505,076)		(37,946,042)
Accumulated other comprehensive income		9,896,567		10,033,267
Accumulated other comprehensive income		10,033,267		9,772,277
Total shareholders' equity		124,732,354		96,728,129
Total shareholders' equity		96,728,129		100,612,965
Total liabilities and shareholders' equity	$	228,239,417	$	120,454,785
Total liabilities and shareholders' equity	$	120,454,785	$	124,042,613

The accompanying notes are an integral part of these consolidated financial statements

4247

EPSILON ENERGY LTD.

Consolidated Statements of Operations and Comprehensive Income


	Year ended December 31,
	~~2024~~2025		~~2023~~2024
Revenues from contracts with customers:
Gas, oil, NGL, and condensate revenue	$	2544,~~998~~903,~~712~~821	$	2025,~~939~~998,~~221~~712
Gas gathering and compression revenue		56,~~524~~683,~~063~~735		95,~~790~~524,~~531~~063
Total revenue		3151,~~522~~587,~~775~~556		3031,~~729~~522,~~752~~775

Operating costs and expenses:
Lease operating expenses		712,~~264~~518,~~824~~325		67,~~405~~264,~~281~~824
Gathering system operating expenses		2,~~265~~362,~~190~~036		2,~~459~~265,~~694~~190
Depletion, depreciation, amortization, and accretion		1012,~~185~~170,~~119~~320		710,~~685~~185,~~084~~119
Impairment expense		13,~~450~~936,~~076~~669		—1,450,076
Loss on sale of oil and gas properties		—19,256,530		~~1,449,871~~—
Transaction costs		2,947,907		—
General and administrative expenses:
Stock based compensation expense		1,~~244~~744,~~416~~917		1,~~018~~244,~~262~~416
Other general and administrative expenses		57,~~688~~168,~~714~~235		65,~~293~~688,~~234~~714
Total operating costs and expenses		2862,~~098~~104,~~339~~939		2528,~~311~~098,~~426~~339
Operating income		3,424,436		5,418,326
Operating (loss) income		(10,517,383)		3,424,436

Other income (expense):
Interest income		~~493~~188,~~277~~369		1493,~~673,241~~277
Interest expense		(46624,~~400~~160)		(8046,~~379~~400)
(Loss) gain on derivative contracts		(391,147)		3,130,055
Gain (loss) on derivative contracts, net		5,500,486		(391,147)
Other income		76,727		4,357
Other income, net		16,556		76,727
Other income, net		~~132~~5,~~457~~081,251		4132,~~727,274~~457

Net income before income tax expense		3,556,893		10,145,600
Net (loss) income before income tax expense		(5,436,132)		3,556,893
Income tax expense		1,629,093		3,200,447
Income tax (benefit) expense		362,731		1,629,093
NET INCOME	$	1,927,800	$	6,945,153
NET (LOSS) INCOME	$	(5,798,863)	$	1,927,800
Currency translation adjustments		~~262~~(136,~~588~~700)		(3262,~~872)~~588
Unrealized (loss) gain on securities		(1,598)		1,598
Unrealized loss on securities		—		(1,598)
NET COMPREHENSIVE INCOME	$	2,188,790	$	6,942,879
NET COMPREHENSIVE (LOSS) INCOME	$	(5,935,563)	$	2,188,790

Net income per share, basic	$	0.09	$	0.31
Net (loss) income per share, basic	$	(0.25)	$	0.09
Net income per share, diluted	$	0.09	$	0.31
Net (loss) income per share, diluted	$	(0.25)	$	0.09
Weighted average number of shares outstanding, basic		2123,~~930~~020,~~277~~672		2221,~~496~~930,~~772~~277
Weighted average number of shares outstanding, diluted		2123,~~930~~020,~~277~~672		2221,~~511~~930,~~647~~277

The accompanying notes are an integral part of these consolidated financial statements

4348

EPSILON ENERGY LTD.

Consolidated Statements of Changes in Shareholders’ Equity


									Accumulated
									Other				Total
	Common Shares Issued			Treasury Shares			Additional		Comprehensive		Accumulated		Shareholders'
	Shares	Amount		Shares	Amount		paid-in Capital		Income		Deficit		Equity
Balance at December 31, 2022	23,117,144	$	123,904,965	—	$	—	$	9,856,229	$	9,774,551	$	(39,290,540)	$	104,245,205
Net income	—		—	—		—		—		—		6,945,153		6,945,153
Dividends	—		—	—		—		—		—		(5,600,655)		(5,600,655)
Stock-based compensation expense	—		—	—		—		1,018,262		—		—		1,018,262
Buyback of common shares	—		—	(1,158,849)		(6,055,601)		—		—		—		(6,055,601)
Retirement of treasury shares	(1,087,975)		(5,695,275)	1,087,975		5,695,275		—		—		—		—
Exercise of stock options	12,500		62,875	—		—		—		—		—		62,875
Vesting of shares of restricted stock	181,053		—	—		—		—		—		—		—
Other comprehensive loss	—		—	—		—		—		(2,274)		—		(2,274)
Balance at December 31, 2023	22,222,722	$	118,272,565	(70,874)	$	(360,326)	$	10,874,491	$	9,772,277	$	(37,946,042)	$	100,612,965
Net income	—		—	—		—		—		—		1,927,800		1,927,800
Dividends	—		—	—		—		—		—		(5,486,834)		(5,486,834)
Stock-based compensation expense	—		—	—		—		1,244,416		—		—		1,244,416
Buyback of common shares	—		—	(373,700)		(1,831,208)		—		—		—		(1,831,208)
Retirement of treasury shares	(444,574)		(2,191,534)	444,574		2,191,534		—		—		—		—
Vesting of shares of restricted stock	230,618		—	—		—		—		—		—		—
Other comprehensive loss	—		—	—		—		—		260,990		—		260,990
Other comprehensive income	—		—	—		—		—		260,990		—		260,990
Balance at December 31, 2024	22,008,766	$	116,081,031	—	$	—	$	12,118,907	$	10,033,267	$	(41,505,076)	$	96,728,129
Net loss	—		—	—		—		—		—		(5,798,863)		(5,798,863)
Dividends	—		—	—		—		—		—		(5,998,223)		(5,998,223)
Dividend equivalent rights	47,417		—	—		—		—		—		—		—
Stock-based compensation expense	—		—	—		—		1,744,917		—		—		1,744,917
Shares issued in business combination	7,916,336		38,193,094	—		—		—		—		—		38,193,094
Vesting of shares of restricted stock	267,461		—	—		—		—		—		—		—
Other comprehensive loss	—		—	—		—		—		(136,700)		—		(136,700)
Balance at December 31, 2025	30,239,980	$	154,274,125	—	$	—	$	13,863,824	$	9,896,567	$	(53,302,162)	$	124,732,354

The accompanying notes are an integral part of these consolidated financial statements

4449

EPSILON ENERGY LTD.

Consolidated Statements of Cash Flows


	Year ended December 31,
	~~2024~~2025		~~2023~~2024
Cash flows from operating activities:
Net income	$	1(5,~~927~~798,~~800~~863)	$	61,~~945~~927,~~153~~800
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		1012,~~185~~170,~~119~~320		710,~~685~~185,~~084~~119
Impairment expense		13,~~450~~936,~~076~~669		—1,450,076
Accretion of discount on available for sale securities		~~(297,637)~~—		(~~836~~297,~~528~~637)
Loss on sale of oil and gas properties		—		1,449,871
Amortization on deferred financing costs		44,510		—
Gain (loss) on derivative contracts		391,147		(3,130,055)
Loss on sale of oil and gas properties		19,256,530		—
Settlement received on derivative contracts		1,196,656		3,251,890
(Gain) loss on derivative contracts		(5,500,486)		391,147
Settlement of asset retirement obligation		(88,992)		(509,802)
Settlement received on derivative contracts		1,163,662		1,196,656
Stock-based compensation expense		1,244,416		1,018,262
Settlement of asset retirement obligation		(1,600)		(88,992)
Deferred income tax expense		1,184,634		936,549
Stock-based compensation expense		1,744,917		1,244,416
Changes in assets and liabilities:
Deferred income tax (benefit) expense		117,008		1,184,634
Accounts receivable		171,726		1,185,938
Changes in assets and liabilities, net of assets and liabilities acquired in business combination:
Prepaid income taxes		(23,662)		187,793
Accounts receivable		(1,588,383)		171,726
Other assets and liabilities		(17,828)		126,347
Prepaid income taxes		(1,973,348)		(23,662)
Accounts payable, royalties payable and other accrued liabilities		(493,176)		(122,203)
Other assets and liabilities		(10,365)		(17,828)
Net cash provided by operating activities		16,830,279		18,188,299
Accounts payable, royalties payable, gathering fees payable, and other accrued liabilities		(2,940,888)		(493,176)
Net cash provided by operating activities		20,619,683		16,830,279
Cash flows from investing activities:
Additions to unproved oil and gas properties		(46,~~507~~999,~~280~~905)		(84,~~136~~507,~~442~~280)
Additions to proved oil and gas properties		(317,~~695~~929,~~651~~773)		(1031,~~377~~695,~~642~~651)
Additions to gathering system properties		(~~341~~465,~~452~~203)		(82341,~~302~~452)
Additions to land, buildings and property and equipment		~~(16~~270,~~513)~~488		(4916,~~689~~513)
Purchases of short term investments - held to maturity		—		(32,812,974)
Purchases of short term investments - available for sale		—		(4,045,785)
Purchases of short term investments - available for sale		(4,045,785)		(11,988,982)
Proceeds from short term investments - held to maturity		—		6,743,178
Proceeds from short term investments - held to maturity		6,743,178		26,864,976
Proceeds from short term investments - available for sale		—		16,373,752
Proceeds from short term investments - available for sale		16,373,752		—
Net asset acquired in business combination		(49,754,846)		—
Proceeds from sale of oil and gas properties		—2,500,000		~~12,498~~—
Prepaid drilling costs		~~831~~736,~~091~~497		(1831,~~813,808)~~091
Net cash used in investing activities		(1661,~~658~~642,~~660~~742)		(3816,~~384~~658,~~365~~660)
Cash flows from financing activities:
Buyback of common shares		~~(1,831,208)~~—		(61,~~055~~831,~~601~~208)
Exercise of stock options		—		62,875
Borrowings on credit facility		50,500,000		—
Dividends paid		(5,~~486~~998,~~834~~223)		(5,~~600~~486,~~655~~834)
Debt issuance costs		—		(140,000)
Deferred financing costs		(818,857)		—
Net cash used in financing activities		(7,318,042)		(11,733,381)
Net cash provided by (used in) financing activities		43,682,920		(7,318,042)
Effect of currency rates on cash, cash equivalents, and restricted cash		~~262~~(136,~~588~~700)		(3262,~~872)~~588
Decrease in cash, cash equivalents, and restricted cash		(6,883,835)		(31,933,319)
Increase (decrease) in cash, cash equivalents, and restricted cash		2,523,161		(6,883,835)
Cash, cash equivalents, and restricted cash, beginning of period		136,~~873~~989,~~628~~793		4513,~~806~~873,~~947~~628
Cash, cash equivalents, and restricted cash, end of period	$	69,~~989~~512,~~793~~954	$	136,~~873~~989,~~628~~793

Supplemental cash flow disclosures:
Income tax paid - federal	$	~~414~~1,~~250~~417,860	$	1414,250~~,000~~
Income tax paid - state (PA)	$	—755,138	$	~~182,000~~—
Income tax (refund) paid - state (other)	$	(2,071)	$	7,583
Income tax paid - state (other)	$	3,986	$	(2,071)
Interest paid	$	169,~~832~~935	$	9716,~~595~~832

Non-cash investing activities:
Change in proved properties accrued in accounts payable and accrued liabilities	$	(862,744)	$	1,611,724
Change in proved properties accrued in accounts payable	$	(937,079)	$	(862,744)
Change in gathering system accrued in accounts payable and accrued liabilities	$	36,645	$	16,969
Change in gathering system accrued in accounts payable	$	(41,186)	$	36,645
Asset retirement obligation asset additions and adjustments	$	5425,~~902~~195	$	154,~~190,579~~902

The accompanying notes are an integral part of these consolidated financial statements

4550

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

1. Description of Business

Epsilon Energy Ltd. (the “Company” or “Epsilon” or “we”) was incorporated under the laws of the Province of Alberta, Canada on March 14, 2005. 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.” Epsilon is a North American on-shore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves.

2. Basis of Preparation

Principles of Consolidation

The Company’s consolidated financial statements include the accounts of the Company and its wholly owned subsidiary, Epsilon Energy USA, Inc. and its wholly owned subsidiaries, Epsilon Midstream, LLC, Epsilon Operating, LLC, Dewey Energy GP, LLC, ~~Dewey~~Peak Exploration & Production LLC, Peak BLM Lease LLC, Peak Powder River Resources, LLC, Peak Energy ~~Holdings~~Operating #2, LLC, Willow Springs Development, LLC, Peak Powder River Acquisition, LLC and Altolisa Holdings, LLC. With regard to the gathering system, in which Epsilon owns an undivided interest in the asset, proportionate consolidation accounting is used. All inter-company transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas reserves and related cash flow estimates used in impairment tests of oil and natural gas and gathering system properties, asset retirement obligations, accrued natural gas and oil revenues and operating expenses, accrued gathering system revenues and operating expenses, as well as the valuation of commodity derivative instruments. Actual results could differ from those estimates.

3. Summary of Significant Accounting Policies

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents includes cash on hand and short- term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.

Restricted cash consists of amounts deposited to back bonds or letters of credit. The Company presents restricted cash with cash and cash equivalents in the Consolidated Statements of Cash Flows.

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported in the Consolidated Balance Sheets to the total of the amounts in the Consolidated Statements of Cash Flows as of December 31, ~~2024~~2025 and ~~2023~~2024:


	December 31,		December 31,
	~~2024~~2025		~~2023~~2024
Cash and cash equivalents	$	68,~~519~~959,~~793~~954	$	136,~~403~~519,~~628~~793
Restricted cash included in other assets		~~470~~553,000		470,000
Cash, cash equivalents, and restricted cash in the statement of cash flows	$	69,~~989~~512,~~793~~954	$	136,~~873~~989,~~628~~793

4651

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

Oil and Natural Gas Properties

Epsilon accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting.

Oil and natural gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and natural gas properties. Lease delay rentals are expensed as incurred.

Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether Epsilon has discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized (see Note 5).

Depreciation, depletion and amortization of the cost of proved oil and natural gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.

When circumstances indicate that proved (developed and undeveloped) oil and natural gas properties may be impaired, Epsilon compares 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 Epsilon’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the carrying value of the asset, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach which considers estimated discounted future cash flows. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable.

Gas Gathering System Properties

Epsilon’s 35% portion of asset development costs are capitalized when incurred. All other costs are expensed.

Depreciation, depletion and amortization of the cost of gathering system properties is calculated using the unit-of- production method. The reserve base used to calculate depreciation, depletion and amortization for the gathering system includes only proved Pennsylvania natural gas developed reserves.

Revenue Recognition

Revenues are comprised primarily of sales of natural gas, crude oil and NGLs, along with the revenue generated from the Company’s ownership interest in the gas gathering system in the Auburn field in ~~Northeastern~~ Pennsylvania.

Revenue recognition is evaluated through the following five steps: (i) identification of the contract, or contracts, with a customer; (ii) identification of the performance obligations in the contract; (iii) determination of the transaction ~~price; (iv) allocation of the transaction price to the performance obligations in the contract; and (v) recognition of revenue when or as a performance obligation is satisfied.~~

4752

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

price; (iv) allocation of the transaction price to the performance obligations in the contract; and (v) recognition of revenue when or as a performance obligation is satisfied.

Accounting Policies

Revenue is recognized when performance obligations under the terms of a contract with a customer are satisfied. The Company recognizes upstream revenue at the point in time when control has been transferred to the customer, generally at the time natural gas reaches an agreed-upon delivery point and collectability is reasonably assured. Upstream revenue is based upon a fixed price, based on market pricing, and is measured as the amount of consideration the Company expects to receive in exchange for the transferring of the natural gas and oil. The services provided by the gas gathering system take place continuously and as a practical expedient, the revenues are recognized monthly for the volumes that are processed and transported for the upstream producers during that period of time. Revenue for the services performed are based on the rates outlined in the Anchor Shipper Gas Gathering Agreement for Northern Pennsylvania (the “ASGGA”) effective January 1, 2024 that governs all volumes gathered and processed by the system. The gathering rate is fixed, but is adjusted annually by the Consumer Price Index for All Urban Consumers (“CPI-U”) as published by US Bureau of Labor Statistics. Typically, the Company sells its natural gas directly to customers, under agreements with payment terms less than 30 days after delivery and 60 days on the revenue generated by the gas gathering system. For operated assets in Wyoming, payment is received within 30 days after the end of a month for oil and 60 days after the end of the month for natural gas and NGLs.

Natural Gas Revenues

The Company’s natural gas purchase contracts are generally structured such that Epsilon commits and dedicates for sale its proportionate share of natural gas production per day to a purchaser. Natural gas is sold at market prices. Control transfers at the delivery point specified in the contract, which typically is stated as the inlet of the third-party sales transportation pipeline. The Company recognizes revenue proportionate to its entitled share of volumes sold. Currently, the vast majority of Epsilon’s natural gas production comes from the ~~Marcellus~~Appalachian Basin in ~~Northeastern~~ Pennsylvania.

Epsilon uses a third-party service for its natural gas marketing. In this capacity, the third-party is responsible for carrying out marketing activities such as submission of nominations, receipt of payments, submission of invoices and negotiation of contracts. Commissions payable to the third-party broker for these services are treated as lease operating expenses in the financial statements.

For the Company’s operated assets in Wyoming, revenues from the sale of natural gas and NGLs are recognized, as the product is delivered to the customers’ custody transfer points and collectability is reasonably assured. The Company fulfills the performance obligations under the customer contracts through daily delivery of natural gas and NGLs to the customers’ custody transfer points. Revenues are recorded on a monthly basis using the prices received under the Company’s contracts. These contracts are generally derived from stated market prices which are adjusted to reflect deductions, including transportation, fractionation and processing. As a result, the revenues from the sale of natural gas and NGLs are subject to change with the increase or decrease in market prices. As a result, the sale of natural gas and NGLs, as presented on the consolidated statements of operations, represent the Company’s share of revenues, net of gathering and processing costs, net of royalties and excluding revenue interests owned by others. When selling natural gas and NGLs on behalf of royalty owners or working interest owners, the Company acts as an agent and therefore reports the revenue on a net share basis. To the extent actual volumes and prices of natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Historically, differences between revenue estimates and actual revenue received have not been significant.

The majority of product sale commitments of the Company are short term in nature with a contractual term of one year or less. For these contracts, the Company applies the practical expedient in Accounting Standards Codification (“ASC”) 606-10-50-14, which exempts entities from disclosing the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.

For contracts with terms greater than one-year, the Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in ASC 606-10-50-14A,

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2025 and 2024

which applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Gas Gathering System Revenue

The Company has a 35% ownership interest in the Auburn ~~Gas Gathering System (“Auburn~~ GGS”). This system aggregates the natural gas from the various pads in the field and transports the natural gas to the inlet of the Auburn ~~compression~~CF ~~facility~~ where it is dehydrated, compressed and injected into the Tennessee Gas Pipeline. The gathering and compression services operate under fee-based contracts. The producers in the area served by the gathering system pay fees to the system owners based on the services provided to them in getting their share of the gas production to the third-party sales transmission point. Revenue is recognized over time as the services are provided.

Oil and ~~Other~~Natural Gas Liquids Revenue

The source of the Company’s oil and ~~other~~natural gas liquids revenue is its ownership in wells in Wyoming, the Permian Basin, ~~Oklahoma,~~ and Alberta, Canada. ~~The~~With the exception of Wyoming, the Company does not operate the wells and has elected not to receive its proportionate share of the production. As such, under the Joint Operating Agreement, the operators have control of the marketing of this production at current market prices and remits our net revenue interest less taxes and fees on a monthly basis. The Company recognizes revenue with a monthly accrual of its proportionate share of volumes produced at an estimated market price.

~~Accounts~~For ~~Receivable~~the Company’s operated assets in Wyoming, revenue from the sale of oil and ~~Other~~natural gas liquids are recognized, as the product is delivered to the customers’ custody transfer points and collectability is reasonably assured. The Company fulfills the performance obligations under the customer contracts through daily delivery of oil and natural gas liquids to the customers’ custody transfer points. Revenues are recorded on a monthly basis using the prices received under the Company’s contracts. These contracts are generally derived from stated market prices which are adjusted to reflect deductions, including transportation, fractionation and processing. As a result, the revenues from the sale of oil and natural gas liquids are subject to change with the increase or decrease in market prices. As a result, the sales of oil and natural gas liquids, as presented on the consolidated statements of operations, represent the Company’s share of revenues, net of gathering and processing costs, net of royalties and excluding revenue interests owned by others. When selling oil and natural gas liquids on behalf of royalty owners or working interest owners, the Company acts as an agent and therefore reports the revenue on a net share basis. To the extent actual volumes and prices of oil and natural gas liquids sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Historically, differences between revenue estimates and actual revenue received have not been significant.

~~Oil,~~The ~~natural~~majority ~~gas~~of ~~liquid~~product ~~and~~sale ~~natural~~commitments ~~gas receivables consist~~ of ~~amounts~~the ~~due~~Company ~~from~~are ~~purchasers~~short orterm ~~operators for commodity sales from our revenue interest~~ in ~~the~~nature ~~leases~~with ina ~~Northeastern~~contractual ~~Pennsylvania,~~term ~~the~~of ~~Permian~~one ~~Basin,~~year ~~Oklahoma,~~or ~~and Alberta, Canada~~less. ~~Payments~~For ~~from~~these ~~purchasers~~contracts, ~~are typically due by~~ the ~~last~~Company ~~day~~applies of the ~~month~~practical ~~following~~expedient ~~the~~in ~~month~~Accounting ofStandards ~~delivery.~~Codification ~~Gathering~~(“ASC”) ~~fee~~606-10-50-14, ~~revenue~~which ~~consists~~exempts ofentities ~~fees due~~ from ~~the~~disclosing ~~operator of~~ the ~~Auburn~~transaction ~~GGS,~~price asallocated anto ~~agent~~remaining ~~for~~performance ~~the~~obligations, ~~Company~~if ~~fulfilling~~any, ~~the~~if ~~operations of~~ the ~~gathering~~performance ~~system.~~obligation ~~Payments~~is ~~from~~part ~~the~~of ~~operator~~a ~~are~~contract ~~typically~~that ~~due~~has 60an ~~days~~original ~~from~~expected ~~the~~duration ~~last day~~ of ~~the~~one ~~month~~year ~~of transmission. The Company’s operations do not result in any contract assets~~ or ~~liabilities on the accompanying consolidated balance sheets~~less.

48For contracts with terms greater than one-year, the Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in ASC 606-10-50-14A, which applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Accounts Receivable

Oil, natural gas liquid and natural gas receivables consist of amounts due from purchasers or operators for commodity sales from our revenue interest in the leases in Pennsylvania, Wyoming, the Permian Basin, and Alberta, Canada. Payments from purchasers are typically due by the last day of the month following the month of delivery. Gathering fee revenue consists of fees due from the operator of the Auburn GGS, as an agent for the Company fulfilling the operations of the gathering system. Payments from the operator are typically due 60 days from the last day of the month

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

of transmission. The Company’s operations do not result in any contract assets or liabilities on the accompanying consolidated balance sheets.

For its operated assets in Wyoming, the Company accrues for oil, natural gas and natural gas liquids sales based on actual production dates. These are due within 45 days of production for oil and 60 days for natural gas and other liquids. To the extent the Company has joint interest owners in properties, joint interest billings represent monthly billings to working interest owners in the properties the Company operates. Joint interest billings are due within 30 days, with a right of offset against revenues due to working interest owners in the respective properties. The Company monitors the creditworthiness of its counterparties by reviewing credit ratings, financial statements, and payment history.

Buildings and Other Property and Equipment

Buildings are depreciated on a straight-line basis over the estimated useful life of the property, 30 years. The Company’s office building in Durango is stated at cost and depreciated over the estimated useful life of 25 years using straight-line method.

Other property and equipment consists of computer hardware and software, and furniture and fixtures. Other property and equipment is generally depreciated on a straight-line basis over the estimated useful lives of the property and equipment, which range from 3 years to 7 years.

Financial Instruments and Fair Value

Epsilon’s financial instruments consist of cash and cash equivalents, ~~short term investments,~~ restricted cash, commodity derivative contracts, accounts receivable, accounts payable, and long- term debt.

The Company classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instrument.

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

Level 3—Valuations in this level are those with inputs for the asset or liability that are not based on observable market data. The Company makes its own assumptions about how market participants would price the assets and liabilities.

Cash, restricted cash, accounts receivable, and accounts payable are carried at cost, which approximates fair value because of the short- term maturity of these instruments. Cash equivalents are carried at fair value. The Company’s revolving line of credit has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates and the applicable margins represent market rates. The revolving line of credit is classified within Level 2 of the fair value hierarchy.

~~The~~Commodity ~~Company~~derivative ~~had~~instruments ~~investments~~consist inof UNYMEX HH and NYMEX WTI CMA swaps and options as well as basis swap contracts for natural gas.S. ~~Treasury~~The ~~Bills,~~Company’s ~~which~~derivative ~~mature~~contracts ~~over~~are avalued ~~period~~based ~~between~~on 3a ~~and~~marked 12to ~~months~~market ~~and~~approach. These assumptions are ~~classified~~observable asin ~~short~~the marketplace throughout the full term ~~investments.~~of ~~The~~the ~~U.S.~~contract, ~~Treasury~~can ~~Bills~~be derived from observable data or are ~~carried~~supported by observable levels at ~~fair~~which ~~value.~~transactions ~~The~~are ~~U.S.~~executed ~~Treasury~~in ~~Bills~~the marketplace, and are ~~classified~~therefore ~~within~~designated as Level 12 ofwithin the ~~fair~~valuation ~~value~~ hierarchy. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.

Commodity derivative instruments consist of NYMEX HH swap and basis swap contracts for natural gas. The Company’s derivative contracts are valued based on a marked to market approach. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.55

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2025 and 2024

Derivative Instruments

The Company enters into derivative contracts to hedge price risk associated with a portion of natural gas and oil production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated, which has, and could, result in over-hedged volumes. Natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the NYMEX or the published natural gas index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. Our derivative transactions have included the following:

●

Fixed-price swaps—where a fixed price is received for production and a variable market price is paid to the contract counterparty.

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

●

Basis swap contracts—which guarantee a specified price differential between the price at Henry Hub and our physical pricing points. If the settled price differential is greater than the swapped basis, then we receive a payment from the counterparty in the amount of the difference between the two. If the settled price differential is less than the swapped basis, then we make a payment to the counterparty for the difference between the two.

● Two-way costless collar contracts—which guarantee a specified price range for NYMEX by using the proceeds of selling a call option at a specified strike price (the “Ceiling”) to finance the purchase of a put option at a specified strike price (the “Floor”).

Derivative instruments are recorded on the consolidated balance sheets at fair value as either current or non-current assets or liabilities based on their anticipated settlement date. Gains or losses on derivative contracts are recorded as gain (loss) on derivative contracts in the consolidated statements of operations and comprehensive income. Hedge accounting is not used for our derivative assets and liabilities.

Asset Retirement Obligations

The Company records a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method of the asset’s useful life. Recognized asset retirement obligations relate to the plugging and abandonment of oil and natural gas wells and decommissioning of the gas gathering system. Management reviews the estimates of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate. These adjustments are recorded to the asset retirement obligations with an offsetting change to oil and gas properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the forecast inflation due to the passage of time, which is recorded in depreciation, depletion, amortization, and accretion expense in the consolidated statements of operations and comprehensive income.

Concentrations of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents, ~~short term investments,~~ accounts receivable and derivative contracts. Exposure to credit risk associated with these instruments is controlled by (i) placing assets and other financial interests with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring paying history, although the Company does not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties with a legal right of offset.

At December 31, ~~2024,~~2025 ~~cash~~ and ~~cash equivalents was primarily concentrated in one financial institution the U.S. At December 31~~2024, ~~2023,~~ cash and cash equivalents ~~and short term investments~~ were primarily concentrated in one financial institution the U.S. We currently have $48.15 million in excess of the federally insured limits. The Company periodically assesses the financial condition of these institutions and ~~believe~~believes that any possible credit risk is minimal.

For the year ended December 31, ~~2024~~2025, the Company had ~~three~~five customers that accounted for ~~89.1~~more than 90% of the total trade accounts receivable. For the year ended December 31, ~~2023~~2024, the Company had ~~four~~three customers that accounted for 9089.71% of the total trade accounts receivable.

~~Geographic Locations of Operations~~56

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 year 2024 and 2023, respectively, was derived from oil, natural gas, and natural gas liquids revenues in the state of Texas. 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.

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

Geographic Locations of Operations

Income Taxes

~~Deferred~~The Company accounts for income taxes in accordance with ASC 740, Income Taxes, which requires the recognition of deferred tax assets and liabilities ~~are~~for ~~recognized~~the ~~based~~expected ~~on anticipated~~ future tax consequences ~~attributable~~of totemporary differences between the financial statement carrying amounts and the tax bases of assets and liabilities, and ~~their~~for ~~respective~~operating loss and tax ~~basis~~credit carryforwards. ~~Epsilon~~Deferred ~~assesses~~tax assets and liabilities are measured using enacted tax rates expected to apply in the periods in which those temporary differences are expected to reverse. Significant judgment is required in evaluating the realizability of deferred tax assets, including the need for and ~~recognizes~~amount ~~valuation~~of ~~allowances~~any asvaluation ~~appropriate~~allowance. (see Note 10).

Foreign Currency Transactions

Even though the Canadian dollar is the functional currency of Epsilon Energy Ltd. (the parent entity), the United States dollar is the reporting currency for all of Epsilon’s consolidated subsidiaries. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. Gains and losses on translation of balances denominated in Canadian dollars, calculated using the end of the period exchange rate, are included in accumulated other comprehensive income.

Stock- Based Compensation

The Company has issued time-based restricted stock ~~and~~units (“RSU”), performance share units (“PSU”), and dividend equivalent rights shares (“DER”) to employees and directors of the Company. The fair value of the time-based ~~restricted~~RSU ~~stock~~and the DER shares is determined using the fair value of the Company’s common shares on the date of grant. The fair value of the PSUs is determined by the performance requirements. ~~These~~The RSU and PSU awards vest ratably over a three-year period. The DER awards vest immediately. Compensation expense and a corresponding increase to additional paid in capital are recorded over the vesting period.

Leases

The Company leases office space to be used for general, administrative, and executive offices with terms typically ranging from five to seven years, subject to certain renewal options as applicable. The Company considers renewal or termination options that are reasonably certain to be exercised in the determination of the lease term and initial measurement of lease liabilities and right-of-use assets. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Interest expense for finance leases is incurred based on the carrying value of the lease liability. Leases with an initial term of 12 months or less are not recorded on the Company’s Consolidated Balance Sheets and lease agreements with lease and non-lease components are generally accounted for as a single lease component.

The Company determines whether a contract is, or contains, a lease at inception of the contract and whether that lease meets the classification criteria of a finance or operating lease. When available, the Company uses the rate implicit in the lease to discount lease payments to present value; however, most of the Company’s leases do not provide a readily determinable implicit rate. Therefore, the Company must discount lease payments based on an estimate of its incremental borrowing rate based on prevailing financial market conditions at the later of date of adoption or lease commencement, credit analysis of comparable companies and management judgments to determine the present values of its lease payments (see Note 12).

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2025 and 2024

Joint Interests

The majority of the Company’s oil and natural gas exploration, development and production activities, and the gathering system, are conducted jointly with others and, accordingly, these financial statements reflect only the Company’s proportionate interest in such jointly controlled assets.

Deferred Financing Costs

The Company has deferred financing costs - upfront fees and expenses that include origination, underwriting, legal and other fees – that were incurred to secure our revolving credit facility. The fees are amortized using the straight-line method, which approximates the effective interest method, over the life of the credit facility and are recognized in our consolidated statements of operations as interest expense. The unamortized deferred financing costs related to the credit facility are reported in the consolidated balance sheets as Deferred financing costs in non-current assets.

Business Combinations

The Company accounts for business combinations in accordance with FASB ASC Topic 805, Business Combinations. The Company accounts for our acquisitions that qualify as a business using the acquisition method in which the Company recognizes and measures identifiable assets acquired, liabilities assumed, and any non-controlling interest in the acquired entity at their fair values as of the acquisition date. If the set of assets and activities acquired is not considered a business, it is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model, the cost of the acquisition, including certain transaction costs, is allocated to the assets acquired on the basis of relative fair values.

The Company includes the results of operations of acquired businesses beginning on the respective acquisition dates. In accordance with the acquisition method, the Company allocates the purchase price of an acquired business to its identifiable assets and liabilities based on the estimated fair values. The fair values of identifiable assets acquired and liabilities assumed are determined based on various valuation techniques, including market prices, discounted cash flow analysis, and independent appraisals. This fair value measurement is based on unobservable (Level 3) inputs. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. The excess value of the net identifiable assets and liabilities acquired over the purchase price of an acquired business, if any, is recorded as a bargain purchase gain. Transaction costs related to the business combination are expensed as incurred.

Recently Issued Accounting Standards

In ~~October~~December 2023, the FASB issued ASU No. 2023-0609, ~~Disclosure~~Income ~~Improvements~~Taxes (Topic 740): ~~Codification~~Improvements ~~Amendments~~to inIncome ~~Response~~Tax Disclosures, which requires public entities, on an annual basis, to ~~the~~disclose ~~SEC~~disaggregated information about a reporting entity’s ~~Disclosure~~effective ~~Update~~tax rate reconciliation, using both percentages and ~~Simplification~~reporting ~~Initiative~~currency amounts for specific standardized categories, toas ~~amend~~well ~~certain~~as disclosure ~~and~~of ~~presentation~~income ~~requirements~~taxes paid disaggregated by jurisdiction. ~~For~~Effective ~~entities~~January ~~subject~~1, 2025, the Company adopted ASU 2023‑09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments enhance income tax disclosures, primarily related to the ~~SEC~~effective tax rate reconciliation and income taxes paid. The Company adopted the amendments on a prospective basis. The adoption did not have a material impact on the Company’s ~~existing~~consolidated ~~disclosure~~financial ~~requirements~~statements, as the ~~effective~~amendments ~~date~~relate primarily to expanded disclosures and do not change the recognition or measurement of income taxes. Because the amendments were adopted prospectively, the enhanced disclosures required by ASU 2023‑09 are provided for ~~each~~the ~~amendment~~year ended December 31, 2025. Prior‑year disclosures continue to be presented in accordance with the Company’s previously applied accounting guidance. See Note 9 “Income Taxes” in the Notes to Consolidated Financial Statements.

51 In March 2024, the FASB issued ASU No. 2024-01, Compensation – Stock Compensation (Topic 718): Scope Applications of Profits Interest and Similar Awards (“ASU 2024-01”). The amendments in ASU 2024-01 improves its overall clarity and operability without changing the guidance and adding illustrative examples to determine whether profits interest award should be accounted for in accordance with Topic 718. The guidance is effective for fiscal years beginning after December 15, 2024, and interim periods within those annual periods. The Company has adopted ASU No. 2024-01 as of December 31, 2025 with no material impact.

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

will be the date on which the SEC’s removal of that related disclosure from Regulation S-X or Regulation S-K becomes effective, with early adoption prohibited. For all entities, if by June 30, 2027, the SEC has not removed the applicable requirement from Regulation S-X or Regulation S-K, the pending content of the related amendment will be removed from the codification and will not become effective for any entity. The Company is currently evaluating the impact of this ASU.

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. This ASU required disclosure of incremental segment information, primarily through enhanced disclosures about significant segment expenses and amounts for each reportable segment on an annual and interim basis. This guidance is effective for fiscal years beginning after December 15, 2023 and interim periods with fiscal years beginning after December 15, 2024. The Company has adopted ASU No. 2023-07 as of December 31, 2024. See Note 14 “Operating Segments” in the Notes to Consolidated Financial Statements.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires public entities, on an annual basis, to disclose disaggregated information about a reporting entity’s effective tax rate reconciliation, using both percentages and reporting currency amounts for specific standardized categories, as well as disclosure of income taxes paid disaggregated by jurisdiction. The amendments will be effective for fiscal years beginning after December 15, 2024, with early adoption permitted. The Company is evaluating the impact of this new standard and believes that the adoption will result in additional disclosures, but will not have any other impact on its consolidated financial statements.

In March 2024, the FASB issued ASU No. 2024-01, Compensation – Stock Compensation (Topic 718): Scope Applications of Profits Interest and Similar Awards (“ASU 2024-01”). The amendments in ASU 2024-01 improves its overall clarity and operability without changing the guidance and adding illustrative examples to determine whether profits interest award should be accounted for in accordance with Topic 718. The amendments will be effective for fiscal years beginning after December 15, 2024, and interim periods within those annual periods. The Company does not anticipate that these updates, once adopted, will have a material effect.

In November 2024, the FASB issued ASU 2024-3 "Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures." The ASU will improve the decision usefulness for investors by requiring public business entities to disclose more detailed information about their expenses such as (a) inventory and manufacturing expense, (b) employee compensation, (c) depreciation, (d) intangible asset amortization, etc. The amendments will be effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027, with early adoption permitted. The amendments will be applied prospectively with an option for a retrospective application. The Company is evaluating the impact of this new standard and believes that the adoption will result in additional disclosures, but will not have any other impact on its consolidated financial statements.

In July 2025, the FASB issued ASU 2025-05, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit losses for Accounts Receivable and Contract Assets. The amendments in this update provide (1) all entities with a practical expedient to assume that current conditions as of the balance sheet date do not change for the remaining life of the assets and (2) entities other than public business entities with an accounting policy election to consider collection activity after the balance sheet date when estimating expected credit losses for current accounts receivable and current contract assets arising from transactions accounted for under Topic 606. The amendments will be effective for fiscal years beginning after December 15, 2025, with early adoption permitted. The Company is evaluating the impact of this new standard and believes that the adoption may result in additional disclosures, but will not have any material impact on its consolidated financial statements.

4. Business Combination

During the year ended December 31, 2025, Epsilon acquired 100% of the ownership interest in Peak Exploration & Production LLC and Peak BLM Lease LLC and their subsidiaries (together, “Peak”) for total consideration of $88.5 million consisting of 1) issuance of 5,681,489 common shares valued at $27.6 million, 2) contingent consideration of up to 2,500,000 common shares valued at $10.6 million, and the settlement of $50.3 million of debt. The contingent consideration was settled on November 19, 2025, through the issuance of 2,234,847 common shares for $10.6 million. The acquired assets primarily include operated and non-operated production and leasehold interests in the core of the Powder River Basin in Wyoming.

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2025 and 2024

4.The ~~Short~~following ~~Term~~table ~~Investments~~summarizes the allocation of the total purchase price to the assets acquired and liabilities assumed based on the estimated fair value as of the closing date of the acquisition.

Short term investments are highly liquid investments with original maturities between three and twelve months. The Company’s short term investments consist of US Treasury Bills. These investments are classified as available-for-sale. Available-for-sale short term investments are reported at fair value in the Consolidated Balance Sheets. Unrealized gains and losses are excluded from earnings and are reported in accumulated other comprehensive income in the Consolidated Statements of Operations and Comprehensive Income.

The following table summarizes the available-for-sale short term investments as of December 31, 2024 and 2023.


	December 31, 2024						December 31, 2023
Purchase price allocation as of November 14, 2025:
	Amortized		Unrealized		Fair		Amortized		Unrealized		Fair
Consideration:
	Cost		Losses		Value		Cost		Gains		Value
Share consideration issued to sellers November 14, 2025 - 5,681,489 common shares	$	27,555,222
U.S. Treasury Bills	$	—	$	—	$	—	$	18,773,508	$	1,598	$	18,775,106
Fair value of contingent share consideration (1)		10,637,872
Debt repayment		50,335,666
Total consideration transferred		88,528,760

Fair value of assets acquired:
Cash		580,820
Oil and gas receivable		5,962,465
Joint interest billing receivable		2,717,522
Prepaid and other assets		1,045,265
Proved oil and gas properties		47,870,041
Unproved oil and gas properties		59,014,000
Land and buildings		3,664,201
Other non-current assets		1,130,472
Amount attributable to assets acquired		121,984,786

Fair value of liabilities assumed:
Account payable		7,745,885
Revenue and production taxes payable		7,533,581
Accrued liabilities		3,966,408
Ad valorem taxes payable - current		1,830,419
ROU liability - current		150,577
Asset retirement obligations		3,815,948
Ad valorem taxes payable - long term		8,283,967
ROU liability - long term		129,241
Amount attributable to liabilities assumed		33,456,026

Net assets acquired	$	88,528,760

(1)	The contingent consideration was settled on November 19, 2025. The Company issued 2,234,847 common shares with a fair value of $10.6 million.

~~During~~The Company funded the ~~year~~acquisition ~~ended~~through ~~December~~the ~~31,~~issuance ~~2024,~~of ~~the~~shares ~~Company~~and ~~sold~~borrowings ~~securities~~under ~~with~~our acredit ~~carrying~~facility. ~~amount~~The results of ~~$14,989,595~~operations ~~for~~attributable ~~total~~to ~~proceeds~~Peak since the closing date of ~~$15,336,930.~~the ~~The~~acquisition ~~realized~~have ~~gains~~been onincluded ~~these~~in ~~sales~~the ~~were~~consolidated statements of operations and comprehensive income and include $~~347,335.~~4 Anmillion ~~additional~~of total revenues and a $75,~~780,000~~747 ofnet ~~securities~~loss for the year ended December 31, 2025.

Pro Forma Operating Results (Unaudited)

The following supplemental, unaudited pro forma combined financial information for the year ended December 31, 2025 reflects the consolidated results of operations of the Company as if the Peak acquisition had occurred on January 1, 2024. The information below reflects pro forma adjustments based on available information and certain assumptions that the Company believes are factual and supportable. The unaudited pro forma information includes adjustments for (i) leasehold expense (ii) depreciation, depletion, amortization, and accretion, (iii) loss on impairment of long term assets, (iv) interest expense related to long term debt, and (v) loss on sale of assets. In addition, for the year ended December 31, 2025 and 2024, the pro forma information has been effected for income taxes with an effective tax rate of 6.31% and 45.79%, respectively.

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

reached maturity with total realized gains of $234,248. The realized gains are included in interest income in the consolidated Statements of Operations and Comprehensive Income.

During the year ended December 31, 2023, the Company sold securities with a carrying amount of $10,394,482 for total proceeds of $10,454,976. The realized gains on these sales were $60,494. These securities were sold to raise cash to fund capital expenditures. An additional $16,410,000 of securities reached maturity with total realized gains of $395,767. The realized gains are included in interest income in the consolidated statements of operations and comprehensive income.


		Year ended			Year ended
		December 31,			December 31,
(unaudited)		2025			2024
Total revenues		$	83,817,737		$	82,149,610
Net income		$	3,716,248		$	10,307,310
Basic net income per common share		$	0.16		$	0.47
Diluted net income per common share		$	0.16		$	0.47

The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Peak acquisition been completed as of January 1, 2024, and should not be taken as indicative of the Company's future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results.

5. Property and Equipment

The following table summarizes the Company’s property and equipment at December 31, ~~2024~~2025 and ~~2023~~2024:


	December 31,		December 31,
	~~2024~~2025		~~2023~~2024
Property and equipment:
Oil and gas properties, successful efforts method
Proved properties	$	~~191~~233,~~349~~334,~~210~~212	$	~~160~~191,~~263~~879,~~511~~210
Unproved properties		2879,~~364~~307,~~186~~169		2528,~~504~~364,~~873~~186
Accumulated depletion, depreciation, amortization and impairment		(~~122~~131,~~751~~636,~~395~~141)		(~~113~~123,~~708~~281,~~210~~395)
Total oil and gas properties, net		96181,~~962~~005,~~001~~240		7296,~~060~~962,~~174~~001
Gathering system		43,~~116~~540,~~371~~389		4243,~~738~~116,~~273~~371
Accumulated depletion, depreciation, amortization and impairment		(3637,~~449~~472,~~511~~139)		(3536,~~539~~449,~~996~~511)
Total gathering system, net		6,~~666~~068,~~860~~250		76,~~198~~666,~~277~~860
Land		~~637~~1,~~764~~231,965		637,764
Buildings and other property and equipment, net		~~259~~4,~~335~~132,732		~~291~~259,~~807~~335
Total property and equipment, net	$	~~104~~192,~~525~~438,~~960~~187	$	80104,~~188~~525,~~022~~960

Asset Acquisitions

During the year ended December 31, 2025, Epsilon had no asset acquisitions.

During the year ended December 31, 2024, Epsilon made the following four acquisitions. Management determined that substantially all of the fair value of the gross assets acquired were concentrated in oil and gas properties and therefore accounted for these transactions as asset acquisitions and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

● a 25% working interest in ~~three~~ producing wells in Ector County, Texas for $12.1 million.

● a 25% working interest in ~~3,620 gross~~ undeveloped ~~acres~~acreage in Ector County, Texas for $2.6 million.

● a 50% working interest in ~~14,243 gross~~ undeveloped ~~acres~~acreage in Alberta, Canada for $1.0 million.

● a joint venture covering ~~approximately 130,000 gross~~ undeveloped ~~acres~~acreage in Alberta, Canada with a commitment to provide an approximately $7.0 million drilling carry to earn a 25% working interest

During the year ended December 31, 2023, Epsilon made the following three acquisitions. Management determined that substantially all of the fair value of the gross assets acquired were concentrated in oil and gas properties and therefore accounted for these transactions as asset acquisitions and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. 61

● a 10% interest in two wellbores located in Eddy County, New Mexico for total consideration of $2.1 million paid in cash.

● a 25% working interest in 1,297 gross acres in Ector County, Texas for total consideration of $1.3 million paid in cash.

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

~~● a 25% working interest in 11,067 gross acres in Ector County, Texas for total consideration of $6.3 million paid in cash.~~

Property Sale

During the year ended December 31, 2025, Epsilon sold all of its interest in Dewey Energy Holding, LLC for $2.5 million. This sale resulted in a loss of $19.3 million. During the year ended December 31, 2024, Epsilon had no asset sales.

During the year ended December 31, 2023, Epsilon sold two wellbore-only Oklahoma assets for $12,498. This sale resulted in a loss of $1.45 million.

Property Impairment

Epsilon performs a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable. When indicators of impairment are present, the Company first compares 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 to the estimated fair values is required. This is determined based on discounted cash flow techniques using significant assumptions including production volumes, future commodity prices, and a market-specific weighted average cost of capital which are affected by expectations about future market and economic conditions. Additionally, U.S. GAAP requires that if an exploratory well is determined not to have found proved reserves, the costs incurred, net of any salvage value, are charged to expense. For unproved properties, such as leasehold costs, expected current and future market prices for similar assets are considered relative to carrying values in evaluating impairment.

~~During~~For the year ended December 31, ~~2024~~2025, ~~Epsilon~~the Company recorded an impairment of $13.452 million on the ~~Killam~~Canadian ~~project~~wells (~~interest~~2 ~~acquired~~gross, in0.5 ~~April 2024~~net) inand ~~Alberta~~$0.7 million on the New Mexico wells (2 gross, ~~Canada~~0.2 ~~One~~net) ~~well~~due ~~was~~to ~~impaired~~low asforward aoil ~~result~~prices ofon aDecember ~~decrease~~31, in2025 ~~reserves~~ (~~$0.53~~which ~~million~~are required to be used in impairment testing) and ~~one~~an ~~well~~offset ~~drilled~~frac ~~during~~hit ~~the~~impacting ~~year~~production ~~was~~and ~~deemed~~reserves ~~non-commercial~~in ~~($0.92~~New ~~million)~~Mexico. ~~For~~During the year ended December 31, ~~2023~~2024, ~~there~~Epsilon ~~was~~recorded noan 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. Refer to Note 1716 – Fair Value Measurements.

6. Revolving Line of Credit

The Company closed a new senior secured reserve based revolving credit facility on ~~June~~October 2810, ~~2023~~2025 with Frost Bank as ~~issuing~~administrative ~~bank~~agent and ~~sole~~Frost ~~lender.~~Bank ~~The~~and ~~current~~Texas ~~borrowing~~Capital ~~base~~Bank isas ~~$45~~lenders. ~~million~~As ~~(redetermined as~~ of ~~February~~December 1031, 2025), the borrowing base was $80 million, supported by the Company’s ~~upstream~~producing ~~assets~~reserves ~~in Pennsylvania~~ and is subject to semi-annual redeterminations with a maturity date of ~~June~~October 2810, ~~2027~~2029. Interest will be charged at the ~~Daily~~3-month ~~Simple~~Term SOFR rate plus a margin of 3~~.25~~-4% (depending on facility utilization), payable quarterly. The facility is secured by the assets of the Company’s Epsilon Energy USA subsidiary ~~(Borrower)~~. ~~There~~During ~~are~~March ~~currently~~2026, nothe ~~borrowings~~Company ~~under~~made a $5 million repayment on the outstanding credit facility.

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~~noncash amounts)

We were in compliance with the financial covenants of the agreement as of December 31, ~~2024~~2025.


	Balance at		Balance at
	December 31,		December 31,		~~Current~~
	~~2024~~2025		~~2023~~2024		Borrowing Base		Interest Rate
Revolving line of credit	$	—	$	—	$	45,000,000		SOFR + 3.25%
Credit facility payable	$	50,500,000	$	—	$	80,000,000		SOFR + 3.25%

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

7. Shareholders’ Equity

~~(a)~~ Authorized shares

The Company is authorized to issue an unlimited number of common shares with no par value and an unlimited number of Preferred Shares with no par value.

~~(b)~~ Purchases of Equity Securities

On ~~March~~February 1918, ~~2024~~2026, the Board ~~of Directors~~ authorized a new share repurchase program of up to 23,~~191~~014,~~320~~986 common shares, representing 10% of the outstanding common shares of ~~Epsilon~~the Company at such time, for an aggregate purchase price of not more than US $1215.0 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~~February 2719, ~~2024~~2026 and ~~was~~is set to expire onFebruary ~~March 26~~18, ~~2025~~2027, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination. 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~~On ~~previous~~February ~~share~~12, ~~repurchase program commenced on March 9~~2025, ~~2023. During~~ the ~~year~~Board ~~ended~~authorized ~~December~~a ~~31,~~new ~~2023,~~share werepurchase ~~repurchased~~program ~~968,149 common shares~~ of ~~the~~up ~~maximum~~to of 2,~~292~~200,~~644~~876 ~~authorized~~common ~~for repurchase and spent $4~~shares,~~940,295~~ ~~under~~representing ~~the~~10% ~~plan. The repurchased stock had an average price~~ of ~~$5.08~~the ~~per~~current ~~share~~outstanding ~~(excluding commissions) and 897,275~~ common shares ~~were~~of ~~retired during the year ended December 31~~Epsilon, ~~2023.~~for Inan ~~2024,~~aggregate wepurchase ~~repurchased~~price ~~248,700~~of ~~common~~not ~~shares~~more ~~and~~than ~~spent~~US $~~1,203,708~~13.0 ~~at an average price of $4~~million.82 ~~per~~The ~~share~~program ~~(excluding~~commenced ~~commissions)~~on ~~and~~February ~~retired 319~~12,~~574~~ ~~common~~2025 ~~shares~~and ~~before~~expired ~~the plan terminated~~ on ~~March~~February 2611, ~~2024~~2026.

InOn March 19, 2024, the ~~Company~~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 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 ~~373~~125,~~700~~000 common shares and spent $1627,~~831,208~~500 at an average price of $45.8800 per share (excluding commissions) under the ~~two consecutive repurchase programs~~plan.

OnIn ~~February 12~~2024, ~~2025,~~ the ~~Board~~Company ~~authorized~~also arepurchased ~~new share repurchase program of up to 2~~248,~~200,876~~700 common shares, ~~representing~~and ~~10%~~spent ~~of the current outstanding common shares of Epsilon~~$1,203,708 ~~for~~at an ~~aggregate~~average ~~purchase~~ price of ~~not~~$4.82 ~~more~~per ~~than~~share US(excluding ~~$13.0~~commissions) ~~million.~~and ~~The~~retired ~~program~~319,574 iscommon ~~pursuant~~shares tounder athe ~~normal~~2023-2024 ~~course~~repurchase ~~issuer~~program ~~bid~~before ~~and~~the ~~will~~plan beterminated ~~conducted~~on inMarch ~~accordance~~26, ~~with~~2024. ~~Rule~~During ~~10b-18~~the ~~under~~year ~~the~~ended ~~Exchange~~December ~~Act.~~31, ~~The~~2024, ~~program~~the ~~will~~Company ~~commence~~repurchased ona ~~February~~total 12of 373,700 ~~2025~~shares and ~~end~~spent ~~on February 11~~$1, ~~2026~~831,208 ~~unless~~at ~~the~~an ~~maximum~~average ~~amount~~price of ~~common~~$4.88 ~~shares~~per isshare ~~purchased~~(excluding ~~before~~commissions) ~~then~~under or the ~~Board~~two ~~approves~~previous ~~earlier~~repurchase ~~termination~~programs.

Equity Incentive Plan

The Board adopted the 2020 Equity Incentive Plan (the “2020 Plan”) on July 22, 2020 subject to approval by Epsilon’s shareholders at Epsilon’s 2020 Annual General and Special Meeting of shareholders, which occurred on September 1, 2020 (the “Meeting”). Shareholders approved the 2020 Plan at the Meeting.

The 2020 Plan provides for incentive compensation in the form of stock options, stock appreciation rights, restricted stock and stock units, performance shares and units, dividend equivalent rights, other stock-based awards and cash-based awards. Under the 2020 Plan, Epsilon is authorized to issue up to 2,000,000 common shares.

Restricted Stock Unit

For the year ended December 31, ~~2024~~2025, ~~300~~488,~~052~~283 restricted common shares with a weighted average grant date fair value of $54.9778 were awarded to the Company’s management, employees, and board of directors. For the year ended December 31, ~~2023~~2024, ~~358~~300,~~546~~052 restricted common shares with a weighted average grant date fair value of $5.4297 were awarded to the Company’s management, employees, and board of directors. These shares vest over a three or four-year period, with an equal number of shares being issued per period on the anniversary of the award resolution. The vesting of the shares is contingent on the individuals’ continued employment or service. The Company determined the fair value of the granted Restricted Stock-based on the market price of the common shares of the Company on the date of grant.

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

The following table summarizes restricted stock for the years ended December 31, 2024 and 2023:


	Year ended				Year ended
	December 31, 2024				December 31, 2023
	Number of	Weighted	Weighted		Number of	Weighted	Weighted
	Restricted	Average	Average		Restricted	Average	Average
	Shares	Remaining Life	Grant Date		Shares	Remaining Life	Grant Date
	Outstanding	(years)	Fair Value		Outstanding	(years)	Fair Value
Balance non-vested Restricted Stock at beginning of period	491,536	1.74	$	5.59	298,210	1.74	$	6.00
Granted	300,052	1.92	$	5.97	358,546	1.90	$	5.42
Vested	(230,618)	—	$	5.65	(165,220)	—	$	5.95
Balance non-vested Restricted Stock at end of period	560,970	1.61	$	5.77	491,536	1.74	$	5.59

The following table summarizes restricted stock for the years ended December 31, 2025 and 2024:

Stock compensation expense for the granted Restricted Stock is recognized over the vesting period. Stock compensation expense recognized during the year ended December 31, 2024 was $1,244,416 (during the year ended December 31, 2023, $959,525). The total fair value of vested shares during the year ended December 31, 2024 was $1,303,187 (during the year ended December 31, 2023: $875,014).


		Year ended							Year ended
		December 31, 2025							December 31, 2024
		Number of		Weighted		Weighted			Number of		Weighted		Weighted
		Restricted		Average		Average			Restricted		Average		Average
		Shares		Remaining Life		Grant Date			Shares		Remaining Life		Grant Date
		Outstanding		(years)		Fair Value			Outstanding		(years)		Fair Value
Balance non-vested Restricted Stock at beginning of period		560,970		1.61		$	5.77		491,536		1.74		$	5.59
Granted		488,283		1.50			4.78		300,052		1.92			5.97
Vested		(267,461)		—			5.60		(230,618)		—			5.65
Balance non-vested Restricted Stock at end of period		781,792		1.71		$	5.06		560,970		1.61		$	5.77

At December 31, 2024, the Company had unrecognized stock-based compensation related to these shares of $3,198,469 to be recognized over a weighted-average period of 1.30 years.

Performance Share Unit (“PSU”)

The Company historically granted PSUs, which are paid in stock to certain key employees. The number of shares ultimately issued under these awards can range from zero to 200% of target awarded amounts at the discretion of the Compensation committee of the Board of Directors. During the years ended December 31, 2024 and 2023, the Company awarded no PSUs. During the year ended December 31, 2023, a total of 15,833 common shares vested. Stock compensation expense recognized during the year ended December 31, 2024 related to PSUs was $0 (during the year ended December 31, 2023, $58,737). At December 31, 2024, the Company had no unrecognized stock-based compensation related to these shares.

Stock Options

As of December 31, 2024, the Company had no outstanding stock options.

The following table summarizes stock option activity for the years ended December 31, 2024 and 2023:


	Year ended			Year ended
	December 31, 2024			December 31, 2023
		Weighted				Weighted
	Number of	Average		Number of		Average
	Options	Exercise		Options		Exercise
Exercise price in US$	Outstanding	Price		Outstanding		Price
Balance at beginning of period	57,500	$	5.03		70,000	$	5.03
Exercised	—		—		(12,500)		5.03
Expired	(57,500)		5.03		—		—
Balance at period-end	—	$	—		57,500	$	5.03

Exercisable at period-end	—	$	—		57,500	$	5.03

Stock compensation expense for the granted Restricted Stock is recognized over the vesting period. Stock compensation expense recognized during the year ended December 31, 2025 was $1,524,902 (during the year ended December 31, 2024, $1,244,416). The total fair value of vested shares during the year ended December 31, 2025 was $1,763,433 (during the year ended December 31, 2024: $1,303,187).

At December 31, 2025, the Company had unrecognized stock-based compensation related to these shares of $4,146,227 to be recognized over a weighted-average period of 1.37 years.

Dividend Equivalent Rights

Per the 2020 Plan, all employees and directors are entitled to Dividend Equivalent Rights with respect to the payment of cash dividends on Common Shares during the period beginning on the grant date of this award and ending, with respect to each share subject to the award, on the earlier of the date the Award is settled or the date on which it is terminated. Dividend Equivalent Rights shall be paid by crediting the holder with a cash amount or with additional whole RSUs within 30 days of the date of payment of such cash dividends on Common Shares, as determined by the Committee, subject to the holder’s continued service with the Company. Such cash amount or additional RSUs shall be subject to the same terms and conditions and shall be settled in the same manner and at the same time as the RSUs originally subject to this Award.

For the year ended December 31, 2025, 47,417 common shares were issued as dividend equivalent rights. Stock compensation expense recognized during the year ended December 31, 2025 was $200,015.

~~At December 31, 2024 and 2023, the Company had unrecognized stock-based compensation related to these options of nil~~8. ~~The~~Revenue total intrinsic value of the outstanding options at December 31, 2024 was nil (at December 31, 2023: $2,875). The total intrinsic value of options exercised during the year ended December 31, 2024 was nil (during the year ended December 31, 2023: $5,500).Recognition

~~During~~Revenues ~~the~~are ~~years~~comprised ~~ended~~primarily ~~December~~of 31sales of natural gas, ~~2024~~oil and ~~2023~~NGLs, along with the revenue generated from the Company’s ~~awarded~~ownership nointerest ~~stock~~in ~~options~~the Auburn GGS in Pennsylvania.

56Overall, product sales revenue generally is recorded in the month when contractual delivery obligations are satisfied, which occurs when control is transferred to the Company’s customers at delivery points based on contractual terms and conditions. In addition, gathering and compression revenue generally is recorded in the month when contractual service obligations are satisfied, which occurs as control of those services is transferred to the Company’s customers. Gathering System revenues derived from Epsilon’s production, which have been eliminated from total gathering system revenues (“elimination entry”), amounted to $1.9 million and $1.1 million, respectively, for the years ended December 31, 2025 and 2024.

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

8. Revenue Recognition

Revenues are comprised primarily of sales of natural gas, oil and NGLs, along with the revenue generated from the Company’s ownership interest in the Auburn gas gathering system in Northeastern Pennsylvania.

Overall, product sales revenue generally is recorded in the month when contractual delivery obligations are satisfied, which occurs when control is transferred to the Company’s customers at delivery points based on contractual terms and conditions. In addition, gathering and compression revenue generally is recorded in the month when contractual service obligations are satisfied, which occurs as control of those services is transferred to the Company’s customers. 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.

The following table details revenue for the years ended December 31, 2024 and 2023:


	Year Ended December 31,
	2024		2023
Operating revenue
Natural gas	$	10,786,068	$	14,864,214
Natural gas liquids		1,481,958		984,418
Oil and condensate		13,730,686		5,090,589
Gathering and compression fees (1)		5,524,063		9,790,531
Total operating revenue	$	31,522,775	$	30,729,752

The following table details revenue for the years ended December 31, 2025 and 2024:


		Year Ended December 31,
		2025			2024
Revenue
Natural gas		$	29,121,446		$	10,786,068
Natural gas liquids			1,978,860			1,481,958
Oil and condensate			13,803,515			13,730,686
Gathering and compression fees⁽¹⁾			6,683,735			5,524,063
Total revenue		$	51,587,556		$	31,522,775

(1)Net of elimination

Product Sales Revenue

The Company enters into contracts with third -party purchasers to sell its natural gas, oil, NGLs and condensate production. Under these product sales arrangements, the sale of each unit of product represents a distinct performance obligation. Product sales revenue is recognized at the point in time that control of the product transfers to the purchaser based on contractual terms which reflect prevailing commodity market prices. To the extent that marketing costs are incurred by the Company prior to the transfer of control of the product, those costs are included in lease operating expenses on the Company’s consolidated statements of operations and comprehensive income.

Settlement statements for product sales, and the related cash consideration, are generally received from the purchaser within 30 days. For operated production in Wyoming, cash consideration is typically received within 30 days after the end of a production month for oil, while natural gas and NGLs cash consideration is typically received within 60 days after the end of a production month. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the natural gas, oil, NGLs, or condensate. Estimated revenue due to the Company is recorded within the receivables line item on the accompanying consolidated balance sheets until payment is received.

Gas Gathering and Compression Revenue

The Company also provides natural gas gathering and compression services through its ownership interest in the Auburn ~~gas~~GGS ~~gathering system~~ in Pennsylvania. For the provision of gas gathering and compression services, the Company collects its share of the gathering and compression fees per unit of gas serviced and recognizes gathering revenue over time using an output method based on units of gas gathered.

The settlement statement from the operator of the Auburn GGS is received two months after transmission and compression has occurred. As a result, the Company must estimate the amount of production that was transmitted and compressed within the system. Estimated revenue due to the Company is recorded within the receivables line item on the accompanying consolidated balance sheets until payment is received.

57Current Expected Credit Losses

Under ASU 326, Financial Instruments – Credit Losses, estimated losses on financial assets are provided through an allowance for credit losses. We also have accounts receivable which are primarily from purchasers of oil and natural gas, counterparties to our financial instruments, and revenues earned for compression and gathering services. Our oil, gas, and natural gas liquids accounts receivables are generally collected within 30 days after the end of the month. Compression and gathering receivables are generally collected within 60 days after the end of the month. We assess collectability through various procedures, including review of our trade receivable balances by counterparty, assessing economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount and age of past due accounts. As of December 31, 2025 and 2024, we determined that our allowance for credit loss was nil.

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

Current Expected Credit Losses

Under ASU 326, Financial Instruments – Credit Losses, estimated losses on financial assets are provided through an allowance for credit losses. We also have accounts receivable which are primarily from purchasers of oil and natural gas, counterparties to our financial instruments, and revenues earned for compression and gathering services. Our oil, gas, and natural gas liquids accounts receivables are generally collected within 30 days after the end of the month. Compression and gathering receivables are generally collected within 60 days after the end of the month. We assess collectability through various procedures, including review of our trade receivable balances by counterparty, assessing economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount and age of past due accounts. As of December 31, 2024 and 2023, we determined that our allowance for credit loss was nil.

The following table details accounts receivable as of December 31, 2025, 2024 and 2023:


	December 31,		December 31,		December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Accounts receivable
Natural gas and oil sales	$	410,~~888~~848,~~294~~263	$	4,~~327~~888,~~886~~294	$	54,~~696~~327,~~419~~886
Joint interest billing		—3,603,864		~~17,476~~—		2017,~~454~~476
Gathering and compression fees		~~918~~1,~~471~~307,947		1918,~~543,239~~471		1,~~483~~543,~~956~~239
Commodity contract		36167,~~957~~636		7236,~~075~~957		—72,075
Interest		—		~~54,772~~—		~~557~~54,772
Total accounts receivable	$	5,843,722	$	6,015,448	$	7,201,386
Other receivables		204,791		—		—
Total accounts receivable	$	16,132,501	$	5,843,722	$	6,015,448

9. Accumulated Other Comprehensive Income

Accumulated other comprehensive income includes certain transactions that have generally been reported in the consolidated statements of changes in shareholders’ equity. The activity in accumulated other comprehensive income during the years ended December 31, ~~2024~~2025 and ~~2023~~2024 consisted of the following:


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024
Balance at beginning of period	$	910,~~772~~033,~~277~~267	$	9,~~774~~772,~~551~~277
Translation gain/(loss)		262,588		(3,872)
Translation (loss)/gain		(136,700)		262,588
Unrealized (loss)/gain on securities		(1,598)		1,598
Unrealized gain/(loss) on securities		—		(1,598)
Balance at end of period	$	109,~~033~~896,~~267~~567	$	910,~~772~~033,~~277~~267

10. Income Taxes

Net income (loss) before income taxes is as follows for the periods indicated:


	Year ended December 31,
	~~2024~~2025		~~2023~~2024
Foreign	$	(25,~~769~~002,~~534~~874)	$	(12,~~167~~769,~~609~~534)
U.S.		6(433,~~326,427~~258)		116,~~313~~326,~~209~~427
	$	3(5,~~556~~436,~~893~~132)	$	103,~~145~~556,~~600~~893

We file a ~~federal~~ income tax ~~return~~returns in the United States, Canada, and various state and local jurisdictions.

We believe that we have appropriate support for the income tax positions taken and to be taken on the Company's tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company's tax returns are open to audit under the statute of limitations for the years ending December 31, 2021 through December 31, 2025.

5866

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

including past experience and interpretations of tax law applied to the facts of each matter. The Company's tax returns are open to audit under the statute of limitations for the years ending December 31, 2021 through December 31, 2024.

The following tables present the Company’s current and deferred tax expense (benefit) for the periods indicated:


	Year ended December 31,
	2024		2023
Current:
Federal	$	391,009	$	1,902,584
State		53,450		361,314
Total current income tax expense		444,459		2,263,898
Deferred:
Federal		1,372,363		1,013,452
State		(187,729)		(76,903)
Total deferred tax expense		1,184,634		936,549
Income tax expense	$	1,629,093	$	3,200,447

The following tables present the Company’s current and deferred tax (benefit) expense for the periods indicated:

The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate to the income tax provision in our financial statements. Our effective tax rate for 2024 and 2023 differs from the statutory rate primarily due to states taxes, foreign withholding taxes, and the recognition of a valuation allowance on our Canadian and Oklahoma state deferred tax assets.


		Year ended December 31,
		2025			2024
Current:
Federal		$	218,565		$	391,009
State			16,235			53,450
Foreign			10,923			—
Total current income tax expense			245,723			444,459
Deferred:
Federal			(96,957)			1,372,363
State			213,965			(187,729)
Total deferred tax expense			117,008			1,184,634
Income tax expense		$	362,731		$	1,629,093


	Year Ended				Year Ended
	December 31,		Effective		December 31,		Effective
	2024		Tax Rate		2023		Tax Rate
Income tax provision computed at the statutory federal tax rate	$	746,947	21.00	%	$	2,130,576	21.00	%
Difference in Canadian and U.S. tax rate		(55,391)	(1.56)	%		(23,352)	(0.23)	%
Adjustment of Canadian deferred tax balances		983,975	27.66	%		(128,552)	(1.27)	%
Valuation allowance on Canadian loss		(425,667)	(11.97)	%		397,102	3.91	%
Return to provision adjustment		(1,245)	(0.04)	%		5,244	0.05	%
State taxes		(129,233)	(3.63)	%		108,401	1.07	%
State valuation allowance		(16,271)	(0.46)	%		100,133	0.99	%
Foreign withholding on dividends		414,250	11.65	%		630,722	6.22	%
Miscellaneous other items		111,728	3.14	%		(19,827)	(0.20)	%
Income tax expense	$	1,629,093	45.79	%	$	3,200,447	31.54	%

The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate to the income tax provision in our financial statements. Our effective tax rate for 2025 differs from the statutory rate primarily due to states taxes, foreign withholding taxes, and the recognition of a valuation allowance on our Canadian and Oklahoma state deferred tax assets.

Our effective tax rate for 2024 and 2023, excluding the impact of Canadian loss net valuation allowance, is 25.48% and 28.29%, respectively.


		Year Ended
		December 31,			Effective
		2025			Tax Rate
US Federal Statutory Tax Rate		$	(1,141,588)		21.00	%
State and Local Income Taxes, Net of Federal Income Tax Effect*			226,790		(4.17)	%
Foreign Tax Effects
Canada
Statutory tax rate difference between Canada and United States			(467,456)		8.60	%
US withholding tax on dividends from United States to Canada			248,783		(4.58)	%
Changes in valuation allowance			1,144,121		(21.05)	%
Other			(26,291)		0.48	%
Alberta
Statutory tax rate difference between Alberta and United States			(195,946)		3.60	%
Changes in valuation allowance			610,198		(11.22)	%
Other			(14,022)		0.26	%
Nontaxable or Nondeductible Items
Other			(21,858)		0.40	%
Income tax expense		$	362,731		(6.68)	%

*State taxes in Pennsylvania made up the majority (greater than 50 percent) of the tax effect in this category.

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2025 and 2024

Our effective tax rate for 2024 differs from the statutory rate primarily due to states taxes, foreign withholding taxes, & the recognition of a valuation allowance on our Canadian and Oklahoma state deferred tax assets. Our effective tax rate for 2024, excluding the impact of Canadian loss net valuation allowance, is 25.48%.


	Year Ended
	December 31,			Effective
	2024			Tax Rate
Income tax provision computed at the statutory federal tax rate	$	746,947		21.00	%
Difference in Canadian and U.S. tax rate		(55,391)		(1.56)	%
Adjustment of Canadian deferred tax balances		983,975		27.66	%
Valuation allowance on Canadian loss		(425,667)		(11.97)	%
Return to provision adjustment		(1,245)		(0.04)	%
State taxes		(129,233)		(3.63)	%
State valuation allowance		(16,271)		(0.46)	%
Foreign withholding on dividends		414,250		11.65	%
Miscellaneous other items		111,728		3.14	%
Income tax expense	$	1,629,093		45.79	%

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

59Net deferred tax liabilities consisted of the following at December 31, 2025 and 2024:


		As of December 31,
		2025			2024
Deferred tax assets:
US Federal and state net operating loss carryforwards		$	2,030,390		$	358,224
Canadian net operating loss carryforwards			12,839,073			11,084,754
ARO			1,768,208			873,169
Lease Liabilities			87,015			114,196
Other			275,810			159,582
Unrealized derivatives			—			116,743
Gross deferred tax assets			17,000,496			12,706,668
Valuation allowance			(13,258,688)			(11,213,899)
Total net deferred tax assets			3,741,808			1,492,769
Deferred tax liabilities:
Oil and gas property			(14,184,652)			(12,620,466)
Partnership			(1,413,943)			(1,528,368)
ROU Assets			(60,811)			(82,512)
Unrealized derivatives			(937,987)			—
Gross deferred tax liabilities			(16,597,393)			(14,231,346)
Net deferred tax liability		$	(12,855,585)		$	(12,738,577)

As of December 31, 2025, we have $1.4 million of U.S. federal net operating loss carry-forwards, all of which has an indefinite carryforward period but is limited to offset 80% of taxable income in any future year. We also have approximately $30.8 million of state net operating loss carry-forwards (tax-effected $0.6 million), of which $0.2 million expires in 2037 and the remaining can be carried forward indefinitely. These loss carryforwards may reduce future taxable income, however, the extent of which may be limited in the circumstances that an IRC Section 382 limitation would apply due to an ownership change. A state valuation allowance of $0.4 million is applicable to the net state deferred tax assets attributable to Oklahoma because of objective negative evidence on the cumulative loss incurred in the state over the three-year period ended December 31, 2025. As of December 31, 2025, we have $48.2 million (tax-effected 11.1 million) of Canadian net operating loss carry-forwards. A separate valuation allowance of $12.8 million attributable to Canadian net operating losses and other tax carryovers is recorded because it is more likely than not to be utilized.

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

Net deferred tax liabilities consisted of the following at December 31, 2024 and 2023:


	As of December 31,
	2024		2023
Deferred tax assets:
State net operating loss carryforwards	$	358,224	$	396,416
Canadian net operating loss carryforwards		11,084,754		11,510,422
ARO		873,169		865,214
Lease Liabilities		114,196		139,153
Other		159,582		—
Unrealized derivatives		116,743		89,758
Gross deferred tax assets		12,706,668		13,000,963
Valuation allowance		(11,213,899)		(11,655,838)
Total deferred tax assets		1,492,769		1,345,125
Deferred tax liabilities:
Oil and gas property		(12,620,466)		(10,765,374)
Partnership		(1,528,368)		(1,752,767)
ROU Assets		(82,512)		(109,169)
Unrealized derivatives		—		(271,758)
Gross deferred tax liabilities		(14,231,346)		(12,899,068)
Net deferred tax liability	$	(12,738,577)	$	(11,553,943)

of operations and comprehensive loss. Accrued interest and penalties are included in other non-current liabilities in the consolidated balance sheet and were $0 as of December 31, 2025 and 2024.

Total net income tax payments were $2.2 million for the year ended December 31, 2025. The following table lists the components of the payments for income taxes:

As of December 31, 2024, we have no federal net operating loss carry-forwards and approximately $11.3 million of state net operating loss carry-forwards, of which $0.2 million expires in 2037 and the remaining can be carried forward indefinitely. These loss carryforwards may reduce future taxable income, however, the extent of which may be limited due to any IRC Section 382 limitation. A state valuation allowance of $0.13 million is applicable to the net state deferred tax assets attributable to Oklahoma because of objective negative evidence on the cumulative loss incurred in the state over the three-year period ended December 31, 2024. As of December 31, 2024, we have $40.9 million of Canadian net operating loss carry-forwards. A separate valuation allowance of $11.1 million attributable to Canadian net operating losses and other tax carryovers is recorded because it is more likely than not to be utilized. The net change in the total valuation allowance for each of the years ended December 31, 2024 and 2023 was a decrease of $0.5 million and an increase of $0.50 million, respectively.


		Year Ended
		December 31,
		2025
US Federal		$	1,417,860
State
Pennsylvania			755,138
Other			3,986
Total net payments		$	2,176,984

The Company does not have any material uncertain tax positions. The Company recognizes interest expense and penalties related to the uncertain tax position in the income tax expense line in the accompanying consolidated statements of operations and comprehensive loss. Accrued interest and penalties are included in other non-current liabilities in the consolidated balance sheets and were $0 as of December 31, 2024 and 2023.

11. Commitments and Contingencies

The Company also enters into commitments for capital expenditures in advance of the expenditures being made. As of December 31, 2024, our commitments for capital expenditures were $7.8 million. All of the capital commitments are related to the first two wells of the joint venture in Alberta entered into in October 2024. Of the total commitment, $3.4 million is drilling carry in favor of the operator, and the remaining amount is our working interest share of outstanding authorizations for future expenditures.

11. Commitments and Contingencies

The Company also enters 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 drilling costs.

Litigation

In 2025, the Company filed a lawsuit against a contractor regarding alleged non-performance while running casing in a well. The Company is seeking damages due to its inability to complete the Leavitt Fed 2-9-4MH well. The Company is in the process of scheduling arbitration

The Company has intervened as a defendant-intervenor in litigation challenging BLM’s issuance of federal oil and gas leases acquired by the Company in 2017, 2018, and 2020. Plaintiffs allege deficiencies in BLM’s environmental review under NEPA. The Company intervened to protect its leasehold interests. Management does not believe the outcome will have a material adverse effect on the Company’s financial position.

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

12. Leases

Under ASC 842, Leases, the Company recognized an operating lease related to its corporate office as of December 31, 2024 summarized in the following table:


	December 31,		December 31,
	2024		2023
Asset
Operating lease right-of-use assets, long term	$	344,589	$	441,987
Total operating lease right-of-use assets	$	344,589	$	441,987

Liabilities
Operating lease liabilities	$	121,135	$	86,473
Operating lease liabilities, long term		355,776		476,911
Total operating lease liabilities	$	476,911	$	563,384

Operating lease costs	$	236,044	$	144,490

Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	214,230	$	27,010
Right-of-use assets obtained in exchange for new operating lease liabilities	$	—	$	535,149
Weighted average remaining lease term (years) - operating lease		2.50		3.00
Weighted average discount rate (annualized) - operating lease		8.25%		8.25%

Supplemental Disclosures was an admission of the legal necessity or materiality under applicable law of any of the disclosures set forth in the Preliminary Proxy Statement or the Definitive Proxy Statement. To the contrary, we deny all allegations in the Demands and Complaints that any additional disclosure was required.

~~On March 1, 2023, the Company commenced a new office lease with a 70 month lease term and future lease payments estimated to be approximately $0~~12.85 million. There are no other pending leases, and no lease arrangements in which the Company is the lessor. Lease expense for operating leases was $0.24 million and $0.14 for the years ended December 31, 2024 and 2023, respectively. This lease expense is presented in other general and administrative expenses in the consolidated statements of operations and comprehensive income.Leases

~~Future~~Under ~~minimum~~ASC 842, Leases, the Company recognized an operating lease ~~payments~~related to its corporate office as of December 31, ~~2024~~2025 ~~are~~summarized asin ~~follows~~the following table:


	Operating Leases
2025	$	173,550
2026		177,021
2027		180,492
2028		183,963
Total minimum lease payments		715,026
Less: imputed interest		(238,115)
Present value of future minimum lease payments		476,911
Less: current obligations under leases		(121,135)
Long-term lease obligations	$	355,776


		December 31,			December 31,
		2025			2024
Asset
Operating lease right-of-use assets, long term		$	488,949		$	344,589
Total operating lease right-of-use assets		$	488,949		$	344,589

Liabilities
Operating lease liabilities		$	271,494		$	121,135
Operating lease liabilities, long term			340,052			355,776
Total operating lease liabilities		$	611,546		$	476,911

Operating lease costs		$	269,910		$	236,044

Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases		$	316,435		$	214,230
Weighted average remaining lease term (years) - operating lease			1.86			2.50
Weighted average discount rate (annualized) - operating lease			8.25%			8.25%

On March 1, 2023, the Company commenced a new office lease with a 70 month lease term and future lease payments estimated to be approximately $0.85 million. Through its subsidiaries, the Company also leases office space in both Englewood, CO and Wright, WY. Lease expense for operating leases was $0.27 million and $0.24 for the years ended December 31, 2025 and 2024, respectively. This lease expense is presented in other general and administrative expenses in the consolidated statements of operations and comprehensive income.

Future minimum lease payments as of December 31, 2025 are as follows:


	Operating Leases
2026	$	334,155
2027		282,059
2028		183,963
Total minimum lease payments		800,177
Less: imputed interest		(188,631)
Present value of future minimum lease payments		611,546
Less: current obligations under leases		(271,494)
Long-term lease obligations	$	340,052

13. Net Income Per Share

Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities.

6170

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

The net income used in the calculation of basic and diluted net income per share are as follows:


	Year ended December 31,
	~~2024~~2025		~~2023~~2024
Net income	$	1,927,800	$	6,945,153
Net (loss) income	$	(5,798,863)	$	1,927,800

In calculating the net income per share, basic and diluted, the following weighted-average shares were used:


	Year ended December 31,
	~~2024~~2025	~~2023~~2024
Basic weighted-average number of shares outstanding	2123,~~930~~020,~~277~~672	2221,~~496~~930,~~772~~277
Dilutive stock options	—	4,431
Unvested time-based restricted shares	—	—
Unvested performance-based restricted shares	—	10,444
Diluted weighted-average shares outstanding	23,020,672	21,930,277
Diluted weighted-average shares outstanding	21,930,277	22,511,647

We excluded the following shares from the diluted net income per share because their inclusion would have been anti-dilutive.


	Year ended December 31,
	~~2024~~2025	~~2023~~2024
Anti-dilutive options	—	53,069
Anti-dilutive unvested time-based restricted shares	531,610	512,072
Anti-dilutive unvested time-based restricted shares	512,072	331,810
Anti-dilutive unvested performance-based restricted units	—	5,389
Total Anti-dilutive shares	512,072	390,268

14. Operating Segments

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker (CODM). The CODM, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as executive management consisting of the Chief Executive Officer, Chief Financial Officer, and Chief Operating Officer. The CODM uses the Company’s consolidated financial results, including operating income or loss by segment, to make key operating decisions, assess performance, and to allocate resources. Segment performance is evaluated based on operating income or loss as shown in the table below. Interest income and income taxes are managed separately on a group basis.

The Company’s reportable segments are as follows:

The Upstream segment activities include acquisition, development and production of natural gas and oil reserves on properties within the United States and Canada; and

The Gas Gathering segment partners with two other companies to operate a natural gas gathering system.

6271

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, ~~2024~~2025 and ~~2023~~2024

Segment activity as of, and for the years ended December 31, 2024 and 2023 is as follows:


	Upstream		Gas Gathering		Total
As of and for the year ended December 31, 2024
Operating revenue
Natural gas	$	10,786,068	$	—	$	10,786,068
Natural gas liquids		1,481,958		—		1,481,958
Oil and condensate		13,730,686		—		13,730,686
Gathering and compression fees		—		5,524,063		5,524,063
Intersegment gathering and compression fees		—		1,135,176		1,135,176
		25,998,712		6,659,239		32,657,951

Reconciliation of operating revenue
Elimination of intersegment revenues						(1,135,176)
Total consolidated operating revenue(1)						31,522,775

Operating costs
Gathering, transportation, and compression		4,996,764		—		4,996,764
Other lease operating expense		2,268,060		2,265,190		4,533,250
Intersegment other lease operating expense		1,135,176		—		1,135,176
Impairment		1,450,076		—		1,450,076
Depletion, depreciation, amortization and accretion		9,268,155		916,964		10,185,119
Segment operating income	$	6,880,481	$	3,477,085	$	9,222,390

Reconciliation of segment operating income
Salary expense						2,815,428
Stock based compensation						1,244,416
Other general and administrative						2,873,286
Elimination of intersegment other lease operating expenses						(1,135,176)
Total consolidated operating income						3,424,436

Other income (expense)
Interest income						493,277
Interest expense						(46,400)
Loss on derivative contracts						(391,147)
Other income						76,727
Other income, net						132,457
Net income before income tax expense					$	3,556,893

Capital expenditures (2)	$	36,219,444	$	341,452	$	36,560,896
Segment assets	$	97,944,718	$	6,666,860	$	104,611,578

Total segment assets reconciled to consolidated amounts are as follows:
Total segment assets					$	104,611,578
Current assets, net						14,131,519
Other property and equipment						897,099
Operating lease right-of-use asset						344,589
Restricted Cash						470,000
					$	120,454,785

Segment activity as of, and for the years ended December 31, 2025 and 2024 is as follows:

Year ended December 31,

~~2024~~2025

~~2023~~2024

Depletion, depreciation, amortization and accretion

1012,~~185~~170,~~119~~320

710,~~685~~185,~~084~~119

Filing Compare · Epsilon Energy Ltd.