10-K

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.

OR

☐ 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: $90.9 million. There were 22,008,766 Common Shares (no par value) outstanding as of March 18, 2025.

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’’ 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.

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‘‘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’’ One thousand BOE.

‘‘MBOE/d’’ One MBOE per day.

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

‘‘MMBbl’’ One million Bbl.

‘‘MMBOE’’ One million 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.

‘‘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.

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‘‘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:

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

b. 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:

a. 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

b. 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

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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.

‘‘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.

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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, Epsilon’s total estimated net proved reserves were 69,401 million cubic feet of natural gas reserves, 876,808 barrels of NGL reserves, and 1,572,465 barrels of oil and other liquids. Epsilon holds leasehold rights to approximately 102,506 gross (23,602 net) acres. The Company has natural gas production in the Marcellus Shale in Pennsylvania; oil, natural gas liquids and natural gas production in the Permian Basin in Texas and New Mexico, the NW Anadarko Basin in Oklahoma; and oil production in the Western Canadian Sedimentary Basin in Alberta, Canada.

We conduct operations in the United States through our wholly owned subsidiaries Epsilon Energy USA Inc., an Ohio corporation, or Epsilon Energy USA; Epsilon Midstream, LLC, a Pennsylvania limited liability company, or Epsilon Midstream; Epsilon Operating, LLC, a Delaware limited liability company; Dewey Energy GP LLC, a Delaware limited liability company; Dewey Energy Holdings LLC, a Delaware limited liability company; and Altolisa Holdings, LLC, a Delaware limited liability company.  

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.

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 highlights of 2024

Operational Highlights

Marcellus Shale—Pennsylvania

● During the year ended December 31, 2024, Epsilon’s realized natural gas price was $1.80 per Mcf, excluding the impact of hedges, a 4% increase from $1.74 for the year ended December 31, 2023.

● Total natural gas sales for the year ended December 31, 2024 were 5.7 Bcf, a 28% decrease from the 7.9 Bcf for the year ended December 31, 2023, driven by curtailed production volumes.

● Gathered and delivered 36.9 Bcf gross (12.9 Bcf net to Epsilon’s interest) during the year, or 101 MMcf/d through the Auburn GGS.

● We participated in the drilling of 3 gross (0.04 net) and the completion of 10 gross (0.82 net) Marcellus wells in 2024. 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.

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Permian Basin—Texas and New Mexico

● During the year ended December 31, 2024, Epsilon’s realized price for all Permian Basin production was $53.52 per BOE, excluding the impact of hedges, a 2% increase from the $52.49 for the year ended December 31, 2023.

● Total sales for the year ended December 31, 2024, including oil, natural gas, and other liquids, were 259 MBOE, a 242% increase from the 75.7 MBOE for the year ended December 31, 2023.

● In 2024, the Company acquired a 25% working interest in three producing wells and 3,246 gross undeveloped acres in Ector County, Texas.

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

Anadarko, NW STACK Trend—Oklahoma

● During the year ended December 31, 2024, Epsilon’s realized price for all Oklahoma production was $4.34 per Mcfe, excluding the impact of hedges, a 19% decrease from $5.35 for the year ended December 31, 2023.

● Total sales for the year ended December 31, 2024, including natural gas, oil, and other liquids, were 0.41 Bcfe, a 32% decrease from 0.60 Bcfe for the year ended December 31, 2023.

Western Canadian Sedimentary Basin—Alberta, Canada

● During the year ended December 31, 2024, Epsilon’s realized price for Canada oil production was $46.04 per Bbl.

● Total oil sales for the year ended December 31, 2024 were 2.5 MBbl.

● In 2024, the Company participated in the drilling of 4 gross (1.5 net) wells in Canada. One well went into production in September 2024. As of December 31, 2024, one well was deemed non-commercial, one well was still being drilled, and one well was waiting on completion.

Properties

Wells

As of December 31, 2024, Epsilon’s 102,506 gross (23,602 net) acres are located in the United States and Canada and include 368 gross (37.90 net) wells.

	Gross(1)	Net(2)
Producing Wells
Gas	274	29.87
Oil	39	5.58
Total Producing Wells	313	35.45
Non-Producing Wells	55	2.45
Total Wells	368	37.90

Acreage

As of December 31, 2024, our leasehold inventory consisted of the following acreage amounts, rounded to the

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nearest acre:

	Gross(1)	Net(2) (3)
Developed Acres
Pennsylvania	11,270	4,807
Texas	2,763	691
Oklahoma	5,113	991
Canada	640	320
	19,786	6,809
Undeveloped Acres
Pennsylvania	335	327
Texas	13,829	3,455
Oklahoma	54,953	6,209
Canada	13,603	6,802
	82,720	16,793
Total Acres
Pennsylvania	11,605	5,134
Texas	16,592	4,146
Oklahoma	60,066	7,200
Canada	14,243	7,122
Total acres	102,506	23,602

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

(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 and 2023.

The two segments are as follows:

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

Gathering System: Interest in a natural gas gathering system.

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

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Oil and Natural Gas Production and Revenues and Gathering System Revenues

A summary of our net oil and natural gas production, average oil and natural gas prices and related revenues and our gathering system revenues for the years ended December 31, 2024 and 2023, respectively, follows:

	Year ended
	December 31,
	2024		2023
Production Volumes
Pennsylvania
Natural gas (MMcf)		5,699		7,906
Total (Mmcfe)		5,699		7,906
Permian Basin
Natural gas (MMcf)		205		80
Natural gas liquids (MBOE)		52		18
Oil & other liquids (MBbl)		173		44
Total (Mmcfe)		1,554		454
Oklahoma
Natural gas (MMcf)		237		354
Natural gas liquids (MBOE)		17		21
Oil & other liquids (MBbl)		11		21
Total (Mmcfe)		408		605
Canada
Oil & other liquids (MBbl)		3		-
Total (Mmcfe)		15		-
Company Total
Natural gas (MMcf)		6,142		8,340
Natural gas liquids (MBOE)		69		39
Oil & other liquids (MBbl)		187		65
Total (Mmcfe)		7,676		8,965

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	Year ended
	December 31,
	2024		2023
Revenues
Pennsylvania
Natural gas revenue	$	10,247,834	$	13,733,052
Avg. Price ($/Mcf)	$	1.80	$	1.74
Gathering system revenue (net of elimination)	$	5,524,063	$	9,790,531
Total PA Revenues	$	15,771,897	$	23,523,583
Permian Basin
Natural gas revenue	$	32,930	$	117,112
Avg. Price ($/Mcf)	$	0.16	$	1.47
Natural gas liquids revenue	$	1,060,967	$	353,612
Avg. Price ($/Bbl)	$	20.48	$	19.78
Oil and condensate revenue	$	12,770,258	$	3,501,098
Avg. Price ($/Bbl)	$	73.81	$	78.71
Total Permian Basin Revenues	$	13,864,155	$	3,971,822
Oklahoma
Natural gas revenue	$	505,304	$	1,014,050
Avg. Price ($/Mcf)	$	2.13	$	2.87
Natural gas liquids revenue	$	420,991	$	630,806
Avg. Price ($/Bbl)	$	24.16	$	29.96
Oil and condensate revenue	$	844,265	$	1,589,491
Avg. Price ($/Bbl)	$	76.75	$	76.37
Total OK Revenues	$	1,770,560	$	3,234,347
Canada
Oil and condensate revenue	$	116,163	$	—
Avg. Price ($/Bbl)	$	—	$	—
Total Canada Revenues	$	116,163	$	—
Total Company Revenues	$	31,522,775	$	30,729,752

Gathering System Operations

Epsilon Energy USA is the 100% owner of Epsilon Midstream, which owns a 35% undivided interest in the Auburn GGS, located in Susquehanna County, Pennsylvania, with partners Appalachia Midstream Services, LLC (43.875%) and Equinor Pipelines, LLC (21.125%). The Anchor Shippers, consisting of Epsilon Energy USA, Equinor USA Onshore Properties, Inc., and Expand Energy Corporation, dedicated approximately 18,000 mineral acres to the Auburn GGS on January 1, 2012 for an initial term of 15 years under an Anchor Shopper Gas Gathering Agreement for Northern Pennsylvania whereby the Auburn GGS owners receive a fixed percentage rate of return on the total capital invested in the construction of the system.

On May 17, 2024, Epsilon Energy USA, Inc. (“Epsilon”) executed a new Anchor Shipper Gas Gathering Agreement for Northern Pennsylvania (the “ASGGA”) with operator Appalachia Midstream Services, LLC for a primary term of ten years and an effective date of January 1, 2024. Epsilon simultaneously terminated the prior agreement. 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

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the gathering rate of the originating gathering system plus 25% of the Auburn GGS gathering rate. The purpose of the reduced rate is to attract additional volumes that require delivery to Tennessee Gas Pipeline when there is spare capacity at the Auburn compression facility, or the “Auburn CF”.

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. 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 220,000 Mcf per day. The facility capacity could be increased again, if required, by either adding compression units or increasing the design suction pressure.

The Auburn CF delivers processed natural gas into the Tennessee Gas Pipeline at the Shoemaker Dehy receipt meter. The 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 and 2023, the Auburn GGS delivered 36.9 Bcf and 66.2 Bcf respectively, of natural gas, or 101 and 181 MMcf per day.

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.

Proved Reserves

Per our reserve report prepared by independent petroleum consultants, DeGolyer and MacNaughton, our estimated proved reserves as of December 31, 2024, are summarized in the table below. 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.

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● In 2023 in Pennsylvania, we drilled 7 gross (0.74 net) wells and completed 2 gross (0.02 net) wells. The two wells turned online in January 2023.

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

● In 2023 in the Permian Basin, The Company participated in the drilling and completion of 4 gross (0.7 net) wells. These wells went into production in April 2023 (1 – New Mexico), May 2023 (1 – New Mexico) and October 2023 (2 – Texas).

● In 2024 in Oklahoma, there was no development activity.

● In 2023 in Oklahoma, we completed 1 gross (0.11 net) well. (Net development capital $0.7 million). The well turned online in May 2023.

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

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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, 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, 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.

Geographic Locations of Operations

Approximately 50% and 77% of our revenue during fiscal years 2024 and 2023, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania. 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 the geographic concentration, we may be disproportionately exposed to the effect of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of crude oil or natural gas.

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, we had ten full-time employees (including executive officers) in Houston, Texas. 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, or the EPA, issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that

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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, 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

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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.

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 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

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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 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	560,970	$	5.77	676,337

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

	As of			As of
	December 31, 2024			December 31, 2023
		Weighted			Weighted
	Number of	Average		Number of	Average
	Options	Exercise		Options	Exercise
	Outstanding	Price		Outstanding	Price
Balance at beginning of period	57,500	$	5.03	70,000	$	5.03
Exercised	—		—	(12,500)		5.03
Expired/Forfeited	(57,500)		—	—		—
Balance at period-end	—	$	—	57,500	$	5.03
Exercisable at period-end	—	$	—	57,500	$	5.03

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

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The following table sets out the number of time restricted common shares available to be issued upon vesting over the next three years and the changes during the year pursuant to our share compensation plans and the weighted average market price at date of issue for outstanding shares for the periods indicated:

	As of			As of
	December 31, 2024			December 31, 2023
		Weighted			Weighted
	Number of	Average		Number of	Average
	Shares	Grant Date		Shares	Grant Date
	Outstanding	Market Price		Outstanding	Market Price
Balance non-vested Restricted Stock at beginning of period	491,536	$	6.00	298,210	$	3.96
Granted	300,052		5.97	358,546		6.28
Vested	(230,618)		5.65	(165,220)		4.34
Forfeited	—		—	—		—
Balance non-vested Restricted Stock at end of period	560,970	$	5.77	491,536	$	6.00

The following table sets out the number of performance-based common shares available to be issued upon vesting over the next three years and the changes during the year pursuant to our share compensation plans and the weighted average market price at date of issue for outstanding shares for the periods indicated:

	As of			As of
	December 31, 2024			December 31, 2023
		Weighted			Weighted
	Number of	Average		Number of	Average
	Shares	Grant Date		Shares	Grant Date
	Outstanding	Market Price		Outstanding	Market Price
Balance non-vested Performance Shares at beginning of period	—	$	—	15,833	$	3.84
Vested	—		—	(15,833)		3.48
Balance non-vested Performance Shares at end of period	—	$	—	—	$	—

Recent Developments

None.

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 to experience low prices, we may, among other things, be unable to meet all our financial obligations or make planned expenditures.

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Substantial and extended declines in oil and natural gas prices may result in impairments of proved natural gas and oil properties or undeveloped acreage and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures. 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 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,

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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 grow.

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

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

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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 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 debt. In the event our lenders accelerate the repayment of our borrowings, we may not have sufficient assets 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.

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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.

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

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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.

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 99% of our oil and natural gas properties are operated by third-party operators.  As such, we will be dependent on such operators for the timing of activities related to such properties and will largely be unable to direct or control the activities of the operators. 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.

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In addition to the operator, our success will depend in large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse effect on us. We do not have key-person insurance in effect 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 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, 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

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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 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 natural gas may depend upon our ability to acquire space on pipelines that deliver crude oil and natural gas to commercial markets. This risk is somewhat mitigated by our 35% ownership of a gathering system in the Marcellus Shale in Pennsylvania. We may also be affected by extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, and many other aspects of the oil and natural gas business.

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

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.

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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.

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.

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

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

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

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have an adverse effect 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.

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

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 the Marcellus Shale, 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.

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

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do not take or are unable to take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness, and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivable. 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 for natural gas in Northeast Pennsylvania are volatile and are subject to significant discounts from pricing at Henry Hub. This discount and volatility has and could continue to adversely affect our financial results, cash flows, 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

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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, 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 applicable.

ITEM 4.     MINE SAFETY DISCLOSURES.

Not applicable.

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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 1, 2024, the Board of Directors made grants to our directors entitling them to an aggregate of 63,980 common shares which shall not be issued to the award recipients unless certain time based vesting criteria are met, in which case the vesting will occur in three equal parts on the succeeding periods ending on December 31. The awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act.

On March 19, 2024, the Board authorized a new share repurchase program of up to 2,191,320 common shares, representing 10% of the outstanding common shares of the Company at such time, for an aggregate purchase price of not more than US $12.0 million. The program was pursuant to a normal course issuer bid and was conducted in accordance with Rule 10b-18 under the Exchange Act. The program commenced on March 27, 2024 and was set to expire March 26, 2025, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination. On February 12, 2025, the Board terminated and revoked authority under this share repurchase program.

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

On December 31, 2024, our Board made grants to our management, employees, and directors entitling them to receive an aggregate of 236,072 common shares which shall not be issued to the award recipients unless certain time based vesting criteria are met, in which case the vesting will occur in three equal parts on the succeeding periods ending on December 31. 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 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.

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 and 2023 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 Shale section of the Appalachian Basin in Pennsylvania, the Permian Basin in Texas and New Mexico, the NW Anadarko Basin in Oklahoma, and the Western Canadian Sedimentary Basin in Alberta, Canada.

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At December 31, 2024 our total estimated net proved reserves were 69,401 MMcf of natural gas reserves, 876,808 Bbls of NGL reserves, and 1,572,465 Bbls of oil and condensate, and we held leasehold rights to approximately 102,506 gross (23,602 net) acres. We have natural gas production from our non-operated wells in Pennsylvania; natural gas, oil and other liquids production from our non-operated wells in the Permian Basin, Oklahoma; and oil production from our non-operated well in Alberta, Canada.

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.

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

On April 11, 2024, Epsilon acquired a 50% working interest in 14,243 gross undeveloped acres in Alberta, Canada. The Company participated in the drilling and completion of 2 gross (0.5 net) wells. One well was put on production in September 2024. One well was deemed non-commercial. Total capital expenditures (net to Epsilon) through year-end 2024 in the project (including undeveloped leasehold) are $2.9 million.

In October 2024, Epsilon formed a joint venture with a private operator covering approximately 130,000 gross acres in Garrington and Harmattan areas in Alberta, Canada. The Company will provide a $7 million drilling carry during 2025 in favor of the operator in exchange for a 25% working interest in the leasehold. To date, the Company participated in the drilling and completion of 2 gross (0.5 net) wells. Total capital expenditures (net to Epsilon) through year-end 2024 are $1.4 million.

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

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

At December 31, 2024, our total estimated net proved developed reserves were 64,872 MMcfe, a 28% increase from December 31, 2023. The increase is mainly attributable to transfers from proved undeveloped reserves in Pennsylvania and acquisitions in Texas. 

At December 31, 2024, our total estimated net proved reserves were 84,097 MMcfe, a 20% increase from December 31, 2023. 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.

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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.

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.

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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 system revenue (net of elimination) for the year ended December 31, 2024 decreased by $4.3 million, or 44% over 2023. The decrease was primarily due to lower anchor shipper volumes as a result of natural decline in the wells and operator elected well shut-ins due to poor natural gas pricing in Pennsylvania partially offset by an increase in the Auburn gathering rate. Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues, amounted to $1.1 million and $1.4 million, respectively, for the years ended December 31, 2024 and 2023.

Operating Costs

The following table presents total cost and cost per unit of production (Mcfe), including ad valorem, severance, and production taxes for the years ended December 31, 2024 and 2023:

	Year ended December 31,
	2024		2023
Lease operating costs (net of elimination)	$	7,264,824	$	6,405,281
Gathering system operating costs		2,265,190		2,459,694
	$	9,530,014	$	8,864,975
Upstream operating costs—Total $/Mcfe	$	0.95	$	0.71
Gathering system operating costs $/Mcf	$	0.30	$	0.15

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

Upstream operating costs consist of lease operating expenses necessary to extract natural gas and oil, including gathering and treating the natural gas and oil to ready it for sale. For the year ended December 31, 2024, upstream operating costs increased by $0.9 million, or 13.4% from the same period in 2023. The increase is primarily due to the acquired and developed wells in the Permian Basin. The higher unit operating cost is primarily due to the higher liquids (oil and natural gas liquids) proportion of total sales (Mcfe).

Gathering system operating costs consist primarily of rental payments for the natural gas fueled compression units and overhead fees due to the system’s operator. For the year ended December 31, 2024, gathering system operating costs decreased by $0.2 million, or 7.9% from the same period in 2023.

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

	Year ended December 31,
	2024		2023
Depletion, depreciation, amortization and accretion	$	10,185,119	$	7,685,084

Natural gas and oil and gathering system assets are depleted and depreciated using the units of production method aggregating properties on a field basis. 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.

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Accretion expense is related to the asset retirement costs.

During the year ended December 31, 2024, DD&A expense increased by $2.5 million, or 33%, compared to the same period in 2023. This increase was a result of the lower third-party reserves causing an increased depletion rate in addition to higher production from the Permian Basin.

Impairment

	Year ended December 31,
	2024		2023
Impairment	$	1,450,076	$	—

We perform a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable, over proved properties using the market forward prices, timing, methods and other assumptions consistent with historical periods. 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, the Company recorded an impairment of $1.45 million on the Killam project (interest acquired in April 2024) in Alberta, Canada. One well was impaired as a result of a decrease in reserves ($0.53 million) and one well drilled during the year was deemed non-commercial ($0.92 million). For the year ended December 31, 2023, there was no impairment.

General and Administrative (“G&A”)

	Year ended December 31,
	2024		2023
General and administrative	$	6,933,130	$	7,311,496

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

G&A expenses for the year ended December 31, 2024 decreased by $0.3 million, or 5%, compared to the same period in 2023. This decrease was primarily due to a reduction in legal expenses.

Interest Income

	Year ended December 31,
	2024		2023
Interest income	$	493,277	$	1,673,241

During the year ended December 31, 2024, interest income decreased by $1.2 million, or 71%, from the same period in 2023. This decrease was primarily due to the reduction in the balance of cash and short term investments.

Interest Expense

	Year ended December 31,
	2024		2023
Interest expense	$	46,400	$	80,379

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

Interest expense decreased by $0.03 million, or 42%, during the year ended December 31, 2024 from 2023. The decrease is due to higher fees in 2023 associated with our new credit facility.

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Net (loss) gain on commodity contracts

	Year ended December 31,
	2024		2023
(Loss) gain on derivative contracts	$	(391,147)	$	3,130,055

During the year ended December 31, 2024, the Company had NYMEX Henry Hub (“HH”) Natural Gas Futures swaps, Tennessee Gas Pipeline Zone 4 basis swaps, and crude oil NYMEX WTI CMA swaps derivative contracts for the purpose of hedging a portion of its physical natural gas and oil sales revenue. During the year ended December 31, 2023, the Company had NYMEX HH Natural Gas Futures swaps and Tennessee Gas Pipeline Zone 4 basis swaps derivative contracts for the same hedging purpose. The amounts recorded represent the fair value changes on our derivative instruments during the year. For the year ended December 31, 2024, the Company received net cash settlements of $1,196,656. For the year ended December 31, 2023, the Company received net cash settlements of $3,251,890.

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

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

Income Tax Expense

	Year ended December 31,
	2024		2023
Income tax expense	$	1,629,093	$	3,200,447

During the year ended December 31, 2024, income tax expense decreased by $1.6 million, or 49%, from the same period in 2023. This decrease was primarily due to a decrease in taxable income as a result of losses on derivative contracts and higher intangible drilling cost deductions.

Net Income Compared to Adjusted EBITDA

	Year ended December 31,
	2024		2023
Net income	$	1,927,800	$	6,945,153
Add Back:
Interest income, net		(446,877)		(1,592,862)
Income tax expense		1,629,093		3,200,447
Depreciation, depletion, amortization, and accretion		10,185,119		7,685,084
Impairment expense		1,450,076		—
Stock based compensation expense		1,244,416		1,018,262
Loss on sale of assets		—		1,449,871
Loss on derivative contracts net of cash received or paid on settlement		1,587,803		121,835
Foreign currency translation loss		570		(278)
Adjusted EBITDA	$	17,578,000	$	18,827,512

We define Adjusted EBITDA as earnings before (1) net interest expense, (2) taxes, (3) depreciation, depletion, amortization and accretion expense, (4) impairments of natural gas and oil properties, (5) non-cash stock compensation expense, (6) gain or loss on sale of assets, (7) gain or loss on derivative contracts net of cash received or paid on settlement, and (8) other income. Adjusted EBITDA is not a measure of financial performance as determined under U.S. GAAP and

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

At December 31, 2024, we had a working capital surplus of $7.0 million, a decrease of $26.2 million from the $33.2 million surplus at December 31, 2023. The surplus decreased from December 31, 2023 due to lower cash and short term investment balances. We anticipate that our current cash balance, short term investments, available borrowings, and cash flows from operations to be sufficient to meet our cash requirements for at least the next twelve months.

Year ended December 31, 2024 compared to 2023

During the year ended December 31, 2024, $16.8 million was provided by our operating activities, compared to $18.2 million in 2023, a $1.4 million, or 7%, decrease. The decrease was primarily due to lower production and throughput volumes in the Marcellus due to operator elected shut-ins, offset by higher production volumes in Texas.

The company used $16.7 million for investing activities during the year ended December 31, 2024, compared to $38.4 million in 2023, a $21.7 million, or 57%, decrease. The decrease was primarily due to a $40.8 million decrease in purchases of short-term investments, offset by a $15.2 million increase in capital investments in upstream properties.

During the year ended December 31, 2024, the Company used $7.3 million for financing activity compared to $11.7 million in 2023, a $4.4 million, or 38% decrease. The decrease was due to fewer repurchases of our common shares.

Credit Agreement

The Company closed a senior secured reserve based revolving credit facility on June 28, 2023 with Frost Bank as issuing bank and sole lender. The current borrowing base is $45 million (redetermined as of February 10, 2025), supported by the Company’s upstream assets in Pennsylvania and subject to semi-annual redeterminations with a maturity date of June 28, 2027. Interest will be charged at the Daily Simple SOFR rate plus a margin of 3.25%. The facility is secured by the assets of the Company’s Epsilon Energy USA subsidiary (Borrower). There are currently no borrowings under the facility.

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

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● Current ratio of 1.0 to 1.0 (current assets / current liabilities)

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

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

Repurchase Transactions

On March 19, 2024, the Board of Directors authorized a new share repurchase program of up to 2,191,320 common shares, representing 10% of the outstanding common shares of Epsilon at such time, for an aggregate purchase price of not more than US $12.0 million. 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.

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.

Derivative Transactions

The Company has entered into hedging arrangements to reduce the impact of natural gas price volatility on operations. By removing the price volatility from a significant portion of natural gas production, the potential effects of changing prices on operating cash flows have been mitigated, but not eliminated. 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, Epsilon’s outstanding natural gas and crude oil commodity contracts consisted of the following:

		Weighted Average
	Volume	Price ($/MMbtu)		Fair Value of Asset
Derivative Type	(MMbtu)	Swaps		December 31, 2024
2025
NYMEX Henry Hub swap	2,261,500	$	3.26	$	(297,579)
Tennessee Z4 basis swap	2,261,500	$	(0.91)	$	(246,516)
	4,523,000			$	(544,095)

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				Fair Value
	Volume	Weighted Average		December 31,
Derivative Type	(Bbl)	Price ($/Bbl)		2024
2025
Crude Oil NYMEX WTI CMA	20,662	$	73.49	$	56,547
	20,662			$	56,547

Contractual Obligations

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

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 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

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

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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.

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

38

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

Recently Issued Accounting Standards

See Note 3, “Summary of Significant Accounting Policies” in Notes to the Consolidated Financial Statements.

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

Derivative Contracts

The Company’s financial results and condition depend on the prices received for natural gas production. Natural gas prices have fluctuated widely and are determined by economic and political factors. Supply and demand factors, including weather, general economic conditions, the ability to transport the gas to other regions, as well as conditions in other natural gas regions, impact prices. 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 and 2023, and the consolidated statements of operations and comprehensive income, changes in shareholders’ equity and cash flows for years ended December 31, 2024 and 2023 included in this annual report have been prepared in accordance with U.S. GAAP.

39

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 and 2023, 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 and 2023, 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

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates 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 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 below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

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 was $97.0 million, which includes proved

40

oil and natural gas properties of $191.3 million and accumulated depletion, amortization and impairment of $122.8 million. DD&A expense was $10.2 million for the year ended December 31, 2024.

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. 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, 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.

/s/ BDO USA, P.C.

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

Houston, Texas

March 19, 2025

41

EPSILON ENERGY LTD.

Consolidated Balance Sheets

	December 31,		December 31,
	2024		2023
ASSETS
Current assets
Cash and cash equivalents	$	6,519,793	$	13,403,628
Accounts receivable		5,843,722		6,015,448
Short term investments		—		18,775,106
Fair value of derivatives		—		1,219,025
Prepaid income taxes		975,963		952,301
Other current assets		792,041		763,288
Total current assets		14,131,519		41,128,796
Non-current assets
Property and equipment:
Oil and gas properties, successful efforts method
Proved properties		191,349,210		160,263,511
Unproved properties		28,364,186		25,504,873
Accumulated depletion, depreciation, amortization and impairment		(122,751,395)		(113,708,210)
Total oil and gas properties, net		96,962,001		72,060,174
Gathering system		43,116,371		42,738,273
Accumulated depletion, depreciation, amortization and impairment		(36,449,511)		(35,539,996)
Total gathering system, net		6,666,860		7,198,277
Land		637,764		637,764
Buildings and other property and equipment, net		259,335		291,807
Total property and equipment, net		104,525,960		80,188,022
Other assets:
Operating lease right-of-use assets, long term		344,589		441,987
Restricted cash		470,000		470,000
Prepaid drilling costs		982,717		1,813,808
Total non-current assets		106,323,266		82,913,817
Total assets	$	120,454,785	$	124,042,613
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable trade	$	2,334,732	$	3,149,371
Gathering fees payable		997,016		1,136,237
Royalties payable		1,400,976		1,422,898
Accrued capital expenditures		572,079		696,761
Accrued compensation		695,018		636,295
Other accrued liabilities		371,503		649,037
Fair value of derivatives		487,548		118,770
Operating lease liabilities		121,135		86,473
Total current liabilities		6,980,007		7,895,842
Non-current liabilities
Asset retirement obligations		3,652,296		3,502,952
Deferred income taxes		12,738,577		11,553,943
Operating lease liabilities, long term		355,776		476,911
Total non-current liabilities		16,746,649		15,533,806
Total liabilities		23,726,656		23,429,648
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
Treasury shares, at cost, 0 at December 31, 2024 and 70,874 at December 31, 2023		—		(360,326)
Additional paid-in capital		12,118,907		10,874,491
Accumulated deficit		(41,505,076)		(37,946,042)
Accumulated other comprehensive income		10,033,267		9,772,277
Total shareholders' equity		96,728,129		100,612,965
Total liabilities and shareholders' equity	$	120,454,785	$	124,042,613

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

42

EPSILON ENERGY LTD.

Consolidated Statements of Operations and Comprehensive Income

	Year ended December 31,
	2024		2023
Revenues from contracts with customers:
Gas, oil, NGL, and condensate revenue	$	25,998,712	$	20,939,221
Gas gathering and compression revenue		5,524,063		9,790,531
Total revenue		31,522,775		30,729,752
Operating costs and expenses:
Lease operating expenses		7,264,824		6,405,281
Gathering system operating expenses		2,265,190		2,459,694
Depletion, depreciation, amortization, and accretion		10,185,119		7,685,084
Impairment expense		1,450,076		—
Loss on sale of oil and gas properties		—		1,449,871
General and administrative expenses:
Stock based compensation expense		1,244,416		1,018,262
Other general and administrative expenses		5,688,714		6,293,234
Total operating costs and expenses		28,098,339		25,311,426
Operating income		3,424,436		5,418,326
Other income (expense):
Interest income		493,277		1,673,241
Interest expense		(46,400)		(80,379)
(Loss) gain on derivative contracts		(391,147)		3,130,055
Other income		76,727		4,357
Other income, net		132,457		4,727,274
Net income before income tax expense		3,556,893		10,145,600
Income tax expense		1,629,093		3,200,447
NET INCOME	$	1,927,800	$	6,945,153
Currency translation adjustments		262,588		(3,872)
Unrealized (loss) gain on securities		(1,598)		1,598
NET COMPREHENSIVE INCOME	$	2,188,790	$	6,942,879
Net income per share, basic	$	0.09	$	0.31
Net income per share, diluted	$	0.09	$	0.31
Weighted average number of shares outstanding, basic		21,930,277		22,496,772
Weighted average number of shares outstanding, diluted		21,930,277		22,511,647

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

43

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
Balance at December 31, 2024	22,008,766	$	116,081,031	—	$	—	$	12,118,907	$	10,033,267	$	(41,505,076)	$	96,728,129

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

44

EPSILON ENERGY LTD.

Consolidated Statements of Cash Flows

	Year ended December 31,
	2024		2023
Cash flows from operating activities:
Net income	$	1,927,800	$	6,945,153
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		10,185,119		7,685,084
Impairment expense		1,450,076		—
Accretion of discount on available for sale securities		(297,637)		(836,528)
Loss on sale of oil and gas properties		—		1,449,871
Gain (loss) on derivative contracts		391,147		(3,130,055)
Settlement received on derivative contracts		1,196,656		3,251,890
Settlement of asset retirement obligation		(88,992)		(509,802)
Stock-based compensation expense		1,244,416		1,018,262
Deferred income tax expense		1,184,634		936,549
Changes in assets and liabilities:
Accounts receivable		171,726		1,185,938
Prepaid income taxes		(23,662)		187,793
Other assets and liabilities		(17,828)		126,347
Accounts payable, royalties payable and other accrued liabilities		(493,176)		(122,203)
Net cash provided by operating activities		16,830,279		18,188,299
Cash flows from investing activities:
Additions to unproved oil and gas properties		(4,507,280)		(8,136,442)
Additions to proved oil and gas properties		(31,695,651)		(10,377,642)
Additions to gathering system properties		(341,452)		(82,302)
Additions to land, buildings and property and equipment		(16,513)		(49,689)
Purchases of short term investments - held to maturity		—		(32,812,974)
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		26,864,976
Proceeds from short term investments - available for sale		16,373,752		—
Proceeds from sale of oil and gas properties		—		12,498
Prepaid drilling costs		831,091		(1,813,808)
Net cash used in investing activities		(16,658,660)		(38,384,365)
Cash flows from financing activities:
Buyback of common shares		(1,831,208)		(6,055,601)
Exercise of stock options		—		62,875
Dividends paid		(5,486,834)		(5,600,655)
Debt issuance costs		—		(140,000)
Net cash used in financing activities		(7,318,042)		(11,733,381)
Effect of currency rates on cash, cash equivalents, and restricted cash		262,588		(3,872)
Decrease in cash, cash equivalents, and restricted cash		(6,883,835)		(31,933,319)
Cash, cash equivalents, and restricted cash, beginning of period		13,873,628		45,806,947
Cash, cash equivalents, and restricted cash, end of period	$	6,989,793	$	13,873,628
Supplemental cash flow disclosures:
Income tax paid - federal	$	414,250	$	1,250,000
Income tax paid - state (PA)	$	—	$	182,000
Income tax (refund) paid - state (other)	$	(2,071)	$	7,583
Interest paid	$	16,832	$	97,595
Non-cash investing activities:
Change in proved properties accrued in accounts payable and accrued liabilities	$	(862,744)	$	1,611,724
Change in gathering system accrued in accounts payable and accrued liabilities	$	36,645	$	16,969
Asset retirement obligation asset additions and adjustments	$	54,902	$	1,190,579

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

45

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements

For the years ended December 31, 2024 and 2023

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 Energy Holdings, 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 and 2023:

	December 31,		December 31,
	2024		2023
Cash and cash equivalents	$	6,519,793	$	13,403,628
Restricted cash included in other assets		470,000		470,000
Cash, cash equivalents, and restricted cash in the statement of cash flows	$	6,989,793	$	13,873,628

46

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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.

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.

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.

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.

47

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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. 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.

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 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.

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 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 Liquids Revenue

The source of the Company’s oil and other liquids revenue is its ownership in wells in the Permian Basin, Oklahoma, and Alberta, Canada.  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 Receivable and Other

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 Northeastern Pennsylvania, the Permian Basin, Oklahoma, 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 of transmission. The Company’s operations do not result in any contract assets or liabilities on the accompanying consolidated balance sheets.

48

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

Buildings and Other Property and Equipment

Buildings are depreciated on a straight-line basis over the estimated useful life of the property, 30 years.

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 Company had investments in U.S. Treasury Bills, which mature over a period between 3 and 12 months and are classified as short term investments. The U.S. Treasury Bills are carried at fair value. The U.S. Treasury Bills are classified within Level 1 of the fair value hierarchy.

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.

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.

49

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 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, cash and cash equivalents was primarily concentrated in one financial institution the U.S. At December 31, 2023, cash and cash equivalents and short term investments were primarily concentrated in one financial institution the U.S. We currently have $4.1 million in excess of the federally insured limits. The Company periodically assesses the financial condition of these institutions and believe that any possible credit risk is minimal.

For the year ended December 31, 2024, the Company had three customers that accounted for 89.1% of the total trade accounts receivable. For the year ended December 31, 2023, the Company had four customers that accounted for 90.7% of the total trade accounts receivable.

Geographic Locations of Operations

Approximately 50% and 77% of our revenue during fiscal years 2024 and 2023, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania. 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.

50

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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.

Income Taxes

Deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. Epsilon assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate (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 are included in accumulated other comprehensive income.

Stock-Based Compensation

The Company has issued time-based restricted stock and performance share units (“PSU”) to employees and directors of the Company. The fair value of the time-based restricted stock 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 awards vest ratably over a three-year period. 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).

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.

Recently Issued Accounting Standards

In October 2023, the FASB issued ASU No. 2023-06, Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative, to amend certain disclosure and presentation requirements. For entities subject to the SEC’s existing disclosure requirements, the effective date for each amendment

51

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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.

4. Short Term Investments

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
	Amortized		Unrealized		Fair		Amortized		Unrealized		Fair
	Cost		Losses		Value		Cost		Gains		Value
U.S. Treasury Bills	$	—	$	—	$	—	$	18,773,508	$	1,598	$	18,775,106

During the year ended December 31, 2024, the Company sold securities with a carrying amount of $14,989,595 for total proceeds of $15,336,930. The realized gains on these sales were $347,335. An additional $7,780,000 of securities

52

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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.

5. Property and Equipment

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

	December 31,		December 31,
	2024		2023
Property and equipment:
Oil and gas properties, successful efforts method
Proved properties	$	191,349,210	$	160,263,511
Unproved properties		28,364,186		25,504,873
Accumulated depletion, depreciation, amortization and impairment		(122,751,395)		(113,708,210)
Total oil and gas properties, net		96,962,001		72,060,174
Gathering system		43,116,371		42,738,273
Accumulated depletion, depreciation, amortization and impairment		(36,449,511)		(35,539,996)
Total gathering system, net		6,666,860		7,198,277
Land		637,764		637,764
Buildings and other property and equipment, net		259,335		291,807
Total property and equipment, net	$	104,525,960	$	80,188,022

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 in Ector County, Texas for $2.6 million.

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

● a joint venture covering approximately 130,000 gross undeveloped acres 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.

● 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.

53

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

● 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, 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 the year ended December 31, 2024, Epsilon recorded an impairment of $1.45 million on the Killam project (interest acquired in April 2024) in Alberta, Canada. One well was impaired as a result of a decrease in reserves ($0.53 million) and one well drilled during the year was deemed non-commercial ($0.92 million). For the year ended December 31, 2023, there was no impairment. Refer to Note 17 – Fair Value Measurements.

6. Revolving Line of Credit

The Company closed a senior secured reserve based revolving credit facility on June 28, 2023 with Frost Bank as issuing bank and sole lender. The current borrowing base is $45 million (redetermined as of February 10, 2025), supported by the Company’s upstream assets in Pennsylvania and subject to semi-annual redeterminations with a maturity date of June 28, 2027. Interest will be charged at the Daily Simple SOFR rate plus a margin of 3.25%. The facility is secured by the assets of the Company’s Epsilon Energy USA subsidiary (Borrower). There are currently no borrowings under the facility.

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

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

	Balance at		Balance at
	December 31,		December 31,		Current
	2024		2023		Borrowing Base		Interest Rate
Revolving line of credit	$	—	$	—	$	45,000,000		SOFR + 3.25%

54

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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 19, 2024, the Board of Directors authorized a new share repurchase program of up to 2,191,320 common shares, representing 10% of the outstanding common shares of Epsilon at such time, for an aggregate purchase price of not more than US $12.0 million. The program was pursuant to a normal course issuer bid and was conducted in accordance with Rule 10b-18 under the Exchange Act. The program commenced on March 27, 2024 and was set to expire on March 26, 2025, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination. During the year ended December 31, 2024, we repurchased 125,000 common shares and spent $627,500 at an average price of $5.00 per share (excluding commissions) under the plan. On February 12, 2025, the Board terminated and revoked authority under the program.

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

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

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

(c) 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, 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, 300,052 restricted common shares with a weighted average grant date fair value of $5.97 were awarded to the Company’s management, employees, and board of directors. For the year ended December 31, 2023, 358,546 restricted common shares with a weighted average grant date fair value of $5.42 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.

55

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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

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).

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

At December 31, 2024 and 2023, the Company had unrecognized stock-based compensation related to these options of nil. The 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).

During the years ended December 31, 2024 and 2023, the Company awarded no stock options.

56

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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

(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. 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 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.

57

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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, 2024 and 2023:

	December 31,		December 31,		December 31,
	2024		2023		2022
Accounts receivable
Natural gas and oil sales	$	4,888,294	$	4,327,886	$	5,696,419
Joint interest billing		—		17,476		20,454
Gathering and compression fees		918,471		1,543,239		1,483,956
Commodity contract		36,957		72,075		—
Interest		—		54,772		557
Total accounts receivable	$	5,843,722	$	6,015,448	$	7,201,386

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 and 2023 consisted of the following:

	Year Ended December 31,
	2024		2023
Balance at beginning of period	$	9,772,277	$	9,774,551
Translation gain/(loss)		262,588		(3,872)
Unrealized (loss)/gain on securities		(1,598)		1,598
Balance at end of period	$	10,033,267	$	9,772,277

10. Income Taxes

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

	Year ended December 31,
	2024		2023
Foreign	$	(2,769,534)	$	(1,167,609)
U.S.		6,326,427		11,313,209
	$	3,556,893	$	10,145,600

We file a federal income tax return 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

58

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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 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				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	%

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

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.

59

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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)

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.

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.

60

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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%

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. 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.

Future minimum lease payments as of December 31, 2024 are as follows:

	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

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.

61

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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

	Year ended December 31,
	2024		2023
Net income	$	1,927,800	$	6,945,153

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

	Year ended December 31,
	2024	2023
Basic weighted-average number of shares outstanding	21,930,277	22,496,772
Dilutive stock options	—	4,431
Unvested performance-based restricted shares	—	10,444
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	2023
Anti-dilutive options	—	53,069
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:

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

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

62

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

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

63

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

	Upstream		Gas Gathering		Total
As of and for the year ended December 31, 2023
Operating revenue
Natural gas	$	14,864,214	$	—	$	14,864,214
Natural gas liquids		984,418		—		984,418
Oil and condensate		5,090,589		—		5,090,589
Gathering and compression fees		—		9,790,531		9,790,531
Intersegment gathering and compression fees		—		1,375,879		1,375,879
		20,939,221		11,166,410		32,105,631
Reconciliation of operating revenue
Elimination of intersegment revenues						(1,375,879)
Total consolidated operating revenue(1)						30,729,752
Operating costs
Gathering, transportation, and compression		5,938,422		—		5,938,422
Other lease operating expense		466,859		2,459,694		2,926,553
Intersegment other lease operating expense		1,375,879		—		1,375,879
Loss on sale of oil and gas properties		1,449,871		—		1,449,871
Depletion, depreciation, amortization and accretion		6,638,882		1,046,202		7,685,084
Segment operating income	$	5,069,308	$	7,660,514	$	11,353,943
Reconciliation of segment operating income
Salary expense						2,856,089
Stock based compensation						1,018,262
Other general and administrative						3,437,145
Elimination of intersegment other lease operating expenses						(1,375,879)
Total consolidated operating income						5,418,326
Other income (expense)
Interest income						1,673,241
Interest expense						(80,379)
Gain on derivative contracts						3,130,055
Other income						4,357
Other income, net						4,727,274
Net income before income tax expense					$	10,145,600
Capital expenditures (2)	$	18,563,773	$	82,302	$	18,646,075
Segment assets	$	73,873,982	$	7,198,277	$	81,072,259
Total segment assets reconciled to consolidated amounts are as follows:
Total segment assets					$	81,072,259
Current assets, net						41,128,796
Other property and equipment						929,571
Operating lease right-of-use asset						441,987
Restricted Cash						470,000
					$	124,042,613

(1) Segment operating revenue represents revenues generated from the operations of the segment. Inter-segment sales during the years ended December 31, 2024 and 2023 have been eliminated upon consolidation. For the year ended December 31, 2024, we sold natural gas 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, we sold natural gas to 33 unique customers. Direct Energy Business Marketing, LLC and EQT Energy, LLC each accounted for 10% or more of our total revenue.

(2) Capital expenditures for the Upstream segment consist primarily of the acquisition of properties, and the drilling and completing of wells while Gas Gathering consists of expenditures relating to the expansion, completion, and maintenance of the gathering and compression facility.

15. Commodity Risk Management Activities

Commodity Price Risks

Epsilon engages in price risk management activities from time to time. These activities are intended to manage Epsilon’s exposure to fluctuations in commodity prices for natural gas by securing fixed price contracts for a portion of expected sales volumes.

64

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

Inherent in the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company may be required to post collateral depending on the cumulative balance owed to a counterparty on a mark-to-market basis.

The Company enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future natural gas and oil production and related cash flows. The natural gas and oil revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future natural gas sales from the risk of significant declines in commodity prices, which helps ensure the Company’s ability to fund the capital budget.

Epsilon has historically elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for these financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as (loss) gain on derivative contracts on the consolidated statements of operations and comprehensive income. The related cash flow impact is reflected in cash flows from operating activities. During 2024, Epsilon recognized losses on financial commodity derivative contracts of $391,147. This amount included cash received on the settlement of these contracts of $1,196,656. During 2023, Epsilon recognized gains on financial commodity derivative contracts of $3,130,055. This amount included cash paid on the settlement of these contracts of $3,251,890.

Commodity Derivative Contracts

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) covering January 2025 to October 2025, and NYMEX WTI CMA swaps totaling 20,662 Bbls with a weighted average strike price of $73.49 to hedge a portion of expected volumes for the contract period of January 2025 to June 2025.

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

	Fair Value of Derivative  Assets
	December 31,		December 31,
	2024		2023
Current
NYMEX Henry Hub swap	$	151,274	$	1,353,667
Tennessee Z4 basis swap		195,211		112,719
Crude Oil NYMEX WTI CMA		56,547		—
	$	403,032	$	1,466,386

	Fair Value of Derivative  Liabilities
	December 31,		December 31,
	2024		2023
Current
NYMEX Henry Hub swap	$	(448,852)	$	—
Tennessee Z4 Basis swap		(441,728)		(366,131)
	$	(890,580)	$	(366,131)
Net Fair Value of Derivatives	$	(487,548)	$	1,100,255

65

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

The following table presents the changes in the fair value of Epsilon’s commodity derivatives for the periods indicated:

	Year ended December 31,
	2024		2023
Fair value of asset, beginning of the period	$	1,100,255	$	1,222,090
(Loss) gain on derivative contracts included in earnings		(391,147)		3,130,055
Settlement of commodity derivative contracts		(1,196,656)		(3,251,890)
Fair value of (liability) asset, end of the period	$	(487,548)	$	1,100,255

The following table presents the fair value of derivatives, as presented in the Consolidated Balance Sheets, on a net basis as they are subject to master netting arrangements:

	December 31, 2024						December 31, 2023
	Gross Fair		Amounts		Net Fair		Gross Fair		Amounts		Net Fair
	Value		Netted		Value		Value		Netted		Value
Derivative Assets
Fair value of derivatives	$	403,032	$	(403,032)	$	-	$	1,466,386	$	(247,361)	$	1,219,025
Derivative Liabilities
Fair value of derivatives	$	(890,580)	$	403,032	$	(487,548)	$	(366,131)	$	247,361	$	(118,770)

16. Asset Retirement Obligations

Asset retirement obligations are estimated by management based on Epsilon’s net ownership interest in all wells and the gathering system, estimated costs to reclaim and abandon such assets and the estimated timing of the costs to be incurred in future periods, and the forecast risk free cost of capital. Epsilon has estimated the net present value of its total asset retirement obligations to be $3.7 million as of December 31, 2024 ($3.5 million at December 31, 2023). Each year we review, and to the extent necessary, revise our asset retirement obligations estimates in accordance with recent activity and current service costs.

The following table presents the activity in Epsilon’s asset retirement obligations for the periods indicated:

	Year Ended		Year ended
		December 31,		December 31,
	2024		2023
Balance beginning of period	$	3,502,952	$	2,780,237
Liabilities acquired		48,207		12,437
Liabilities disposed of		—		(46,961)
Wells plugged and abandoned		(88,992)		(509,802)
Change in estimates		6,695		1,178,142
Accretion		183,434		88,899
Balance end of period	$	3,652,296	$	3,502,952

66

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

17. Fair Value Measurements

The methodologies used to determine the fair value of our financial assets and liabilities at December 31, 2024 were the same as those used at December 31, 2023.

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 Company had investments in U.S. Treasury bills, all of which mature over a period of 3 and 12 months and are classified as short term investments. The U.S. Treasury bills are carried at fair value. The U.S. Treasury bills are classified within Level 1 of the fair value hierarchy.

Commodity derivative instruments consist of NYMEX HH swap and basis swap contracts for natural gas and NYMEX WTI CMA swap contracts for crude oil. 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.

	December 31, 2024
	Level 1		Level 2		Level 3		Effect of Netting		Net Fair Value
Assets
Derivative contracts	$	—	$	403,032	$	—	$	(403,032)	$	—
Cash equivalents	$	298,767	$	—	$	—	$	—	$	298,767
Liabilities
Derivative contracts	$	—	$	890,580	$	—	$	(403,032)	$	487,548

	December 31, 2023
	Level 1		Level 2		Level 3		Effect of Netting		Net Fair Value
Assets
Derivative contracts	$	—	$	1,219,025	$	—	$	—	$	1,219,025
Cash equivalents	$	195,669	$	—	$	—	$	—	$	195,669
Short term investments	$	18,775,106	$	—	$	—	$	—	$	18,775,106
Liabilities
Derivative contracts	$	—	$	247,361	$	—	$	(366,131)	$	(118,770)

Non-Recurring Fair Value Measurements

The Company performed an impairment test on our oil and gas properties and it was determined that the carrying amount of the Killam project in Alberta, Canada exceeded the estimated undiscounted future cash flows resulting in a reduction of the carrying amount of the oil properties to their estimated fair values by $1.45 million. This nonrecurring fair value measurement is classified within Level 3 of the fair value hierarchy.  For the year ended December 31, 2023, there was no impairment.

67

EPSILON ENERGY LTD.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2024 and 2023

The table below summarizes the fair value of the impaired assets at December 31, 2024.

			Quoted Prices		Significant
			in Active		Other		Significant
			Markets for		Observable		Unobservable
	December 31,		Identical Assets		Inputs		Inputs
	2024		(Level 1)		(Level 2)		(Level 3)
Nonrecurring fair value measurement
Long-lived assets held and used	$	492,253	$	—	$	—	$	492,253
Total Nonrecurring fair value measurement	$	492,253	$	—	$	—	$	492,253

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EPSILON ENERGY LTD.

Supplemental Information to Consolidated Financial Statements

(Unaudited)

SUPPLEMENTAL NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)

Natural gas and oil Reserves

Users of this information should be aware that the process of estimating quantities of ‘‘proved,’’ ‘‘proved developed’’ and ‘‘proved undeveloped’’ crude oil, natural gas liquids (NGLs) and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. 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; crude oil and condensate, NGL and natural gas prices; 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. Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved reserves represent estimated quantities of crude oil, NGLs and natural gas, which, 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 under then-existing economic conditions, operating methods and government regulations before 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.

Proved developed reserves are proved reserves expected to be recovered under operating methods being utilized at the time the estimates were made, through wells and equipment in place or if the cost of any required equipment is relatively minor compared to the cost of a new well.

Proved undeveloped reserves (PUDs) are 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 are 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. PUDs can be recorded in respect of a particular undrilled location only if the location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the date that the PUDs are to be recorded, unless specific factors (such as those described in interpretative guidance issued by the Staff of the SEC) justify a longer timeframe. Likewise, absent any such specific factors, PUDs associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond five years from the date that the PUDs were recorded. Epsilon has formulated development plans for all drilling locations associated with its PUDs at December 31, 2024. Under these plans, each PUD location will be drilled within five years from the date it was recorded.

Estimates for PUDs are not attributed 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.

The following tables set forth Epsilon’s net proved reserves at December 31, 2024 and 2023 and changes for each of the two years in the year ended December 31, 2024. Net proved reserves at December 31 are estimated by the Company’s independent petroleum engineers, DeGolyer and MacNaughton.

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EPSILON ENERGY LTD.

Supplemental Information to Consolidated Financial Statements

(Unaudited)

NET PROVED RESERVE SUMMARY

		Permian
	Pennsylvania	Basin	Oklahoma	Canada	Total
Natural Gas (MMcf)
Net proved reserves at December 31, 2022	84,497	-	5,543	-	90,040
Revisions of previous estimates	(14,831)	-	(1,515)	-	(16,346)
Acquisitions	-	481	-	-	481
Production	(7,906)	-	(354)	-	(8,260)
Net proved reserves at December 31, 2023	61,760	481	3,674	-	65,915
Revisions of previous estimates	8,334	303	(480)	-	8,157
Acquisitions	-	1,471	-	-	1,471
Production	(5,700)	(205)	(237)	-	(6,142)
Net proved reserves at December 31, 2024	64,394	2,050	2,957	-	69,401
Natural Gas Liquids (MBbl)
Net proved reserves at December 31, 2022	-	-	491	-	491
Revisions of previous estimates	-	-	(203)	-	(203)
Acquisitions	-	116	-	-	116
Production	-	-	(21)	-	(21)
Net proved reserves at December 31, 2023	-	116	267	-	383
Revisions of previous estimates	-	89	(1)	-	88
Acquisitions	-	475	-	-	475
Production	-	(52)	(17)	-	(69)
Net proved reserves at December 31, 2024	-	628	249	-	877
Oil and Condensate (MBbl)
Net proved reserves at December 31, 2022	-	-	211	-	211
Revisions of previous estimates	-	-	(43)	-	(43)
Acquisitions	-	194	-	-	194
Production	-	-	(21)	-	(21)
Net proved reserves at December 31, 2023	-	194	147	-	341
Revisions of previous estimates	-	243	(20)	-	223
Acquisitions	-	1,175	-	17	1,192
Production	-	(173)	(11)	-	(184)
Net proved reserves at December 31, 2024	-	1,439	116	17	1,572
Total Company (MMcfe)
Net proved reserves at December 31, 2022	84,497	-	9,758	-	94,255
Revisions of previous estimates (1)(2)	(14,831)	-	(2,991)	-	(17,822)
Acquisitions	-	2,341	-	-	2,341
Production	(7,906)	-	(606)	-	(8,512)
Net proved reserves at December 31, 2023	61,760	2,341	6,161	-	70,262
Revisions of previous estimates (3)(4)(5)	8,334	2,294	(606)	-	10,022
Acquisitions	-	11,371	-	102	11,473
Production	(5,700)	(1,555)	(405)	-	(7,660)
Net proved reserves at December 31, 2024	64,394	14,451	5,150	102	84,097

(1) Revisions of previous estimates for Pennsylvania for 2023 include reductions of 9,626 MMcf related to well performance, reductions of 21,830 MMcf related to commodity pricing, and additions of 16,625 MMcf related to changes in previously adopted development plans.

(2) Revisions of previous estimates for Oklahoma for 2023 include reductions of 454 MMcfe related to commodity pricing, 1,760 MMcfe related to changes in previously adopted development plans, and 777 MMcfe related to well performance.

(3) Revisions of previous estimates for Pennsylvania for 2024 include additions of 10,244 MMcf related to changes in previously adopted development plans, reductions of 2,849 MMcf related to commodity pricing, and additions of 939 MMcf related to well performance.

(4) Revisions of previous estimates for the Permian Basin for 2024 include additions of 2,317 MMcfe related to well performance and reductions of 23 MMcfe related to commodity pricing.

(5) Revisions of previous estimates for Oklahoma for 2024 include reductions of 196 MMcfe related to commodity pricing and 410 MMcfe related to well performance.

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EPSILON ENERGY LTD.

Supplemental Information to Consolidated Financial Statements

(Unaudited)

		Permian
	Pennsylvania	Basin	Oklahoma	Canada	Total
Proved developed reserves:
Natural Gas (MMcf)
At December 31, 2022	76,302	-	2,664	-	78,966
At December 31, 2023	45,135	481	1,939	-	47,555
At December 31, 2024	54,150	1,265	1,436	-	56,851
Natural Gas Liquids (MBbl)
At December 31, 2022	-	-	198	-	198
At December 31, 2023	-	116	133	-	249
At December 31, 2024	-	375	115	-	490
Oil and condensate (MBbl)
At December 31, 2022	-	-	107	-	107
At December 31, 2023	-	194	78	-	272
At December 31, 2024	-	779	51	17	847
Total proved developed reserves (MMcfe)
At December 31, 2022	76,302	-	4,494	-	80,796
At December 31, 2023	45,135	2,341	3,205	-	50,681
At December 31, 2024	54,150	8,188	2,432	102	64,872
Proved undeveloped reserves:
Natural Gas (MMcf)
At December 31, 2022	8,195	-	2,879	-	11,074
At December 31, 2023	16,625	-	1,736	-	18,361
At December 31, 2024	10,244	785	1,521	-	12,550
Natural Gas Liquids (MBbl)
At December 31, 2022	-	-	293	-	293
At December 31, 2023	-	-	134	-	134
At December 31, 2024	-	253	134	-	387
Oil and condensate (MBbl)
At December 31, 2022	-	-	104	-	104
At December 31, 2023	-	-	69	-	69
At December 31, 2024	-	660	65	-	725
Total proved undeveloped reserves (MMcfe)
At December 31, 2022	8,195	-	5,264	-	13,459
At December 31, 2023	16,625	-	2,956	-	19,581
At December 31, 2024	10,244	6,263	2,718	-	19,225
Total proved reserves:
Natural Gas (MMcf)
At December 31, 2022	84,497	-	5,543	-	90,040
At December 31, 2023	61,760	481	3,675	-	65,916
At December 31, 2024	64,394	2,050	2,957	-	69,401
Natural Gas Liquids (MBbl)
At December 31, 2022	-	-	491	-	491
At December 31, 2023	-	116	267	-	383
At December 31, 2024	-	628	249	-	877
Oil and condensate (MBbl)
At December 31, 2022	-	-	211	-	211
At December 31, 2023	-	194	147	-	341
At December 31, 2024	-	1,439	116	17	1,572
Total proved reserves (MMcfe)
At December 31, 2022	84,497	-	9,758	-	94,255
At December 31, 2023	61,760	2,341	6,161	-	70,262
At December 31, 2024	64,394	14,451	5,150	102	84,097

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EPSILON ENERGY LTD.

Supplemental Information to Consolidated Financial Statements

(Unaudited)

Capitalized Costs Relating to Natural gas and oil Producing Activities

The following table sets forth the capitalized costs relating to Epsilon’s crude oil and natural gas production activities at December 31, 2024 and 2023:

	Year ended December 31,
	2024		2023
Proved properties	$	191,349,210	$	160,263,511
Unproved properties		28,364,186		25,504,873
Total Oil & Gas Properties		219,713,396		185,768,384
Accumulated depreciation, depletion, amortization and impairment		(122,751,395)		(113,708,210)
Net capitalized costs	$	96,962,001	$	72,060,174

Costs incurred for oil and natural gas property acquisition, exploration and development activities

The following table summarizes costs incurred and capitalized in oil and natural gas properties related to acquisition, exploration and development activities. Property acquisition costs are those costs incurred to lease property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling, as well as the costs to develop the gathering system.

			Permian
	Pennsylvania		Basin		Oklahoma		Canada		Total
Oil and Natural Gas Activities:
Total costs incurred for oil and natural gas activities as of December 31, 2024
Unproved acquisition costs	$	499,820	$	1,345,113	$	—	$	1,014,380	$	2,859,313
Proved acquisition costs		17,389		12,147,327		—		—		12,164,716
Proved development costs		4,782,274		12,193,104		68,651		1,876,953		18,920,982
Total costs incurred	$	5,299,483	$	25,685,544	$	68,651	$	2,891,333	$	33,945,011
Total costs incurred for oil and natural gas activities as of December 31, 2023
Unproved acquisition costs	$	6,727,250	$	556,047	$	49,737	$	2,682	$	7,335,716
Proved development costs		4,714,022		8,384,986		(1,132,451)		—		11,966,557
Total costs incurred	$	11,441,272	$	8,941,033	$	(1,082,714)	$	2,682	$	19,302,273

Results of Operations for Natural Gas and Oil Producing Activities

The following table sets forth results of operations for natural gas and oil producing activities for the years ended December 31, 2024 and 2023:

	Year ended December 31,
	2024		2023
Oil and gas producing activities:
Gas sales	$	10,786,068	$	14,864,214
Oil and other liquid sales		15,212,644		6,075,007
Total revenues		25,998,712		20,939,221
Lease operating costs		(7,264,824)		(6,405,281)
Depreciation, depletion, amortization, accretion and impairment		(10,718,231)		(6,638,882)
Income tax expense		(1,629,093)		(2,569,725)
Results of operations from oil and gas producing activities	$	6,386,564	$	5,325,333

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural gas and oil Reserves

The following information has been developed utilizing procedures prescribed by the Extractive Activities—Natural Oil and Gas (Topic 932) of the ASC and based on natural gas reserves and production volumes estimated by our

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EPSILON ENERGY LTD.

Supplemental Information to Consolidated Financial Statements

(Unaudited)

independent petroleum consultants, DeGolyer and MacNaughton. The commodity prices estimated below were based on a 12-month average of first-day-of-the-month commodity prices for the years 2024 and 2023. The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating Epsilon or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of Epsilon.

The future cash flows presented below are based on expense and cost rates in existence as of the date of the projections. It is expected that material revisions to some estimates of natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Estimated future income taxes are computed using current statutory income tax rates including consideration of the current tax basis of the properties and related carryforwards. The resulting tax-effected future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible reserves as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The following table sets forth the standardized measure of discounted future net cash flows from projected production of Epsilon’s gas reserves as of December 31, 2024 and 2023.

			Permian
	Pennsylvania		Basin		Oklahoma		Canada		Total
Standard measure of discounted net cash flows as of December 31, 2024
Future cash inflows	$	100,218,636	$	125,275,660	$	21,830,652	$	941,636	$	248,266,584
Future production costs		(54,462,887)		(43,915,587)		(10,313,945)		(377,798)		(109,070,217)
Future development costs(1)		(12,274,739)		(14,245,000)		(4,896,984)		(45,000)		(31,461,723)
Future income taxes(2)		(7,461,773)		(10,447,829)		(701,602)		—		(18,611,204)
Future net cash flows (undiscounted)		26,019,237		56,667,244		5,918,121		518,838		89,123,440
10% annual discount for estimated timing of cash flows		(10,628,574)		(24,726,300)		(3,014,198)		(97,774)		(38,466,846)
Standardized measure of discounted future net cash flows	$	15,390,663	$	31,940,944	$	2,903,924	$	421,064	$	50,656,595
Standard measure of discounted net cash flows as of December 31, 2023
Future cash inflows	$	103,665,328	$	18,829,996	$	29,629,506	$	—	$	152,124,830
Future production costs		(54,684,801)		(6,755,857)		(12,372,663)		—		(73,813,321)
Future development costs(1)		(10,931,859)		(87,500)		(4,796,571)		—		(15,815,930)
Future income taxes(2)		(8,311,899)		(1,295,491)		(1,973,614)		—		(11,581,004)
Future net cash flows (undiscounted)		29,736,769		10,691,148		10,486,658		—		50,914,575
10% annual discount for estimated timing of cash flows		(10,162,963)		(2,548,601)		(5,230,103)		—		(17,941,667)
Standardized measure of discounted future net cash flows	$	19,573,806	$	8,142,548	$	5,256,555	$	—	$	32,972,908

(1) Costs associated with the abandonment of proved properties are included in future development costs.

(2) Future income taxes for 2024 and 2023 were estimated using a combined federal and state statutory tax rate of approximately 24%.

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EPSILON ENERGY LTD.

Supplemental Information to Consolidated Financial Statements

(Unaudited)

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2024 and 2023:

			Permian
	Pennsylvania		Basin		Oklahoma		Canada		Total
Future net cash flows as of December 31, 2022	$	127,038,998	$	—	$	18,738,110	$	—	$	145,777,108
Revenue less production and other costs		(7,598,080)		(3,131,578)		(2,428,537)		—		(13,158,195)
Changes in price, net of production costs		(144,425,073)		—		(11,948,735)		—		(156,373,808)
Development costs incurred		3,538,365		7,571,473		(1,098,330)		—		10,011,508
Net changes in future development costs		(1,929,366)		(7,627,799)		4,468,819		—		(5,088,346)
Revisions of previous quantity estimates		(5,794,427)		9,352,748		(4,089,834)		—		(531,513)
Accretion of discount		12,078,196		—		2,192,989		—		14,271,185
Net change in income taxes		39,014,488		(1,153,874)		1,938,755		—		39,799,369
Timing differences and other technical revisions		(2,349,296)		3,131,578		(2,516,681)		—		(1,734,399)
Future net cash flows as of December 31, 2023		19,573,805		8,142,548		5,256,555		—		32,972,908
Revenue less production and other costs		(4,953,087)		(11,478,606)		(1,123,854)		(43,696)		(17,599,243)
Changes in price, net of production costs		(2,686,674)		1,164,105		(1,816,853)		—		(3,339,422)
Development costs incurred		4,784,359		8,450,190		68,651		1,016,640		14,319,839
Net changes in future development costs		(5,084,036)		(20,313,738)		(131,859)		(1,020,101)		(26,549,734)
Revisions of previous quantity estimates		390,639		6,394,390		(770,571)		—		6,014,458
Accretion of discount		2,598,426		578,818		565,753		—		3,742,998
Net change in income taxes		644,355		(4,914,788)		622,733		—		(3,647,700)
Purchases of reserves in place		—		40,846,884		—		—		40,846,884
Timing differences and other technical revisions		122,876		3,071,142		233,368		468,221		3,895,607
Future net cash flows as of December 31, 2024	$	15,390,663	$	31,940,944	$	2,903,924	$	421,064	$	50,656,595

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ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A.     CONTROLS AND PROCEDURES.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and our principal financial officer, evaluated, as of the end of the period covered by this Annual Report on Form 10-K, the design and effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer have concluded that as of December 31, 2024, our disclosure controls and procedures were effective at the reasonable assurance level. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and our management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting for Epsilon as such term is defined in the Exchange Act. Our internal control structure is designed to provide reasonable assurance that assets are safeguarded and that transactions are properly executed and recorded. The internal control structure includes, among other things, established policies and procedures, the selection and training of qualified personnel as well as management oversight.

With the participation of our management, we performed an evaluation of the effectiveness of our internal control over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “2013 Framework)”. Based upon our evaluation under the 2013 Framework, we have concluded that as of December 31, 2024 our internal control over financial reporting was effective.

This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by Epsilon’s independent registered public accounting firm pursuant to rules of the SEC that permit Epsilon to provide only management's report in this Annual Report. We were not required to have, nor have we, engaged our independent registered public accounting firm to perform an audit of internal control over financial reporting pursuant to the rules of the Commission that permit us to provide only management’s report in this Annual Report.

Changes in Internal Control Over Financial Reporting

There have been no significant changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.     OTHER INFORMATION.

During the quarter ended December 31, 2024, none of our directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS.

None.

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PART III

ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

The names, ages, business experience (for at least the past five years) and positions of our directors and executive officers as of December 31, 2024, are set out below. Our Board of Directors consisted of six members at such date. All directors serve until the next annual meeting of shareholders or until their successors are elected or appointed and qualified. The Board of Directors appoints the executive officers annually.

Directors and Executive Officers	Age	Position with us
Jason Stabell	50	Chief Executive Officer and Director
Henry N. Clanton	62	Chief Operating Officer
Andrew Williamson	36	Chief Financial Officer
John Lovoi	64	Chairman of the Board and Director
Tracy Stephens	64	Director
Jason Stankowski	54	Director
David Winn	62	Director
Nicola Maddox	69	Director

Biographies of Corporate Directors and Executive Officers.

Jason Stabell. Mr. Stabell has served as chief executive officer and a director for Epsilon Energy Ltd. since July 2022. He has worked in the energy industry since 1998 with a focus on upstream E&P. Most recently he served as President and CEO of Merlon International, LLC, a privately held company with assets in the Western Desert of Egypt and US Gulf Coast which was sold in 2019 to a publicly listed UK company where he served as an advisor until 2021. Previously, he served as CFO and ultimately President of privately held Merlon Petroleum Company, which had assets in the US Gulf Coast and Egypt and was sold in 2006. He has a BA in Economics from Williams College. We believe that Mr. Stabell is qualified to serve as a member of our board of directors as a result of his experience in the natural gas and oil industry.

Henry N. Clanton. Mr. Clanton has served as our chief operating officer since January 2017. He has over 30 years of experience in the upstream E&P sector. His experience includes financial and technical management over all phases of drilling, completions, production, and field operations. Before joining us, he spent 14 years with a private E&P start-up, ARES Energy, Ltd, which he co-founded and served as a Managing Partner. Previous to that time Mr. Clanton worked with Schlumberger, ARCO Permian, and Coastal Management Company. He holds a MBA and a BS in Petroleum Engineering from Texas A&M University.

Andrew Williamson. Mr. Williamson has served as our chief financial officer since July 2022. He has spent his entire career in the energy business. From 2012 to early 2019, he served as Corporate Development Manager then Vice President Finance (CFO) of Merlon International, LLC. More recently, he served as the Corporate Strategy Manager for Petrosantander Inc. Mr. Williamson started his career in management consulting advising energy clients on transaction due diligence, growth strategy, and cost reduction. He has a BBA in Finance and a BA in Political Science from Southern Methodist University.

John Lovoi. Mr. Lovoi has been chairman of our board of directors since July 2013. Mr. Lovoi has been the managing partner of JVL Advisors, LLC, a private natural gas and oil investment advisor, since November 2002. He is a Director of Helix Energy Solutions Group, an operator of offshore natural gas and oil properties and production facilities, the Chairman of Innovex International, a leading provider of a broad range of products and services to the global oil and gas industry.  We believe that Mr. Lovoi is qualified to serve as a member of our board of directors as a result of his background in investment banking, equity research, and asset management, with an emphasis on the global natural gas and oil practice.

Tracy Stephens. Mr. Stephens has been a director since May 2018. He has also been a member of our Compensation, Nominating and Corporate Governance Committee, and Conflicts Committee since February 2019. He is the founder of Westminster Advisors, a CEO advisory services company, and served as its Chief Executive Officer from January 2018. He was previously employed by Resources Global Professionals, a large business consulting company, from

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July 2001 to December 2016, and was the Chief Operating Officer the last three years. We believe that Mr. Stephens is qualified to serve as a member of our board of directors as a result of his extensive experience with public companies.

Jason Stankowski. Mr. Stankowski has been a director and member of the Audit Committee since January 2021. Mr. Stankowski is the founder and a partner and portfolio manager for Clayton Partners, LLC. He began his career at Prudential Securities in San Francisco and spent eight years in structured finance at CMA Capital Management, where he acted in a number of roles, including specializing in corporate retirement planning, structuring complex investment and financing structures for Fortune 1000 companies. He became designated as a Chartered Financial Analyst in 2003. We believe that Mr. Stankowski is qualified to serve as a member of our board of directors based on his corporate finance and experience in public equity markets.

David Winn. Mr. Winn has been a director and member of the Audit Committee since January 2021. Mr. Winn recently retired from a 36 year career in public accounting that involved extensive board interaction. From 2003 until July 2020, Mr. Winn was an Audit Partner for Grant Thornton LLP, which is an independent audit, tax, and advisory firm and the U.S. member firm of Grant Thornton International Ltd. During his tenure, Mr. Winn served as audit department head, industry program leader, an engagement partner, quality control reviewer, and was a relationship partner to large clients. Mr. Winn has extensive Securities and Exchange Commission reporting experience with registration statements and annual and quarterly filings. Previously Mr. Winn served as a Director for PricewaterhouseCoopers LLP and previously as a Partner with Arthur Andersen LLP. We believe that Mr. Winn is qualified to serve as a member of our board of directors because of his experience in public accounting and public company reporting.

Nicola Maddox. Ms. Maddox has over forty years’ experience in the oil and gas industry. After receiving her BA in Communications, she was employed by Exxon Minerals starting as an Associate Landman eventually ending in Executive Management positions starting in 1993. She was a co-founder of Centurion Exploration Company in 2004, initially serving as an EVP and then becoming its President, CEO and Chairman of the Board from 2007 to 2009. At Merlon International, LLC, Ms. Maddox was SVP in charge of its Texas subsidiary. She advanced to EVP and ultimately President after Merlon sold its Egyptian subsidiary in 2019. Since 2022, she has been a self-employed energy advisor specializing in contract analysis, strategic planning, and negotiation strategies. We believe that Ms. Maddox is qualified to serve as a member of our board of directors because of his significant industry experience in upstream oil and gas.

Corporate Governance Practices and Policies

Our corporate governance practices and policies are administered by the board of directors and by committees of the board appointed to oversee specific aspects of our management and operations, pursuant to written charters and policies adopted by the board and such committees.

The Board of Directors

The Board is committed to a high standard of corporate governance practices. The Board believes that this commitment is not only in the best interests of the shareholders but that it also promotes effective decision-making at the Board level. The Board is of the view that its approach to corporate governance is appropriate and complies with the objectives and guidelines relating to corporate governance set out in National Instrument 58-201 adopted by the Canadian securities administrators, or NI 58-201, as well as the governance requirements of the NASDAQ Global Market. In addition, the Board monitors and considers for implementation the corporate governance standards that are proposed by various Canadian regulatory authorities or that are published by various non-regulatory organizations in Canada. The Board has also established a Compensation, Nominating and Corporate Governance Committee and has adopted a Compensation, Nominating and Corporate Governance Charter to ensure the objectives of NI 58-201 and the NASDAQ Global Market are met.

Mr. Lovoi is the Managing Partner of JVL Advisors, LLC, beneficial owner of 1.29% of our common shares and Chairman of the Board.

The Board held ten meetings during 2024 and eleven meetings during 2023. All Board meetings were conducted with open and candid discussions. As such, directors did not hold any separate meetings, other than Audit and Compensation, Nominating and Corporate Governance Committee meetings. The members of the Board have the ability to meet on their own and are authorized to retain independent financial, legal and other experts as required whenever, in their opinion, matters come before the Board that require an independent analysis by the members of the Board. The Board

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intends to hold at least four regular meetings each year, as well as additional meetings as required. The Board has not established any required attendance levels for the Board and committee meetings. In setting the regular meeting schedule, care is taken to ensure that meeting dates are set to accommodate directors’ schedules so as to encourage full attendance.

The Board has stewardship responsibilities, including responsibilities with respect to oversight of our investments, management of the Board, monitoring of our financial performance, financial reporting, financial risk management and oversight of policies and procedures, communications and reporting and compliance. In carrying out its mandate, the Board meets regularly and a broad range of matters are discussed and reviewed for approval. These matters include overall plans and strategies, budgets, internal controls and management information systems, risk management as well as interim and annual financial and operating results. The Board is also responsible for the approval of all major transactions, including property acquisitions, property divestitures, equity issuances and debt transactions, if any. The Board strives to ensure that our corporate actions correspond closely with the objectives of its shareholders. The Board will meet at least once annually to review in depth our strategic plan and review our available resources required to carry out our growth strategy and to achieve its objectives. The mandate of the Board is to be reviewed by the Board annually.

Position Descriptions. The Board has outlined the responsibilities in respect to our Chief Executive Officer, or CEO. The Board and CEO do not have a written position description for the CEO; however, the CEO’s principal duties and responsibilities are planning our strategic direction, providing leadership, acting as our spokesperson, reporting to shareholders, and overseeing our executive management with respect to operations and finance.

The charter for each of the Board committees outlines the duties and responsibilities of the members of each of the committees, including the chair of such committees. See ‘‘Board Committees’’ below.

Orientation and Continuing Education. We have not adopted a formalized process of orientation for new Board members. However, all directors have been provided with a base line of knowledge about us that serves as a basis for informed decision making. This includes a combination of written material, in person meetings with our senior management, site visits and other briefings and training, as appropriate.

Directors are kept informed as to matters affecting, or that may affect, our operations through reports and presentations at the quarterly Board meetings. Special presentations on specific business operations are also provided to the Board.

Ethical Business Conduct and Whistleblower Policy. Our Code of Ethics and Whistleblower Policy are available on our website at http://www.epsilonenergyltd.com/. Each director is expected to disclose all actual or potential conflicts of interest and refrain from voting on matters in which such director has a conflict of interest. In addition, a director must recuse himself from any discussion or decision on any matter of which the director is precluded from voting as a result of a conflict of interest. The Board has reviewed and approved a disclosure and insider trading policy for us, in order to promote consistent disclosure practices aimed at informative, timely and broadly disseminated disclosure of material information to the market in accordance with applicable securities legislation. The disclosure policy promotes, among other things, the disclosure and reporting of any serious weaknesses which may affect the financial stability and assets of us and our operating entities.

National Instrument 52-110 adopted by the Canadian securities administrators, the listing standards of the Toronto Stock Exchange and the listing standards of the NASDAQ Global Market require the Audit Committee to establish formal procedures for (a) the receipt, retention, and treatment of complaints received by us and our subsidiaries regarding accounting, internal accounting controls, or auditing matters and (b) the confidential, anonymous submission by our consultants or employees of concerns regarding questionable accounting or auditing matters. We are committed to achieving compliance with all applicable securities laws and regulations, accounting standards, accounting controls and audit practices. In addition, we post on our website all disclosures that are required by law or the listing standards of the NASDAQ Global Market concerning any amendments to, or waivers from, any provision of the code.

Assessments. The Board does not conduct regular assessments of the Board, its committees or individual directors, however, the Board does periodically review and satisfy itself at meetings that the Board, its committees and its individual directors are performing effectively.

Board Diversity. Our Compensation, Nominating and Corporate Governance Committee is responsible for reviewing with the board of directors, on an annual basis, the appropriate characteristics, skills and experience required

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for the board of directors as a whole and its individual members. In evaluating the suitability of individual candidates (both new candidates and current members), the nominating and corporate governance committee, in recommending candidates for election, and the board of directors, in approving (and, in the case of vacancies, appointing) such candidates, will take into account many factors, including the following:

◾ personal and professional integrity, ethics and values;

◾ experience in corporate management, such as serving as an officer or former officer of a publicly held company;

◾ experience as a board member or executive officer of another publicly held company;

◾ strong finance experience;

◾ diversity of expertise and experience in substantive matters pertaining to our business relative to other board members;

◾ diversity of background and perspective, including, but not limited to, with respect to age, gender, race, place of residence and specialized experience;

◾ experience relevant to our business industry and with relevant social policy concerns; and

◾ relevant academic expertise or other proficiency in an area of our business operations.

Currently, our Board evaluates each individual in the context of the board of directors as a whole, with the objective of assembling a group that can best maximize the success of the business and represent stockholder interests through the exercise of sound judgment using its diversity of experience in these various areas.

Board Committees

The Board has two committees. The committees are the Audit Committee and the Compensation, Nominating and Corporate Governance Committee. Each committee has been constituted with independent directors.

Audit Committee. The Audit Committee currently consists of David Winn (Chairman), John Lovoi, and Jason Stankowski. All members of the Audit Committee are independent and financially literate under the applicable rules and regulations of the SEC and the NASDAQ Global Market.

The Audit Committee meets at least on a quarterly basis to review and approve our consolidated financial statements before the financial statements are publicly filed.

The Audit Committee reviews our interim unaudited condensed consolidated financial statements and annual audited consolidated financial statements and certain corporate disclosure documents including the Annual Information Form, Management’s Discussion and Analysis, and annual and interim earnings press releases before they are approved by the Board. The Audit Committee reviews and makes a recommendation to the Board in respect of the appointment and compensation of the external auditors and it monitors accounting, financial reporting, control and audit functions. The Audit Committee meets to discuss and review the audit plans of external auditors and is directly responsible for overseeing the work of the external auditors with respect to preparing or issuing the auditors’ report or the performance of other audit, review or attest services, including the resolution of disagreements between management and the external auditors regarding financial reporting. The Audit Committee questions the external auditors independently of management and reviews a written statement of its independence. The Audit Committee must be satisfied that adequate procedures are in place for the review of our public disclosure of financial information extracted or derived from our consolidated financial statements and it periodically assesses the adequacy of those procedures. The Audit Committee must approve or pre-approve, as applicable, any non-audit services to be provided to us by the external auditors. In addition, it reviews and reports to the Board on our risk management policies and procedures and reviews the internal control procedures to determine their effectiveness and to ensure compliance with our policies and avoidance of conflicts of interest. The Audit Committee has established procedures for dealing with complaints or confidential submissions which come to its attention with respect to accounting, internal accounting controls or auditing matters. To date, neither the Board nor the Audit Committee has formally assessed any individual director with respect to their effectiveness and contribution to us in their capacity as a director. Instead, members of the Board have relied on informal conversations among themselves to adequately cover such matters.

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The Audit Committee operates under a written charter that satisfies the applicable standards of the SEC and The NASDAQ Global Market. A copy of the Audit Committee Charter can be found on our website at www.epsilonenergyltd.com.

Compensation, Nominating and Corporate Governance Committee. The Compensation, Nominating and Corporate Governance Committee is currently comprised of Tracy Stephens (Chairman), John Lovoi, and Nicola Maddox. All members of this committee are independent directors.

The Compensation, Nominating and Corporate Governance Committee’s mandate is to:

1. Assist and advise the Board regarding its responsibility for oversight of our compensation policy; provided that all determinations on officer compensation will be subject to review and approval by the Board;

2. Study and evaluate appropriate compensation mechanisms and criteria;

3. Develop and establish appropriate compensation policies and practices for the Board and our senior management, including our security-based compensation arrangements;

4. Evaluate senior management;

5. Serve in an advisory capacity on organizational and personnel matters to the Board;

6. Assist the Board by identifying individuals qualified to serve on the Board and its committees;

7. Recommend to the Board the director nominees for the next annual meeting;

8. Recommend to the Board members and chairpersons for each committee;

9. Develop and recommend to the Board and review from time to time, a set of corporate governance principles and monitor compliance with such principles; and

10. Serve in an advisory capacity on matters of governance structure and the conduct of the Board.

These responsibilities include reporting and making recommendations to the Board for their consideration and approval. Corporate governance also relates to the activities of the Board, the members of which are elected by and are accountable to the shareholders, and takes into account the role of the individual members of management who are appointed by the Board and who are charged with the day-to-day management of us. The Board is committed to sound corporate governance practices, which are both in the interest of its shareholders and contribute to effective and efficient decision making.

The Compensation, Nominating and Corporate Governance Committee operates under a written charter that satisfies the applicable standards of the SEC and The NASDAQ Global Market. A copy of such charter can be found on our website at www.epsilonenergyltd.com.

Communications to the Board

Shareholders may communicate directly with our Board or any director by writing to the board or a director in care of the corporate secretary at Epsilon Energy Ltd., 500 Dallas Street, Suite 1250, Houston, Texas 77002, or by faxing their written communication to AeRayna Flores at (281) 668-0985. Shareholders may also communicate with the Board or any director by calling Ms. Flores at (281) 670-0002. Ms. Flores will review any communication before forwarding it to the Board or director, as the case may be.

Employment Agreements

All named executive officers have executed employment contracts with us. Mr. Jason Stabell’s employment agreement is effective from July 1, 2022 and filed in Form 8-K with the SEC on June 24, 2022. Mr. Henry Clanton’s employment agreement is effective from January 1, 2024 and filed in Form 8K with the SEC on March 12, 2024. Mr. Andrew Williamson’s employment agreement is effective from July 1, 2022 and filed in Form 8-K with the SEC on June 24, 2022.

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ITEM 11.     EXECUTIVE COMPENSATION.

Summary Compensation Table

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 following table sets out information concerning the compensation paid to our principal executive officer and our two most highly compensated executive officers other than our principal executive officer, or our named executive officers, for the two years ended December 31, 2024 and 2023. Compensation amounts in the following table are in U.S. dollars.

Name and principal						Share-based		Other		Total
position	Year	Salary		Bonuses		Awards		Compensation (4)		Compensation
Jason Stabell, CEO (1)	2024	$	322,000	$	164,000	$	552,001	$	18,446	$	1,056,447
	2023	$	311,000	$	184,000	$	851,003	$	7,350	$	1,353,353
Henry N. Clanton, COO (2)	2024	$	282,000	$	123,000	$	164,000	$	19,341	$	588,341
	2023	$	272,000	$	92,000	$	92,004	$	15,752	$	471,756
Andrew Williamson, CFO (3)	2024	$	264,000	$	139,000	$	221,001	$	17,469	$	641,470
	2023	$	239,000	$	138,000	$	355,006	$	12,448	$	744,454

(1) Mr. Stabell was hired as our chief executive officer in July 2022. His current base salary is $322,000.

2024—Share award of 88,889 common shares valued at $6.21 per share, market price on the grant date of December 31, 2024, which vests evenly over a three year period.

2023—Share award of 108,465 common shares valued at $5.08 per share, market price on the grant date of December 31, 2023, which vests evenly over a three year period.

Share award of 56,180 common shares valued at $5.34 per share, market price on the grant date of July 1, 2023. This stub grant, although awarded in 2023, was based on 2022 performance. The grant vests evenly over a three year period.

(2) Mr. Henry Clanton was hired as our chief operating officer in January 2018. His current base salary of $282,000.

2024—Share award of 26,409 common shares valued at $6.21 per share, market price on the grant date of December 31, 2024, which vest evenly over a three year period.

2023—Share award of 18,111 common shares valued at $5.08 per share, market price on the grant date of December 31, 2023, which vest evenly over a three year period.

(3) Mr. Andrew Williamson was hired as our chief financial officer in July 2022. His current base salary is $264,000.

2024—Share award of 35,588 valued at $6.21 per share, market price on the grant date of December 31, 2024, which grants vest evenly over a three year period.

2023—Share award of 45,276 valued at $5.08 per share, market price on the grant date of December 31, 2023, which grants vest evenly over a three year period.

Share award of 23,409 common shares valued at $5.34 per share, market price on the grant date of July 1, 2023. This stub grant, although awarded in 2023, was based on 2022 performance. The grant vests evenly over a three year period.

(4) As a Company policy, Epsilon matches on 401K contributions up to 5%.

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Mr. Stabell and the Company entered into an Executive Employment Agreement, effective July 1, 2022.  The terms of the Employment Agreement have been adjusted by the Board subsequent to its effective date.  Mr. Stabell serves as CEO on an “at-will” basis for an annual base salary of $322,000 during 2024 and $311,000 during 2023. In addition to his base salary, Mr. Stabell is eligible to receive an annual incentive cash bonus targeted at $200,000 for achieving performance goals established by the Compensation Committee of the Board in its sole discretion for the then current calendar year. Additionally, Mr. Stabell is eligible for equity awards in the discretion of the Compensation Committee, which in 2024 included 88,889 common shares valued at $6.21 per share (market price on the grant date of December 31, 2024), which vests evenly over a three year period, and in 2023 included 108,465 common shares valued at $5.08 per share (market price on the grant date of December 31, 2023), which vests evenly over a three year period.  Mr. Stabell is entitled to participate in all applicable Company benefit plans, programs, or arrangements that the Company may offer to its executives generally, from time to time, and as may be amended from time to time.

Mr. Clanton and the Company entered into an Executive Employment Agreement, effective January 14, 2024.  The terms of the Employment Agreement have been adjusted by the Board subsequent to its effective date.  Mr. Clanton serves as COO on an “at-will” basis for an annual base salary of $282,000 during 2024 and $272,000 during 2023. In addition to his base salary, Mr. Clanton is eligible to receive an annual incentive cash bonus targeted at $150,000 for achieving performance goals established by the Compensation Committee of the Board in its sole discretion for the then current calendar year. Additionally, Mr. Clanton is eligible for equity awards in the discretion of the Compensation Committee, which in 2024 included 26,409 common shares valued at $6.21 per share (market price on the grant date of December 31, 2024), which vests evenly over a three year period, and in 2023 included 18,811 common shares valued at $5.08 per share (market price on the grant date of December 31, 2023), which vests evenly over a three year period.  Mr. Clanton is entitled to participate in all applicable Company benefit plans, programs, or arrangements that the Company may offer to its executives generally, from time to time, and as may be amended from time to time.

Mr. Williamson and the Company entered into an Executive Employment Agreement, effective July 1, 2022.  The terms of the Employment Agreement have been adjusted by the Board subsequent to its effective date.  Mr. Williamson serves as CFO on an “at-will” basis for an annual base salary of $264,000 during 2024 and $239,000 during 2023. In addition to his base salary, Mr. Williamson is eligible to receive an annual incentive cash bonus targeted at $170,000 for achieving performance goals established by the Compensation Committee of the Board in its sole discretion for the then current calendar year. Additionally, Mr. Williamson is eligible for equity awards in the discretion of the Compensation Committee, which in 2024 included 35,588 common shares valued at $6.21 per share (market price on the grant date of December 31, 2024), which vests evenly over a three year period, and in 2023 included 45,276 common shares valued at $5.08 per share (market price on the grant date of December 31, 2023), which vests evenly over a three year period.  Mr. Williamson is entitled to participate in all applicable Company benefit plans, programs, or arrangements that the Company may offer to its executives generally, from time to time, and as may be amended from time to time.

Description of the 2020 Equity Incentive Plan

The 2020 Plan was approved by the Board on July 22, 2020 and shareholders on September 1, 2020 as a replacement of our Amended and Restated 2017 Stock Option Plan and the Share Compensation Plan.

The 2020 Plan is administered by the Board, a committee of the Board or one or more officers delegated authority by the Board to administer the 2020 Plan. The Board has the authority in its discretion to interpret the 2020 Plan. The Board determines to whom stock options, stock appreciation rights, restricted stock and stock units, performance shares and units, other stock-based awards and cash-based awards are granted, subject to options and all other terms and conditions of the awards.

The maximum number common shares that may be issued under the 2020 Plan is 2,000,000. As of December 31, 2024, 234,834 performance stock units (“PSUs”), and 1,323,663 time-based restricted shares have been issued, leaving 676,337 shares available to be granted under the 2020 Plan.

If the shares granted under the 2020 Plan expire or terminate for any reason without having been issued or are forfeited, they again become available for grant under the 2020 Plan. Shares granted under the 2020 Plan are not transferable or assignable other than by will or other testamentary instrument or the laws of succession.

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In the event we undergo a change of control by a reorganization, acquisition, amalgamation or merger (or a plan or arrangement in connection with any of these) with respect to which all or substantially all of the persons who were the beneficial owners of the common shares immediately prior to such transaction do not, following such transaction, beneficially own, directly or indirectly more than 50% of the resulting voting power, a sale of all, or substantially all, of the Company’s assets, or the liquidation, dissolution or winding-up of the Company, outstanding awards shall be subject to the definitive agreement entered into by the Company in connection with the change of control.

At December 31, 2024, we were authorized to issue equity securities as follows:

	Number of Shares to be		Weighted Average	Number of Shares Remaining
	Issued Upon Exercise		Exercise Price of	Available for Future Issuance
	of Outstanding Options,		Outstanding Options,	Under Equity Compensation Plans
Plan Category	Warrants and Rights		Warrants and Rights	(excluding shares in column (a))
Common shares under 2020 Equity Incentive Plan	560,970	$	5.77	676,337

Incentive Plan Awards for Named Executive Officers

Outstanding Share-Based Awards and Option-Based Awards as of December 31, 2024 are as follows:

	Share-based Awards
		Market
	Number of	Value of
	Shares or Units	Share-Based
	of Shares that	Awards that
	Have Not	Have Not
Name	Vested	Vested
Jason Stabell	235,235	$	1,460,809
Henry N. Clanton	43,111	$	267,719
Andrew Williamson	96,621	$	600,016

Incentive Plan Awards—Value Vested or Earned for Named Executive Officers

The values of incentive plan awards that were vested or earned during the year ended December 31, 2024 are as follows:

		Share-based awards—Value
Name		Vested During the Year
Jason Stabell	$	471,177
Henry N. Clanton	$	88,392
Andrew Williamson	$	196,459

We have adopted the 2020 Plan as an incentive-based share award plan applicable to all named executive officers and employees.

Change of control is defined as any event whereby any person acquires at least 50% of the Company’s stock or if a group of shareholders causes at least 50% of the board members to change.

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DIRECTOR COMPENSATION

The following table contains compensation earned in the year ended December 31, 2024 by our independent directors who are not named executive officers:

			Share-Based
Name	Fees Earned		Awards		Total
John Lovoi	$	95,000	$	65,000	$	160,000
Tracy Stephens	$	65,000	$	65,000	$	130,000
David Winn	$	70,000	$	65,000	$	135,000
Jason Stankowski	$	55,000	$	65,000	$	120,000
Nicola Maddox	$	55,000	$	65,000	$	120,000

On a quarterly basis, we compensate each director for services rendered (unless a director elects not to receive payment) and reimburse reasonable out-of-pocket travel expenses when incurred.

As of January 1, 2023, board member compensation is fixed at an annual fee of $55,000 paid in cash quarterly and $65,000 as a share-based award valued at the prior year-end share price (vesting evenly over a three year period). The chairman of the board receives an additional $40,000 annual cash fee, the chairman of the audit committee receives an additional $15,000 annual cash fee, and the chairman of the compensation, nominating, and corporate governance committee receives an additional $10,000 annual cash fee.

Incentive Plan Awards—Value Vested or Earned During the Year for Directors (Other Than Named Executive Officers)

Outstanding Share-Based Awards and Option-Based Awards as of December 31, 2024 are as follows:

	Share-based Awards
		Market or
	Number of	Payout Value
	Shares or Units	of Share-Based
	of Shares that	Awards that
	Have Not	Have Not
Name	Vested	Vested
John Lovoi	28,266	$	175,532
Tracy Stephens	22,266	$	138,272
David Winn	22,266	$	138,272
Jason Stankowski	22,266	$	138,272
Nicola Maddox	21,048	$	130,708

The values of incentive plan awards that were vested or earned during the year ended December 31, 2024 are as follows:

		Share-based awards
		Value Vested
Name		During the Year
John Lovoi	$	107,601
Tracy Stephens	$	70,701
David Winn	$	70,701
Jason Stankowski	$	70,701
Nicola Maddox	$	35,264

Directors and Officers Liability Insurance

We maintain directors’ and officers’ liability insurance for the protection of our directors and officers against liability incurred by them in their capacities as our directors and officers. The policy provides an aggregate limit of liability

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of $30,000,000 with a retention held by the Company of $1,500,000. The current annual premium for the Directors’ and Officers’ liability insurance is approximately $350,000 and is re-bid annually. The premium is not allocated between Directors and Officers as separate groups.

ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The table set forth below is information with respect to beneficial ownership of common shares as of March 19, 2025, by our named executive officers, by each of our directors, by all our current executive officers and directors as a group, and by each person known to us who beneficially own 5% or more of the outstanding common shares. To our knowledge, each person named in the table has sole voting and investment power with respect to the common shares identified as beneficially owned.

Unless otherwise indicated, the address of each of the individuals named below is c/o Epsilon Energy Ltd., 500 Dallas, Suite 1250, Houston, Texas 77002.

	Number of	Percentage of
	Common	Common
Name of Beneficial Owner	Shares	Shares Owned
5% Stockholders
Solas Capital Management LLC (1)	3,768,467	17.12	%
Jumana Capital Investments LLC (2)	1,896,574	8.62	%
Named Executive Officers and Directors
Jason Stabell (3)	622,198	*
Henry Clanton (4)	80,611	*
Andrew Williamson (5)	98,302	*
John Lovoi (6)	284,979	*
Tracy Stephens (7)	61,801	*
David Winn (8)	32,901	*
Jason Stankowski (9)	363,396	*
Nicola Maddox (10)	10,361	*
All executive officers and directors as a group (8 persons)	1,554,549	7.05	%

* Indicates beneficial ownership of less than 5% of outstanding shares.

(1) The address of Solas Capital Management, LLC is 1063 Post Rd, 2^nd Floor, Darien, Connecticut 06820. Pursuant to a Schedule 13G filed with the SEC on February 14, 2024, Solas Capital Management, LLC (“Solas”) and Frederick Tucker Golden share voting and dispositive power with respect to these common shares. All of the securities reported are owned by advisory clients of Solas, none of which is a beneficial owner of more than 5% as of July 14, 2020.

(2) The address of Jumana Capital Investments LLC is 1717 St. James Place, Suite 335, Houston, Texas 77056. Christopher Martin is the managing of Jumana Capital and exercises the voting and dispositive power with respect to the common shares held by Jumana Capital.

(3) Mr. Stabell is our chief executive officer and a member of our board of directors.

(4) Mr. Clanton is our chief operating officer.

(5) Mr. Williamson is our chief financial officer.

(6) Mr. Lovoi is the chairman of our board of directors and is the managing member of JVL Advisors, LLC.

(7) Mr. Stephens is a member of our board of directors.

(8) Mr. Winn is a member of our board of directors.

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(9) Mr. Stankowski is a member of our board of directors and a partner and portfolio manager for Clayton Partners, LLC.

(10) Ms. Maddox is a member of our board of directors.

Changes in Control. We do not know of any arrangement, the operation of which may at a subsequent date result in a change in control of us.

Securities Authorized For Issuance under Equity Compensation Plans

The information required by Item 201 of Regulation S-K in “Item 1. Business – Market for Our Common Equity and Related Stockholder Matters.”

ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

Certain Relationships and Related Transactions

Since the beginning of fiscal 2024, there has not been, nor is there currently proposed, any transaction or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our voting securities, or any member of the immediate family of any of the foregoing persons, had or will have a direct or indirect material interest, except for the compensation and other arrangements described in “Executive Compensation” and “Director Compensation” elsewhere in this document and the transactions described below.

Independence of the Board of Directors

The Board is currently composed of five directors who provide us with a wide diversity of business experience.

Our Board has determined that John Lovoi, Tracy Stephens, Jason Stankowski, David Winn, and Nicola Maddox are independent in accordance with the listing requirements of the NASDAQ Global Market, representing over 50% of the Board. Our Board conducted its independence analysis for each of its current members, considering all relevant facts and circumstances, including the director’s other commercial, accounting, legal, banking, consulting, charitable and familial relationships. Pursuant to its review, the Board determined that with respect to each of its current members, there are no disqualifying factors with respect to director independence enumerated in the listing standards of NASDAQ or any relationships that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director, and that each such member is an “independent director” as defined in the listing standards of NASDAQ.

Indemnification of Officers and Directors

Under Section 124 of the Business Corporations Act (Alberta) (the "ABCA"), except in respect of an action by or on behalf of us or body corporate to procure a judgment in our favor, we may indemnify a current or former director or officer or a person who acts or acted at our request as a director or officer of a body corporate of which we are or were a shareholder or creditor and the heirs and legal representatives of any such persons (collectively, "Indemnified Persons") against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by any such Indemnified Person in respect of any civil, criminal or administrative actions or proceedings to which the director or officer is made a party by reason of being or having been our director or officer, if (i) the director or officer acted honestly and in good faith with a view to our best interests, and (ii) in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, the director or officer had reasonable grounds for believing that such director's or officer's conduct was lawful (collectively, the "Indemnification Conditions").

Notwithstanding the foregoing, the ABCA provides that an Indemnified Person is entitled to indemnity from us in respect of all costs, charges and expenses reasonably incurred by the person in connection with the defense of any civil, criminal or administrative action or proceeding to which the person is made a party by reason of being or having been our director or officer, if the person seeking indemnity (i) was substantially successful on the merits in the person's defense of the action or proceeding, (ii) fulfills the Indemnification Conditions, and (iii) is fairly and reasonably entitled to indemnity. We may advance funds to an Indemnified Person for the costs, charges and expenses of a proceeding; however, the

86

Indemnified Person shall repay the moneys if such individual does not fulfill the Indemnification Conditions. The indemnification may be made in connection with a derivative action only with court approval and only if the Indemnification Conditions are met.

As contemplated by Section 124(4) of the ABCA and our by-laws, we have acquired and maintain liability insurance for our directors and officers with coverage and terms that are customary for a company of our size in our industry of operations. The ABCA provides that we may not purchase insurance for the benefit of an Indemnified Person against a liability that relates to the person's failure to act honestly and in good faith with a view to our best interests.

Our by-laws provide that, subject to the ABCA, the Indemnified Persons shall be indemnified against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by such person in respect of any civil, criminal or administrative action or proceeding to which such person is made a party by reason of being or having been a director or officer of the Company or such body corporate, if the Indemnification Conditions are satisfied. In addition, pursuant to our by-laws, we may indemnify such person in such other circumstances as the ABCA or law permits.

Our by-laws also provide that none of our directors or officers shall be liable for the acts, receipts, neglects or defaults of any other director, officer or employee, or for joining in any receipt or other act for conformity, or for any loss, damage or expense happening to us through the insufficiency or deficiency of title to any property acquired for or on behalf of us, or for the insufficiency or deficiency of any security in or upon which any of our moneys shall be invested, or for any loss or damage arising from the bankruptcy, insolvency or tortious acts of any person with whom any of our moneys, securities or effects shall be deposited, or for any loss occasioned by any error of judgment or oversight on his part, or for any other loss, damage or misfortune which shall happen in the execution of the duties of his or her office or in relation thereto; provided that nothing in our by-laws shall relieve any director or officer from the duty to act in accordance with the ABCA and the regulations thereunder. The foregoing is premised on the requirement under our by-laws that each of our directors and officers in exercising his or her powers and discharging duties shall act honestly and in good faith with a view to our best interests and exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances.

We have entered into indemnification agreements with our directors and officers which generally require that we indemnify and hold the indemnitees harmless to the greatest extent permitted by law for liabilities arising out of the indemnitees' service to us and our subsidiaries as directors and officers, if the indemnitees acted honestly and in good faith with a view to our best interests and, with respect to criminal or administrative actions or proceedings that are enforced by monetary penalty, if the indemnitee had no reasonable grounds to believe that his or her conduct was unlawful. The indemnification agreements also provide for the advancement of defense expenses to the indemnitees by us.

ITEM 14.     PRINCIPAL ACCOUNTING FEES AND SERVICES.

The following table summarizes fees billed to us for fiscal 2024 and for fiscal 2023 by our principal auditors, BDO USA, P.C.:

	December 31,		December 31,
	2024		2023
Audit Fees:
Audit of financial statements	$	388,886	$	395,759
Total Audit Fees	$	388,886	$	395,759

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PART IV

ITEM 15.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

(a)1.	Financial Statements:
	Report of Independent Registered Public Accounting Firm (PCAOB ID 243)
	Consolidated Balance Sheets as of December 31, 2024 and December 31, 2023.
	Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2024 and December 31, 2023.
	Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2024 and December 31, 2023.
	Consolidated Statements of Cash Flows for the years ended December 31, 2024 and December 31, 2023.
	Notes to Consolidated Financial Statements
(a)2.	Financial Statement Schedules:
	None.
(a)3.	Exhibits
3.1	Articles of Incorporation of Epsilon Energy Ltd (incorporated by reference to Exhibit 3.1 of Form 10, File No. 001-38770, filed on December 21, 2018).
3.2	Bylaws of Epsilon Energy Ltd. (incorporated by reference to Exhibit 3.2 of Form 10, File No. 001-38770, filed on December 21, 2018)
3.3	Articles of Amendment dated December 19, 2019 (incorporated by reference to Exhibit 3.3 of Form 10, File No. 001-38770, filed on December 21, 2018)
4.1	Description of Registrant’s Securities Registered Under Section 12 of the Exchange Act. (incorporated by reference to Exhibit 4.1 of Form 10-K, File No. 001-38770, filed on March 18, 2020)
10.1+	Henry Clanton Employment Agreement (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 001-38770, filed on March 12, 2024)
10.2	Anchor Shipper Gas Gathering Agreement, effective January 1, 2024, by and between Appalachia Midstream Services, L.L.C. and Epsilon Energy USA, Inc., as shipper and producer (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 001-38770, filed on May 21, 2024)
10.3+	2020 Equity Incentive Plan effective as of September 1, 2020 (incorporated by reference to Exhibit 10.1 of Form8-K, File No. 001-38770, filed on September 1, 2020)
10.4+	Share Compensation Plan (incorporated by reference to Exhibit 10.10 of Form 10, File No. 001-38770, filed on December 21, 2018)
10.5	Agreement for the Construction, Ownership, and Operation of Midstream Assets in AMI Area D of Northern Pennsylvania effective the 1st day of January, 2012, by and between Statoil Pipelines, LLC, a Delaware limited liability company formerly known as StatoilHydro Pipelines, LLC, Epsilon Midstream LLC, a Pennsylvania limited liability company, and Appalachia Midstream Services, L.L.C., an Oklahoma limited liability company (incorporated by reference to Exhibit 10.11 of Form 10, File No. 001-38770, filed on December 21, 2018)
10.6+	Jason Stabell Executive Employment Agreement (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 001-38770, filed on June 24, 2022)
10.7+	Andrew Williamson Executive Employment Agreement (incorporated by reference to Exhibit 10.4 of Form 8-K, File No. 001-38770, filed on June 24, 2022)

88

10.8	Credit Agreement, dated as of June 28, 2023, by and among Epsilon Energy USA Inc., Frost Bank, as agent and issuing bank, and the lenders from time to time party hereto (incorporated by reference to Exhibit 10.8 of Form 10-K, File No. 001-38770, filed on March 21, 2024)
10.9	Participation Agreement with HWN Energy, Ltd dated October 22, 2024 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 001-38770, filed on October 28, 2024)
19.1*	Insider Trading Policy, updated November 13, 2024
21.1	Subsidiaries of the Registrant (incorporated by reference to Exhibit 21.1 of Form 10, File No. 001-38770, filed on December 21, 2018)
23.1*	Consent of DeGolyer and MacNaughton
23.2*	Consent of BDO USA, P.C.
31.1*	Rule 13a-14(a)/15d-14(a) Certification.
31.2*	Rule 13a-14(a)/15d-14(a) Certification.
32.1**	Section 1350 Certifications.
32.2**	Section 1350 Certifications.
97.1	Epsilon Energy Ltd. Clawback Policy (incorporated by reference to Exhibit 97.1 of Form 10-K, File No. 001-38770, filed on March 21, 2024)
99.1*	Summary Reserve Report
101.INS*	Inline XBRL Instance Document.
101.SCH*	Inline XBRL Taxonomy Extension Schema Document.
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*	Filed herewith.
**	Furnished herewith.
+	Denotes a management contract or compensatory plan or arrangement.

89

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on March 19, 2025.

Epsilon Energy Ltd.

By: /s/ J. Andrew Williamson

J. Andrew Williamson

Chief Financial Officer

(duly authorized to sign on behalf of the registrant)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:

Signature	Title	Date
/s/ Jason Stabell	Chief Executive Officer and Director	March 19, 2025
Jason Stabell	(Principal Executive Officer)
/s/ J. Andrew Williamson	Chief Financial Officer	March 19, 2025
J. Andrew Williamson	(Principal Financial and Accounting Officer)
/s/ John Lovoi	Chairman of the Board and Director	March 19, 2025
John Lovoi
/s/ Jason Stankowski	Director	March 19, 2025
Jason Stankowski
/s/ Tracy Stephens	Director	March 19, 2025
Tracy Stephens
/s/ David Winn	Director	March 19, 2025
David Winn
/s/Nicola Maddox	Director	March 19, 2025
Nicola Maddox

90

EX-19.1

Exhibit 19.1

III. BLACKOUT PERIODS AND INSIDER TRADING POLICY ON

EPSILON SECURITIES

Issued By: Chief Financial Officer

Approved By: Board of Directors

Updated: November 13, 2024

PURPOSE

This insider trading and blackout period policy is being provided to all directors, officers, employees, contractors, subcontractors, agents, and consultants of Epsilon to help ensure compliance with the various securities laws and rules of the Nasdaq Stock Market (“Nasdaq”) surrounding the trading of common shares and other securities of Epsilon.

INSIDER TRADING

There are effectively two groups of insiders.

Securities legislation defines, in part, an insider as:

- a director or officer of a corporation;

- a director or officer of a subsidiary of a corporation; or

- a person who owns either directly or indirectly more than 10% of the outstanding class of securities of a corporation that is registered under the Securities Exchange Act of 1934 (the “Exchange Act”).

Under the Exchange Act, this group of insiders must file reports on beneficial ownership of, and transactions involving, any common shares of Epsilon, including acquisition of options or other securities convertible into common shares of Epsilon, with the Securities and Exchange Commission (the “SEC”).  These reports are required to be filed within 10 days (for new filers), and, subject to limited exceptions, by the end of the second business day (for existing filers) following the transaction.  If you are an insider in this group and you have children living at home who trade in Epsilon securities, then most likely such trades have to be reported on your report.  Both direct and indirect beneficial ownership is required to be reported.

A second group of insiders includes people who have a special relationship with Epsilon.  The existence of a special relationship can be determined based on your position with, or within, Epsilon and the nature of information your role requires you to have or have access to.  In effect, all employees, contractors, subcontractors, agents, and consultants probably qualify as having a special relationship with Epsilon and, as a result, must comply with specific trading restrictions on Epsilon's securities.

These specific trading restrictions prohibit trading in Epsilon securities if you have knowledge of an undisclosed material fact or material change regarding Epsilon, sometimes referred to as “material non-public information,” or “MNPI.”  Further, this restriction prohibits the disclosure of MNPI to third parties. This is to prevent those third parties from acting on MNPI before it becomes publicly available in order to make illegal gains in the stock market.

Information is no longer considered to be MNPI when a news release is published by Epsilon and disseminated on one of the recognized corporate newswires, or otherwise publicly filed with or furnished to the SEC, and enough time has elapsed to permit the investment market to absorb and evaluate the information.  As a general rule, you should consider information to be nonpublic until two full trading days have lapsed following public disclosure.

If you violate the federal insider trading laws, you may have to pay civil fines of up to three times the profit gained or loss avoided by such trading, as well as criminal fines of up to $5 million.  You also may have to serve a jail sentence of up to 20 years.  In addition, Epsilon may face civil penalties up to the greater of $1 million, or three times the profit gained or loss avoided as a result of your insider trading violations, as well as criminal fines of up to $25 million.

MATERIAL INFORMATION

MNPI can include, but is not limited to:

-An acquisition, disposition or merger involving Epsilon;

-A new issue of securities of Epsilon;

-A change in Epsilon's dividend policy;

-A change in lending or financial arrangements;

-A change in expected earnings;

-Major changes in operational events;

-Executing or losing significant contracts; or

-Problems with labor, suppliers, contractors or customers

Securities legislation defines “material information” as information that would reasonably be expected to have a significant effect on the market price or value of the securities.  Another rule of thumb defines information as material if an arm's length investor would decide to buy, sell, or hold the stock based on the information in question.  Federal and other investigators will scrutinize a questionable trade after the fact with the benefit of hindsight, so you should always err on the side of deciding that the information is material and not trade.

Every employee, contractor, subcontractor, agent, or consultant may become aware of MNPI in the ordinary course of their duties.

Restrictions on trading Epsilon shares also extends to trading in shares of third-party organizations that Epsilon may be negotiating with on a business transaction or opportunity until the information has been fully disclosed and a reasonable period of time has passed for the information to be widely disseminated.

BLACKOUT PERIODS

Blackout periods are specific time periods during which trading of securities of Epsilon are prohibited.  These blackout periods are established by Epsilon based on certain regular reporting periods or transaction activities that arise from time to time.  Blackout periods are related to insider trading but reflect a specific intent of Epsilon to prevent insider trading, or the appearance of impropriety, by its officer, directors, employees and consultants.

Blackout periods may be implemented by a senior officer of Epsilon who is responsible for dealing with a variety of material information relating to Epsilon as described above.  Based on material information that may arise, the senior officer is then responsible for determining whether a blackout period should be imposed and to whom the blackout period should apply.  A notice advising of the blackout period will be distributed by the Chief Financial Officer.

Typically a blackout period covers the directors, officers, employees and consultants of Epsilon but may be expanded to specific individuals depending on their particular responsibilities and information they have access to regarding the material information in question.  The imposition of a blackout period will be specific both to its duration and application.

As a matter of policy, blackout periods will be imposed by Epsilon for the time periods surrounding the release of quarterly and annual financial results.  These blackout periods apply to the officers, directors, employees and consultants of Epsilon and include:

the period after the end of a fiscal quarter or year and continuing until the close of trading of the 2^nd full day of trading after earnings are released.

These deemed blackout periods may be expanded or modified in time and application by the President or other senior officers as they consider necessary.

In any instance, other than the regularly scheduled blackout periods described above, should a senior officer implement a blackout period, its duration and its application to particular individuals will be specified and disseminated through an interoffice notification by the Chief Financial Officer.  Notwithstanding that a particular individual may not be specifically addressed in an interoffice notification for a blackout period, that individual is still subject to the broader insider trading restrictions.

This policy does not prevent the exercise of Epsilon stock options if no shares are to be sold or if there is a net exercise (as defined below).  Therefore, you may freely exercise your stock options, engage in “net exercises” and have Epsilon withhold shares to satisfy your tax obligations without violating this policy.  Note that a “net exercise” (which is permitted) is the use of the underlying shares to pay the exercise price and/or tax withholding obligations, whereas a broker-assisted cashless exercise (which is not permitted) involves the broker selling some or all of the shares underlying the option on the open market.

RULE 10b5-1 TRADING PLANS

Rule 10b5-1 under the Exchange Act provides a defense from insider trading liability if trades occur pursuant to a pre-arranged trading plan that meets specified conditions.  It is possible to pre-arrange trades in Epsilon securities by entering into a written trading plan.  Trading plans can be established for a single trade or a series of trades.  A plan must either specify the number of securities to be bought or sold, along with the price and the date, or provide a written formula for determining this information.  Alternatively, a trading plan can delegate investment discretion to a third party, such as a broker, who then makes trading decisions without further input from the person implementing the plan.  Because the SEC rules on trading plans are complex, you should consult with your broker and be sure you fully understand the limitations and conditions of the rules before you establish a trading plan.

All Rule 10b5-1 trading plans and any amendments thereto and terminations thereof must be reviewed and approved in advance by the Chief Financial Officer.

SUMMARY

Insider trading restrictions apply to every insider associated with Epsilon who in fact becomes aware of material information regarding Epsilon that is not available to the general public.

Blackout periods restrict trading of Epsilon's shares by directors, officers, employees and consultants of Epsilon for a specific period of time because they are assumed to have received material information about Epsilon that has not been generally released to the public.

For confirmation of whether a blackout period is in effect, or any questions regarding insider trading or requirements of the SEC, please feel free to contact the Chief Financial Officer for clarification.

EX-23.1

Exhibit 23.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

March 19, 2025

Epsilon Energy Ltd.

500 Dallas, Suite 1250

Houston, Texas 77002

Ladies and Gentlemen:

We hereby consent to the reference to DeGolyer and MacNaughton and to the incorporation of the estimates contained in our reports entitled “Report as of December 31, 2024 on Reserves and Revenue of Certain Properties with interests attributable to Epsilon Energy Ltd” and “Report as of December 31, 2024 on Reserves and Revenue of Certain Properties with interests attributable to Epsilon Energy Ltd. NI 51-101” in Part 1 and in the “Supplemental Information to Consolidated Financial Statements (Unaudited)” portion of the Annual Report on Form 10-K of Epsilon Energy Ltd. for the year ended December 31, 2024 (the Annual Report). We further consent to the inclusion of our report of third party dated January 23, 2025, relating to our independent evaluation of the estimated proved oil, condensate, natural gas liquids, and gas reserves, as of December 31, 2024, attributable to Epsilon Energy Ltd. in the Annual Report.

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

EX-23.2

‌Exhibit 23.2

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-269267) and Form S-8 (No. 333-232520) of Epsilon Energy Ltd. of our report dated March 19, 2025, relating to the consolidated financial statements, which appears in this Annual Report on Form 10-K.

/s/ BDO USA, P.C.

Houston, Texas

March 19, 2025

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

pursuant to Rule 13a-14(a)/15d-14(a)

I, Jason Stabell, Chief Executive Officer of Epsilon Energy Ltd., certify that:

1. I have reviewed this Annual Report on Form 10-K of Epsilon Energy Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

9

Date: March 19, 2025

/s/ Jason Stabell

Jason Stabell

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

pursuant to Rule 13a-14(a)/15d-14(a)

I, J. Andrew Williamson, Chief Financial Officer of Epsilon Energy Ltd., certify that:

1. I have reviewed this Annual Report on Form 10-K of Epsilon Energy Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

9

Date: March 19, 2025

/s/ J. Andrew Williamson

J. Andrew Williamson

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Epsilon Energy Ltd. (the “Corporation”) on Form 10-K for the period ending December 31, 2024 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Corporation.

Date: March 19, 2025

/s/ Jason Stabell

Jason Stabell

Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Epsilon Energy Ltd. (the “Corporation”) on Form 10-K for the period ending December 31, 2024 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Corporation.

Date: March 19, 2025

/s/ J. Andrew Williamson

J. Andrew Williamson

Chief Financial Officer

EX-99.1

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

January 23, 2025

Epsilon Energy Ltd.

500 Dallas Street

Suite 1250

Houston, Texas 77002

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2024, of the extent and value of the estimated net proved oil, condensate, natural gas liquids (NGL), and gas reserves of certain properties in which Epsilon Energy Ltd. (Epsilon) has represented it holds an interest. This evaluation was completed on January 23, 2025. The properties evaluated herein consist of working and royalty interests located in the States of New Mexico, Oklahoma, Pennsylvania, and Texas, in the United States and the Province of Alberta in Canada. Epsilon has represented that these properties account for 100 percent on a net gas equivalent basis of Epsilon’s net proved reserves as of December 31, 2024. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by Epsilon.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2024. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Epsilon after deducting all interests held by others.

Values for proved reserves in this report are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is defined as that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

production taxes, impact fees, operating expenses, capital costs, and abandonment costs from future gross revenue. Operating expenses include field operating expenses, transportation and processing expenses, and an allocation of overhead that directly relates to production activities. Capital costs include drilling and completion costs, facilities costs, and field maintenance costs. Abandonment costs are represented by Epsilon to be inclusive of those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment. At the request of Epsilon, future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a discount rate of 10 percent per year compounded monthly over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.

Estimates of reserves and revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Information used in the preparation of this report was obtained from Epsilon and from public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by Epsilon with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report.

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a)
(1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) 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.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

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

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

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

(v) 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 prior to 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.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) 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; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category 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.

(i) 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

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) 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 the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for 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, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

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.

Based on the current stage of field development, production performance, the development plans provided by Epsilon, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The undeveloped reserves estimates were based on opportunities identified in the plan of development provided by Epsilon.  

Epsilon has represented that its senior management is committed to the development plan provided by Epsilon and that Epsilon has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

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).

Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs.

In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.

Data provided by Epsilon from wells drilled through December 31, 2024, and made available for this evaluation were used to prepare the reserves estimates herein. Reserves estimates for wells located in New Mexico, Pennsylvania, and Texas were based on consideration of daily and monthly production data available for certain properties only through November 2024. Estimated cumulative production, as of December 31, 2024, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 1 month for properties in New Mexico, Pennsylvania, and Texas. Reserves estimates for wells and overriding royalty interests located in Oklahoma were based on consideration of monthly production data available for certain properties only through June 2024. Estimated cumulative production, as of December 31, 2024, was deducted from the estimated gross ultimate recovery to estimate gross reserves, requiring that production be estimated for up to 6 months for properties in Oklahoma. Additionally, reserves estimates for wells and overriding royalty interests located in Oklahoma were based on consideration of monthly production data available for twelve properties only through April 2024, due primarily to these data not being available in the public domain. Estimated cumulative production, as of December 31, 2024, was deducted from the estimated gross ultimate recovery to estimate gross reserves, requiring that production be estimated for up to

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

8 months for properties in Oklahoma. Epsilon has represented that properties for which monthly production data were available only through April 2024 were producing as of December 31, 2024.

Oil and condensate reserves estimated herein are those to be recovered by normal field separation. NGL reserves estimated herein include pentanes and heavier fractions (C₅₊) and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions, and are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in thousands of barrels (Mbbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the pressure base of the state or province in which the quantities are located. Gas quantities included in this report are expressed in millions of cubic feet (MMcf).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.

At the request of Epsilon, liquid reserves estimated herein were converted to gas equivalent using an energy equivalent factor of 1 barrel of liquids per 6,000 cubic feet of gas equivalent.

Primary Economic Assumptions

Revenue values in this report were estimated using initial prices, expenses, and costs provided by Epsilon. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the revenue values reported herein:

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

Oil, Condensate, and NGL Prices

Epsilon has represented that the oil, condensate, and NGL prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Epsilon supplied differentials to a West Texas Intermediate price of $76.32 per barrel and the prices were held constant thereafter. The volume-weighted average prices attributable to the estimated proved reserves over the lives of the properties were $74.71 per barrel of oil and condensate and $28.20 per barrel of NGL.

Gas Prices

Epsilon has represented that the gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Epsilon supplied differentials to a Henry Hub price of $2.13 per million Btu and the prices were held constant thereafter. Btu factors provided by Epsilon were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $1.528 per thousand cubic feet of gas.

Production Taxes and Impact Fees

For properties located in New Mexico, Oklahoma, Texas, and Alberta, Canada, production taxes were calculated using rates provided by Epsilon. For wells located in Pennsylvania, and in accordance with state law, an annual impact fee is assessed over the course of the first 15 years of production after the well is drilled. The amount of the annual fee imposed is adjusted annually on a sliding scale based on the average price of gas for each given year. For wells located in Alberta, Canada, production taxes were calculated using rates provided by Epsilon.

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

Royalties

Properties evaluated herein that are located in Alberta, Canada are subject to applicable royalties under the Modernized Royalty Framework, effective January 1, 2017.

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses and future capital expenditures, provided by Epsilon and based on existing economic conditions, were held constant for the lives of the properties. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by Epsilon and were not adjusted for inflation. At the request of Epsilon, abandonment costs and any associated negative future net revenue have been included herein for those proved developed properties for which reserves were estimated to be zero. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein.

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, NGL, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

Summary of Conclusions

DeGolyer and MacNaughton has performed an independent evaluation of the extent and value of the estimated net proved oil, condensate, NGL, and gas reserves of certain properties in which Epsilon has represented it holds an interest. The estimated net proved reserves, as of December 31, 2024, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and millions of cubic feet of gas equivalent (MMcfe):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2024
	Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Gas Equivalent (MMcfe)
Proved Developed	847	490	56,851	64,872
Proved Undeveloped	725	387	12,550	19,225
Total Proved	1,572	877	69,401	84,097
Note: Liquid reserves estimated herein were converted to gas equivalent using an energy equivalent factor of 1 barrel of liquids per 6,000 cubic feet of gas equivalent.

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

The estimated future revenue to be derived from the production and sale of the net proved reserves, as of December 31, 2024, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):

	Proved Developed (M$)	Total Proved (M$)
Future Gross Revenue	164,016	248,266
Production Taxes and Impact Fees	7,077	12,893
Operating Expenses	71,702	96,177
Capital Costs	0	23,133
Abandonment Costs	7,956	8,329
Future Net Revenue	77,281	107,734
Present Worth at 10 Percent	50,591	62,310
Note:  Future income taxes have not been taken into account in the preparation of these estimates.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2024, estimated reserves.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Epsilon. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Epsilon. DeGolyer and MacNaughton has used all assumptions, procedures, data, and methods that it considers necessary to prepare this report.

Submitted,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

/s/ Dilhan Ilk

Dilhan Ilk, P.E.

Executive Vice President

DeGolyer and MacNaughton

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

CERTIFICATE of QUALIFICATION

I, Dilhan Ilk, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1. That I am an Executive Vice President with DeGolyer and MacNaughton, which firm did prepare this report of third party addressed to Epsilon dated January 23, 2025, and that I, as Executive Vice President, was responsible for the preparation of this report of third party.

2. That I attended Istanbul Technical University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 2003, a Master of Science degree in Petroleum Engineering from Texas A&M University in 2005, and a Doctor of Philosophy degree in Petroleum Engineering from Texas A&M University in 2010; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 14 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ Dilhan Ilk

Dilhan Ilk, P.E.

Executive Vice President

DeGolyer and MacNaughton

XML

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Mar. 18, 2025	Jun. 28, 2024
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2024
Document Transition Report	false
Document Fiscal Year Focus	2024
Securities Act File Number	001-38770
Entity Registrant Name	EPSILON ENERGY LTD.
Entity Incorporation, State or Country Code	A0
Entity Tax Identification Number	98-1476367
Entity Address, Address Line One	500 Dallas Street
Entity Address, Address Line Two	Suite 1250
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	281
Local Phone Number	670-0002
Title of 12(b) Security	Common Shares, no par value
Trading Symbol	EPSN
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 90.9
Entity Common Stock, Shares Outstanding		22,008,766
Entity Central Index Key	0001726126
Current Fiscal Year End Date	--12-31
Document Fiscal Period Focus	FY
Amendment Flag	false
Auditor Name	BDO USA, P.C.
Auditor Firm ID	243
Auditor Location	Houston, Texas

XML

Consolidated Balance Sheets - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Current assets
Cash and cash equivalents	$ 6,519,793	$ 13,403,628
Accounts receivable	5,843,722	6,015,448
Short term investments	0	18,775,106
Fair value of derivatives	0	1,219,025
Prepaid income taxes	975,963	952,301
Other current assets	792,041	763,288
Total current assets	14,131,519	41,128,796
Oil and gas properties, successful efforts method
Proved properties	191,349,210	160,263,511
Unproved properties	28,364,186	25,504,873
Accumulated depletion, depreciation, amortization and impairment	(122,751,395)	(113,708,210)
Total oil and gas properties, net	96,962,001	72,060,174
Gathering system	43,116,371	42,738,273
Accumulated depletion, depreciation, amortization and impairment	(36,449,511)	(35,539,996)
Total gathering system, net	6,666,860	7,198,277
Land	637,764	637,764
Buildings and other property and equipment, net	259,335	291,807
Total property and equipment, net	104,525,960	80,188,022
Other assets:
Operating lease right-of-use assets, long term	344,589	441,987
Restricted cash	470,000	470,000
Prepaid drilling costs	982,717	1,813,808
Total non-current assets	106,323,266	82,913,817
Total assets	120,454,785	124,042,613
Current liabilities
Accounts payable trade	2,334,732	3,149,371
Gathering fees payable	997,016	1,136,237
Royalties payable	1,400,976	1,422,898
Accrued capital expenditures	572,079	696,761
Accrued compensation	695,018	636,295
Other accrued liabilities	371,503	649,037
Fair value of derivatives	487,548	118,770
Operating lease liabilities	121,135	86,473
Total current liabilities	6,980,007	7,895,842
Non-current liabilities
Asset retirement obligations	3,652,296	3,502,952
Deferred income taxes	12,738,577	11,553,943
Operating lease liabilities, long term	355,776	476,911
Total non-current liabilities	16,746,649	15,533,806
Total liabilities	23,726,656	23,429,648
Commitments and contingencies (Note 11)
Shareholders' equity
Preferred shares, no par value, unlimited shares authorized, none issued or outstanding	0	0
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
Treasury shares, at cost, 0 at December 31, 2024 and 70,874 at December 31, 2023	0	(360,326)
Additional paid-in capital	12,118,907	10,874,491
Accumulated deficit	(41,505,076)	(37,946,042)
Accumulated other comprehensive income	10,033,267	9,772,277
Total shareholders' equity	96,728,129	100,612,965
Total liabilities and shareholders' equity	$ 120,454,785	$ 124,042,613

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Stockholders' Equity, Number of Shares, Par Value and Other Disclosure [Abstract]
Preferred shares, no par value	$ 0	$ 0
Preferred shares, unlimited authorized	Unlimited	Unlimited
Preferred shares issued	0	0
Common shares, no par value	$ 0	$ 0
Common shares, unlimited authorized	Unlimited	Unlimited
Common shares issued	22,008,766	22,222,722
Common shares outstanding	22,008,766	22,151,848
Treasury shares	0	70,874

XML

Consolidated Statements of Operations and Comprehensive Income - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Revenues from contracts with customers:
Total revenue	$ 31,522,775	$ 30,729,752
Operating costs and expenses:
Lease operating expenses	7,264,824	6,405,281
Gathering system operating expenses	2,265,190	2,459,694
Depletion, depreciation, amortization, and accretion	10,185,119	7,685,084
Impairment expense	1,450,076	0
Loss on sale of oil and gas properties	0	1,449,871
General and administrative expenses:
Stock based compensation expense	1,244,416	1,018,262
Other general and administrative expenses	5,688,714	6,293,234
Total operating costs and expenses	28,098,339	25,311,426
Operating income	3,424,436	5,418,326
Other income (expense):
Interest income	493,277	1,673,241
Interest expense	(46,400)	(80,379)
(Loss) gain on derivative contracts	(391,147)	3,130,055
Other income	76,727	4,357
Other income, net	132,457	4,727,274
Net income before income tax expense	3,556,893	10,145,600
Income tax expense	1,629,093	3,200,447
NET INCOME	1,927,800	6,945,153
Currency translation adjustments	262,588	(3,872)
Unrealized (loss) gain on securities	(1,598)	1,598
NET COMPREHENSIVE INCOME	$ 2,188,790	$ 6,942,879
Net income per share, basic (in dollars per share)	$ 0.09	$ 0.31
Net income per share, diluted (in dollars per share)	$ 0.09	$ 0.31
Weighted average number of shares outstanding, basic (in shares)	21,930,277	22,496,772
Weighted average number of shares outstanding, diluted (in shares)	21,930,277	22,511,647
Gas, oil, NGL, and condensate revenue
Revenues from contracts with customers:
Total revenue	$ 25,998,712	$ 20,939,221
Gas gathering and compression revenue
Revenues from contracts with customers:
Total revenue	$ 5,524,063	$ 9,790,531

XML

Consolidated Statements of Changes in Shareholders' Equity - USD ($)	Common Shares	Treasury Shares	Additional paid-in Capital	Accumulated Other Comprehensive Income	Accumulated Deficit	Total
Balance at beginning of period at Dec. 31, 2022	$ 123,904,965		$ 9,856,229	$ 9,774,551	$ (39,290,540)	$ 104,245,205
Balance (in shares) at Dec. 31, 2022	23,117,144
Increase (Decrease) in Stockholders' Equity
Net income					6,945,153	6,945,153
Dividends paid					(5,600,655)	(5,600,655)
Stock-based compensation expense			1,018,262			1,018,262
Exercise of stock options	$ 62,875					62,875
Exercise of stock options (in shares)	12,500
Buyback of common shares		$ (6,055,601)				(6,055,601)
Buyback of common shares (in shares)		(1,158,849)
Retirement of treasury shares	$ (5,695,275)
Retirement of treasury shares (in shares)	(1,087,975)
Treasury Shares, Retirement of treasury shares		$ 5,695,275
Treasury Shares, Retirement of treasury shares (in shares)		1,087,975
Vesting of shares of restricted stock	181,053
Other comprehensive income (loss)				(2,274)		(2,274)
Balance at end of period at Dec. 31, 2023	$ 118,272,565	$ (360,326)	10,874,491	9,772,277	(37,946,042)	$ 100,612,965
Balance (in shares) at Dec. 31, 2023	22,222,722
Treasury Shares, End Balance (in shares) at Dec. 31, 2023		(70,874)				(70,874)
Increase (Decrease) in Stockholders' Equity
Net income					1,927,800	$ 1,927,800
Dividends paid					(5,486,834)	(5,486,834)
Stock-based compensation expense			1,244,416			1,244,416
Buyback of common shares		$ (1,831,208)				(1,831,208)
Buyback of common shares (in shares)		(373,700)
Retirement of treasury shares	$ (2,191,534)
Retirement of treasury shares (in shares)	(444,574)
Treasury Shares, Retirement of treasury shares		$ 2,191,534
Treasury Shares, Retirement of treasury shares (in shares)		444,574
Vesting of shares of restricted stock	230,618
Other comprehensive income (loss)				260,990		260,990
Balance at end of period at Dec. 31, 2024	$ 116,081,031		$ 12,118,907	$ 10,033,267	$ (41,505,076)	$ 96,728,129
Balance (in shares) at Dec. 31, 2024	22,008,766
Treasury Shares, End Balance (in shares) at Dec. 31, 2024						0

XML

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Cash flows from operating activities:
Net income	$ 1,927,800	$ 6,945,153
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion	10,185,119	7,685,084
Impairment expense	1,450,076	0
Accretion of discount on available for sale securities	(297,637)	(836,528)
Loss on sale of oil and gas properties	0	1,449,871
Gain (loss) on derivative contracts	391,147	(3,130,055)
Settlement received on derivative contracts	1,196,656	3,251,890
Settlement of asset retirement obligation	(88,992)	(509,802)
Stock-based compensation expense	1,244,416	1,018,262
Deferred income tax expense	1,184,634	936,549
Changes in assets and liabilities:
Accounts receivable	171,726	1,185,938
Prepaid income taxes	(23,662)	187,793
Other assets and liabilities	(17,828)	126,347
Accounts payable, royalties payable and other accrued liabilities	(493,176)	(122,203)
Net cash provided by operating activities	16,830,279	18,188,299
Cash flows from investing activities:
Additions to unproved oil and gas properties	(4,507,280)	(8,136,442)
Additions to proved oil and gas properties	(31,695,651)	(10,377,642)
Additions to gathering system properties	(341,452)	(82,302)
Additions to land, buildings and property and equipment	(16,513)	(49,689)
Purchases of short term investments - held to maturity	0	(32,812,974)
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	26,864,976
Proceeds from short term investments - available for sale	16,373,752	0
Proceeds from sale of oil and gas properties	0	12,498
Prepaid drilling costs	831,091	(1,813,808)
Net cash used in investing activities	(16,658,660)	(38,384,365)
Cash flows from financing activities:
Buyback of common shares	(1,831,208)	(6,055,601)
Exercise of stock options	0	62,875
Dividends paid	(5,486,834)	(5,600,655)
Debt issuance costs	0	(140,000)
Net cash used in financing activities	(7,318,042)	(11,733,381)
Effect of currency rates on cash, cash equivalents, and restricted cash	262,588	(3,872)
Decrease in cash, cash equivalents, and restricted cash	(6,883,835)	(31,933,319)
Cash, cash equivalents, and restricted cash, beginning of period	13,873,628	45,806,947
Cash, cash equivalents, and restricted cash, end of period	6,989,793	13,873,628
Supplemental cash flow disclosures:
Income tax paid - federal	414,250	1,250,000
Interest paid	16,832	97,595
Non-cash investing activities:
Change in proved properties accrued in accounts payable and accrued liabilities	(862,744)	1,611,724
Change in gathering system accrued in accounts payable and accrued liabilities	36,645	16,969
Asset retirement obligation asset additions and adjustments	54,902	1,190,579
State (PA)
Supplemental cash flow disclosures:
Income tax (refund) paid	0	182,000
State (other)
Supplemental cash flow disclosures:
Income tax (refund) paid	$ (2,071)	$ 7,583

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Description of Business

12 Months Ended

Dec. 31, 2024

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of Business

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.

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Basis of Preparation

12 Months Ended

Dec. 31, 2024

Accounting Policies [Abstract]

Basis of Preparation

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 Energy Holdings, 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.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2024

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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 and 2023:

	December 31,		December 31,
	2024		2023
Cash and cash equivalents	$	6,519,793	$	13,403,628
Restricted cash included in other assets		470,000		470,000
Cash, cash equivalents, and restricted cash in the statement of cash flows	$	6,989,793	$	13,873,628

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.

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.

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.

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.

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. 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.

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 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.

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 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 Liquids Revenue

The source of the Company’s oil and other liquids revenue is its ownership in wells in the Permian Basin, Oklahoma, and Alberta, Canada.  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 Receivable and Other

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 Northeastern Pennsylvania, the Permian Basin, Oklahoma, 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 of transmission. The Company’s operations do not result in any contract assets or liabilities on the accompanying consolidated balance sheets.

Buildings and Other Property and Equipment

Buildings are depreciated on a straight-line basis over the estimated useful life of the property, 30 years.

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 Company had investments in U.S. Treasury Bills, which mature over a period between 3 and 12 months and are classified as short term investments. The U.S. Treasury Bills are carried at fair value. The U.S. Treasury Bills are classified within Level 1 of the fair value hierarchy.

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.

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.

● 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 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, cash and cash equivalents was primarily concentrated in one financial institution the U.S. At December 31, 2023, cash and cash equivalents and short term investments were primarily concentrated in one financial institution the U.S. We currently have $4.1 million in excess of the federally insured limits. The Company periodically assesses the financial condition of these institutions and believe that any possible credit risk is minimal.

For the year ended December 31, 2024, the Company had three customers that accounted for 89.1% of the total trade accounts receivable. For the year ended December 31, 2023, the Company had four customers that accounted for 90.7% of the total trade accounts receivable.

Geographic Locations of Operations

Approximately 50% and 77% of our revenue during fiscal years 2024 and 2023, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania. 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.

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.

Income Taxes

Deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. Epsilon assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate (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 are included in accumulated other comprehensive income.

Stock-Based Compensation

The Company has issued time-based restricted stock and performance share units (“PSU”) to employees and directors of the Company. The fair value of the time-based restricted stock 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 awards vest ratably over a three-year period. 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).

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.

Recently Issued Accounting Standards

In October 2023, the FASB issued ASU No. 2023-06, Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative, to amend certain disclosure and presentation requirements. For entities subject to the SEC’s existing disclosure requirements, the effective date for each amendment

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.

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Short Term Investments

12 Months Ended

Dec. 31, 2024

Investments, Debt and Equity Securities [Abstract]

Short Term Investments

4. Short Term Investments

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
	Amortized		Unrealized		Fair		Amortized		Unrealized		Fair
	Cost		Losses		Value		Cost		Gains		Value
U.S. Treasury Bills	$	—	$	—	$	—	$	18,773,508	$	1,598	$	18,775,106

During the year ended December 31, 2024, the Company sold securities with a carrying amount of $14,989,595 for total proceeds of $15,336,930. The realized gains on these sales were $347,335. An additional $7,780,000 of securities

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.

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Property and Equipment

12 Months Ended

Dec. 31, 2024

Oil and Gas Property, Successful Effort Method, Gross [Abstract]

Property and Equipment

5. Property and Equipment

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

	December 31,		December 31,
	2024		2023
Property and equipment:
Oil and gas properties, successful efforts method
Proved properties	$	191,349,210	$	160,263,511
Unproved properties		28,364,186		25,504,873
Accumulated depletion, depreciation, amortization and impairment		(122,751,395)		(113,708,210)
Total oil and gas properties, net		96,962,001		72,060,174
Gathering system		43,116,371		42,738,273
Accumulated depletion, depreciation, amortization and impairment		(36,449,511)		(35,539,996)
Total gathering system, net		6,666,860		7,198,277
Land		637,764		637,764
Buildings and other property and equipment, net		259,335		291,807
Total property and equipment, net	$	104,525,960	$	80,188,022

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 in Ector County, Texas for $2.6 million.

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

● a joint venture covering approximately 130,000 gross undeveloped acres 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.

● 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.

● 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, 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 the year ended December 31, 2024, Epsilon recorded an impairment of $1.45 million on the Killam project (interest acquired in April 2024) in Alberta, Canada. One well was impaired as a result of a decrease in reserves ($0.53 million) and one well drilled during the year was deemed non-commercial ($0.92 million). For the year ended December 31, 2023, there was no impairment. Refer to Note 17 – Fair Value Measurements.

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Revolving Line of Credit

12 Months Ended

Dec. 31, 2024

Debt Disclosure [Abstract]

Revolving Line of Credit

6. Revolving Line of Credit

The Company closed a senior secured reserve based revolving credit facility on June 28, 2023 with Frost Bank as issuing bank and sole lender. The current borrowing base is $45 million (redetermined as of February 10, 2025), supported by the Company’s upstream assets in Pennsylvania and subject to semi-annual redeterminations with a maturity date of June 28, 2027. Interest will be charged at the Daily Simple SOFR rate plus a margin of 3.25%. The facility is secured by the assets of the Company’s Epsilon Energy USA subsidiary (Borrower). There are currently no borrowings under the facility.

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

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

	Balance at		Balance at
	December 31,		December 31,		Current
	2024		2023		Borrowing Base		Interest Rate
Revolving line of credit	$	—	$	—	$	45,000,000		SOFR + 3.25%

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Shareholders' Equity

12 Months Ended

Dec. 31, 2024

Equity [Abstract]

Shareholders' Equity

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 19, 2024, the Board of Directors authorized a new share repurchase program of up to 2,191,320 common shares, representing 10% of the outstanding common shares of Epsilon at such time, for an aggregate purchase price of not more than US $12.0 million. The program was pursuant to a normal course issuer bid and was conducted in accordance with Rule 10b-18 under the Exchange Act. The program commenced on March 27, 2024 and was set to expire on March 26, 2025, unless the maximum amount of common shares is purchased before then or the Board approves earlier termination. During the year ended December 31, 2024, we repurchased 125,000 common shares and spent $627,500 at an average price of $5.00 per share (excluding commissions) under the plan. On February 12, 2025, the Board terminated and revoked authority under the program.

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

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

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

(c) 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, 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, 300,052 restricted common shares with a weighted average grant date fair value of $5.97 were awarded to the Company’s management, employees, and board of directors. For the year ended December 31, 2023, 358,546 restricted common shares with a weighted average grant date fair value of $5.42 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.

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

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).

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

At December 31, 2024 and 2023, the Company had unrecognized stock-based compensation related to these options of nil. The 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).

During the years ended December 31, 2024 and 2023, the Company awarded no stock options.

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Revenue Recognition

12 Months Ended

Dec. 31, 2024

Revenues [Abstract]

Revenue Recognition

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

(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. 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 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.

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, 2024 and 2023:

	December 31,		December 31,		December 31,
	2024		2023		2022
Accounts receivable
Natural gas and oil sales	$	4,888,294	$	4,327,886	$	5,696,419
Joint interest billing		—		17,476		20,454
Gathering and compression fees		918,471		1,543,239		1,483,956
Commodity contract		36,957		72,075		—
Interest		—		54,772		557
Total accounts receivable	$	5,843,722	$	6,015,448	$	7,201,386

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Accumulated Other Comprehensive Income

12 Months Ended

Dec. 31, 2024

Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

Accumulated Other Comprehensive Income

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 and 2023 consisted of the following:

	Year Ended December 31,
	2024		2023
Balance at beginning of period	$	9,772,277	$	9,774,551
Translation gain/(loss)		262,588		(3,872)
Unrealized (loss)/gain on securities		(1,598)		1,598
Balance at end of period	$	10,033,267	$	9,772,277

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Income Taxes

12 Months Ended

Dec. 31, 2024

Income Tax Disclosure [Abstract]

Income Taxes

10. Income Taxes

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

	Year ended December 31,
	2024		2023
Foreign	$	(2,769,534)	$	(1,167,609)
U.S.		6,326,427		11,313,209
	$	3,556,893	$	10,145,600

We file a federal income tax return 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, 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 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				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	%

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

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.

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)

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.

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.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2024

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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.

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Leases

12 Months Ended

Dec. 31, 2024

Leases [Abstract]

Leases

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%

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. 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.

Future minimum lease payments as of December 31, 2024 are as follows:

	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

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Net Income Per Share

12 Months Ended

Dec. 31, 2024

Earnings Per Share [Abstract]

Net Income Per Share

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.

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

	Year ended December 31,
	2024		2023
Net income	$	1,927,800	$	6,945,153

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

	Year ended December 31,
	2024	2023
Basic weighted-average number of shares outstanding	21,930,277	22,496,772
Dilutive stock options	—	4,431
Unvested performance-based restricted shares	—	10,444
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	2023
Anti-dilutive options	—	53,069
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

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Operating Segments

12 Months Ended

Dec. 31, 2024

Segment Reporting [Abstract]

Operating Segments

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:

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

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

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

	Upstream		Gas Gathering		Total
As of and for the year ended December 31, 2023
Operating revenue
Natural gas	$	14,864,214	$	—	$	14,864,214
Natural gas liquids		984,418		—		984,418
Oil and condensate		5,090,589		—		5,090,589
Gathering and compression fees		—		9,790,531		9,790,531
Intersegment gathering and compression fees		—		1,375,879		1,375,879
		20,939,221		11,166,410		32,105,631
Reconciliation of operating revenue
Elimination of intersegment revenues						(1,375,879)
Total consolidated operating revenue(1)						30,729,752
Operating costs
Gathering, transportation, and compression		5,938,422		—		5,938,422
Other lease operating expense		466,859		2,459,694		2,926,553
Intersegment other lease operating expense		1,375,879		—		1,375,879
Loss on sale of oil and gas properties		1,449,871		—		1,449,871
Depletion, depreciation, amortization and accretion		6,638,882		1,046,202		7,685,084
Segment operating income	$	5,069,308	$	7,660,514	$	11,353,943
Reconciliation of segment operating income
Salary expense						2,856,089
Stock based compensation						1,018,262
Other general and administrative						3,437,145
Elimination of intersegment other lease operating expenses						(1,375,879)
Total consolidated operating income						5,418,326
Other income (expense)
Interest income						1,673,241
Interest expense						(80,379)
Gain on derivative contracts						3,130,055
Other income						4,357
Other income, net						4,727,274
Net income before income tax expense					$	10,145,600
Capital expenditures (2)	$	18,563,773	$	82,302	$	18,646,075
Segment assets	$	73,873,982	$	7,198,277	$	81,072,259
Total segment assets reconciled to consolidated amounts are as follows:
Total segment assets					$	81,072,259
Current assets, net						41,128,796
Other property and equipment						929,571
Operating lease right-of-use asset						441,987
Restricted Cash						470,000
					$	124,042,613

(1) Segment operating revenue represents revenues generated from the operations of the segment. Inter-segment sales during the years ended December 31, 2024 and 2023 have been eliminated upon consolidation. For the year ended December 31, 2024, we sold natural gas 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, we sold natural gas to 33 unique customers. Direct Energy Business Marketing, LLC and EQT Energy, LLC each accounted for 10% or more of our total revenue.

(2) Capital expenditures for the Upstream segment consist primarily of the acquisition of properties, and the drilling and completing of wells while Gas Gathering consists of expenditures relating to the expansion, completion, and maintenance of the gathering and compression facility.

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Commodity Risk Management Activities

12 Months Ended

Dec. 31, 2024

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Commodity Risk Management Activities

15. Commodity Risk Management Activities

Commodity Price Risks

Epsilon engages in price risk management activities from time to time. These activities are intended to manage Epsilon’s exposure to fluctuations in commodity prices for natural gas by securing fixed price contracts for a portion of expected sales volumes.

Inherent in the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company may be required to post collateral depending on the cumulative balance owed to a counterparty on a mark-to-market basis.

The Company enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future natural gas and oil production and related cash flows. The natural gas and oil revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future natural gas sales from the risk of significant declines in commodity prices, which helps ensure the Company’s ability to fund the capital budget.

Epsilon has historically elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for these financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as (loss) gain on derivative contracts on the consolidated statements of operations and comprehensive income. The related cash flow impact is reflected in cash flows from operating activities. During 2024, Epsilon recognized losses on financial commodity derivative contracts of $391,147. This amount included cash received on the settlement of these contracts of $1,196,656. During 2023, Epsilon recognized gains on financial commodity derivative contracts of $3,130,055. This amount included cash paid on the settlement of these contracts of $3,251,890.

Commodity Derivative Contracts

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) covering January 2025 to October 2025, and NYMEX WTI CMA swaps totaling 20,662 Bbls with a weighted average strike price of $73.49 to hedge a portion of expected volumes for the contract period of January 2025 to June 2025.

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

	Fair Value of Derivative  Assets
	December 31,		December 31,
	2024		2023
Current
NYMEX Henry Hub swap	$	151,274	$	1,353,667
Tennessee Z4 basis swap		195,211		112,719
Crude Oil NYMEX WTI CMA		56,547		—
	$	403,032	$	1,466,386

	Fair Value of Derivative  Liabilities
	December 31,		December 31,
	2024		2023
Current
NYMEX Henry Hub swap	$	(448,852)	$	—
Tennessee Z4 Basis swap		(441,728)		(366,131)
	$	(890,580)	$	(366,131)
Net Fair Value of Derivatives	$	(487,548)	$	1,100,255

The following table presents the changes in the fair value of Epsilon’s commodity derivatives for the periods indicated:

	Year ended December 31,
	2024		2023
Fair value of asset, beginning of the period	$	1,100,255	$	1,222,090
(Loss) gain on derivative contracts included in earnings		(391,147)		3,130,055
Settlement of commodity derivative contracts		(1,196,656)		(3,251,890)
Fair value of (liability) asset, end of the period	$	(487,548)	$	1,100,255

The following table presents the fair value of derivatives, as presented in the Consolidated Balance Sheets, on a net basis as they are subject to master netting arrangements:

	December 31, 2024						December 31, 2023
	Gross Fair		Amounts		Net Fair		Gross Fair		Amounts		Net Fair
	Value		Netted		Value		Value		Netted		Value
Derivative Assets
Fair value of derivatives	$	403,032	$	(403,032)	$	-	$	1,466,386	$	(247,361)	$	1,219,025
Derivative Liabilities
Fair value of derivatives	$	(890,580)	$	403,032	$	(487,548)	$	(366,131)	$	247,361	$	(118,770)

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2024

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

16. Asset Retirement Obligations

Asset retirement obligations are estimated by management based on Epsilon’s net ownership interest in all wells and the gathering system, estimated costs to reclaim and abandon such assets and the estimated timing of the costs to be incurred in future periods, and the forecast risk free cost of capital. Epsilon has estimated the net present value of its total asset retirement obligations to be $3.7 million as of December 31, 2024 ($3.5 million at December 31, 2023). Each year we review, and to the extent necessary, revise our asset retirement obligations estimates in accordance with recent activity and current service costs.

The following table presents the activity in Epsilon’s asset retirement obligations for the periods indicated:

	Year Ended		Year ended
		December 31,		December 31,
	2024		2023
Balance beginning of period	$	3,502,952	$	2,780,237
Liabilities acquired		48,207		12,437
Liabilities disposed of		—		(46,961)
Wells plugged and abandoned		(88,992)		(509,802)
Change in estimates		6,695		1,178,142
Accretion		183,434		88,899
Balance end of period	$	3,652,296	$	3,502,952

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Fair Value Measurements

12 Months Ended

Dec. 31, 2024

Fair Value Disclosures [Abstract]

Fair Value Measurements

17. Fair Value Measurements

The methodologies used to determine the fair value of our financial assets and liabilities at December 31, 2024 were the same as those used at December 31, 2023.

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 Company had investments in U.S. Treasury bills, all of which mature over a period of 3 and 12 months and are classified as short term investments. The U.S. Treasury bills are carried at fair value. The U.S. Treasury bills are classified within Level 1 of the fair value hierarchy.

Commodity derivative instruments consist of NYMEX HH swap and basis swap contracts for natural gas and NYMEX WTI CMA swap contracts for crude oil. 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.

	December 31, 2024
	Level 1		Level 2		Level 3		Effect of Netting		Net Fair Value
Assets
Derivative contracts	$	—	$	403,032	$	—	$	(403,032)	$	—
Cash equivalents	$	298,767	$	—	$	—	$	—	$	298,767
Liabilities
Derivative contracts	$	—	$	890,580	$	—	$	(403,032)	$	487,548

	December 31, 2023
	Level 1		Level 2		Level 3		Effect of Netting		Net Fair Value
Assets
Derivative contracts	$	—	$	1,219,025	$	—	$	—	$	1,219,025
Cash equivalents	$	195,669	$	—	$	—	$	—	$	195,669
Short term investments	$	18,775,106	$	—	$	—	$	—	$	18,775,106
Liabilities
Derivative contracts	$	—	$	247,361	$	—	$	(366,131)	$	(118,770)

Non-Recurring Fair Value Measurements

The Company performed an impairment test on our oil and gas properties and it was determined that the carrying amount of the Killam project in Alberta, Canada exceeded the estimated undiscounted future cash flows resulting in a reduction of the carrying amount of the oil properties to their estimated fair values by $1.45 million. This nonrecurring fair value measurement is classified within Level 3 of the fair value hierarchy.  For the year ended December 31, 2023, there was no impairment.

The table below summarizes the fair value of the impaired assets at December 31, 2024.

			Quoted Prices		Significant
			in Active		Other		Significant
			Markets for		Observable		Unobservable
	December 31,		Identical Assets		Inputs		Inputs
	2024		(Level 1)		(Level 2)		(Level 3)
Nonrecurring fair value measurement
Long-lived assets held and used	$	492,253	$	—	$	—	$	492,253
Total Nonrecurring fair value measurement	$	492,253	$	—	$	—	$	492,253

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Subsequent Events

12 Months Ended

Dec. 31, 2024

Subsequent Events [Abstract]

Subsequent Events

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Pay vs Performance Disclosure - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Pay vs Performance Disclosure
Net Income (Loss)	$ 1,927,800	$ 6,945,153

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Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2024
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

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Insider Trading Policies and Procedures	12 Months Ended
	Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

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Cybersecurity Risk Management and Strategy Disclosure

12 Months Ended

Dec. 31, 2024

Cybersecurity Risk Management, Strategy, and Governance [Line Items]

Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]

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.

Cybersecurity Risk Management Processes Integrated [Flag]

true

Cybersecurity Risk Management Processes Integrated [Text Block]

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.  

Cybersecurity Risk Management Third Party Engaged [Flag]

true

Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]

true

Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]

false

Cybersecurity Risk Board of Directors Oversight [Text Block]

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, 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.

Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]

Audit Committee

Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]

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.

Cybersecurity Risk Role of Management [Text Block]

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

Cybersecurity Risk Management Positions or Committees Responsible [Flag]

true

Cybersecurity Risk Management Positions or Committees Responsible [Text Block]

Chief Financial Officer

Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]

The Chief Financial Officer notifies the Audit Committee and Chief Executive Officer of any cybersecurity threats

Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]

true

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Basis of Preparation (Policies)

12 Months Ended

Dec. 31, 2024

Accounting Policies [Abstract]

Principles of Consolidation

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 Energy Holdings, 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

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.

Recently Issued Accounting Standards

Recently Issued Accounting Standards

In October 2023, the FASB issued ASU No. 2023-06, Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative, to amend certain disclosure and presentation requirements. For entities subject to the SEC’s existing disclosure requirements, the effective date for each amendment

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.

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Summary Of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2024

Accounting Policies [Abstract]

Principles of Consolidation

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 Energy Holdings, 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

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.

Cash, Cash Equivalents and Restricted Cash

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 and 2023:

	December 31,		December 31,
	2024		2023
Cash and cash equivalents	$	6,519,793	$	13,403,628
Restricted cash included in other assets		470,000		470,000
Cash, cash equivalents, and restricted cash in the statement of cash flows	$	6,989,793	$	13,873,628

Oil and Natural Gas Properties

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.

Gas Gathering System Properties

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.

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.

Revenue Recognition

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.

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. 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.

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 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.

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 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 Liquids Revenue

The source of the Company’s oil and other liquids revenue is its ownership in wells in the Permian Basin, Oklahoma, and Alberta, Canada.  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 Receivable and Other

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 Northeastern Pennsylvania, the Permian Basin, Oklahoma, 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 of transmission. The Company’s operations do not result in any contract assets or liabilities on the accompanying consolidated balance sheets.

Buildings and Other Property and Equipment

Buildings and Other Property and Equipment

Buildings are depreciated on a straight-line basis over the estimated useful life of the property, 30 years.

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

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 Company had investments in U.S. Treasury Bills, which mature over a period between 3 and 12 months and are classified as short term investments. The U.S. Treasury Bills are carried at fair value. The U.S. Treasury Bills are classified within Level 1 of the fair value hierarchy.

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.

Derivative Instruments

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.

● 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 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

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

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, cash and cash equivalents was primarily concentrated in one financial institution the U.S. At December 31, 2023, cash and cash equivalents and short term investments were primarily concentrated in one financial institution the U.S. We currently have $4.1 million in excess of the federally insured limits. The Company periodically assesses the financial condition of these institutions and believe that any possible credit risk is minimal.

For the year ended December 31, 2024, the Company had three customers that accounted for 89.1% of the total trade accounts receivable. For the year ended December 31, 2023, the Company had four customers that accounted for 90.7% of the total trade accounts receivable.

Geographic Locations of Operations

Geographic Locations of Operations

Approximately 50% and 77% of our revenue during fiscal years 2024 and 2023, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania. 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.

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.

Income Taxes

Income Taxes

Deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. Epsilon assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate (see Note 10).

Foreign Currency Transactions

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 are included in accumulated other comprehensive income.

Stock-Based Compensation

Stock-Based Compensation

The Company has issued time-based restricted stock and performance share units (“PSU”) to employees and directors of the Company. The fair value of the time-based restricted stock 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 awards vest ratably over a three-year period. Compensation expense and a corresponding increase to additional paid in capital are recorded over the vesting period.

Leases

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).

Joint Interests

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.

Recently Issued Accounting Standards

Recently Issued Accounting Standards

In October 2023, the FASB issued ASU No. 2023-06, Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative, to amend certain disclosure and presentation requirements. For entities subject to the SEC’s existing disclosure requirements, the effective date for each amendment

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.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2024

Accounting Policies [Abstract]

Schedule of cash, cash equivalents and restricted cash

	December 31,		December 31,
	2024		2023
Cash and cash equivalents	$	6,519,793	$	13,403,628
Restricted cash included in other assets		470,000		470,000
Cash, cash equivalents, and restricted cash in the statement of cash flows	$	6,989,793	$	13,873,628

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Short Term Investments (Tables)

12 Months Ended

Dec. 31, 2024

Investments, Debt and Equity Securities [Abstract]

Summary of available-for-sale short term investments

	December 31, 2024						December 31, 2023
	Amortized		Unrealized		Fair		Amortized		Unrealized		Fair
	Cost		Losses		Value		Cost		Gains		Value
U.S. Treasury Bills	$	—	$	—	$	—	$	18,773,508	$	1,598	$	18,775,106

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Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2024

Oil and Gas Property, Successful Effort Method, Gross [Abstract]

Schedule of property and equipment

	December 31,		December 31,
	2024		2023
Property and equipment:
Oil and gas properties, successful efforts method
Proved properties	$	191,349,210	$	160,263,511
Unproved properties		28,364,186		25,504,873
Accumulated depletion, depreciation, amortization and impairment		(122,751,395)		(113,708,210)
Total oil and gas properties, net		96,962,001		72,060,174
Gathering system		43,116,371		42,738,273
Accumulated depletion, depreciation, amortization and impairment		(36,449,511)		(35,539,996)
Total gathering system, net		6,666,860		7,198,277
Land		637,764		637,764
Buildings and other property and equipment, net		259,335		291,807
Total property and equipment, net	$	104,525,960	$	80,188,022

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Revolving Line of Credit (Tables)

12 Months Ended

Dec. 31, 2024

Debt Disclosure [Abstract]

Schedule of revolving line of credit

	Balance at		Balance at
	December 31,		December 31,		Current
	2024		2023		Borrowing Base		Interest Rate
Revolving line of credit	$	—	$	—	$	45,000,000		SOFR + 3.25%

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Shareholders' Equity (Tables)

12 Months Ended

Dec. 31, 2024

Equity [Abstract]

Schedule of restricted stock activity

	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

Summary of stock option activity

	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

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Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2024

Revenues [Abstract]

Summary of revenue

	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

(1)Net of elimination

Schedule of accounts receivable net of allowance for doubtful accounts

	December 31,		December 31,		December 31,
	2024		2023		2022
Accounts receivable
Natural gas and oil sales	$	4,888,294	$	4,327,886	$	5,696,419
Joint interest billing		—		17,476		20,454
Gathering and compression fees		918,471		1,543,239		1,483,956
Commodity contract		36,957		72,075		—
Interest		—		54,772		557
Total accounts receivable	$	5,843,722	$	6,015,448	$	7,201,386

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Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2024

Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

Schedule of Accumulated Other Comprehensive Income

	Year Ended December 31,
	2024		2023
Balance at beginning of period	$	9,772,277	$	9,774,551
Translation gain/(loss)		262,588		(3,872)
Unrealized (loss)/gain on securities		(1,598)		1,598
Balance at end of period	$	10,033,267	$	9,772,277

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2024

Income Tax Disclosure [Abstract]

Schedule of income (loss) before income taxes

	Year ended December 31,
	2024		2023
Foreign	$	(2,769,534)	$	(1,167,609)
U.S.		6,326,427		11,313,209
	$	3,556,893	$	10,145,600

Schedule of current and deferred tax expense (benefit)

	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

Schedule of reconciliation between statutory rate and effective income tax rate

	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	%

Schedule of net deferred tax liabilities

	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)

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Leases (Tables)

12 Months Ended

Dec. 31, 2024

Leases [Abstract]

Schedule of operating lease

	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%

Schedule of maturity analysis of operating lease liability

Future minimum lease payments as of December 31, 2024 are as follows:

	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

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Net Income Per Share (Tables)

12 Months Ended

Dec. 31, 2024

Earnings Per Share [Abstract]

Schedule of net income used in the calculation of basic and diluted net income per share

	Year ended December 31,
	2024		2023
Net income	$	1,927,800	$	6,945,153

Schedule of weighted-average shares used in calculation of net income per share

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

Schedule of anti-dilutive shares

	Year ended December 31,
	2024	2023
Anti-dilutive options	—	53,069
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

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Operating Segments (Tables)

12 Months Ended

Dec. 31, 2024

Segment Reporting [Abstract]

Schedule of segment financial information

	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

	Upstream		Gas Gathering		Total
As of and for the year ended December 31, 2023
Operating revenue
Natural gas	$	14,864,214	$	—	$	14,864,214
Natural gas liquids		984,418		—		984,418
Oil and condensate		5,090,589		—		5,090,589
Gathering and compression fees		—		9,790,531		9,790,531
Intersegment gathering and compression fees		—		1,375,879		1,375,879
		20,939,221		11,166,410		32,105,631
Reconciliation of operating revenue
Elimination of intersegment revenues						(1,375,879)
Total consolidated operating revenue(1)						30,729,752
Operating costs
Gathering, transportation, and compression		5,938,422		—		5,938,422
Other lease operating expense		466,859		2,459,694		2,926,553
Intersegment other lease operating expense		1,375,879		—		1,375,879
Loss on sale of oil and gas properties		1,449,871		—		1,449,871
Depletion, depreciation, amortization and accretion		6,638,882		1,046,202		7,685,084
Segment operating income	$	5,069,308	$	7,660,514	$	11,353,943
Reconciliation of segment operating income
Salary expense						2,856,089
Stock based compensation						1,018,262
Other general and administrative						3,437,145
Elimination of intersegment other lease operating expenses						(1,375,879)
Total consolidated operating income						5,418,326
Other income (expense)
Interest income						1,673,241
Interest expense						(80,379)
Gain on derivative contracts						3,130,055
Other income						4,357
Other income, net						4,727,274
Net income before income tax expense					$	10,145,600
Capital expenditures (2)	$	18,563,773	$	82,302	$	18,646,075
Segment assets	$	73,873,982	$	7,198,277	$	81,072,259
Total segment assets reconciled to consolidated amounts are as follows:
Total segment assets					$	81,072,259
Current assets, net						41,128,796
Other property and equipment						929,571
Operating lease right-of-use asset						441,987
Restricted Cash						470,000
					$	124,042,613

(1) Segment operating revenue represents revenues generated from the operations of the segment. Inter-segment sales during the years ended December 31, 2024 and 2023 have been eliminated upon consolidation. For the year ended December 31, 2024, we sold natural gas 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, we sold natural gas to 33 unique customers. Direct Energy Business Marketing, LLC and EQT Energy, LLC each accounted for 10% or more of our total revenue.

(2) Capital expenditures for the Upstream segment consist primarily of the acquisition of properties, and the drilling and completing of wells while Gas Gathering consists of expenditures relating to the expansion, completion, and maintenance of the gathering and compression facility.

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Commodity Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2024

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of fair value of derivatives

	Fair Value of Derivative  Assets
	December 31,		December 31,
	2024		2023
Current
NYMEX Henry Hub swap	$	151,274	$	1,353,667
Tennessee Z4 basis swap		195,211		112,719
Crude Oil NYMEX WTI CMA		56,547		—
	$	403,032	$	1,466,386

	Fair Value of Derivative  Liabilities
	December 31,		December 31,
	2024		2023
Current
NYMEX Henry Hub swap	$	(448,852)	$	—
Tennessee Z4 Basis swap		(441,728)		(366,131)
	$	(890,580)	$	(366,131)
Net Fair Value of Derivatives	$	(487,548)	$	1,100,255

Schedule of fair value of derivatives rollforward

	Year ended December 31,
	2024		2023
Fair value of asset, beginning of the period	$	1,100,255	$	1,222,090
(Loss) gain on derivative contracts included in earnings		(391,147)		3,130,055
Settlement of commodity derivative contracts		(1,196,656)		(3,251,890)
Fair value of (liability) asset, end of the period	$	(487,548)	$	1,100,255

Schedule of fair value of derivative assets, subject to master netting arrangements

	December 31, 2024						December 31, 2023
	Gross Fair		Amounts		Net Fair		Gross Fair		Amounts		Net Fair
	Value		Netted		Value		Value		Netted		Value
Derivative Assets
Fair value of derivatives	$	403,032	$	(403,032)	$	-	$	1,466,386	$	(247,361)	$	1,219,025
Derivative Liabilities
Fair value of derivatives	$	(890,580)	$	403,032	$	(487,548)	$	(366,131)	$	247,361	$	(118,770)

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2024

Asset Retirement Obligation Disclosure [Abstract]

Schedule of activity in asset retirement obligations

	Year Ended		Year ended
		December 31,		December 31,
	2024		2023
Balance beginning of period	$	3,502,952	$	2,780,237
Liabilities acquired		48,207		12,437
Liabilities disposed of		—		(46,961)
Wells plugged and abandoned		(88,992)		(509,802)
Change in estimates		6,695		1,178,142
Accretion		183,434		88,899
Balance end of period	$	3,652,296	$	3,502,952

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2024

Fair Value Disclosures [Abstract]

Schedule of Derivative Instruments

	December 31, 2024
	Level 1		Level 2		Level 3		Effect of Netting		Net Fair Value
Assets
Derivative contracts	$	—	$	403,032	$	—	$	(403,032)	$	—
Cash equivalents	$	298,767	$	—	$	—	$	—	$	298,767
Liabilities
Derivative contracts	$	—	$	890,580	$	—	$	(403,032)	$	487,548

	December 31, 2023
	Level 1		Level 2		Level 3		Effect of Netting		Net Fair Value
Assets
Derivative contracts	$	—	$	1,219,025	$	—	$	—	$	1,219,025
Cash equivalents	$	195,669	$	—	$	—	$	—	$	195,669
Short term investments	$	18,775,106	$	—	$	—	$	—	$	18,775,106
Liabilities
Derivative contracts	$	—	$	247,361	$	—	$	(366,131)	$	(118,770)

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Description of Business (Details)	12 Months Ended
	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Date of Incorporation	Mar. 14, 2005

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Summary of Significant Accounting Policies- Reconciliation of Cash (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Cash and Cash Equivalents [Abstract]
Cash and cash equivalents	$ 6,519,793	$ 13,403,628
Restricted cash included in other assets	470,000	470,000
Cash, cash equivalents and restricted cash in the statement of cash flows	$ 6,989,793	$ 13,873,628	$ 45,806,947

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Summary of Significant Accounting Policies - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 customer	Dec. 31, 2023 customer	Dec. 31, 2024	Dec. 31, 2024 Institution	Dec. 31, 2024 item	Dec. 31, 2024 USD ($)
Property, Plant and Equipment [Line Items]
Asset development costs capitalization, Percentage	35.00%
Vesting period	3 years
Number of financial institutions				1	1
Federally insured limits | $						$ 4.1
Auburn Gas Gathering System
Property, Plant and Equipment [Line Items]
Ownership interest			35.00%
Total Revenue | Geographic Concentration Risk | Pennsylvania
Property, Plant and Equipment [Line Items]
Concentration risk (as a percent)	50.00%	77.00%
Total Revenue | Geographic Concentration Risk | Texas
Property, Plant and Equipment [Line Items]
Concentration risk (as a percent)	40.00%	6.00%
Accounts Receivable | Customer Concentration Risk
Property, Plant and Equipment [Line Items]
Number of customers | customer	3	4
Accounts Receivable | Customer Concentration Risk | Customer Four
Property, Plant and Equipment [Line Items]
Concentration risk (as a percent)	89.10%
Accounts Receivable | Customer Concentration Risk | Customer Three
Property, Plant and Equipment [Line Items]
Concentration risk (as a percent)		90.70%
Buildings
Property, Plant and Equipment [Line Items]
Estimated useful lives of the property and equipment	30 years
Other property and equipment | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives of the property and equipment	3 years
Other property and equipment | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives of the property and equipment	7 years
Office Lease | Minimum
Property, Plant and Equipment [Line Items]
Lessor, Operating Lease, Term of Contract	5 years
Office Lease | Maximum
Property, Plant and Equipment [Line Items]
Lessor, Operating Lease, Term of Contract	7 years
Gas, oil, NGL and condensate revenue
Property, Plant and Equipment [Line Items]
Receivable collection period	30 days
Gathering and Compression fees
Property, Plant and Equipment [Line Items]
Receivable collection period	60 days

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Short Term Investments (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Schedule of Held-to-Maturity Securities [Line Items]
Fair Value	$ 0	$ 18,775,106
US Treasury Securities
Schedule of Held-to-Maturity Securities [Line Items]
Amortized Cost	0	18,773,508
Unrealized Gains/(Losses)	0	1,598
Fair Value	$ 0	$ 18,775,106

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Short Term Investments - Narratives (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Securities Sold Prior To Maturity Date
Schedule of Held-to-Maturity Securities [Line Items]
Carrying amount of available for sale debt securities sold	$ 14,989,595	$ 10,394,482
Total Proceeds for available for sale securities	15,336,930	10,454,976
Realized gains on available for sale securities	347,335	60,494
Securities Sold After Maturity Date
Schedule of Held-to-Maturity Securities [Line Items]
Realized gains on available for sale securities	234,248	395,767
Securities that reached maturity	$ 7,780,000	$ 16,410,000

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Property and Equipment (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Oil and gas properties, successful efforts method
Proved properties	$ 191,349,210	$ 160,263,511
Unproved properties	28,364,186	25,504,873
Accumulated depletion, depreciation, amortization and impairment	(122,751,395)	(113,708,210)
Total oil and gas properties, net	96,962,001	72,060,174
Gathering system	43,116,371	42,738,273
Accumulated depletion, depreciation, amortization and impairment	(36,449,511)	(35,539,996)
Total gathering system, net	6,666,860	7,198,277
Land	637,764	637,764
Buildings and other property and equipment, net	259,335	291,807
Total property and equipment, net	$ 104,525,960	$ 80,188,022

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Property and Equipment - Property Acquisition and Sale (Details)	12 Months Ended
	Dec. 31, 2024 USD ($) a item	Dec. 31, 2023 USD ($) a item
Property and equipment Acquisition and Sale
Number of asset acquisitions	4	3
Impairment expense	$ 1,450,076	$ 0
Loss (gain) on sale of oil and gas properties	$ 0	$ (1,449,871)
Oklahoma | Sale of Wellbores | Disposed of by sale of properties
Property and equipment Acquisition and Sale
Number of wellbores sold | item	2
Consideration received on sale of property	$ 12,498
Loss (gain) on sale of oil and gas properties	$ (1,450,000)
Asset Acquisition One | New Mexico | Eddy County
Property and equipment Acquisition and Sale
Asset acquisition, number of wellbores acquired | item		2
Asset acquisition, percentage of interests acquired		10.00%
Asset acquisition, consideration		$ 2,100,000
Asset Acquisition One | Texas | Ector County
Property and equipment Acquisition and Sale
Asset acquisition, number of wellbores acquired | item	3
Asset acquisition, percentage of interests acquired	25.00%
Asset acquisition, consideration	$ 12,100,000
Asset Acquisition Two | Texas | Ector County, including drilling of well and completion of well
Property and equipment Acquisition and Sale
Asset acquisition, percentage of interests acquired		25.00%
Asset acquisition, consideration		$ 1,300,000
Acres of land acquired | a		1,297
Asset Acquisition Two | Texas | Ector County
Property and equipment Acquisition and Sale
Asset acquisition, percentage of interests acquired	25.00%
Asset acquisition, consideration	$ 2,600,000
Acres of land acquired | a	3,620
Asset Acquisition Three | Texas | Ector County
Property and equipment Acquisition and Sale
Asset acquisition, percentage of interests acquired		25.00%
Asset acquisition, consideration		$ 6,300,000
Acres of land acquired | a		11,067
Asset Acquisition Three | Canada
Property and equipment Acquisition and Sale
Asset acquisition, percentage of interests acquired	50.00%
Asset acquisition, consideration	$ 1,000,000
Acres of land acquired | a	14,243
Asset Acquisition Four | Canada
Property and equipment Acquisition and Sale
Asset acquisition, percentage of interests acquired	25.00%
Asset acquisition, consideration	$ 7,000,000
Acres of land acquired | a	130,000

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Property and Equipment - Property Impairment (Details)	12 Months Ended
	Dec. 31, 2024 USD ($) item	Dec. 31, 2023 USD ($)
Oil and Gas Property, Successful Effort Method, Gross [Abstract]
Impairment expense	$ 1,450,076	$ 0
Number of wells impaired | item	1
Result of decrease in reserves	$ 530,000
Number of wells drilled | item	1
Property deemed non-commercial	$ 920,000

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Revolving Line of Credit (Details) - Revolving Credit Facility	12 Months Ended
	Dec. 31, 2024 USD ($)
Revolving Credit Facility
Current borrowing base	$ 45,000,000
Margin added to variable interest rate	3.25%
Investment, Variable Interest Rate, Type [Extensible Enumeration]	us-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember

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Revolving Line of Credit - Ratios (Details) - Revolving Credit Facility	12 Months Ended
	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Revolving Credit Facility
Current borrowing base	$ 45,000,000
Current ratio	1
Line of credit	$ 0	$ 0
Margin added to variable interest rate	3.25%
Investment, Variable Interest Rate, Type [Extensible Enumeration]	us-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember
Percentage of Utilization of Borrowing Base	50.00%
Percentage of Hedging Anticipated Production from PDP Reserves	50.00%
Rolling Term for Calculation of Anticipated Production from PDP Reserves	24 months
Minimum
Revolving Credit Facility
Leverage ratio	1
Maximum
Revolving Credit Facility
Leverage ratio	2.5

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Shareholders' Equity - Share Capital (Details) - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Components of share capital:
Common shares, no par value	$ 0	$ 0
Common shares, unlimited authorized	Unlimited	Unlimited
Preferred shares, no par value	$ 0	$ 0
Preferred shares, unlimited authorized	Unlimited	Unlimited

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Shareholders' Equity - Purchases of Equity Shares (Details) - USD ($)			3 Months Ended	9 Months Ended	10 Months Ended	12 Months Ended
	Feb. 12, 2025	Mar. 19, 2024	Mar. 25, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2024
Share Repurchase Program [Line Items]
Shares repurchased						373,700
Consideration for shares repurchased						$ 1,831,208
Average price paid per share						$ 4.88
NCIB Program 3/27/2023-3/26/2024
Share Repurchase Program [Line Items]
Authorized shares to be repurchased					2,292,644
Retirement of treasury shares (in shares)			319,574		897,275
Shares repurchased			248,700		968,149
Consideration for shares repurchased			$ 1,203,708		$ 4,940,295
Average price paid per share			$ 4.82		$ 5.08
NCIB Program 3/27/2024-3/26/2025
Share Repurchase Program [Line Items]
Authorized shares to be repurchased		2,191,320
Shares repurchased as a percentage of outstanding common shares		10.00%
Shares repurchased				125,000
Consideration for shares repurchased				$ 627,500
Average price paid per share				$ 5
NCIB Program 3/27/2024-3/26/2025 | Maximum
Share Repurchase Program [Line Items]
Authorized amount repurchase		$ 12,000,000
NCIB Program 2/12/2025-2/11/2026 | Subsequent Event
Share Repurchase Program [Line Items]
Authorized shares to be repurchased	2,200,876
Shares repurchased as a percentage of outstanding common shares	10.00%
NCIB Program 2/12/2025-2/11/2026 | Maximum | Subsequent Event
Share Repurchase Program [Line Items]
Authorized amount repurchase	$ 13,000,000

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Shareholders' Equity - Equity Incentive Plan (Details)	Dec. 31, 2024 shares
Equity [Abstract]
Number of shares authorized to be issued	2,000,000

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Shareholders' Equity - Restricted Stock (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Vesting period	3 years
Restricted Stock Unit
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Vested in period, fair value	$ 1,303,187	$ 875,014
Stock based compensation expense	1,244,416	$ 959,525
Compensation cost not yet recognized	$ 3,198,469
Weighted average period for recognition	1 year 3 months 18 days
Number outstanding
Balance non-vested Stock at beginning of period (in shares)	491,536	298,210
Granted (in shares)	300,052	358,546
Vested (in shares)	(230,618)	(165,220)
Balance non-vested Stock at end of period (in shares)	560,970	491,536	298,210
Weighted Average Remaining Life
Balance non-vested Stock at end of period (in years)	1 year 7 months 9 days	1 year 8 months 26 days	1 year 8 months 26 days
Granted (in years)	1 year 11 months 1 day	1 year 10 months 24 days
Weighted Average Grant Date Fair Value
Weighted Average Grant Date Fair Value , beginning of period	$ 5.59	$ 6
Weighted Average Grant Date Fair Value, Granted	5.97	5.42
Weighted Average Grant Date Fair Value, Vested	5.65	5.95
Weighted Average Grant Date Fair Value, end of period	$ 5.77	$ 5.59	$ 6
Management, Employees, and Board Of Directors | Restricted Stock Unit
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Weighted average market price at grant date (in dollars per share)	$ 5.97	$ 5.42
Number outstanding
Granted (in shares)	300,052	358,546
Maximum | Management, Employees, and Board Of Directors | Restricted Stock Unit
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Vesting period	4 years
Minimum | Management, Employees, and Board Of Directors | Restricted Stock Unit
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Vesting period	3 years

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Shareholders' Equity - Performance Stock Units Assumptions (Details) - Performance Share Unit (PSU) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Granted (in shares)	0	0
Vested (in shares)		15,833
Stock based compensation expense	$ 0	$ 58,737
Compensation cost not yet recognized	$ 0
Minimum
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Percentage of number of shares issued on target award amounts	0.00%
Maximum
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Percentage of number of shares issued on target award amounts	200.00%

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Shareholders' Equity - Stock Option Activity (Details) - Employee Stock Option - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Number of Options Outstanding
Balance at beginning of period (in shares)	57,500	70,000
Exercised (in shares)		(12,500)
Expired (in shares)	(57,500)	0
Balance at period-end (in shares)		57,500
Exercisable at period-end (in shares)		57,500
Weighted average exercise price
Balance at beginning of period (in dollars per share)	$ 5.03	$ 5.03
Exercised (in dollars per share)		5.03
Expired/Forfeited (in dollars per share)	$ 5.03
Balance at period-end (in dollars per share)		5.03
Exercisable at period-end (in dollars per share)		$ 5.03

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Shareholders' Equity - Stock Option Activity, Narrative (Details) - Employee Stock Option - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Compensation cost not yet recognized	$ 0
Unrecognized stock based compensation to be recognized over a period	0	$ 0
Aggregate intrinsic value of options outstanding	$ 0	$ 2,875
Granted (in shares)	0	0
Exercises in period, value	$ 0	$ 5,500

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Revenue Recognition - Summary of revenue (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Revenue recognition
Total operating revenue	$ 31,522,775	$ 30,729,752
Natural Gas
Revenue recognition
Total operating revenue	10,786,068	14,864,214
Natural Gas Liquids
Revenue recognition
Total operating revenue	1,481,958	984,418
Oil and Condensate
Revenue recognition
Total operating revenue	13,730,686	5,090,589
Gathering and Compression fees
Revenue recognition
Total operating revenue	5,524,063	9,790,531
Gathering and Compression fees | Intersubsegment Eliminations
Revenue recognition
Total operating revenue	$ 1,100,000	$ 1,400,000

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Revenue Recognition - Additional Information (Details)	12 Months Ended
	Dec. 31, 2024
Gas, oil, NGL and condensate revenue
Revenue recognition
Period settlement statement received	30 days
Gathering and Compression fees | Auburn Gas Gathering System
Revenue recognition
Period settlement statement received	2 months

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Revenue Recognition - Accounts receivable (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Allowance for credit loss	$ 0	$ 0
Accounts receivable	5,843,722	6,015,448	$ 7,201,386
Natural gas and oil sales
Disaggregation of Revenue [Line Items]
Accounts receivable	4,888,294	4,327,886	5,696,419
Joint Interest Billing
Disaggregation of Revenue [Line Items]
Accounts receivable		17,476	20,454
Gathering and Compression fees
Disaggregation of Revenue [Line Items]
Accounts receivable	918,471	1,543,239	1,483,956
Commodity Contract
Disaggregation of Revenue [Line Items]
Accounts receivable	$ 36,957	72,075
Interest
Disaggregation of Revenue [Line Items]
Accounts receivable		$ 54,772	$ 557

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Accumulated Other Comprehensive Income (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	$ 100,612,965	$ 104,245,205
Translation gain/(loss)	260,990	(2,274)
Unrealized (loss) gain on securities	(1,598)	1,598
Balance at end of period	96,728,129	100,612,965
Foreign Currency Translation Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	9,772,277	9,774,551
Translation gain/(loss)	262,588	(3,872)
Unrealized (loss) gain on securities	(1,598)	1,598
Balance at end of period	$ 10,033,267	$ 9,772,277

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Income Taxes - Income (loss) before income taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Income (loss) before income taxes
Foreign	$ 2,769,534	$ 1,167,609
U.S.	(6,326,427)	(11,313,209)
Net income before income tax expense	$ 3,556,893	$ 10,145,600

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Income Taxes - Current and Deferred Tax Expense (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 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

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Income Taxes - Reconciliation of Income taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Income Tax Expense (Benefit), Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income tax provision computed at the statutory federal tax rate	$ 746,947	$ 2,130,576
Difference in Canadian and U.S. tax rate	(55,391)	(23,352)
Adjustment of Canadian deferred tax balances	983,975	(128,552)
Valuation allowance on Canadian loss	(425,667)	397,102
Return to provision adjustment	(1,245)	5,244
State taxes	(129,233)	108,401
State valuation allowance	(16,271)	100,133
Foreign withholding on dividends	414,250	630,722
Miscellaneous other items	111,728	(19,827)
Income tax expense	$ 1,629,093	$ 3,200,447
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Income tax provision computed at the statutory federal tax rate (as a percent)	21.00%	21.00%
Difference in Canadian and U.S. tax rate (as a percent)	(1.56%)	(0.23%)
Adjustment of Canadian deferred tax (as a percent)	27.66%	(1.27%)
Valuation allowance on Canadian loss (as a percent)	(11.97%)	3.91%
Return to provision adjustment (as a percent)	(0.04%)	0.05%
State taxes (as a percent)	(3.63%)	1.07%
State Valuation Allowance (as a percent)	(0.46%)	0.99%
Foreign withholding on dividends (as a percent)	11.65%	6.22%
Miscellaneous other items (as a percent)	3.14%	(0.20%)
Effective Tax Rate (as a percent)	45.79%	31.54%

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Income Taxes - Net Deferred Tax Liabilities (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 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	0
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)

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Income Taxes - Narrative (Details)	12 Months Ended
	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Operating Loss Carryforwards [Line Items]
Effective tax rate of net valuation allowance	25.48	28.29
Operating loss carryforward expected to expire	$ 200,000
Accrued interest and penalties	0	$ 0
U.S. Federal
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	0
State
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	11,300,000
Valuation allowance	130,000
Foreign
Operating Loss Carryforwards [Line Items]
Net operating loss carry-forwards	40,900,000
Foreign | Canada
Operating Loss Carryforwards [Line Items]
Valuation allowance	11,100,000
Increase (decrease) in valuation allowance	$ 500,000	$ (500,000)

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Commitments and Contingencies (Details) $ in Millions	1 Months Ended
	Oct. 31, 2024 USD ($) item	Dec. 31, 2024 USD ($)
Lessee, Lease, Description [Line Items]
Commitments for capital expenditures		$ 7.8
Number of wells related to capital commitments | item	2
Commitment in favor of operator
Lessee, Lease, Description [Line Items]
Commitments for capital expenditures	$ 3.4

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Leases - Lease Commitment (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Assets
Operating lease right-of-use assets, long term	$ 344,589	$ 441,987
Total operating lease right-of-use assets	344,589	441,987
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	$ 0	$ 535,149
Weighted average remaining lease term	2 years 6 months	3 years
Weighted average discount rate	8.25%	8.25%

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Leases - Future Minimum Lease Commitments (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Future Minimum Lease Commitments
2025	$ 173,550
2026	177,021
2027	180,492
2028	183,963
Total minimum lease payments	715,026
Less: imputed interest	(238,115)
Total operating lease liabilities	476,911	$ 563,384
Less: current obligations under leases	(121,135)	(86,473)
Long-term lease obligations	$ 355,776	$ 476,911

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Leases - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Mar. 01, 2023
Leases
Future lease payments estimated	$ 715,026
Rent expense for operating leases	$ 240,000	$ 140,000
New office lease
Leases
Lease term			70 months
Future lease payments estimated			$ 850,000

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Net Income Per Share (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net income	$ 1,927,800	$ 6,945,153
Weighted average number of shares - basic and diluted
Basic weighted-average number of shares outstanding	21,930,277	22,496,772
Diluted weighted average shares outstanding	21,930,277	22,511,647
Total Anti-dilutive shares	512,072	390,268
Employee Stock Option
Weighted average number of shares - basic and diluted
Incremental common shares		4,431
Total Anti-dilutive shares		53,069
Time-Based Restricted Shares
Weighted average number of shares - basic and diluted
Total Anti-dilutive shares	512,072	331,810
Performance Share Unit (PSU)
Weighted average number of shares - basic and diluted
Incremental common shares		10,444
Total Anti-dilutive shares		5,389

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Operating Segments - Segments (Details)	12 Months Ended
	Dec. 31, 2024 USD ($) segment	Dec. 31, 2023 USD ($)
Segment information
Total operating revenue	$ 31,522,775	$ 30,729,752
Operating costs
Loss on sale of oil and gas properties	0	1,449,871
Impairment expense	1,450,076	0
Depletion, depreciation, amortization and accretion	10,185,119	7,685,084
Salary expense	2,815,428	2,856,089
Stock based compensation expense	1,244,416	1,018,262
Other general and administrative	2,873,286	3,437,145
Operating income	3,424,436	5,418,326
Other income (expense):
Interest income	493,277	1,673,241
Interest expense	(46,400)	(80,379)
(Loss) gain on derivative contracts	(391,147)	3,130,055
Other income	76,727	4,357
Other income, net	132,457	4,727,274
Net income before income tax expense	3,556,893	10,145,600
Capital expenditures	36,560,896	18,646,075
Assets	120,454,785	124,042,613
Current assets, net	14,131,519	41,128,796
Other property and equipment	897,099	929,571
Operating lease right-of-use asset	344,589	441,987
Restricted cash	470,000	470,000
Operating Segments
Segment information
Total operating revenue	32,657,951	32,105,631
Operating costs
Gathering, transportation, and compression	4,996,764	5,938,422
Other lease operating expense	4,533,250	2,926,553
Intersegment other lease operating expense	1,135,176	1,375,879
Loss on sale of oil and gas properties		(1,449,871)
Impairment expense	1,450,076
Depletion, depreciation, amortization and accretion	10,185,119	7,685,084
Operating income	9,222,390	11,353,943
Other income (expense):
Assets	104,611,578	81,072,259
Elimination
Segment information
Total operating revenue	(1,135,176)	(1,375,879)
Operating costs
Intersegment other lease operating expense	(1,135,176)	(1,375,879)
Natural Gas
Segment information
Total operating revenue	10,786,068	14,864,214
Natural Gas | Operating Segments
Segment information
Total operating revenue	10,786,068	14,864,214
Natural Gas Liquids
Segment information
Total operating revenue	1,481,958	984,418
Natural Gas Liquids | Operating Segments
Segment information
Total operating revenue	1,481,958	984,418
Oil and Condensate
Segment information
Total operating revenue	13,730,686	5,090,589
Oil and Condensate | Operating Segments
Segment information
Total operating revenue	13,730,686	5,090,589
Gathering and Compression fees
Segment information
Total operating revenue	5,524,063	9,790,531
Gathering and Compression fees | Operating Segments
Segment information
Total operating revenue	5,524,063	9,790,531
Intersegment revenue	1,135,176	1,375,879
Upstream | Operating Segments
Segment information
Total operating revenue	25,998,712	20,939,221
Operating costs
Gathering, transportation, and compression	4,996,764	5,938,422
Other lease operating expense	2,268,060	466,859
Intersegment other lease operating expense	1,135,176	1,375,879
Loss on sale of oil and gas properties		(1,449,871)
Impairment expense	1,450,076
Depletion, depreciation, amortization and accretion	9,268,155	6,638,882
Operating income	6,880,481	5,069,308
Other income (expense):
Capital expenditures	36,219,444	18,563,773
Assets	97,944,718	73,873,982
Upstream | Natural Gas | Operating Segments
Segment information
Total operating revenue	10,786,068	14,864,214
Upstream | Natural Gas Liquids | Operating Segments
Segment information
Total operating revenue	1,481,958	984,418
Upstream | Oil and Condensate | Operating Segments
Segment information
Total operating revenue	13,730,686	5,090,589
Upstream | Gathering and Compression fees | Operating Segments
Segment information
Total operating revenue	0
Intersegment revenue	$ 0
Gas Gathering | Operating Segments
Operating Segments
Number of companies partnered to operate natural gas gathering system | segment	2
Segment information
Total operating revenue	$ 6,659,239	11,166,410
Operating costs
Gathering, transportation, and compression	0
Other lease operating expense	2,265,190	2,459,694
Intersegment other lease operating expense	0
Impairment expense	0
Depletion, depreciation, amortization and accretion	916,964	1,046,202
Operating income	3,477,085	7,660,514
Other income (expense):
Capital expenditures	341,452	82,302
Assets	6,666,860	7,198,277
Gas Gathering | Natural Gas | Operating Segments
Segment information
Total operating revenue	0
Gas Gathering | Natural Gas Liquids | Operating Segments
Segment information
Total operating revenue	0
Gas Gathering | Oil and Condensate | Operating Segments
Segment information
Total operating revenue	0
Gas Gathering | Gathering and Compression fees | Operating Segments
Segment information
Total operating revenue	5,524,063	9,790,531
Intersegment revenue	$ 1,135,176	$ 1,375,879

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Operating Segments - Customers (Details) - customer	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Natural Gas
Concentration risk
Number of customers	34	33
Total Revenue | Customer Concentration Risk | Customer One
Concentration risk
Concentration risk (as a percent)	10.00%	10.00%
Total Revenue | Customer Concentration Risk | Customer Two
Concentration risk
Concentration risk (as a percent)	10.00%

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Commodity Risk Management Activities - Commodity Price Risks (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Recognized gains (losses) on financial commodity derivative contracts	$ 391,147	$ 3,130,055
Cash received (paid) from settlements of derivative contracts	$ 1,196,656	$ 3,251,890

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Commodity Risk Management Activities - Fair Value of Derivative Instruments (Details)	12 Months Ended
	Dec. 31, 2024 USD ($) $ / DerivativeInstrument bbl Bcf	Dec. 31, 2023 USD ($) $ / DerivativeInstrument Bcf
Risk Management Activities
Fair Value of Derivative Assets, Gross, Current	$ 403,032	$ 1,466,386
Fair Value of Derivative Liabilities, Gross, Current	(890,580)	(366,131)
Commodity Derivative Contracts
Risk Management Activities
Fair Value of Derivative Assets, Gross, Current	403,032	1,466,386
Fair Value of Derivative Liabilities, Gross, Current	(890,580)	(366,131)
Net Fair Value of Derivatives	$ (487,548)	$ 1,100,255
Commodity Derivative Contracts | NYMEX Henry Hub Swap | Natural Gas
Risk Management Activities
Nonmonetary notional amount | Bcf	2.2615	1.905
Weighted average strike price | $ / DerivativeInstrument	3.26	3.25
Fair Value of Derivative Assets, Gross, Current	$ 151,274	$ 1,353,667
Fair Value of Derivative Liabilities, Gross, Current	$ (448,852)
Commodity Derivative Contracts | Tennessee Z4 basis swap | Natural Gas
Risk Management Activities
Nonmonetary notional amount | Bcf	2.2615	1.905
Weighted average strike price | $ / DerivativeInstrument	(0.91)	(1.1)
Fair Value of Derivative Assets, Gross, Current	$ 195,211	$ 112,719
Fair Value of Derivative Liabilities, Gross, Current	$ (441,728)	$ (366,131)
Commodity Derivative Contracts | Crude Oil NYMEX WTI CMA | Crude Oil
Risk Management Activities
Nonmonetary notional amount | bbl	20,662
Weighted average strike price | $ / DerivativeInstrument	73.49
Fair Value of Derivative Assets, Gross, Current	$ 56,547

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Commodity Risk Management Activities - Fair Value of Asset (Liability) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair value of asset, beginning of the period	$ 1,100,255	$ 1,222,090
(Loss) gain on derivative contracts included in earnings	$ (391,147)	$ 3,130,055
Gain (loss) on derivative contracts included in earnings, Statement of Income or Comprehensive Income	Gain (Loss) on Sale of Derivatives	Gain (Loss) on Sale of Derivatives
Settlement of commodity derivative contracts	$ (1,196,656)	$ (3,251,890)
Fair value of (liability) asset, end of the period	$ (487,548)	$ 1,100,255

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Commodity Risk Management Activities - Fair value of derivatives on a net basis (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Derivative Assets
Derivative assets, gross fair value	$ 403,032	$ 1,466,386
Derivative liability, amounts netted	(403,032)	(247,361)
Derivative assets, net fair value	0	1,219,025
Derivative Liabilities
Fair Value of Derivative Liabilities, Gross, Current	(890,580)	(366,131)
Derivative asset, amounts netted	403,032	247,361
Derivative liabilities, net fair value	$ (487,548)	$ (118,770)

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Asset Retirement Obligations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Net present value of asset retirement obligation	$ 3,700,000	$ 3,500,000
Reconciliation of provision for asset retirement obligations
Balance beginning of period	3,502,952	2,780,237
Liabilities acquired	48,207	12,437
Liabilities disposed of	0	(46,961)
Wells plugged and abandoned	(88,992)	(509,802)
Change in estimates	6,695	1,178,142
Accretion	183,434	88,899
Balance end of period	$ 3,652,296	$ 3,502,952

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Fair Value Measurements (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and gas properties	$ 1,450,000
Fair Value of Derivative Assets, Gross, Current	403,032	$ 1,466,386
Net Fair Value, Asset	403,032	247,361
Fair value, Liability gross	890,580	366,131
Net Fair Value, Liability	403,032	247,361
Derivative contracts, Liabilities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Fair Value, Asset	487,548
Effect of Netting, Liability	(403,032)	(366,131)
Net Fair Value, Liability		(118,770)
Derivative contracts, Assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of Netting, Asset	(403,032)	0
Net Fair Value, Asset		1,219,025
Net Fair Value, Liability	0
Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of Netting, Asset	0	0
Net Fair Value, Asset		195,669
Net Fair Value, Liability	298,767
Short term investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of Netting, Asset		0
Net Fair Value, Asset		18,775,106
Level 1 | Derivative contracts, Liabilities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value, Liability gross	0	0
Level 1 | Derivative contracts, Assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets, Gross, Current	0	0
Level 1 | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets, Gross, Current	298,767	195,669
Level 1 | Short term investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets, Gross, Current		18,775,106
Level 2 | Derivative contracts, Liabilities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value, Liability gross	890,580	247,361
Level 2 | Derivative contracts, Assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets, Gross, Current	403,032	1,219,025
Level 2 | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets, Gross, Current	0	0
Level 2 | Short term investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets, Gross, Current		0
Level 3 | Derivative contracts, Liabilities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value, Liability gross	0	0
Level 3 | Derivative contracts, Assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets, Gross, Current	0	0
Level 3 | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets, Gross, Current	$ 0	0
Level 3 | Short term investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets, Gross, Current		$ 0

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Fair Value Measurements - Fair value of the impaired assets (Details) - Non-recurring	Dec. 31, 2024 USD ($)
Property and Equipment
Total Nonrecurring fair value measurement	$ 492,253
Oil and gas properties
Property and Equipment
Total Nonrecurring fair value measurement	492,253
Level 1
Property and Equipment
Total Nonrecurring fair value measurement	0
Level 1 | Oil and gas properties
Property and Equipment
Total Nonrecurring fair value measurement	0
Level 2
Property and Equipment
Total Nonrecurring fair value measurement	0
Level 2 | Oil and gas properties
Property and Equipment
Total Nonrecurring fair value measurement	0
Level 3
Property and Equipment
Total Nonrecurring fair value measurement	492,253
Level 3 | Oil and gas properties
Property and Equipment
Total Nonrecurring fair value measurement	$ 492,253

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Current Expected Credit Loss (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Receivables [Abstract]
Allowance for credit loss	$ 0	$ 0