Epsilon Energy Ltd. Annual Report 2018

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FY2018 Annual Report · Epsilon Energy Ltd.

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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, 2018.

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

For the transition period from to

Commission file number 001-38770

EPSILON ENERGY LTD.
(Exact name of registrant as specified in its charter)

Alberta, Canada
(State or Other Jurisdiction of Incorporation or Organization)

N/A
(I.R.S. Employer Identification No.)

116701 Greenspoint Park Drive, Suite 195
Houston, Texas
(Address of Principal Executive Offices)

77060
(Zip Code)

Registrant’s telephone number, including area code (281) 670 - 0002

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

Title of each class
Common Shares, no par value

Name of each exchange on which registered
Nasdaq Capital Market

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

NONE

(Title of class)

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§299.405 of this chapter) is not contained herein, and will not be
contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10 - K or any amendment
to this Form 10 - K. 

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 

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

Yes  No 

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. [ ]

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:
$47.2 million. There were 27,355,247 shares of Common Shares ($0 par value) outstanding as of March 26, 2019.

PART I

FORWARD LOOKING STATEMENTS.

This Annual Report on Form 10 - K contains forward-looking statements about our future performance. These
statements are based on our assumptions and beliefs in light of the information currently available to us. These statements
are subject to a number of known and unknown risks, uncertainties and other important factors, including the risks and
other factors discussed in “Risk Factors” and “Outlook” below, that could cause actual results and outcomes to differ
materially from any future results or outcomes expressed or implied by such forward looking statements. Such statements
are indicated by words such as “comfortable,” “committed,” “will,” “expect,” “goal,” “should,” “intend,” “target,”
“believe,” “anticipate,” “plan,” and similar words or phrases. Moreover, statements in the sections entitled Risk Factors,
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) and Outlook, and
elsewhere in this report regarding our expectations, projections, beliefs, intentions or strategies are forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended.

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 Midstream, LLC.

‘‘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 an oil and gas wellbore for production through the installation of

permanent production equipment, as well as perforation and fracture stimulation to optimize production.

‘‘Costless collar’’ An option position where the proceeds from the sale of a call option at its inception fund the

purchase of a put option at its inception.

‘‘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 oil and gas lease during its primary term, and typically
extends the lease for an additional year.

‘‘Development well’’ A well drilled within the proved area of an oil or natural gas reservoir to the depth of a

stratigraphic horizon known to be productive.

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

spot price, and the wellhead price received.

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

completion as an oil or gas 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.

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

owned.

‘‘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 our fractional working interest owned.

‘‘NGL’’ Natural gas liquid.

‘‘NYMEX’’ The New York Mercantile Exchange. ‘‘PDNP’’ Proved developed nonproducing reserves. ‘‘PDP’’

Proved developed producing reserves.

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

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

geological information.

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

‘‘Proved reserves’’ Those reserves that, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing
economic conditions, operating methods and government regulations— prior to the time at which contracts providing the
right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or

probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the
operator must be reasonably certain that it will commence the project, within a reasonable time.

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

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
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 oil and gas 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 oil and gas 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 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.

EXCHANGE RATE

The following tables set forth for the period indicated the rate used to convert one Canadian dollar to U.S. dollars,

expressed in U.S. dollars.

Daily Closing Rate

Annual Average Rate
Yearly High Closing Rate
Yearly Low Closing Rate

ITEM 1. BUSINESS.

Summary

December 31, December 31,

2018
0.7329

2017
0.7971

0.7718
0.7326
0.8143

0.7708
0.8245
0.7276

Epsilon Energy Ltd. was incorporated March 14, 2005, pursuant to the ABCA. The Corporation is
extra - provincially registered in Ontario pursuant to the Business Corporations Act (Ontario). Epsilon is a North American
on-shore focused independent oil and gas company engaged in the acquisition, development, gathering and production of
oil and gas reserves. Our primary areas of operation are Pennsylvania and Oklahoma. Our assets are concentrated in areas
with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. Commencing on
February 19, 2019, the common shares of the Corporation trade on the Nasdaq Global Market with the ticker symbol
‘‘EPSN.’’ Effective as of the close of trading on March 15, 2019, Epsilon voluntarily delisted its common shares from the
Toronto Stock Exchange. At December 31, 2018, Epsilon’s total estimated net proved reserves were 119,116 million cubic
feet (MMcf) of natural gas reserves and 30,502 barrels (Bbl) of oil and other liquids. Epsilon held leasehold rights to
approximately 76,251 gross (11,601 net) acres. The Corporation has natural gas production in Pennsylvania and has also
added oil and natural gas production from its recent acquisitions in the Anadarko Basin in Oklahoma.

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, and Dewey Energy Holdings LLC, a Delaware limited liability company.

All of the production from our Pennsylvania acreage (4,136 net) is dedicated to the Auburn Gas Gathering
System, or the Auburn GGS, located in Susquehanna County, Pennsylvania for a 15 year term expiring in 2026 under an
operating agreement whereby the Auburn GGS owners receive a fixed percentage rate of return on the total capital invested
in the construction of the system. We own a 35% interest in the system which is operated by a subsidiary of Williams
Partners, LP. In 2018, we paid $1.1 million to the Auburn GGS to gather and treat our 7.3 Bcf of 2018 natural gas
production in Pennsylvania ($1.2 million to the Auburn GGS to gather and treat our 8.9 Bcf in 2017 ).

Our principal executive office is located at 16701 Greenspoint Park Drive, Suite 195, Houston, Texas 77060, 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 2018

Operational Highlights

Marcellus Shale—Pennsylvania
• During 2018, Epsilon’s realized natural gas price was $2.51 per Mcf, an 18% increase over 2017.
• Total 2018 natural gas production was 7.3 Bcf, as compared to 8.9 Bcf during 2017.
• Marcellus working interest (WI) gas averaged 23.0 MMcf/d for 2018.

• Gathered and delivered 100.1 Bcf gross (35.0 Bcf net to Epsilon’s interest) during the year, or 274
MMcf/d through the Auburn System which represents approximately 83% of designed throughput
capacity.

Anadarko, NW Stack Trend—Oklahoma
• During 2018, Epsilon’s realized price for all production was $3.83 per Mcfe.
• Total production for 2018 included natural gas, oil, and other liquids and was 0.35 Bcfe.

Business highlights of 2017

Operational Highlights

Marcellus Shale—Pennsylvania

• During 2017, we produced 8.9 Bcf of natural gas net to our revenue interest.
• We participated in the completion of 2 gross (.01 net) upper Marcellus wells in August, which were turned to
production in September. In November, we also resumed the completion of the 6 gross (.13 net) lower Marcellus
wells which were drilled in December 2014 and partially completed in 2015. We completed and had production
from 2 (net 0.04) of the 6 wells by December 31, 2017.

NW Stack Trend—Oklahoma

In the first quarter of 2017, we commenced efforts to acquire a strategic position in the Anadarko Basin of
Oklahoma. During the year ended, December 31, 2017, we closed multiple acquisitions in the Anadarko Basin which
include varying interests in over 88 sections of land, all held by minor production from shallower intervals, including
operations covering 21 sections. The leasehold position includes rights to the prospective and deeper Meramec, Osage and

Woodford formations. This position covers a wide footprint encompassing oil, condensate and liquids rich gas prone areas
in the over - pressured window of the Basin.

Properties

As of December 31, 2018, Epsilon’s 76,251 gross (11,601 net) acres are all located in the United States and

include 266 gross (51.45 net) wells.

Producing Wells

Oil
Gas
Oil & Gas

Total Producing Wells

Non-producing Wells
Total Wells

Acreage

Gross(1)

Net(2)

8
150
67
225
41
266

0.85
24.18
14.77
39.79
11.66
51.45

As of December 31, 2018, our leasehold inventory consisted of the following acreage amounts, rounded to the

nearest acre:

Developed Acres
Pennsylvania
Oklahoma
Mississippi

Undeveloped Acres
Pennsylvania
Oklahoma
Mississippi

Total Acres

Pennsylvania
Oklahoma
Mississippi
Total acres

Gross(1)

Net(2) (3)

8,276
5,769
627
14,672

—
61,579
—
61,579

4,138
601
376
5,115

—
6,486
—
6,486

8,276
67,348
627
76,251

4,138
7,087
376
11,601

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

(2) “Net” means the Corporation’s fractional working interest share in each leasehold tract of land on which productive

wells have been drilled.

(3) “Net Undeveloped” means the Corporation’s fractional working interest share in each leasehold tract of land where
productive wells have yet to be drilled. All of Epsilon’s Oklahoma undeveloped properties are deep rights acreage
which is held by production of developed properties.

Business Segments

Our operations are conducted by three operating segments for which information is provided in our consolidated

financial statements for the years ended December 31, 2018 and 2017.

The three segments are as follows:

Upstream: Activities include acquisition, exploration, development and production of oil and natural gas reserves

on properties within the United States.

Gathering System: We partner with two other companies to operate a natural gas gathering system.

Canada: Activities include our corporate and governance functions.

For information about our segment’s revenues, profits and losses, total assets, and total liabilities, see Note 12,

“Operating Segments,” of the Notes to Consolidated Financial Statements.

Oil and Natural Gas Production and Revenues and Gathering System Revenues

A summary of our net oil and natural gas production, average oil and natural gas prices and related revenues and

our gathering system revenues for the years ended December 31, 2018 and 2017, respectively, follows:

Revenues ($000)
Natural gas revenue
Volume (MMcf)
Avg. Price ($/Mcf)
Exit Rate (MMcfpd)

Oil and other liquids revenue

Volume (MBO)
Avg. Price ($/Bbl)

Gathering system revenue
Total Revenues

Gathering System Operations

Year ended
December 31,

2018

2017

7,563

2.52 $
21.2
671 $
17.1

$ 19,031 $ 19,204
9,010
2.13
27.0
122
3.1
$ 39.31 $ 39.18
$ 9,982 $ 6,432
$ 29,684 $ 25,757

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

The gathering rate of the Auburn gas gathering system (“Auburn GGS”) is determined by a cost of service model
whereby the anchor shippers in the system dedicate acreage and reserves to the gas gathering system in exchange for the
Auburn GGS owners agreeing to a contractual rate of return on invested capital. The term of this arrangement is 15 years
commencing in 2012 and expiring in 2026 with an 18% rate of return. Each year, the Auburn GGS historical and forecast
throughput, revenue, operating expenses and capital expenditures are entered into the cost of service model. The model
then computes the new gathering rate that will yield the contractual rate of return to the Auburn GGS owners. In 2026,
prior to the end of the initial period on December 31, a new agreement governing rates will be negotiated between the
Anchor Shippers and the gathering system owners.

The Auburn GGS consists of 43.9 miles of gathering pipelines, a small auxiliary compression facility and a main
compression facility with three dehydration units and three Caterpillar 3612 compression units. Design capacity of the
Auburn compression facility, or the Auburn CF, is approximately 360,000 thousand cubic feet, or Mcf, per day. 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.

Revenues from the Auburn GGS are earned primarily from Anchor Shippers, Epsilon Energy USA, Statoil USA
Onshore Properties, Inc. and Chesapeake Energy, Inc. Additional but less significant revenues are earned from Chief Oil &
Gas LLC. Revenues derived from Epsilon’s production which have been eliminated from gathering system revenues
amounted to $1.1 million and $1.2 million, respectively, for the years ended December 31, 2018 and 2017.

During years ended December 31, 2018 and 2017, the Auburn GGS delivered 103 Bcf and 88 Bcf respectively,

of natural gas, or 282 and 242 MMcf per day.

Proved Reserves

Per our reserve report prepared by independent petroleum consultants, DeGolyer and MacNaughton, our
estimated proved reserves as of December 31, 2018, are summarized in the table below. See Risk Factors for information
relating to the uncertainties surrounding these reserve categories.

Pennsylvania-Marcellus Shale

Proved developed producing
Proved undeveloped

Total Pennsylvania proved reserves

Oklahoma-Anadarko Basin

Proved developed producing
Proved developed non-producing
Total Oklahoma proved reserves

Total proved reserves at December 31, 2018

Natural Gas Oil and other
Liquids MBbl
MMcf

48,757.8
68,418.0
117,175.8

1,581.3
359.0
1,940.3
119,116.1

—
—
—

28.0
2.5
30.5
30.5

We have not engaged in any exploration capital spending in 2018 or 2017. Our development capital spending to

convert proved undeveloped reserves to proved developed reserves for the periods indicated is as follows:

•

In 2018 in Pennsylvania, 4 gross (.39 net) wells were drilled and are waiting on completion. (Development
capital $0.67 million). Reserves for these wells remain classified as proved undeveloped as the wells have
not yet been completed.

In 2017 in Pennsylvania, 8 gross (.14 net) wells were completed. (Development capital $0.03 million) As a
result, 934 MMcf were transferred from net proved undeveloped to net proved developed producing and net
proved developed non producing; 306 MMcf and 628 MMcf, respectively.

Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with

Oversight for The Corporation’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 Executive 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.
Reserves are reviewed and approved internally by our Chief Executive Officer on a semi - annual basis. Our Chief Executive
Officer holds a Bachelor of Science degree in Chemical Engineering has studied Petroleum Engineering courses on a
Masters Level and completed a Masters in Business Administration. He has over 37 years of experience in various
positions in the global oil and gas business, primarily holding positions in the areas of reservoir development strategy,
property valuations, completions and production optimization. He has also been managing the allocation of capital in oil
and gas investments and appraising the values of those assets on a quarterly basis with Domain Energy Advisors since
January 2005. The reserve information in this report is based on estimates prepared by DeGoyler and MacNaughton, our
independent engineering firm. The person responsible for preparing the reserve report, Gregory Graves, is a Registered
Professional Engineer (No.70734) in the State of Texas and a Senior Vice President of the firm. Mr. Graves graduated
from the University of Texas at Austin with a degree in Petroleum Engineering, and is a member of the Society of

Petroleum Engineers and the Society of Petroleum Evaluation Engineers, and has prepared estimates of oil and gas reserves
since joining DeGolyer and MacNaughton in 2006. We provide our engineering firm with property interests, production,
current operating costs, current production prices and other information. This information is reviewed by our Chief
Executive Officer to ensure accuracy and completeness of the data prior to submission to our independent engineering
firm. Additionally, we have an independent member of the Board interview the reserve engineering firm to ensure the
independent nature of the appraisal.

Marketing and Major Customers

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

For the year ended December 31, 2018, we sold natural gas to 28 unique customers. Citadel Energy Marketing
LLC, and Spotlight Energy LLC each accounted for 10% or more of our total revenue. For the year ended December 31,
2017, we sold natural gas to 26 unique customers. South Jersey Resources Group, LLC and Repsol Energy North America
Corporation each accounted for 10% or more of our total revenue.

Competition

In both the Marcellus Basin and the Anadarko Basin, we operate in an extremely competitive environment for
acquiring leases, developing reserves and marketing production. In most instances, we are a substantially smaller
organization than our competitors both in terms of our personnel as well as our financial capability. This size differential
relative to our competitors could disadvantage us, particularly in regard to accessing capital markets, acquiring technical
expertise, and attracting and retaining talented personnel.

We are affected by industry competition for drilling rigs, completion rigs and availability of related equipment
and services. 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 not immune to these risks.

In our gas gathering activity in the Marcellus, the competition for customer shippers on our Auburn GGS is
intense. Although the Auburn GGS has three dedicated shippers (of which we are one), there is non - dedicated acreage
within the footprint of the gathering system. However, the Auburn GGS currently serves only one non - anchor shipper,
and there is no guarantee that we will be able to attract other customers to the system.

Our Status as an Emerging Growth Company

We are an “emerging growth company,” as defined in the JOBS Act. Certain specified reduced reporting and
other regulatory requirements are available to public companies that are emerging growth companies. These provisions
include:

•

an exemption from the auditor attestation requirement in the assessment of our internal controls over financial
reporting required by Section 404 of the Sarbanes—Oxley Act of 2002;

an exemption from the adoption of new or revised financial accounting standards until they would apply to
private companies;

an exemption from compliance with any new requirements adopted by the Public Company Accounting
Oversight Board, or the PCAOB, requiring mandatory audit firm rotation or a supplement to the auditor’s
report in which the auditor would be required to provide additional information about our audit and our
financial statements; and

•

reduced disclosure about our executive compensation arrangements.

We have elected to take advantage of the exemption from the adoption of new or revised financial accounting

standards until they would apply to private companies.

We will continue to be an emerging growth company until the earliest of:

•

the last day of our fiscal year in which we have total annual gross revenues of $1.07 billion (as such amount
is indexed for inflation every five years by the SEC to reflect the change in the Consumer Price Index for All
Urban Consumers published by the Bureau of Labor Statistics, setting the threshold to the nearest $1 million)
or more;

the last day of our fiscal year following the fifth anniversary of the date of our first sale of common equity
securities under an effective Securities Act registration statement;

the date on which we have, during the prior three - year period, issued more than $1 billion in non - convertible
debt; or

the date on which we are deemed to be a large accelerated filer under the rules of the Securities and Exchange
Commission, or SEC, which means the market value of our common shares that is held by non - affiliates (or
public float) exceeds $700 million as of the last day of our second fiscal quarter in our prior fiscal year.

Employees

As of December 31, 2018, we had eight 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.

Legal Proceedings

We are not a party to any pending or threatened legal proceedings. From time to time, we may become involved

in litigation related to claims arising from the ordinary course of our business.

Regulation

United States

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
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, 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.

In August 2015, the EPA issued final rules outlining the Clean Power Plan (“CPP”), which was developed in
accordance with the Obama Administration’s Climate Action Plan. Under the CPP, carbon pollution from power plants
was set to be reduced over 30% below 2005 levels by 2030. In 2017, EPA completed a review of the Clean Power Plan
pursuant to President Trump’s Energy Independence Executive Order. As a result, EPA proposed the repeal of the CPP,
based in part on its interpretation of Section 111(d) of the Clean Air Act. In August 2018, the Trump Administration,
through the EPA, issued its proposed replacement of the CPP, entitled the Affordable Clean Energy rule.

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. These standards expand the previously issued NSPS
requirements. In February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule, and in
September 2018 the EPA proposed additional amendments, including rescission of certain requirements and revisions to
other requirements, such as fugitive emission monitoring frequency. In November 2016, the Bureau of Land Management
(“BLM”) published a final rule to reduce methane emissions by regulating venting, flaring, and leaking from oil and natural
gas operations on public lands. However, in September 2018, the BLM published a final rule that codifies the BLM’s prior
approach to venting and flaring. The rule rescinding the November 2016 final rule has been challenged in federal court.

Internationally, in April 2016, the United States joined other countries in entering into a non-binding agreement
France for nations to limit their GHG emissions through country-determined reduction goals every five years beginning
in 2020 (the “Paris Agreement”). However, in August 2017, the U.S. State Department announced its intention to withdraw
from the Paris Agreement.

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 “Oil and Gas; 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 federal regulation of hydraulic fracturing
and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other
states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances.

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

Gathering System Regulation

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

The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the
Natural Gas Act, or the NGA, and by regulations and orders promulgated under the NGA by the FERC. In certain limited
circumstances, intrastate transportation, gathering, and wholesale sales of natural gas may also be affected directly or
indirectly by laws enacted by the U.S. Congress and by FERC regulations.

Market for Our Common Equity and Related Stockholder Matters

Market Information. The following table sets forth the high and low closing prices per share, denominated in
Canadian dollars, for our common shares for the periods indicated as reported on the Toronto Stock Exchange. The prices
reflect inter - dealer prices without regard to retail markups, markdowns or commissions and do not necessarily reflect

actual transactions. As of December 31, 2018, the Federal Reserve Bank of New York noon buying rate was $1.36
Canadian dollars per U.S. dollar.

Commencing on February 19, 2019, the common shares of the Corporation trade on the Nasdaq Global Market
with the ticker symbol ‘‘EPSN.’’ Effective as of the close of trading on March 15, 2019, Epsilon voluntarily delisted its
common shares from the Toronto Stock Exchange. The last reported sales price of our common shares on the Nasdaq
Global Market on March 28, 2019 was $4.30 per share.

Year Ended December 31, 2018

Fourth Quarter
Third Quarter
Second Quarter
First Quarter

Year Ended December 31, 2017

Fourth Quarter
Third Quarter
Second Quarter
First Quarter

Year Ended December 31, 2016

Fourth Quarter
Third Quarter
Second Quarter
First Quarter

CDN$

High

Low

$
$
$
$

6.16 $
5.76 $
5.90 $
5.96 $

6.70 $
6.40 $
6.40 $
6.90 $

6.10 $
6.78 $
6.80 $
6.80 $

4.96
4.66
4.60
4.60

5.84
5.80
5.50
5.82

5.74
5.76
6.30
4.56

Shareholders. We had approximately 1,400 shareholders of record as of December 31, 2018.

Dividends. We have not declared or paid any cash or stock dividends on our common shares since our inception

and do not anticipate declaring or paying any cash or stock dividends in the foreseeable future.

Securities Authorized for Issuance under Equity Incentive Plans. At December 31, 2018, we were authorized
to issue options to purchase up to 1,000,000 common shares. As of that date, we had issued options to purchase 290,750
common shares, leaving a maximum amount of 709,250 common shares available for future option issuances. The
following table sets out the number of common shares to be issued upon exercise of outstanding options issued pursuant
to our equity compensation plans and the weighted average exercise price of outstanding options for the periods indicated:

As at
December 31, 2018

As at
December 31, 2017

Weighted

Weighted
Number of Average Number of Average
Exercise

Exercise

Options

Exercise price in Cdn$
Balance at beginning of period

Granted
Exercised
Expired

Balance at period-end

Outstanding Price

—
—

330,750 $ 6.86
—
—
(40,000) $ 8.00
290,750 $ 6.70

255,500 $ 6.66
6.70
120,750
3.26
(20,000)
(25,500)
7.06
330,750 $ 6.86

Exercisable at period-end

210,249 $ 6.70

161,666 $ 6.82

As of December 31, 2018, we had no warrants or other common share - related rights outstanding.

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 make it extremely difficult to
predict future oil and natural gas price movements. Also, prices for crude 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 oil and gas reserve quantities. If the
oil and natural gas industry continues to experience low prices, we may, among other things, be unable to meet all of our
financial obligations or make planned expenditures.

Substantial and extended declines in oil and natural gas prices may result in impairments of proved oil and gas
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 proved 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 thereof, 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 thereof 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 thereof and prepared by different engineers, or by the same engineers at different times, may
vary. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves will
vary from estimates thereof and such variations could be material.

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, 2018 and 2017, or the DeGolyer
Reserve Reports, 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 thereof 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 and Capital Resources

Currently, our activity is highly concentrated to one product in one area. Although we are attempting to expand

our operations to other areas with multiple products, we may not be successful in these other areas.

An investment in us is subject to certain risks. There are numerous factors that may affect the success of our
business that are beyond our control including local, national and international economic and political conditions. Our
business involves a high degree of risk, which a combination of experience, knowledge and careful evaluation may not
overcome. Through December 31, 2018, our primary source of revenue originated from natural gas production and
gathering system revenues in the state of Pennsylvania. Our asset in Pennsylvania has not yet reached the mature stage,

but at some point we may need to acquire and develop other producing assets to maintain our current level or to grow. To
this end, we have begun to acquire leases in the Anadarko basin and to expand our holdings in Pennsylvania. Our future
depends on being able to successfully fund and develop these assets. There can be no assurance that our business will be
successful or that profitability will continue or that we will discover additional commercial quantities of crude oil or natural
gas.

If there is a sustained economic downturn or recession in the United States or globally, oil and gas 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, changes in the political landscape
or limitations on spending. An economic downturn and uncertainty may have a negative impact on our business. In 2008,
the financial markets collapsed causing the capital markets for the oil and gas sector substantial setbacks. As recently as
2015 and 2016, oil and gas prices decreased to a point as to make almost all investment in oil and gas projects uneconomic.
There can be no assurance that we will be able to access capital markets to provide funding for future operations that would
require additional capital beyond our current existing available capital on terms acceptable to us.

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

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

Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times. From time to
time, we may require additional financing in order to carry out our oil and natural gas acquisition, exploration and
development activities. Failure to obtain such financing on a timely basis could cause us to forfeit our interest in certain
properties, miss certain acquisition opportunities, or reduce or terminate our operations. If our revenues from our reserves
decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital
to replace our reserves or to maintain our production. If our cash flow from operations is not sufficient to satisfy our capital
expenditure requirements, there can be no assurance that additional debt, equity financing or the proceeds from the sale of
a portion or all of our interest in one or more projects will be available to meet these requirements or available on terms
acceptable to us.

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 corporations. 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 nor our by - laws limit the amount of indebtedness
that we may incur. The level of our indebtedness, from time to time, could impair our ability to obtain additional financing
in the future on a timely basis to take advantage of business opportunities that may arise.

Our potential lenders will likely require security over substantially all of our assets. If we become unable to pay
our debt service charges or otherwise commit an event of default, such as bankruptcy, these lenders may foreclose on or
sell our properties. The proceeds of any such sale would be applied to satisfy amounts owed to our lenders and other
creditors, and only the remainder, if any, would be available to us.

Future equity transactions could result in dilution to existing stockholders.

We may make future acquisitions or enter into financing or other transactions involving the issuance of securities
or the sale of a portion or all of an interest in one or more of our projects, all of which may be dilutive to existing security
holders.

Competition in the natural gas and oil industry is intense, which may hinder our ability 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 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. However, high returns are not guaranteed, and the results of drilling in new or
emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer
history of established production. Newer or emerging formations and areas have limited or no production history and,
consequently, a less predictable future of drilling results in these areas. Ultimately, the success of drilling and completion
techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long
time period. 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, as a
result of less than desirable results in developments we 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 crude oil or natural gas production, is often used in the completion of unconventional crude 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 operations are currently geographically concentrated and therefore subject to regional economic,

regulatory and capacity risks.

Approximately 97% of our production during fiscal 2018 and 2017 was derived from our properties in the
Marcellus region of Pennsylvania. 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. Additionally, we may be exposed to additional
risks, such as changes in field - wide rules and regulations that could cause us to permanently or temporarily shut - in many
or all of our wells within the Marcellus.

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. Any such
instance may offset the return on and value of the common shares.

We depend on third - party operators and our key personnel, and competition for experienced, technical

personnel may negatively affect our operations.

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 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 conventional 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.

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 and officers 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.

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 the holder of our leasehold interests 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 impact on our business.

Our revenues, profitability and future growth and the carrying value of our oil and natural gas properties are
substantially dependent on prevailing prices of oil and natural gas. Our ability to borrow and to obtain additional capital
on attractive terms is also substantially dependent upon oil and natural gas prices. Prices for oil and natural gas are subject
to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market
uncertainty and a variety of additional factors beyond our control. These factors include economic conditions in the United
States, the Middle East and elsewhere in the world; the actions of OPEC; governmental regulation; political stability in
the Middle East and elsewhere; the foreign supply of oil and natural gas; the price of foreign imports; and the availability
of alternative fuel sources. Any substantial and extended decline in the price of oil and natural gas would have an adverse
effect on the carrying value of our proved reserves, borrowing capacity, revenues, profitability and cash flows from
operations. There can be no assurance that recent commodity prices can be sustained over the life of our operations. There
is substantial risk that commodity prices may decline in the future, although it is not possible to predict the time or extent
of such decline.

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 impact 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 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.

If we are unable to successfully compete with the large number of oil and natural gas producers in our

industry, we may not be able to achieve profitable operations.

Oil and natural gas exploration is intensely competitive in all its phases and involves a high degree of risk. We
compete with numerous other participants in the search for, and the acquisition of, oil and natural gas properties and in the
marketing of oil and natural gas, as well as, for the hiring of skilled industry personnel, contractors and equipment. Our
competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities
than we do. Our ability to increase reserves in the future will depend not only on our ability to explore and develop our
present properties, but also on our ability to select and acquire suitable producing properties or prospects for exploratory
drilling. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and
reliability of delivery. Competition may also be presented by alternate fuel sources.

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 Internal Controls

For as long as we are an “emerging growth company,” we will not be required to comply with certain reporting
requirements, including those relating to accounting standards and disclosure about our executive compensation, that
apply to some other public companies.

As an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS
Act, we are permitted to, and intend to, rely on exemptions from certain disclosure requirements. We are an emerging
growth company until the earliest of:

•

the last day of the fiscal year during which we have total annual gross revenues of $1.07 billion or more;

the last day of the fiscal year following the fifth anniversary of this registration;

the date on which we have, during the previous 3 - year period, issued more than $1 billion in non - convertible
debt; or

the date on which we are deemed a “large accelerated filer” as defined under the federal securities laws.

For so long as we remain an “emerging growth company,” we will not be required to:

•

have an auditor report on our internal control over financial reporting pursuant to the Sarbanes - Oxley Act of
2002;

comply with any requirement that may be adopted by the Public Company Accounting Oversight Board
regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional
information about the audit and the financial statements (auditor discussion and analysis);

submit certain executive compensation matters to shareholders parachute provisions (requiring a non - binding
shareholder vote to approve golden parachute arrangements for certain executive advisory votes pursuant to
the “say on frequency” and “say on pay” provisions (requiring a non - binding shareholder vote to approve
compensation of certain executive officers) and the “say on golden officers in connection with mergers and
certain other business combinations) of the Dodd - Frank Wall Street Reform and Consumer Protection Act
of 2010; and

include detailed compensation discussion and analysis in our filings under the Exchange Act and instead may
provide a reduced level of disclosure concerning executive compensation.

In addition, the JOBS Act provides that an “emerging growth company” can take advantage of the extended
transition period for complying with new or revised accounting standards. We have elected to take advantage of the
extended transition period, which allows us to delay the adoption of new or revised accounting standards until those
standards apply to private companies. As a result of this election, our financial statements may not be comparable to public
companies that comply with new or revised accounting standards.

Because of these exemptions, some investors may find our common shares less attractive, which may result in a

less active trading market for our common shares, and our shares price may be more volatile.

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 expend, 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. 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 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 obtain new supplies. The primary factors affecting our ability to obtain new
supplies of natural gas is the level of successful drilling activity from the anchor shippers, of which Epsilon is one, as well
as our ability to compete for volumes from successful new wells drilled by third parties proximate to our system. If we are
not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, throughput on
our pipelines and the utilization rates of our compression facility would decline, which could have an adverse effect on
our business, results of operations, financial position and cash flows.

The gathering rate on the Auburn Gas Gathering System is subject to a Cost of Service model which could

result in a non - competitive gathering rate and reduced throughput.

The gathering rate charged by the Auburn gas gathering system (“Auburn GGS”) is determined by a cost of
service model whereby the anchor shippers in the system, of which Epsilon is one, dedicate acreage and reserves to the
gas gathering system in exchange for the Auburn GGS owners agreeing to a contractual rate of return on invested capital.
The term of this arrangement is 15 years commencing in 2012 and expiring in 2026 with an 18% rate of return. Each year,
the Auburn GGS historical and forecast throughput, revenue, operating expenses and capital expenditures are entered into
the cost of service model. The model then computes the new gathering rate that will yield the contractual rate of return to
the Auburn GGS owners. In 2026, prior to the end of the initial period on December 31, a new agreement governing rates
will be negotiated between the Anchor Shippers and the gathering system owners. All else being equal, if total throughput
on the system is lower than forecasted, the gathering rate will increase. If the gathering rate on the Auburn GGS increases,
it could render drilling uneconomic for shippers or result in shippers allocating capital to more competitive areas which
could result in further increases in the gathering rate. Although the anchor shippers have dedicated their reserves to the
Auburn GGS, they are under no obligation to develop reserves if they determine that development is uneconomic.

Because of the large supply of gas, and limited availability of transportation out of the Marcellus 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, natural gas is significantly
discounted to Henry Hub 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 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 gas gathering system 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 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 have been in service for many years and 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
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 or complete halt to the development of
reserves will impact our financial results, cash flows, access to capital and ability to maintain our gas gathering system.

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 maintain and expand our natural gas gathering businesses depends on the level of drilling and
production by anchor shippers and third parties in our gathering area. 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 other anchor shippers or third - party natural gas reserves connected to our
systems and compression facilities. Accordingly, we do not have independent estimates of total reserves dedicated to our
systems or the anticipated life of such reserves. 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 losses to us. In accordance with customary industry
practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be
appropriate. The location of certain segments of our facilities in or near populated areas, including residential areas,
commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of
our precautions, an event such as those described above could cause considerable harm to people or property and could
have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully
covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2. PROPERTIES.

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

ITEM 3. LEGAL PROCEEDINGS.

We are not a party to any pending or threatened legal proceedings. From time to time, we may become involved

in litigation related to claims arising from the ordinary course of our business.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

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 December 31, 2018, our Board made a grants to our directors, executive officers and employees, entitling
them to receive an aggregate of 237,000 Common Shares which shares will not be issued to the award recipients unless
certain time or performance based vesting criteria, as applicable, are met, in which case the vesting will occur in equal
parts over a three year period. The awards were made under the Share Compensation Plan in accordance with Rule 701
promulgated under the Securities Act.

ITEM 6. SELECTED FINANCIAL DATA.

The table below presents our selected historical consolidated financial data for the years ended December 31,
2018 and 2017. The selected historical consolidated financial data as of and for the years ended December 31, 2018 and
2017 have been derived from our audited consolidated financial statements, which have been audited by BDO USA, LLP,
an independent registered public accounting firm. The selected historical consolidated financial data set forth below should
be read in conjunction with the section titled “Management’s Discussion and Analysis of Financial Condition and Results
of Operations” for such periods and our consolidated financial statements and related notes. Our consolidated financial
statements included in this report have been prepared in accordance with United States generally accepted accounting
principles, or GAAP. Amounts are expressed in thousands of U.S. dollars, except share and per - share amounts.

To meet Nasdaq listing standards, the shareholders of the Corporation on December 19, 2018 approved a
Consolidation of the issued and outstanding common shares on the basis of one (1) new common share for up to every
existing two (2) common shares issued and outstanding immediately prior to the Consolidation. The common shares
commenced trading on a post-Consolidation basis on the TSX on December 24, 2018. All share amounts and per share
data are presented in these statements on a post-Consolidation basis.

Year ended December 31,

2018

2017

$
$
$
$

29,684 $
7,946
7,182
4,936
9,621
(2,217)
742
6,662 $
6,662 $
0.24 $
0.24 $

25,757
6,619
11,072
4,418
3,648
1,722
(2,066)
7,436
7,436
0.28
0.28
26,119,927
26,133,295

27,462,788
27,474,125

Income Statement Data
Operating revenues
Cost of revenues
Depreciation, depletion, amortization and accretion
General and administrative expense
Income from operations
Other income (expense)
Income tax expense (benefit)
Net income attributable to Epsilon
Net income available to shareholders
Net income per share, basic
Net income per share, diluted
Weighted average number of shares outstanding, basic
Weighted average number of shares outstanding, diluted

Balance Sheet Data
Cash and cash equivalents
Oil and gas properties
Gathering system properties
Total assets
Total long-term liabilities
Total shareholders’ equity(1)

As of December 31,
2017
2018

$ 14,401 $ 9,999
57,351
14,628
86,406
16,724
63,731

54,543
12,903
87,898
11,614
69,944

(1) No cash dividends were declared or paid during the periods presented.

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 or 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 at December 31, 2018 and 2017 and
for the years then ended together with accompanying notes.

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 information” 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.

Overview

We are a North American on - shore focused independent oil and gas company engaged in the acquisition,
development, gathering and production of oil and gas reserves. Our primary areas of operation are Pennsylvania and
Oklahoma. Our assets are concentrated in areas with known hydrocarbon resources, which are conducive to multi - well,
repeatable drilling programs.

All of the production from our Pennsylvania acreage (4,138 net) is dedicated to the Auburn Gas Gathering
System, or the Auburn GGS, located in Susquehanna County, Pennsylvania for a 15 year term expiring in 2026 under an
operating agreement whereby the Auburn GGS owners receive a fixed percentage rate of return on the total capital invested
in the construction of the system. We own a 35% interest in the system which is operated by a subsidiary of Williams
Partners, LP. In 2018, we paid $1.1 million to the Auburn GGS to gather and treat our 7.3 Bcf of natural gas production
in Pennsylvania ($1.2 million to the Auburn GGS to gather and treat our 8.9 Bcf in 2017).

Our common shares trade on the Nasdaq Global Market under the ticker symbol “EPSN.”

At December 31, 2018 our total estimated net proved reserves were 119,116 million cubic feet (MMcf) of natural
gas reserves and 30,502 barrels (Bbl) of oil and other liquids, and we held leasehold rights to approximately 76,251 gross
(11,601 net) acres. We have natural gas production in Pennsylvania, and natural gas and oil production from our operated
and non - operated wells in Oklahoma.

Business Strategy

Our ongoing business strategy involves focused targeting of natural gas and oil properties within the United States
with the goal of converting our leasehold interests into proved natural gas and oil reserves, followed by production that
optimizes cash flow and return on investment

Since July 2013, we have narrowed our strategic focus to our core upstream and gathering system assets in the
Marcellus shale, and the Anadarko Basin, and have divested all non - core properties. As of December 31, 2018, we had
$14 million in cash, and $23.0 million available on our revolver. Also, we have implemented a number of initiatives
operationally that have enhanced the value of core assets in the Marcellus. These initiatives include working with the
operator of our upstream asset to encourage improvements in completion productivity. In addition, we maintain an active
dialogue with our gathering system partners with a view toward maximizing the long term value of our gathering assets.

Our strategy is twofold: maximize the value of our integrated Marcellus and Anadarko assets, and evaluate
investment opportunities in non - Marcellus petroleum basins with attractive economics at the current commodity strip.
When natural gas pricing improves in the Marcellus, we intend to invest capital to increase production from both the lower
and upper Marcellus reservoirs. We believe the upper Marcellus has the potential to meaningfully increase our current
reserve value.

The operating environment remains challenging in our operating area of Pennsylvania. The Marcellus Shale has
proven to be one of the most attractive dry gas resources in the lower United States and, therefore, has attracted significant
drilling capital. Over the past several years, completion productivity has improved dramatically, resulting in increasing
initial production rates and gas recoveries. In many areas, the increase in natural gas deliverability has significantly
outpaced the development of the infrastructure necessary to transport the gas to downstream markets. This phenomenon
has resulted in local natural gas prices with abnormally large differentials to the benchmark NYMEX Henry Hub. Our
preference is to produce less natural gas in this unfavorable pricing environment as our acreage is largely held by
production, and our operating partner shares this view. The completion and commencing of operation of a large
infrastructure project has begun to have a positive impact on the local natural gas price.

We realized net income of $6.7 million during 2018 as compared to net income of $7.4 million for 2017. At
December 31, 2018, our total estimated net proved reserves of natural gas were 119,116 million cubic feet, or MMcf, a
decrease of 96,472 MMcf from December 31, 2017. Our standardized measure of discounted future net cash flows as of
December 31, 2018 and 2017 was $59.1 million and $49.7 million, respectively.

Year ended December 31, 2018 Highlights

Operational Highlights

Marcellus Shale—Pennsylvania

• During the year ended December 31, 2018, Epsilon’s realized natural gas price was $2.51 per Mcf, an 18%

increase from the year ended, December 31, 2017.

• Total year ended December 31, 2018 production of 7.3 Bcf in Pennsylvania, as compared to 8.9 Bcf in 2017.

Additionally, we added 353.4 MMcfe of gas, oil, and other liquids production in Oklahoma.

• Participated in the drilling of 4 gross (.39 net) upper Marcellus wells which are waiting on completion.

• Gathered and delivered 100.1 Bcf gross (35.0 Bcf net to Epsilon’s interest) during the year, or 274 MMcf/d

through the Auburn System which represents approximately 83% of designed throughput capacity.

NW Stack Trend—Oklahoma

• During 2018, Epsilon’s realized price for all production was $3.83 per Mcfe.

• Total production for 2018 included natural gas, oil, and other liquids and was 0.35 Bcfe.

Year ended December 31, 2017 Highlights

Operational Highlights

Marcellus Shale—Pennsylvania

• During the year ended December 31, 2017, our realized natural gas price was $2.13 per Mcf, a 53% increase

from the year ended December 31, 2016.

• Total year ended December 31, 2017 production was 8.9 Bcf in Pennsylvania, as compared to 11.0 Bcf in

2016. Additionally, we added 18.6 MMcfe of gas, oil, and other liquids production in Oklahoma.

• Participated in the completion of 2 gross (.01 net) upper Marcellus wells in August which were turned to

production in September.

• Gathered and delivered 88.2 Bcf gross (30.9 Bcf net to our interest) during the year, or 242 MMcfe/d through

the Auburn System which represents approximately 73% of maximum throughput.

•

In November, we also resumed the completion of the 6 gross (.13 net) lower Marcellus wells which were
drilled in December 2014 and partially completed in 2015. We completed and had production from 2 (0.04
net) of the 6 wells by December 31, 2017.

NW Stack Trend—Oklahoma

In the first quarter of 2017, we commenced efforts to acquire a strategic position in the Anadarko Basin of
Oklahoma. During 2017, we closed multiple acquisitions in the Basin which include varying interests in over 88 sections
of land, all held by minor production from shallower intervals, including operations covering 21 sections. The leasehold
position includes rights to the prospective and deeper Meramec, Osage and Woodford formations. This position covers a
wide footprint encompassing oil, condensate and liquids rich gas prone areas in the over-pressured window of the Basin.

Financing Highlights

Convertible Debentures

On February 28, 2012, we completed a public offering of Cdn$40 million aggregate principal amount of
convertible, unsecured subordinated debentures, or the Convertible Debentures, at a price of Cdn$1,000 per Debenture.
The Convertible Debentures bore interest at the rate of 7.75% per annum, payable commencing September 30, 2012 and
semi - annually thereafter and matured March 31, 2017, or the Maturity Date. The Convertible Debentures were convertible
into common shares at the holder’s option at any time prior to the Maturity Date at a conversion price equal to Cdn$4.45
per common share. Upon redemption or maturity, we had the option to repay the outstanding principal of the Convertible
Debentures through the issuance of common shares. We repaid the outstanding principal and accrued interest in
February 2017 for Cdn$ 39,951,435. This amount includes the original Cdn$40 million debentures, less Cdn$36,000 in
conversions, less Cdn$1.5 million repurchased by Epsilon for a payoff of Cdn$38,464,000 (US$ 29,464,190) of principle
and Cdn$1,487,435 (US$1,139,405) of interest.

Results of Operations

The following review of operations for the periods presented below should be read in conjunction with our

consolidated financial statements and the notes thereto.

Revenues

During the year ended December 31, 2018, revenues increased $3.9 million, or 15.2%, to $29.7 million from

$25.8 million during the same period in 2017.

Revenue and volume statistics for the years ended December 31, 2018 and 2017 were as follows:

Year ended
December 31,

2018

2017

Revenues ($000)

Natural gas revenue
Volume (MMcf)
Avg. Price ($/Mcf)
Exit Rate (MMcfpd)

Oil and other liquids revenue

Volume (MBO)
Avg. Price ($/Bbl)

Gathering system revenue

Total Revenues

7,563

2.52 $
21.2
671 $
17.1

$ 19,031 $ 19,204
9,010
2.13
27.0
122
3.1
$ 39.31 $ 39.18
$ 9,982 $ 6,432
$ 29,684 $ 25,757

We earn gathering system revenue as a 35% owner of the Auburn Gas Gathering system. This revenue consists
of fees paid by Anchor Shippers and third - party customers of the system to transport gas from the wellhead to the
compression facility, and then to the delivery meter at Tennessee Gas Pipeline. For the year ended December 31, 2018,
approximately 86% of the Auburn GGS revenues earned are gathering fees, while 14% are compression fees. Third party
customers represent approximately 11% of gathering revenues and 5% of compression revenues. For the year ended
December 31, 2017, approximately 89% of the Auburn GGS revenues earned were gathering fees, while 11% were
compression fees. Third - party customers represent approximately 11% of gathering revenues and 5% of compression
revenues. Revenues derived from Epsilon’s production which have been eliminated from gathering system revenues
amounted to $1.1 million and $1.2 million respectively for the year ended December 31, 2018 and 2017.

Upstream revenue for the year ended December 31, 2018 increased by $0.38 million, or 2%, over 2017 as a result
of higher natural gas prices, offset somewhat by lower volumes. Volumes were lower during 2018 because no wells were
completed during this time and wells with minimal working interest to Epsilon were completed in 2017, as well as natural
production decline rates. The end of the year daily production rate for gas in Pennsylvania was 21.2 MMcf.

Gathering system revenue increased $3.5 million, or 55.2%, during the year ended December 31, 2018, due to a
32% increase in the volumes flowing through the system and an increase in the gathering and compression rate charged.
The Auburn GGS is subject to a cost of service model, whereby the Anchor Shippers dedicate acreage and reserves to the
Auburn GGS. In exchange for this dedication, the owners of the Auburn system agree to a fixed rate of return on capital
invested which cannot be exceeded. Therefore, rather than being subject to a fixed gathering rate, the Shippers are subject
to a fluctuating gathering rate which is re - determined annually in order to produce the contractual return on capital to the
Auburn GGS owners. The term of the model is fixed from 2012 to 2026. Each year, actual throughput, revenue, operating
expenses and capital are captured in the model, and the remaining years are forecasted. The model then iterates for a
gathering rate that yields the contractual rate of return. All else being equal, to the extent that throughput is higher or
capital is lower than the preceding year’s forecast, the gathering rate will decline.

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, 2018 and 2017:

(in thousands of dollars)
Lease operating costs
Gathering system operating costs

Upstream operating costs—Total $/Mcfe
Gathering system operating costs $ / Mcf

Year ended December 31,

2018
6,666 $
1,280
7,946 $

2017
5,723
896
6,619

0.87
0.06

0.63
0.06

Upstream operating costs consist of lease operating expenses necessary to extract gas and oil, including gathering

and treating the oil and gas to ready it for sale.

Gathering system operating costs consist primarily of rental payments for the natural gas fueled compression
units. Other significant gathering system operating costs include chemicals (to prevent corrosion and to reduce water vapor
in the gas stream), saltwater disposal, measurement equipment / calibration and general project management. The gathering
system operating costs and the associated $/Mcf reported include the effects of elimination entries to remove the gas
gathering fees billed by the gas gathering system operator to Epsilon’s upstream operations, and the volume associated
with those fees. The elimination entries amounted to $1.1 million and $1.2 million for the years ended December 31, 2018
and 2017, respectively (see Note 12, “Operating Segments,” of the Notes to Consolidated Financial Statements).

For the year ended December 31, 2018, upstream operating costs increased by $0.9 million, or 16.5% from the
same period in 2017. The increase in total cost, and $/Mcfe was mainly due to the cost of operating the Oklahoma
properties acquired in late 2017. Gathering system costs for the year ended December 31, 2018 increased $0.4 million, or
42.8% over the same period in 2017 because of costs related to higher throughput volumes and maintenance costs for the
system.

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

(in thousands of dollars)
Depletion, depreciation, amortization and accretion

Year ended December 31,

2018
7,182 $

2017
11,072

Oil and natural gas 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 oil and gas
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. The depletion for the first three quarters of the
next year is based on the reserve report prepared at the end of the previous year, taking into consideration the limited
development of the reserves over these time periods. The fourth quarter depletion is calculated using the reserve volumes
from the reserve report prepared as of December 31 of the current year.

Depreciation expense includes amounts pertaining to our office furniture and fixtures, computer hardware and
software. Depreciation is calculated using the straight - line method over the estimated useful lives of the assets, ranging
from 3 to 5 years.

Accretion expense is related to the asset retirement costs.

As discussed above, DD&A expense for the first three quarters is calculated based on the reserve report from the
prior year. During the year ended December 31, 2018, DD&A expense decreased by $3.9 million, or 35.1%, compared to
the same period in 2017 mainly due to a large increase in the amount of reserves reported in the December 31, 2017 reserve

report as compared to the December 31, 2016 reserve report. This increase resulted from the gain of proved reserves
primarily as a result of higher natural gas prices in 2017. Also contributing to the lower DD&A expense in 2018 was lower
production volumes.

General and Administrative (“G&A”)

(in thousands of dollars)
General and administrative

Year ended December 31,

2018
4,936 $

2017
4,418

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

The G&A expenses increased by $0.5 million, or 11.7%, during the year ended December 31, 2018 from the
same period in 2017, mainly due to increased consulting and legal costs required for the effort to obtain a listing on a major
U.S. stock exchange.

Interest Expense

(in thousands of dollars)
Interest expense
Debenture fee amortization (debt portion)
Interest expense

Year ended December 31,

2018

2017

141 $
—
141 $

903
53
956

Interest expense relates to the interest payable and amortization of the underwriter and administrative fees related

to the convertible debentures issued in 2012, and interest on the revolving line of credit.

Interest expense decreased during the year ended December 31, 2018 from $0.96 million for the year ended
December 31, 2017 to $0.14 million, or 85.3%. This was due to the maturing and payoff of the convertible debentures in
February 2017 and the decrease in the average borrowings outstanding on the line of credit during the year ended
December 31, 2018 over the year ended December 31, 2017.

Net gain (loss) on commodity contracts

(in thousands of dollars)
Net gain (loss) on commodity contracts

Year ended December 31,

2018
(1,938) $

2017
2,624

During 2018, we entered into fixed price swap and basis swap derivative contracts. During the period, the

Corporation paid $1,381,898 on the settlement of contracts due to the increase in commodity prices.

For the year ended December 31, 2017, we entered into fixed price swap, basis swap, and two - way costless collar

derivative contracts. During this period, the Corporation received $2,027,791 on the settlement of contracts.

Miscellaneous Income (Expense)

(in thousands of dollars)
Miscellaneous income

Year ended December 31,

2018

2017

(137) $

For the year ended December 31, 2018 and 2017, miscellaneous income (expense) consisted primarily of interest

income, and foreign currency gains and (losses).

Net Income Compared to Adjusted EBITDA

Net income (loss)

Add Back:

Net interest expense
Deferred income tax provision
Depreciation, depletion, amortization, and accretion
Stock based compensation expense
Net change in unrealized (gain) loss on commodity contracts
Other income
Adjusted EBITDA

Year ended December 31,
2017
2018

6,662 $

7,436

129
742
7,182
330
557
(2)
15,600 $

929
(2,066)
11,072
229
(596)
(4)
17,000

Epsilon defines Adjusted EBITDA as earnings before (1) net interest expense, (2) taxes, (3) depreciation,
depletion, amortization and accretion expense, (4) impairments of oil and gas properties, (5) non-cash stock compensation
expense, (6) unrealized gain on derivatives, and (7) other income. Adjusted EBITDA is not a measure of financial
performance as determined under U.S. GAAP and should not be considered in isolation from or as a substitute for net
income or cash flow measures prepared in accordance with U.S. GAAP or as a measure of profitability or liquidity.

Additionally, Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.
Epsilon has included Adjusted EBITDA as a supplemental disclosure because its management believes that EBITDA
provides useful information regarding its ability to service debt and to fund capital expenditures. It further provides
investors a helpful measure for comparing operating performance on a "normalized" or recurring basis with the
performance of other companies, without giving effect to certain non-cash expenses and other items. This provides
management, investors and analysts with comparative information for evaluating the Company in relation to other oil and
gas 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 Adjusted EBITDA to net income, 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

Our primary source of cash during the years ended December 31, 2018 and 2017 was funds generated from
operations. In addition to operations, the primary uses of cash for the year ended December 31, 2018 were income tax pre-
payments and payments on the revolving line of credit. During the year ended December 31, 2017, we completed a rights
offering that generated $18.0 million of cash in addition to cash generated from operations. The primary uses of cash
during the year ended December 31, 2017 were funds used in operations, development expenditures, the payoff of
Epsilon’s convertible debentures, payments on the revolving line of credit, and the purchase of 67,268 gross (7,008 net)
acres of oil and gas properties in the Anadarko Basin in Oklahoma.

At December 31, 2018, we had a working capital surplus of $13.6 million, an increase of $5.7 million over the
$7.9 million surplus at December 31, 2017. The surplus increased over the last year because of a significant reduction of
interest payments due to the payoff of the convertible debentures in February 2017.

Year ended December 31, 2018 compared to 2017

During the year ended December 31, 2018, $10.1 million was provided by our operating activities, compared to
$17.5 million in 2017, a $7.4 million, or 42%, decrease. The decrease was mainly due to estimated tax payments of $4.1
million, the $1.4 million paid on settlements of derivatives and a decrease in net income as discussed previously.

We used $2.0 million for investing activities during the year ended December 31, 2018 primarily for leasehold
costs in anticipation of new lease purchases and a drilling program. During the same period of 2017, we used $19.3 million,
mainly for the acquisition of oil and gas properties in the Anadarko basin.

We used $3.6 million in financing activities during the year ended December 31, 2018 for the payoff of our
revolving line of credit and the buyback and cancelation of shares of Epsilon stock. The $21.1 million of cash used for
financing activity during the year ended December 31, 2017 included the redemption of the convertible debentures totaling
$29.5 million and the payoff of our line of credit totaling $9.6 million. This was offset by the completion of a rights
offering, which increased our cash by $18.0 million.

Credit Agreement

Effective July 30, 2013, our wholly owned subsidiary Epsilon Energy USA entered into a senior secured
revolving credit facility. The terms of this agreement include a total commitment of up to $100 million. The current
effective borrowing base is $23.0 million. Upon each advance, interest is charged at the rate of LIBOR plus an applicable
margin. The applicable margin ranges from 2.75% to 3.75% and is based on the percent of the line of credit utilized.
Effective January 7, 2019 the agreement was amended to extend the maturity date to March 1, 2022.

The bank has a first priority security interest in the tangible and intangible assets of Epsilon Energy USA to secure
any outstanding amounts under the agreement. Under the terms of the agreement, we must maintain the following
covenants:

•

Interest coverage ratio greater than 3 based on income adjusted for interest, taxes and non - cash amounts.

• Current ratio, adjusted for line of credit amounts used and available and non - cash amounts, greater than 1.

• Leverage ratio less than 3.5 based on income adjusted for interest, taxes and non - cash amounts.

We were in compliance with the financial covenants of the agreement as of December 31, 2018 and December 31,

2017.

Balance at

December 31, December 31,

2018

2017

Borrowing Base
December 31, 2018

Interest
Rate

Revolving line of credit

— $ 2,900,000 $

13,500,000 3 mo. LIBOR + 2.75%

In January 2019 our borrowing base was increased to $23 million, resulting in available borrowing capacity under

the credit agreement of $23 million as of January 7, 2019.

Derivative Transactions

We have 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, 2018, our outstanding natural gas commodity swap contracts consisted of the following:

Derivative Type
2019

Fixed price swap
Basis swap

Contractual Obligations

Weighted Average Price ($/MMbtu)

Volume
(Mmbtu)

Swaps

Differential

Basis

Fair Value of Liability
December 31, 2018

3,635,000 $
3,635,000 $

2.78 $
— $

—
(0.54)

(35,660)
(261,363)
(297,023)

The following table summarizes our contractual obligations at December 31, 2018:

Payments Due by Period

Derivative liabilities(1)
Asset retirement obligation, undiscounted
Capital expenditure commitments
Operating leases
Total future commitments

1 – 3
Years

Greater than

3 Years

Total
498,888
21,487,007
2,317,738
87,306

—
21,487,007
—
—
$ 24,390,939 $ 2,897,203 $ 6,729 $ 21,487,007

—
—
—
6,729

Less than
1 Year
498,888
—
2,317,738
80,577

(1) The liability balance shown represents the gross liability balance of derivative contracts before being offset by

contracts in an asset position.

We enter into commitments for capital expenditures in advance of the expenditures being made. At a given point
in time, it is estimated that we have committed to capital expenditures equal to approximately one quarter of our capital
budget by means of giving the necessary authorizations to incur the expenditures in a future period. Current commitments
have been included in the contractual obligations table above.

Based on current natural gas prices and anticipated levels of production, we believe that the estimated net cash
generated from operations, together with cash on hand and amounts available under our credit agreement, will be adequate
to meet liquidity needs for the next 12 months and beyond, including satisfying our financial obligations and funding our
operating and development activities.

The convertible debentures were scheduled to mature on March 31, 2017. The debentures were fully funded with

cash holdings in Canada and were paid off in February 2017 for Cdn$ 39,951,435.

Off - Balance Sheet Arrangements

As of December 31, 2018 and 2017, we had no off - balance sheet arrangements.

Foreign Currency Exchange Rate Risk

We are exposed to risks arising from fluctuations in foreign currency exchange rates, primarily between Canadian
and U.S. dollars. We do not utilize any foreign currency based derivatives. In order to manage this risk and to defer the
realization of any resulting currency loss from converting Canadian dollars to U.S. dollars, we retain cash balances in both
U.S. and Canadian dollars.

Summary of Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated
financial statements and accompany 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 policies 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
policies. 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.

Successful Efforts Accounting

We use the successful efforts method of accounting for oil and gas operations. Under this method, the fair value
of property acquired and all costs associated with successful exploratory wells and all development wells are capitalized.
The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been
found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made
that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory
wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of
drilling, requiring additional testing and evaluation of the wells. 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.

Gathering System

We hold an undivided interest in a gas gathering system asset that supports our Pennsylvania operations. We

account for the costs and revenue from this system using the proportionate consolidation method.

Proved Oil and Gas Reserves

Our engineers estimate proved oil and gas 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 oil and gas 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 oil and gas 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.”

Unproved Oil and Gas Properties

Unproved properties generally consist of costs incurred to acquire unproved leases. Unproved lease acquisition
costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which
time we expense the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is
recorded as an impairment of oil and gas properties in the consolidated statements of operations and comprehensive income

(loss). Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently
determined to be productive or are assigned proved reserves. Unproved oil and gas properties are assessed periodically for
impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and
other relevant factors.

Depreciation, Depletion and Amortization of Oil and Gas Properties and Gathering Systems

The quantities of estimated proved oil and gas reserves are a significant component of our calculation of
depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense.
Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease,
respectively.

Depreciation, depletion and amortization rates are updated quarterly to reflect the addition of capital costs, reserve

revisions (upwards or downwards) and additions, property acquisitions and/or property dispositions and impairments.

Depreciation and amortization of other property, plant and equipment is calculated on a straight - line basis over

the estimated useful life of the asset.

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 oil and
gas 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 unamortized capitalized cost 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 unamortized capitalized cost, the capitalized
cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value
Measurement Topic of the ASC 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.

Under ASC 360, we evaluate impairment of proved and unproved oil and gas 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.

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 described in the Fair Value Measurement Topic
of the ASC, which considers estimated discounted future cash flows.

Derivative Financial Instruments

Derivative financial instruments are used to hedge exposure to changes in commodity prices arising in the normal
course of business. The principal derivatives that may be used are commodity price swap and collar contracts. The use of
these instruments is subject to policies and procedures as approved by the Board. Derivative financial instruments are not
traded for speculative purposes. No derivative contracts have been designated as cash flow hedges for accounting purposes.
Derivative financial instruments are initially recognized at cost, if any, which approximates fair value. Subsequent to initial
recognition, derivative financial instruments are recognized at fair value. The derivatives are valued on a mark - to - market
valuation, and the gain or loss on re - measurement to fair value is recognized through the consolidated statements of
operations and comprehensive income (loss). The estimated fair value of derivative instruments requires substantial
judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to
maturity, and credit risk. The values reported in Epsilon’s financial statements change as these estimates are revised to
reflect actual results, changes in market conditions or other factors.

The counterparties to our derivative instruments are not known to be in default on their derivative positions.
However, we are exposed to credit risk to the extent of nonperformance by the counterparty in the derivative contracts.
We believe credit risk is minimal and do not anticipate such nonperformance by such counterparties.

Asset Retirement Obligation (“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. These obligations consist of estimated future costs associated with the plugging
and abandonment of oil and gas wells, 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 oil and gas 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 oil and gas 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. Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be
recovered in future periods, which requires judgment. Deferred tax liabilities are recognized when it is considered probable
that temporary differences will be payable to tax authorities in future periods, which requires judgment. Income tax filings
are subject to audits and re - assessments. Changes in facts, circumstances, and interpretations of the standards may result
in a material increase or decrease in our provision for income taxes.

On December 22, 2017, the United States enacted tax reform legislation known as the Tax Cuts and Jobs Act (the
“Act”), resulting in significant modifications to existing law. The Corporation has incorporated the accounting for the
effects of the Act during 2017 (See Note 9 of the consolidated financial statements). As such, our financial statements for
the year ended December 31, 2017 reflect certain effects of the Act, which include a reduction in the corporate tax rate
from 35% to 21% effective January 1, 2018.

Recently Issued Accounting Standards

The Corporation, an emerging growth company (“EGC”), has elected to take advantage of the benefits of the
extended transition period provided for in Section 7(a)(2)(B) of the Securities Act, for complying with new or revised
accounting standards which allows the Corporation to defer adoption of certain accounting standards until those standards
would otherwise apply to private companies.

In August 2018, the FASB issued ASU 2018-13, ‘‘Fair Value Measurement (Topic 820): Disclosure Framework-
Changes to the Disclosure Requirements for Fair Value Measurement,’’ the purpose of which is to improve the
effectiveness of fair value measurement disclosures. The amendments in this ASU are the result of a broader disclosure
project called FASB Concepts Statement, Conceptual Framework for Financial Reporting—Chapter 8: Notes to Financial
Statements, which the Board finalized on August 28, 2018. The Board used the guidance in the Concepts Statement to
improve the effectiveness of ASC 820’s disclosure requirements. ASU 2018-13 is effective for all entities for fiscal years
beginning after December 15, 2019, including interim periods therein. Early adoption is permitted for any eliminated or
modified disclosures upon issuance of this ASU. We have examined the provisions and do not anticipate any of them to
materially affect our financial statements.

In March 2018, the FASB issued an update ASU No. 2018-05, ‘‘Income Taxes (Topic 740): Amendments to SEC
Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118,’’ regarding the accounting implications of the recently
issued Tax Cuts and Jobs Act (‘‘TCJA’’). The update clarifies that in a company’s financial statements that include the
reporting period in which the TCJA was enacted, a company must first reflect the income tax effects of the TCJA in which
the accounting under GAAP is complete. These amounts would not be provisional amounts. The Corporation would also
report provisional amounts for those specific income tax effects for which the accounting under GAAP will be incomplete
but for which a reasonable estimate can be determined. This accounting update is effective immediately. The Corporation
believes its accounting for the income tax effects of the TCJA is complete (See Note 9 of the consolidated financial
statements). Technical corrections or other forthcoming guidance could change how we interpret provisions of the TCJA,
which may impact our effective tax rate and could affect our deferred tax assets, tax positions and/or our tax liabilities.

In February 2016, the FASB issued ASU 2016 - 02, “Leases (Topic 842)” (ASU 2016 - 02), which significantly
changes accounting for leases by requiring that lessees recognize a right - of - use asset and a related lease liability
representing the obligation to make lease payments, for all lease transactions with terms greater than one year. Additional
disclosures about an entity’s lease transactions will also be required. ASU 2016 - 02 defines a lease as “a contract, or part
of a contract, that conveys the right to control the use of identified property, plant, or equipment (an identified asset) for a
period of time in exchange for consideration.” ASU 2016 - 02 is effective for fiscal years beginning after December 15,
2019, and interim periods within fiscal years beginning after December 15, 2020. Lessees and lessors are required to
recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified
retrospective approach. Epsilon is reviewing the provisions of ASU 2016 - 02 to determine the impact on its consolidated
financial statements and related disclosures. We do not anticipate this to materially affect our consolidated financial
statements. In July 2018, the FASB issued ASU 2018-11, ‘‘to provide entities with relief from the costs of implementing
certain aspects of the new leasing standard, ASU 2016-02. Under ASU 2018-11, adopters will take a prospective approach,
rather than a retrospective approach as initially prescribed, when transitioning to ASU 2016-02. Instead of recording the
cumulative impact of all comparative reporting periods presented within retained earnings, we will now assess the facts
and circumstances of all leasing contracts as of January 1, 2020. ASU 2018-11 does not change the effective dates for
ASU 2016-02. We still do not anticipate this to materially affect our financial statements.

In May 2014, the FASB issued ASU 2014-09, ‘‘Revenue from Contracts with Customers’’ (ASU 2014-09),
which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an
amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.
ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new
standard also will require expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash
flows from contracts with customers. In August 2015, the FASB issued ASU 2015-14, ‘‘Revenue from Contracts with
Customers’’ (‘‘ASU 2015-14’’), which approved a one-year delay of the standard’s effective date. In accordance with
ASU 2015-14, the standard is effective for the Corporation for annual reporting periods beginning after December 15,
2018 and interim periods within fiscal years beginning after December 15, 2019, and early adoption is permitted. The new
standard permits adoption through the use of either the full retrospective approach or a modified retrospective approach.
In May 2016, the FASB issued ASU 2016-11 which rescinds certain SEC guidance in the ASC, including guidance related
to the use of the ‘‘entitlements’’ method of revenue recognition. Epsilon does not intend to early-adopt ASU 2014-09.
Epsilon is currently determining the impacts of the new standard on our sales contract portfolio. Our approach includes
performing a detailed review of key contracts representative of our business and comparing historical accounting policies
and practices to the new standard. Also, in May 2016, the FASB issued ASU No. 2016-12, ‘‘Revenue from Contracts with
Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients’’ (ASU 2016-12). The amendments under
this ASU provide clarifying guidance in certain narrow areas and adds some practical expedients. These amendments are
also effective at

the same date that ASU 2014-09 is effective. Additionally, in March 2016, the FASB issued ASU No. 2016-08, ‘‘Revenue
from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus
Net).’’

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 US 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 Basin 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.

Interest Rate Risk

Market risk is estimated as the change in fair value resulting from a hypothetical 100 - basis - point change in the
interest rate on the outstanding balance under our credit agreement. The credit agreement allows us to fix the interest rate
for all or a portion of the principal balance for a period up to three months. To the extent that the interest rate is fixed,
interest rate changes affect the instrument’s fair market value but do not affect results of operations or cash flows.
Conversely, for the portion of the credit agreement that has a floating interest rate, interest rate changes will not affect the
fair market value but will affect future results of operations and cash flows.

At December 31, 2018, the outstanding principal balance under the credit agreement was nil. At December 31,
2017, the outstanding principal balance under the credit agreement was $2.9 million, and the weighted average interest
rate on the outstanding principal balance was 4.1%. The carrying amount approximated fair market value. Assuming a
constant debt level of $2.9 million, the cash flow impact resulting from a 100 basis point change in interest rates during
periods when the interest rate is not fixed would be $0.03 million over a 12 month time period. Changes in interest rates
did not affect the amount of interest paid on the convertible debentures, but changes in interest rates did affect the fair
values of those notes.

Commodity Contracts

The Corporation’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 Epsilon to losses or gains,
entering into these contracts helps to stabilize cash flows and support the Corporation’s capital spending program.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Our consolidated balance sheets as of December 31, 2018 and 2017, and the consolidated statements of operations
and comprehensive income (loss), changes in shareholders’ equity and cash flows for years ended December 31, 2018 and
2017 included in this annual report have been prepared in accordance with U.S. GAAP.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

There were no changes in or disagreements with the registrant’s accountants on accounting and financial

disclosure during the year.

On July 20, 2017, Epsilon engaged a new independent registered public accounting firm for the re - audit of the
financial statements under US GAAP for the years ended December 31, 2015 and 2016. A new firm was engaged as we
intended to redomicile in the United States and so need US accountants. The change of the Corporation’s independent
registered public accounting firm was approved unanimously by our Board of Directors.

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. and subsidiaries (the
“Company”) as of December 31, 2018 and 2017, and the related consolidated statements of operations and comprehensive
income, changes in shareholders’ equity, and cash flows for each of the two years in the period ended December 31, 2018,
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, 2018
and 2017, and the results of their operations and their cash flows for each of the two years in the period ended December 31,
2018, 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 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 audits 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.

/s/ BDO USA LLP

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

Houston, Texas
March 29, 2019

EPSILON ENERGY LTD.

Consolidated Balance Sheets

ASSETS

Current assets

Cash and cash equivalents
Accounts receivable
Fair value of derivatives
Prepaid income taxes
Other current assets

Total current assets

Non-current assets

Property and equipment:

Oil and gas properties, successful efforts method

Proved properties
Unproved properties
Accumulated depletion, depreciation, and amortization

Total oil and gas properties, net

Gathering system

Accumulated depletion, depreciation, and amortization

Total gathering system, net
Other property and equipment, net

Total property and equipment, net

Other assets:

Restricted cash

Total non-current assets

Total assets

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities

Accounts payable trade
Royalties payable
Other accrued liabilities
Income taxes payable
Fair value of derivatives

Total current liabilities

Non-current liabilities

Revolving line of credit
Other non-current liabilities
Asset retirement obligation
Deferred income taxes

Total non-current liabilities

Total liabilities
Commitments and contingencies (See Note 10)

Shareholders' equity

Common shares, no par, unlimited shares authorized and 27,385,133 shares and 27,522,852 shares
issued at December 31, 2018 and December 31, 2017 respectively. At December 31, 2018 Epsilon held
26,953 shares of stock.
Additional paid-in capital
Deficit
Accumulated other comprehensive income

Total shareholders' equity
Total liabilities and shareholders' equity

December 31, December 31,

2018

2017

14,401,257
5,042,134
—
205,711
244,233
19,893,335

9,998,853
3,334,895
259,544
—
276,431
13,869,723

118,851,574
19,498,666
(83,807,401)
54,542,839
41,040,847
(28,137,573)
12,903,274
—
67,446,113

558,261
68,004,374
87,897,709

2,585,324
1,300,539
2,156,304
—
297,023
6,339,190

—
—
1,625,154
9,989,278
11,614,432
17,953,622

118,524,693
17,451,552
(78,625,589)
57,350,656
40,880,503
(26,252,385)
14,628,118
299
71,979,073

556,864
72,535,937
86,405,660

2,008,229
1,029,678
1,895,917
1,017,194
—
5,951,018

2,900,000
1,615,313
1,646,601
10,561,683
16,723,597
22,674,615

143,611,023
6,519,028
(89,983,894)
9,797,930
69,944,087
87,897,709

144,292,238
6,171,525
(96,645,954)
9,913,236
63,731,045
86,405,660

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

EPSILON ENERGY LTD.

Consolidated Statements of Operations and Comprehensive Income

Revenues:

Oil, gas, NGLs and condensate revenue
Gas gathering and compression revenue

Total revenue

Operating costs and expenses:

Lease operating expenses
Gathering system operating expenses
Depletion, depreciation, amortization, and accretion
General and administrative expenses:
Stock based compensation expense
Other general and administrative expenses

Total operating costs and expenses

Operating income (loss)

Other income and (expense):

Interest income
Interest expense
Gain (loss) on derivative contracts
Other income (expense)

Other income (expense), net

Income before tax

Income tax (benefit) expense

NET INCOME

Currency translation adjustments

NET COMPREHENSIVE INCOME

Net income per share, basic
Net income per share, diluted

Weighted average number of shares outstanding, basic
Weighted average number of shares outstanding, diluted

Year ended December 31,
2017
2018

$ 19,702,643 $ 19,325,528
6,431,563
25,757,091

9,981,562
29,684,205

6,665,856
1,279,821
7,181,753

5,723,298
896,089
11,071,759

330,232
4,605,506
20,063,168
9,621,037

229,223
4,189,065
22,109,434
3,647,657

12,087
(140,615)
(1,938,465)
(149,559)
(2,216,552)

26,520
(955,698)
2,623,687
27,313
1,721,822

7,404,485
742,425
6,662,060 $
(115,306)
6,546,754 $

5,369,479
(2,066,426)
7,435,905
566,381
8,002,286

0.24 $
0.24 $

27,462,788
27,474,125

0.28
0.28
26,119,927
26,133,295

$
$

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

EPSILON ENERGY LTD.

Consolidated Statements of Changes in Shareholders’ Equity

Balance at December 31, 2016

Net income
Rights offering shares issued
Rights offering issue costs
Stock-based compensation expenses
Stock options exercised
Conversion of debentures to common
shares
Other comprehensive income
Balance at December 31, 2017

Net income
Stock-based compensation expenses
Buyback and retirement of common
shares
Buyback of common shares not yet
retired
Other comprehensive loss

Balance at December 31, 2018

Share
Capital

Additional
paid-in Capital

Accumulated
Other
Comprehensive
Income (Loss)
$ 126,303,679 $ 5,972,563 $ 9,346,855 $ (104,081,859) $ 37,541,238
7,435,905
17,984,664
(77,478)
229,223
50,243

—
17,984,664
(77,478)
—
80,759

7,435,905
—
—
—
—

—
—
—
229,223
(30,516)

Total
Shareholders'
Equity

—
—
—
—
—

Deficit

614
—
144,292,238
—
—

255
—
6,171,525
—
330,232

—
566,381
9,913,236
—
—

—
—
(96,645,954)
6,662,060
—

869
566,381
63,731,045
6,662,060
330,232

(586,797)

17,271

—

(569,526)

(94,418)
—

(94,418)
(115,306)
$ 143,611,023 $ 6,519,028 $ 9,797,930 $ (89,983,894) $ 69,944,087

—
(115,306)

—
—

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

EPSILON ENERGY LTD.

Consolidated Statements of Cash Flows

Cash flows from operating activities:

Net income
Adjustments to reconcile net income to net cash provided by operating activities:

6,662,060 $

7,435,905

Year ended December 31,
2017
2018

Depletion, depreciation, amortization, and accretion
Debenture fee amortization
(Gain) loss on derivatives
Cash received (paid) from settlements of derivatives
Stock-based compensation expense
Deferred income tax benefit

Changes in current assets and liabilities:

Accounts receivable
Prepaid income taxes and other current assets
Accounts payable and accrued liabilities
Other long-term liabilities

Net cash provided by operating activities
Cash flows from investing activities:

Acquisition of unproved oil and gas properties
Additions to unproved oil and gas properties
Acquisition of proved oil and gas properties
Refunds of cash calls, net of additions to proved oil and gas properties
Additions to gathering system properties
Changes in restricted cash

Net cash used in investing activities
Cash flows from financing activities:

Buyback of common shares
Common stock issued through rights offering (net of issuance costs)
Redemption of convertible debentures
Exercise of stock options
Repayment of revolving line of credit
Net cash used in financing activities

Effect of currency rates on cash and cash equivalents
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of year

Cash and cash equivalents, end of year

Supplemental cash flow disclosures:

Income taxes paid
Interest paid

Non-cash investing activities:

7,181,753
—
1,938,465
(1,381,898)
330,232
(572,405)
—
(1,707,239)
(173,513)
(545,286)
(1,615,313)
10,116,856

11,071,759
52,924
(2,623,687)
2,027,791
229,223
(2,530,136)
—
1,052,593
(136,440)
1,503,231
(529,684)
17,553,479

(260,000)
(1,787,114)
(4,992)
166,661
(148,360)
(1,397)
(2,035,202)

(17,451,552)
—
(1,643,735)
(34,457)
(200,689)
(26,328)
(19,356,761)

(663,944)
—
—
—
(2,900,000)
(3,563,944)
(115,306)
4,402,404
9,998,853

—
17,907,186
(29,464,190)
50,243
(9,560,000)
(21,066,761)
1,382,303
(21,487,740)
31,486,593
9,998,853

$ 14,401,257 $

$
$

4,130,493 $
136,833 $

—
1,477,899

Change in proved properties accrued in accounts payable and accrued liabilities
Change in gathering system accrued in accounts payable and accrued liabilities
Conversion of debentures to shares (Cdn$1,000)

Asset retirement obligation asset additions and adjustments

$
$

(587,472) $
(48,961) $
—

(135,900) $

—
(55,950)
869
74,755

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

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

1. Description of Business

Epsilon Energy Ltd. (the “Corporation” or “Epsilon”) was incorporated under the laws of the Province of Alberta,
Canada on March 14, 2005. On October 24, 2007, the Corporation became a publicly traded entity trading on the TSX in
Canada. On February 14, 2019 we began trading in the United States on the Nasdaq Global Market under the trading
symbol “EPSN.” The Corporation is engaged in the acquisition, development, gathering and production of primarily
natural gas reserves in the United States.

The address of its registered office is 14505 Bannister Road SE, Suite 300, Calgary, AB, Canada T2X 3J3.

2. Basis of Preparation

The accounts are maintained and the consolidated financial statements have been prepared using the accrual basis
of accounting in accordance with accounting principles generally accepted in the United States of America
(“U.S. GAAP”). All amounts presented are in US$ unless otherwise indicated.

Principles of Consolidation

The Corporation’s consolidated financial statements include the accounts of the Corporation and its wholly

owned subsidiary, Epsilon Energy USA, Inc. and its wholly owned subsidiaries, Epsilon Midstream, LLC, Dewey
Energy GP, LLC, and Dewey Energy 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 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 include 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 for potential well liabilities.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are primarily from purchasers of oil and natural gas, counterparties to our financial
instruments, and revenues earned for compression and gathering services. Both oil and natural gas 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 review all outstanding accounts receivable balances and record a reserve for
amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially
all collection efforts have been exhausted. Our allowance for doubtful accounts was nil as of December 31, 2018 and 2017.
There was no bad debt expense recognized for the years ended December 31, 2018 and 2017.

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

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 4).

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 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 unamortized
capitalized cost 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 unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using
the Income Approach described in the Fair Value Measurement Topic of the ASC, which considers estimated discounted
future cash flows.

Gas Gathering System Properties

Epsilon accounts for its gas gathering system asset using the proportionate consolidation method of accounting.

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

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

Revenue Recognition

Revenue associated with the sale of crude oil and natural gas owned by the Corporation is recognized when title

is transferred from the Corporation to its customers. Revenue is measured at the fair value of the consideration received

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

or receivable. Revenue from the sale of crude oil and natural gas is recognized when all of the following conditions have
been satisfied:

• The Corporation has transferred the significant risks and rewards of ownership of the goods to the buyer;

• The Corporation retains no continuing managerial involvement to the degree usually associated with

ownership or effective control over the goods sold;

• The amount of revenue can be measured reliably;

•

It is probable that the economic benefits associated with the transaction will flow to the Corporation; and

• The costs incurred or to be incurred in respect of the transaction can be measured reliably.

Revenue associated with the sale of crude oil and natural gas is presented net of royalties paid and accrued.

Gathering system revenues consist of fees recognized for the gathering, treating, compression, and processing of
natural gas. Revenues are recognized when the service is performed and is based upon non - regulated rates and the related
gathering, treating, compression, and processing volumes.

Other Property and Equipment

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, commodity derivative contracts, accounts

receivable, accounts payable, accrued liabilities, convertible debentures, and long - term debt.

Our financial instruments that are accounted for at fair value measurement consist of commodity derivatives.

The Corporation 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 Corporation makes its own assumptions about how market participants would price
the assets and liabilities.

Cash, cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities are carried
at cost, which approximates their fair value because of the short - term maturity of these instruments. The Corporation’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. Convertible debentures are carried at amortized cost.

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

Commodity derivative instruments consist of fixed - price swaps, costless collars, and basis swap contracts for
natural gas. The Corporation’s derivative contracts are valued based on an income approach. The model considers various
assumptions, such as quoted forward prices for commodities, time value and volatility factors. 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 Corporation utilizes its counterparties’ valuations to assess the reasonableness of its own
valuations.

Derivative Instruments

The Corporation enters into derivative contracts to hedge price risk associated with a portion of natural gas
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.

• Collars—where we pay the counterparty if the market price is above the ceiling price (short call) and the

counterparty pays us if the market price is below the floor (long put) on a notional quantity.

• 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.

Derivative assets and liabilities are initially measured at fair value and then re - valued at each reporting period.
Using this method, 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 in gain (loss) on commodity contracts in the consolidated statements of operations and comprehensive income.

Asset Retirement Obligations

The Corporation 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 obligation relates to the plugging
and abandonment of oil and natural gas wells and decommissioning of the gas gathering system. Management periodically
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 obligation with
an offsetting change to property and equipment. An ongoing accretion expense is recognized for changes in the value of
the liability as a result of 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 Corporation to concentrations of credit risk consist principally
of cash and cash equivalents, accounts receivable and derivative contracts. Exposure is controlled to credit risk associated
with these instruments 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 Corporation does not have collateral requirements and (iii) netting derivative assets and

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

liabilities for counterparties with a legal right of offset. At December 31, 2018 and 2017, the cash and cash equivalents
were primarily concentrated in two financial institutions, one in Canada and one in the US. The Corporation periodically
assesses the financial condition of these institutions and believe that any possible credit risk is minimal.

Income Taxes

Income taxes are accounted for using the asset and liability approach. Under this approach, 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 9).

Foreign Currency Transactions

The United States dollar is the functional 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 Corporation mainly estimates the fair value of all stock options awarded to employees and directors using
the Black - Scholes option pricing model. Other models are used for options with more complex vesting criteria.
Compensation expense and a corresponding increase to additional paid - in capital are recorded over the vesting period
based on the fair value of the options granted using a graded vesting approach. When stock options are exercised for
common shares, consideration paid by the stock option holders and additional paid - in capital associated with the stock
options are recorded as share capital. If stock is repurchased, the excess of the consideration paid over the carrying amount
of the stock cancelled is charged to retained earnings/deficit. The Corporation estimates a forfeiture rate and adjusts the
corresponding expense each period based on an updated forfeiture estimate (see Note 7).

Leases

Agreements under which the Corporation makes payments to owners in return for the right to use an asset for a
period are accounted for as leases. Leases that transfer substantially all the risks and rewards of ownership are recorded at
inception as finance leases within property and equipment and debt. Assets acquired under capital leases are amortized
over the estimated useful lives of the underlying assets. All other leases are accounted for as operating leases and the
related lease payments are charged to expense as incurred.

Joint Interests

The majority of the Corporation’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
Corporation’s proportionate interest in such jointly controlled assets.

Recently Issued Accounting Standards

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

Statements, which the Board finalized on August 28, 2018. The Board used the guidance in the Concepts Statement to
improve the effectiveness of ASC 820’s disclosure requirements. ASU 2018-13 is effective for all entities for fiscal years
beginning after December 15, 2019, including interim periods therein. Early adoption is permitted for any eliminated or
modified disclosures upon issuance of this ASU. We have examined the provisions and do not anticipate any of them to
materially affect our financial statements.

In February 2016, the FASB issued ASU 2016 02, “Leases (Topic 842)” (ASU 2016 02), which significantly
changes accounting for leases by requiring that lessees recognize a right of use asset and a related lease liability
representing the obligation to make lease payments, for all lease transactions with terms greater than one year. Additional
disclosures about an entity’s lease transactions will also be required. ASU 2016 02 defines a lease as “a contract, or part
of a contract, that conveys the right to control the use of identified property, plant, or equipment (an identified asset) for a
period of time in exchange for consideration.” ASU 2016 02 is effective for fiscal years beginning after December 15,
2019, and interim periods within fiscal years beginning after December 15, 2020. Lessees and lessors are required to
recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified
retrospective approach. Epsilon is reviewing the provisions of ASU 2016 02 to determine the impact on its consolidated
financial statements and related disclosures. We do not anticipate this to materially affect our financial statements. In
July 2018, the FASB issued ASU 2018-11, ‘‘to provide entities with relief from the costs of implementing certain aspects
of the new leasing standard, ASU 2016-02. Under ASU 2018-11, adopters will take a prospective approach, rather than a
retrospective approach as initially prescribed, when transitioning to ASU 2016-02. Instead of recording the cumulative
impact of all comparative reporting periods presented within retained earnings, we will now assess the facts and
circumstances of all leasing contracts as of January 1, 2020. ASU 2018-11 does not change the effective dates for ASU
2016-02. We still do not anticipate this to materially affect our financial statements.

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

4. Property and Equipment

The following table summarizes the Corporation’s property and equipment at December 31, 2018 and 2017:

Property and equipment:

Oil and gas properties, successful efforts method

Proved properties
Unproved properties

Accumulated depletion, depreciation, and amortization

Total oil and gas properties, net

Gathering system

Accumulated depletion, depreciation, and amortization

Total gathering system, net
Other property and equipment, net

Total property and equipment, net

December 31,

2018

2017

$ 118,851,574 $ 118,524,693
17,451,552
(78,625,589)
57,350,656
40,880,503
(26,252,385)
14,628,118
299
$ 67,446,113 $ 71,979,073

19,498,666
(83,807,401)
54,542,839
41,040,847
(28,137,573)
12,903,274
—

Property Acquisitions

During the second quarter of 2017, the Corporation began acquiring leasehold properties in the Anadarko Basin
in Oklahoma. Through December 31, 2017, Epsilon acquired varying working interests in certain acreage, all held by
production from shallower intervals, in the NW STACK trend, with rights to the prospective and deeper Meramec, Osage
and Woodford formations. The Corporation accounted for these transactions as asset acquisitions.

During the year ended December 31, 2018 the Corporation acquired additional acreage in the Anadarko Basin
for $260,000. Included in additions to proved oil and gas properties was a $0.5 million cash call refund for wells previously
drilled.

Property Impairment

At December 31, 2018 and 2017, the Corporation evaluated its proved and unproved oil and gas properties, and
its gathering system assets for indicators of any potential impairment. As a result of these assessments, no impairment was
required for the years ended December 31, 2018 and 2017.

5. Convertible Debentures

On February 28, 2012, we completed a public offering of Cdn$40 million aggregate principal amount of
convertible, unsecured subordinated debentures, or the Convertible Debentures, at a price of Cdn$1,000 per Debenture.
The Convertible Debentures bore interest at the rate of 7.75% per annum, payable commencing September 30, 2012 and
semi - annually thereafter and matured March 31, 2017, or the Maturity Date. The Convertible Debentures were convertible
into common shares at the holder’s option at any time prior to the Maturity Date at a conversion price equal to
Cdn$4.45 per common share. Upon redemption or maturity, we had the option to repay the outstanding principal of the
Convertible Debentures through the issuance of common shares. We repaid the outstanding principal and accrued interest
in February 2017 for Cdn$ 39,951,435. This amount includes the original Cdn$40 million debentures, less Cdn$36,000 in
conversions, less Cdn$1.5 million repurchased by Epsilon for a payoff of Cdn$38,464,000 (US$ 29,464,190) of principal
and Cdn$1,487,435 (US$1,139,405) of interest.

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

The following table sets forth a reconciliation of the convertible debentures for the year ended December 31,

2017:

Balance
US$

Balance
Cdn$

Balance at January 1, 2017

Conversion of Convertible Debenture
Amortization of fees
Translation adjustment at February 16, 2017
Redemption of Convertible Debenture

Balance at December 31, 2017

There were no convertible debentures outstanding at December 31, 2018.

6. Revolving Line of Credit

$ 28,596,213 $ 38,394,491
(1,000)
70,509
—
(38,464,000)
—

(869)
52,924
815,922
(29,464,190)

— $

Effective July 30, 2013, Epsilon Energy USA Inc., a wholly owned subsidiary of the Corporation, executed a
three year senior secured revolving credit facility with a bank (“Credit Facility”). The terms of this agreement include a
total commitment of up to $100 million with an initial borrowing base of $20 million available as long as the Corporation
is in compliance with the loan covenants. The borrowing base under the revolving Credit Facility can be redetermined up
or down by the lenders based on, among other things, their evaluation of the Corporation’s natural gas reserves. Effective
February 9, 2016, the borrowing base was increased to $30 million. Upon each advance, interest is charged at the rate of
LIBOR plus an “applicable margin”. The applicable margin ranges from 2.75 - 3.75% and is based on the percent of the
line of credit utilized.

An amendment to the credit agreement governing the Credit Facility was executed December 10, 2016. The
amendment revised the maturity date of the agreement to March 1, 2017. Also included in the amendment was a decrease
in the Corporation’s borrowing base from $30 million to $19.6 million, along with a monthly reduction to the borrowing
base amount of $400,000 commencing January 1, 2017.

A second amendment to the credit agreement was executed October 11, 2016. This amended the “Borrowing
Base” and “Mortgaged Properties” to include the Corporation’s gathering system assets in addition to the already included
oil and gas properties. Also included in the amendment was a decrease in the borrowing base to $13.4 million and a
decrease in the monthly reduction to the borrowing base amount to $200,000. This was to remain in effect until the next
redetermination of the borrowing base and monthly reduction amount.

A third amendment to the credit agreement was executed February 21, 2017 in order to extend the maturity date
of the agreement to March 1, 2019. Also included in the amendment was an increase in the Corporation’s borrowing base,
to $15 million and an increase in the monthly reduction to the borrowing base amount to $230,000. Further stipulated is
the condition that the Corporation will maintain acceptable commodity hedging agreements covering at least 75% of
projected production of natural gas for April through December of 2017 and 60% of projected production of natural gas
for the first six months of 2018.

A fourth amendment to the credit agreement was executed August 4, 2017. This amendment revised the
“Required Reserve Value” to be the lesser of 90% of the recognized value of all proved oil and gas properties or 150% of
the borrowing base instead of the lesser of 80% of the recognized value of all proved oil and gas properties or 150% of the
borrowing base. Also, effective July 1, 2017, the borrowing base was returned to a $15 million balance and the monthly
borrowing base reduction amount was decreased to $0. Additionally, the Corporation is required to maintain acceptable
commodity hedging agreements covering at least 50% of projected production for the calendar year, 2018 and all deposit
accounts must be at Texas Capital Bank after December 31, 2017.

A fifth amendment to the credit agreement was executed January 7, 2019 in order to extend the maturity date of
the agreement to March 1, 2022. Also included in the amendment was an increase in the Corporation’s borrowing base, to
$23 million. Additionally, the Corporation is required to maintain acceptable commodity hedging agreements covering at

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

least 25% of projected production of natural gas for the succeeding calendar year, along with the 50% for the current
calendar year already required.

•

Interest coverage ratio greater than 3 based on income adjusted for interest, taxes and non - cash amounts.

• Current ratio, adjusted for line of credit amounts used and available and non - cash amounts, greater than 1.

• Leverage ratio less than 3.5 based on income adjusted for interest, taxes and non - cash amounts.

The Corporation was in compliance with the financial covenants of the Credit Facility as of December 31, 2018

and 2017 and we expect to be in compliance with the financial covenants for the next 12 months.

Balance at
December 31, December 31,

Balance at

2018

2017

Current
Borrowing Base

Interest Rate
3 mo.
LIBOR + 2.75% (1)

Revolving line of credit

— $ 2,900,000 $ 23,000,000

(1) At December 31, 2018, the interest rate was 5.2%.

7. Shareholders’ Equity

(a) Authorized shares

The Corporation 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) Issued

The following table summarizes the components of share capital for the years ended December 31, 2018 and

2017.

Balance at January 1, 2017

Conversion of debenture to shares
Exercise of stock options
Shares issued through rights offering (net of issuance costs
of $77,478)

Balance at December 31, 2017
Buyback of Shares (net of 26,953 shares of stock not yet
retired)
Balance at December 31, 2018

Number of shares
issued

Amount

22,918,932 $ 126,303,679
614
80,759

112
20,000

4,583,808

17,907,186
27,522,852 $ 144,292,238

(137,719)

(586,797)
27,385,133 $ 143,705,441

Through a normal - course issuer bid (“NCIB”) program, the Corporation repurchased 164,672 common shares
throughout the year ended December 31, 2018. The repurchased stock had an average price of Cdn$5.26 per share. The
average share price on the TSX during the year ended December 31, 2018 was Cdn$5.31 (for the year ended December 31,
2017, Cdn$6.24).

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

The Corporation maintains a stock option plan for directors, officers, employees and consultants of the
Corporation and its subsidiaries. Epsilon shareholders approved the “2007 Stock Option Plan” at a shareholders’ meeting
held on July 16, 2007 prior to Epsilon becoming a reporting issuer and listing on the TSX. At the 2010 Annual General
Meeting in May 2010 (2010 Annual Meeting), an amendment to the 2007 Stock Option Plan was presented and the plan
became the “Amended and Restated 2010 Stock Option Plan.” The Board approved the amendments to the Plan to allow
the period for exercise of options in the case of resignation or termination of an optionee to be increased from 10 days
following resignation or termination to 30 days following resignation or termination, and in case of retirement, from
30 days to 60 days following retirement. On July 9, 2012, the plan was revised by the Board to add a cashless exercise of
vested options. This allowed the optionee to effectively exercise and sell the options for the difference between the market
value of the stock and the strike price of the options. At the 2017 Annual General Meeting in April 2017, Epsilon’s
shareholders approved the Amended and Restated 2017 Stock Option Plan. The Amended and Restated Plan, (i) reduced
the maximum number of Common Shares available under the Plan from a limit of 10% of the total issued and outstanding
Common Shares to a fixed maximum of 1,000,000 Common Shares, and (ii) deleted some redundant definitions and
clarified existing wording in the Plan.

Through December 31, 2018, the Corporation had issued stock options covering 290,750 Common Shares at an
overall average price of Cdn$6.70 per Common Share to directors, officers, employees and consultants of the Corporation
and its subsidiaries. A maximum amount of 709,250 Common Shares are available for future option issuances.

The following table summarizes stock option activity for the years ended December 31, 2018 and 2017:

Year ended
December 31, 2018

Year ended
December 31, 2017

Exercise price in Cdn$
Balance at beginning of period

Granted
Exercised
Expired

Balance at period-end

Number of

Options
Outstanding

Weighted
Average
Exercise
Price

Number of
Options
Outstanding

Weighted
Average
Exercise
Price

330,750 $
— $
— $
(40,000) $
290,750 $

6.86
—
—
8.00
6.70

255,500 $
120,750 $
(20,000) $
(25,500) $
330,750 $

6.66
6.70
3.26
7.06
6.86

Exercisable at period-end

210,249 $

6.70

161,666 $

6.82

At December 31, 2018, the Corporation had unrecognized stock based compensation of $27,877 to be recognized
over a weighted average period of 1.1 years (for the year ended December 31, 2017: $117,520 over 1.2 years). The
aggregate intrinsic value at December 31, 2018 was $58,664 (at December 31, 2017: $79,500).

The average share price during the year ended December 31, 2018 was Cdn$5.31 (for the year ended
December 31, 2017: Cdn$6.24). The average exchange rate for the year ended December 31, 2018 was Cdn$0.77 to US$1
(for the year ended December 31, 2017, Cdn$0.78).

During the year ended December 31, 2018, the Corporation awarded no stock options (During the year ended

December 31, 2017: 120,750 stock options).

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

The following table summarizes information for stock options outstanding at December 31, 2018 (exercise price

in Cdn$):

Exercise Price
As at December 31, 2018:

$2.90
$6.70
$6.80
$7.34

Total

Number of Number of

Options

Option
Pricing
Model

Weighted
Average
Remaining

Contractual Life

Outstanding Exercisable Valuations

(in years)

25,000 $ 28,647
25,000
73,789
14,167
42,500
138,114
78,250
26,082
145,000 145,000
547,608
290,750 210,249 $ 788,158

0.61
5.02
5.07
3.43
3.86

Of the options awarded during 2017, 42,500 have an exercise price of Cdn$6.70 and 78,250 have an exercise
price of Cdn$6.80. One - third of the options vest each year on the anniversary of the grant date. For 42,500 of the options
granted, the weighted average fair value was $2.30 per option calculated using a risk - free rate of 1.89%, dividend yield of
0%, historical volatility factor of 39.06%, forfeiture rate of 51.69% and expected life of 5 years. For 78,250 of the options
granted, the weighted average fair value was $2.38 per option calculated using a risk - free rate of 1.95%, dividend yield of
0%, historical volatility factor of 38.76%, forfeiture rate of 51.78% and expected life of 5 years. The value of the options
was recorded as stock based compensation expense, with an offsetting amount to additional paid - in capital based on the
vesting terms.

(d) Share Compensation Plan

A Share Compensation Plan (the “Plan”) was adopted by the Board on April 13, 2017 and approved by the
shareholders at the Annual General Meeting in April, 2017. The Plan provides that designated participants may, on the
day or days of each fiscal year (the “Current Year”) as determined by the Board, be issued Common Shares in an amount
up to 100% of the participant’s compensation paid by the Corporation in consideration of the participant’s service for the
Current Year divided by the market price (as defined in the TSX Company Manual) of the Common Shares on the TSX at
the date of issuance of the Common Shares in the Current Year.

In December 2018, 174,500 common shares of Restricted Stock were awarded to the Corporation’s officers,
employees, and board of directors. These shares vest over a three year period, with one-third of the 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. In October 2017 125,000 common shares of Restricted Stock were awarded to the Corporation’s
Chief Executive Officer. In December 2017 an additional 37,500 shares were awarded to the Corporation’s board of
directors. The awards vest over a three year period, with one-third of the 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
Corporation determined the fair value of the granted Restricted Stock based on the market price of the common shares of
the Corporation on the date of grant. Stock compensation expense for the granted Restricted Stock is recognized over the
vesting period. Stock compensation expense recognized during the years ended December 31, 2018 and 2017 was
$246,904 and 43,056, respectively.

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

The following table summarizes Restricted Stock activity for the years ended December 31, 2018 and 2017:

Year ended
December 31, 2018

Year ended
December 31, 2017

Balance non-vested Restricted Stock at beginning of period

Granted
Vested

Balance non-vested Restricted Stock at end of period

8. Accumulated Other Comprehensive Income

Number of
Shares
Outstanding
162,500
174,500
(54,167)
282,833

Weighted
Average

Remaining Life
(years)

Weighted
Average

Number of
Shares
Outstanding

Remaining Life
(years)

1.87
2.00
—
2.56

—
162,500
—
162,500

—
2.00
—
1.87

Accumulated other comprehensive income (loss) includes certain transactions that have generally been reported
in the consolidated statements of changes in shareholders’ equity. The activity in of Accumulated Other Comprehensive
Income during the years ended December 31, 2018 and 2017 consisted of the following:

Balance at beginning of period

Translation loss convertible debentures
Translation gain other

Year Ended December 31,

2018

2017

$ 9,913,236 $ 9,346,855
(815,922)
—
(115,306) 1,382,303
$ 9,797,930 $ 9,913,236

9. Income Taxes

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

Foreign
U.S.

Year ended December 31,
2018

2017

(665,924) $ (1,488,296)
6,857,775
8,070,409
$ 7,404,485 $ 5,369,479

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

On December 22, 2017, the United States enacted tax reform legislation known as the H.R.1, commonly referred
to as the “Tax Cuts and Jobs Act” (the “Act”), resulting in significant modifications to existing law. The Corporation
incorporated the accounting for the effects of the Act during 2017. As such, our financial statements for the year ended
December 31, 2017 reflect certain effects of the Act which includes a reduction in the corporate tax rate from 34% to 21%
effective January 1, 2018. Due to the changes to corporate tax rates under the Act, the Corporation recorded a $4.6 million
tax benefit for the remeasurement of its deferred tax assets and liabilities during the year ended December 31, 2017.

The Corporation followed the guidance in SEC Staff Accounting Bulletin 118 (“SAB 118”), which provided
additional clarification regarding the application of ASC Topic 740 in situations where the Corporation does not have the
necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the
accounting for certain income tax effects of the Act for the reporting period in which the Act was enacted. SAB 118
provided for a measurement period beginning in the reporting period that included the Act’s enactment date and ending
when the Corporation has obtained, prepared, and analyzed the information needed in order to complete the accounting
requirements but in no circumstances should the measurement period extend beyond one year from the enactment date.
The Corporation booked no provisional amounts as of December 31, 2017 with respect to the Act and no further
adjustments were required during 2018. The SAB 118 period expired and our accounting is complete. We have calculated

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

the impact of the Act in our income tax provision in accordance with our understanding of the Act and guidance available
as of the date of this filing. As a result of the Tax Act, further clarifications and new regulations to the Tax Act continue
to be issued at times. The Corporation will continue to monitor these new regulations and analyze their applicability and
impact on the Corporation.

We believe that we have appropriate support for the income tax positions taken and to be taken on the
Corporation’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
Corporation’s tax returns are open to audit under the statute of limitations for the years ending December 31, 2015 through
December 31, 2018.

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

indicated:

Current:
Federal
State

Total current income tax expense

Deferred:
Federal
State

Total deferred tax (benefit)

Income tax provision

Year ended December 31,

2018

2017

$ 1,742,898 $
(428,068)
1,314,830

304,070
159,640
463,710

(392,574)
(179,831)
(572,405)

(2,539,621)
9,485
(2,530,136)
$ 742,425 $ (2,066,426)

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 2018 differs from the statutory rate due to
the reduction in our uncertain tax position. For 2017 our effective tax rate differs from the statutory rate due to state taxes
and the valuation allowance on the Canadian loss, but primarily due to the revaluation of the Corporation’s deferred tax
balances for the federal tax rate reduction of 34% to 21% under the Act.

Year Ended
December 31,
2018

Effective
Tax Rate

Year Ended
December 31,
2017

Effective
Tax Rate

Income tax provision computed at the statutory federal

tax rate

Difference in Canadian and U.S. tax rate
Valuation allowance on Canadian loss
Return to provision adjustment
Change in US federal rate—tax reform
State taxes
Miscellaneous other items
Change in uncertain tax position
Income tax expense (benefit)

1,554,942
(30,633)
170,477
(179,120)
—
349,643
28,860

21.00 % $
(0.41)%
2.30 %
(2.42)%
— %
4.72 %
0.39 %
(1,151,744) (15.55)%
10.03 % $

742,425

1,825,623
111,622
394,398
(13,576)

34.00 %
2.08 %
7.35 %
(0.25) %
(4,625,262) (86.14) %
8.42 %
1.40 %
(5.34) %
(2,066,426) (38.48) %

452,040
75,312
(286,583)

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.

As of December 31, 2018, we have no U.S. federal net operating loss carry-forwards and approximately $6.4
million of state net operating loss carry-forwards, which begin to expire after 2025. These loss carryforwards may reduce
future taxable income, however, the extent of which may be limited due to any IRC Section 382 limitation.

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

Net deferred tax liabilities consisted of the following at December 31, 2018 and 2017:

As at December 31,

2018

2017

Deferred tax assets:

State net operating loss carryforwards
Canadian net operating loss carryforwards
Other

Gross deferred tax assets
Valuation allowance
Total deferred tax assets
Deferred tax liabilities:
Oil and gas property
Partnership

Total deferred tax liabilities

Net deferred tax liability

465,496 $

12,113,684
91,646
12,670,826
(12,113,684)
557,142

684,097
11,943,207
120,654
12,747,958
(11,943,207)
804,751

(7,407,828)
(3,138,592)
(10,546,420)

(8,182,788)
(3,183,646)
(11,366,434)
$ (9,989,278) $ (10,561,683)

We have recorded a valuation allowance against the Canadian net operating losses as we do not feel that it is

more likely than not that they will be utilized.

We are subject to taxation in the United States and various state jurisdictions, including Pennsylvania. The
Corporation determined that it has uncertain tax positions relating to certain U.S. Federal and Pennsylvania income tax
filings as summarized in the table below. As of December 31, 2018 and 2017, the gross liability for income taxes
associated with uncertain tax positions was $0 and $1,199,553, respectively. The Corporation 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 and $415,760 as of December 31, 2018 and 2017, respectively.
As of December 31, 2018, tax years ending December 31, 2015, 2016 and 2017 are subject to examination by the tax
authorities.

Changes in the balance of unrecognized tax benefits on uncertain positions were as follows for each of the

two years ended December 31, 2018:

Uncertain Tax Position:
Balance at December 31, 2016
Lapse of statute of limitations
Balance at December 31, 2017
Lapse of statute of limitations
Balance at December 31, 2018

10. Commitments and Contingencies

$ 1,878,397
(678,844)
1,199,553
(1,199,553)
—

The Corporation’s future minimum lease commitments as of December 31, 2018 are summarized in the following

table:

Year ended
December 31,
2019
2020

Payments

80,577
6,729
87,306

The Corporation enters into commitments for capital expenditures in advance of the expenditures being made.

As of December 31, 2018, we had commitments of $2.3 million for capital expenditures.

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

Litigation

The Corporation is not currently involved in any litigation. Management is of the opinion that the potential for
litigation is remote, without merit and would not have a material adverse impact on the Corporation’s financial position or
results of operations.

11. 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:

Net income available to shareholders

Year ended December 31,

2018

2017

$ 6,662,060 $ 7,435,905

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

Basic weighted-average number of shares outstanding
Dilutive stock options
Diluted weighted average shares outstanding

Year ended December 31,

2018
27,462,788
11,337

2017
26,119,927
13,368
27,474,125 26,133,295

We excluded the following shares from the diluted EPS because their inclusion would have been anti - dilutive.

Anti dilutive options
Unvested shares of restricted stock

Total Anti-dilutive shares

12. Operating Segments

Year ended
December 31,

2018
279,413
282,833
562,246

2017
317,382
108,333
425,715

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating
decision - maker. The chief operating decision - maker, who is responsible for allocating resources and assessing
performance of the operating segments, has been identified as executive management. Segment performance is evaluated
based on operating profit or loss as shown in the table below. Interest expense, interest income and income taxes are
managed separately on a group basis.

The Corporation’s reportable segments are as follows:

a. The Upstream segment activities include acquisition, development and production of primarily natural gas

reserves on properties within the United States;

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

and

c. The Canada segment activities include corporate listing and governance functions of the Corporation.

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

Upstream

Gas Gathering

Canada

Corporate

Elimination

Consolidated

19,031,422
295,142
376,079
—

19,702,643 (1) $

— $
—
—
11,087,507
11,087,507 $

7,742,587 $
6,665,856

6,814,188 $
2,385,766

5,294,200

1,887,553

—

71,350,546 $
2,472,917
35,044,173
19,498,666
—
—

15,440,047 $
197,321
—
—
12,903,274
—

1,107,116 $

—
—
—
—
—

— $

— $
—

19,031,422
295,142
376,079
9,981,562
29,684,205

—

(1,105,945)
(1,105,945)

(7,894,715)(3)

—

—
—
—
—
—
—

— $

(1,105,945)

6,662,060
7,945,677

—

7,181,753

— $
—
—
—
—
—

87,897,709
2,670,238
35,044,173
19,498,666
12,903,274
—

Segment assets

As at and for the year ended
December 31, 2018

Operating revenue

Natural gas
Natural gas liquids
Oil and condensate
Gathering and compression fees
Total operating revenue

Net earnings for the period

Operating costs
Depletion, deprec., amortization and
accretion

Capital expenditures(2)
Proved properties
Unproved properties
Gathering system
Other property and equipment

As at and for the year ended
December 31, 2017

Operating revenue

Natural gas
Natural gas liquids
Oil and condensate
Gathering and compression fees
Total operating revenue

Net earnings for the period

Operating costs
Depletion, deprec., amortization and
accretion

19,203,543
24,018
97,967
—

19,325,528 (1) $

— $
—
—
7,614,075
7,614,075 $

5,544,931 $
5,723,298

2,521,014 $
2,078,601

— $

— $
—

Segment assets

Capital expenditures(2)
Proved properties
Unproved properties
Gathering system
Other property and equipment

8,057,299

3,014,460

—

65,704,141 $
19,129,745
39,899,104
17,451,552
—
299

18,222,609 $
200,689
—
—
14,628,118
—

2,478,910 $

—
—
—
—
—

19,203,543
24,018
97,967
6,431,563
25,757,091

(1,182,512)
(1,182,512)

— $

(1,182,512)

8,065,946
6,619,387

—

11,071,759

— $
—
—
—
—
—

86,405,660
19,330,434
39,899,104
17,451,552
14,628,118
299

—

— (3) $
—

—

—
—
—
—
—
—

(1) Segment operating revenue represents revenues generated from the operations of the segment. Inter - segment sales
during the years ended December 31, 2018 and 2017 have been eliminated upon consolidation. For the year ended
December 31, 2018, Epsilon sold natural gas to 28 unique customers. The two customers over 10% comprised 46%
and 21% of total revenue. For the year ended December 31, 2017, Epsilon sold natural gas to 26 unique customers.
The two customers over 10% comprised 51% and 19% of total revenue.

(2) Capital expenditures for Upstream consist primarily of the drilling and completing of wells while Gas Gathering

consists of expenditures relating to the expansion and completion of the compression facility.

(3) Segment reporting for net earnings for the period does not include non - monetary compensation, general and
administrative expense, interest income, interest expense or income tax amounts as they are managed on a group basis
and are instead included in the corporate column for reconciliation purposes. Additionally, gains & (losses) from
commodity hedging contracts are also included in the corporate column for reconciliation purposes.

13. 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.

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

Inherent in the Corporation’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 Corporation’s counterparty to a
contract. The Corporation does not currently require collateral from any of its counterparties nor does its counterparties
require collateral from the Corporation.

The Corporation enters into certain commodity derivative instruments to mitigate commodity price risk associated
with a portion of its future natural gas production and related cash flows. The natural gas 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 Corporation’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 gain (loss) 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 2018, Epsilon recognized losses on financial commodity derivative contracts of $1,938,465. This amount included
cash paid on settlements of these contracts of $1,381,898. For 2017, Epsilon recognized gains of $2,623,687, which
included cash received on settlements of natural gas derivative contracts of $2,027,791.

Commodity Derivative Contracts

Epsilon’s outstanding natural gas price swap contracts as of December 31, 2018 consisted of:

Weighted Average Price ($/MMbtu)

Fair Value

Derivative Type

Volume
(Mmbtu)

Swaps

Basis
Differential

December 31,

2018

2019

Fixed price swap
Basis swap

3,635,000 $
3,635,000 $

2.78 $
— $

—

(35,660)
(0.54) (261,363)
$ (297,023)

As of December 31, 2018 and 2017, all of the Corporation’s economic derivative hedge positions were with large
financial institutions, which are not known to the Corporation to be in default on their derivative positions. The Corporation
is exposed to credit risk to the extent of non - performance by the counterparties in the derivative contracts discussed above;
however, the Corporation does not anticipate non - performance by such counterparties. None of the Corporation’s
derivative instruments contains credit - risk related contingent features. Derivatives are net on the balance sheet as they are
subject to the right to offset the liabilities with the assets.

Current

Basis swap
Fixed price swap
Two-way costless collar

Fair Value of Derivative
Assets

December 31, December 31,

2018

2017

76,075 $ 203,841
22,191
125,790
45,949
—
201,865 $ 271,981

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

Current

Basis swap
Fixed price swap
Two-way costless collar

Fair Value of Derivative
Liabilities

December 31, December 31,

2018

2017

$ (337,438) $
(161,450)
—

—
—
(12,437)
$ (498,888) $ (12,437)

Net Fair Value of Derivatives

$ (297,023) $ 259,544

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

indicated:

Year ended
December 31,
2018

Year ended
December 31,
2017

Fair value of asset (liability), beginning of year

Gains (losses) on derivatives included in earnings
Settlement of commodity derivative contracts

Fair value of asset (liability), end of year

14. Asset Retirement Obligations

259,544 $ (336,352)
2,623,686
(2,027,791)
259,544

(1,938,465)
1,381,898
$ (297,023) $

Asset retirement obligations were 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. Epsilon has estimated the net present value of its total asset retirement obligations to be
$1.6 million as at December 31, 2018 ($1.6 million at December 31, 2017) based on a total net future undiscounted liability
of approximately $21.5 million ($12.0 million at December 31, 2017). Each year we review, and to the extent necessary,
revise our asset retirement obligation estimates. During 2018 and 2017, we reviewed the actual abandonment costs with
previous estimates and, as a result, estimates were updated. Our overall liability increased due to the addition of new wells
in both Pennsylvania and Oklahoma. From 2017 to 2018 our undiscounted liability increased substantially due to the
overall increased life of the field in Pennsylvania. The life of the field increased due to the increase in natural gas prices
which caused the wells to be economically profitable for a longer period of time, and the drilling of new wells which will
extend the life of the field. Even though the undiscounted liability increased, the discounted liability shown below
decreased due to the effect of the discounting over time. The liability is spread over a longer period so the current balance
has decreased.

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

Balance beginning of period
Liabilities from drilling of new wells
Change in estimates
Accretion
Balance end of period

Year ended
December 31,
2018

Year ended
December 31,
2017

$ 1,646,601 $ 1,468,635
90,827
(16,073)
103,212
$ 1,625,154 $ 1,646,601

1,590
(137,490)
114,453

Epsilon Energy Ltd.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2018 and 2017

15. Fair Value Measurements

The methodologies used to determine the fair value of our financial assets and liabilities were the same at

December 31, 2018 and 2017.

Cash, cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities are carried
at cost, which approximates their fair value because of the short-term maturity of these instruments. The Corporation’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.

Commodity derivative instruments consist of fixed-price swaps, costless collars, and basis swap contracts for
natural gas. The Corporation’s derivative contracts are valued based on an income approach. The model considers various
assumptions, such as quoted forward prices for commodities, time value and volatility factors. 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 Corporation utilizes its counterparties’ valuations to assess the reasonableness of its own
valuations.

16. Consolidation of Common Shares

EPSILON ENERGY LTD.
Supplemental Information to Consolidated Financial Statements
(Unaudited)

OIL AND GAS PRODUCING ACTIVITIES

The following disclosures are made in accordance with Financial Accounting Standards Board Accounting
Standards Update No. 2010-03 ‘‘Oil and Gas Reserve Estimates and Disclosures’’ and the United States Securities and
Exchange Commission’s (SEC) final rule on ‘‘Modernization of Oil and Gas Reporting.’’

Oil and Gas 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, 2018. 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, 2018 and 2017 and changes for each
of the two years in the period ended December 31, 2018. Net proved reserves at December 31 are estimated by the
Corporation’s independent petroleum engineers, DeGolyer and MacNaughton.

EPSILON ENERGY LTD.
Supplemental Information to Consolidated Financial Statements
(Unaudited)

NET PROVED RESERVE SUMMARY

All reserves located in United States

Net proved reserves at December 31, 2016
Revisions of previous estimates(1)(2)(5)
Improved recoveries(3)
Acquisitions(4)
Production

Net proved reserves at December 31, 2017
Revisions of previous estimates(1)(2)(5)
Improved recoveries(3)
Production

Net proved reserves at December 31, 2018

Proved developed reserves:
At December 31, 2016
At December 31, 2017
At December 31, 2018

Proved undeveloped reserves:

At December 31,2016
At December 31, 2017
At December 31, 2018

Natural
Gas

Oil

Total

(MMcf)

(MBbl)

49,397
163,261
9,756
2,184
(9,010)
215,588
(89,558)
717
(7,631)
119,116

48,463
60,571
50,698

934
155,017
68,418

(MMcfe)
49,397
163,261
9,756
2,426
(9,029)
215,812
(89,564)
717
(7,665)
119,299

—
—
—
40
(3)
37
(1)
—
(6)
31

—
37
31

—
—
—

48,463
60,795
50,881

934
155,017
68,418

(1) Revisions of previous estimates in the proved producing category are primarily attributable to an increase in the natural

gas price.

(2) Revisions of previous estimates in the proved undeveloped category is attributable to undeveloped well locations

being removed due to lease expiration and revised spacing assumptions.

(3) Reduced recoveries in the proved producing category are primarily attributable to minor revisions to the expected

production curves from the previous year.

(4) Acquisitions are entirely attributable to The Corporation’s purchase of leases and associated production in Oklahoma.

(5) During 2018, 19 MMcf were added to proved producing from the shut-in category. During 2017, 934 MMcf were
transferred from net proved undeveloped, 306 MMcf moved to net proved developed producing and 628 MMcf moved
to net proved developed non-producing.

EPSILON ENERGY LTD.
Supplemental Information to Consolidated Financial Statements
(Unaudited)

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table sets forth the capitalized costs relating to Epsilon’s crude oil and natural gas producing

activities at December 31, 2018 and 2017:

Proved properties
Unproved properties
Gathering system properties

Total Oil & Gas Properties

Accumulated depreciation, depletion and amortization

Net capitalized costs

Year ended December 31,
2017
2018

$ 118,851,574 $ 118,524,693
17,451,552
40,880,503
176,856,748
(104,877,974)
71,978,774

19,498,666
41,040,847
179,391,087
(111,944,974)
$ 67,446,113 $

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.

Year ended December 31,
2018

2017

Oil and Natural Gas Activities:
Proved acquisition costs
Unproved acquisition costs
Development costs(1)

Total costs incurred for oil and natural gas activities

Gathering System development costs

Total costs incurred

4,992 $ 1,734,509
17,451,552
20,758
19,206,819
142,418
$ 2,534,340 $ 19,349,237

2,047,114
321,890
2,373,996
160,344

(1) Development costs for 2018 include a $0.5 million cash call refund for wells previously drilled.

Results of Operations for Oil and Gas Producing Activities

The following table sets forth results of operations for gas producing activities for the years ended December 31,

2018 and 2017:

Oil and gas producing activities:

Gas sales
Oil and other liquid sales

Total revenues

Lease operating costs
Depreciation, depletion, amortization, and accretion

Total costs

Results of operations from oil and gas producing activities

Year ended December 31,
2017
2018

$ 19,031,422 $ 19,203,543
121,985
19,325,528
(5,723,298)
(8,057,299)
(13,780,597)
5,544,931

671,221
19,702,643
(6,665,856)
(5,294,200)
(11,960,056)
$ 7,742,587 $

EPSILON ENERGY LTD.
Supplemental Information to Consolidated Financial Statements
(Unaudited)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing procedures prescribed by the Extractive Industries—Oil
and Gas Topic of the ASC and based on natural gas reserves and production volumes estimated by the reserve engineers
of 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 2018 and 2017. 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, 2018 and 2017.

Future cash inflows
Future production costs
Future development costs(1)
Future income taxes(2)
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future net cash flows

Year ended December 31,

2018

2017

$ 314,768,187 $ 444,906,724
(168,489,681)
(113,557,103)
(92,026,760)
(35,324,796)
(49,347,763)
(45,050,385)
(85,326,963)
(61,761,091)
$ 59,074,812 $
49,715,557

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

(2) Future income taxes for 2018 and 2017 were estimated using a combined federal and state statutory tax rate of
approximately 27.6% which reflects the reduced corporate tax rate of 21% enacted on December 22, 2017 via the Tax
Cuts and Jobs Act.

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, 2018 and 2017:

Beginning balance

Revenue less production and other costs
Changes in price, net of production costs
Development costs incurred
Net changes in future development costs
Revisions of previous quantity estimates(1)
Accretion of discount
Net change in income taxes
Purchases of reserves in place
Timing differences and other technical revisions(1)

Ending balance

Year ended December 31,

2018

2017

$ 49,715,557 $ 16,387,269
(13,634,107)
26,136,085
34,457
(68,608,621)
111,557,578
1,390,234
(19,722,823)
786,392
(4,610,907)
$ 59,074,812 $ 49,715,557

(13,042,411)
44,764,807
512,314
50,335,213
(75,979,298)
7,382,905
(3,192,058)
—
(1,422,217)

(1) The 2017 amounts have been revised to reflect a revision in the discounting factor utilized in the determination of the

revisions of previous quantity estimates.

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 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, 2018, 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

This Annual Report on Form 10-K is not required to include a report of management’s assessment regarding
internal control over financial reporting or an attestation report of our independent registered public accounting firm due
to both a transition period established by rules of the SEC for newly public companies and our status as an emerging
growth company.

Changes in Internal Control Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended December 31, 2018

that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION.

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Directors and Executive Officers. The names, ages, business experience (for at least the past five years) and positions of
our directors and executive officers as of December 31, 2018, are set out below. Our Board of Directors consisted of seven
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.

Director or Executive Officer

Age

Position with us

Michael Raleigh
B. Lane Bond
Henry Clanton
John Lovoi
Matthew Dougherty
Adrian Montgomery
Ryan Roebuck
Jacob Roorda
Tracy Stephens

62 Chief Executive Officer and Director
60 Chief Financial Officer
56 Chief Operating Officer
57 Chairman of the Board and Director
37 Director
45 Director
33 Director
61 Director
58 Director

Biographies of Corporate Directors and Executive Officers.

Michael Raleigh. Mr. Raleigh has served as chief executive officer and a director for Epsilon Energy Ltd. since
July 2013. Before becoming chief executive officer at Epsilon Energy Ltd., he acted in various positions in the global oil
and gas business for 35 years, primarily holding positions in the areas of reservoir development strategy, property
valuations, completions and production. He has also been managing investments with Domain Energy Advisors since
January 2005. Mr. Raleigh has been a member of the board of directors of Roan Resources, Inc,. an Anadarko Basin-
focussed exploration and production company, since September 2018. He has also been managing investments with
Domain Energy Advisors since January 2005. We believe that Mr. Raleigh is qualified to serve as a member of our board
of directors as a result of his background in engineering, including reserve, acquisitions and valuation engineering, and his
experience in the development and appraisal of oil and gas fields. Mr. Raleigh received a Bachelor of Science degree in
Chemical Engineering from Queens University in Canada and received his Master of Business Administration degree from
the University of Colorado.

B. Lane Bond. Mr. Bond has served as our chief financial officer since January 2012. He has served as the chief
financial officer of Epsilon Energy USA and Epsilon Energy Midstream since January 2012. He has also been serving as
the chief financial officer of Dewey Energy Holdings and Dewey Energy GP since March 2017. Mr. Bond’s financial
career spans over 30 years with extensive management and oil and gas experience domestically and internationally.
Mr. Bond holds a Master of Business Administration from the University of Tulsa and a Bachelor of Science in Accounting
from the University of Arkansas.

Henry N. Clanton. Mr. Clanton joined The Corporation as its Chief Operating Officer in 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 Corporation. He holds a MBA and a
BS in Petroleum Engineering from Texas A&M 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 oil and gas investment advisor, since November 2002. He is a Director
of Helix Energy Solutions Group, an operator of offshore oil and gas properties and production facilities, the Chairman of
Dril-Quip, Inc., a provider of subsea, surface and offshore rig equipment, and a Director of Roan Resources, Inc., an
Anadarko Basin-focused exploration and production company. 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 oil and gas practice.

Matthew Dougherty. Mr. Dougherty has been a director since July 2013 and serves as the chair of the
Compensation, Nominating and Governing Committee. He has been the Managing Director of Advisory Research, Inc.,
an investment management firm since June 2003, where he oversees the firm’s investments in oil and natural gas
producers. He has served as the Portfolio Manager of the Advisory Research Energy Fund, LP since 2005. We believe that
Mr. Dougherty is qualified to serve as a member of our board of directors because of his background in oil and gas and
finance industries.

Adrian Montgomery. Mr. Montgomery has been a director and a member of our Audit Committee since
July 2013. Mr. Montgomery has served as
the president of Aquilini Entertainment since September 2017.
Mr. Montgomery was the CEO of QM Environmental, one of Canada’s largest environmental services companies, from
February 2015 to September 2017. He was the President and Chief Information Officer of Tuckamore Capital Management
Inc., a Toronto Stock Exchange—listed company that invests in private businesses from February 2012 to March 2016.
He is also a member of the Young Presidents’ Organization and a member of the New York bar. We believe that
Mr. Montgomery is qualified to serve as a member of our board of directors because of his management experience in
both public and private companies.

Ryan Roebuck. Mr. Roebuck has been a director since July 2011. He has also been serving as the chair of our
Audit Committee, a member of our Compensation, Nominating and Governance Committee since July 2011, and a
member of our Conflicts Committee since February 2017.Mr. Roebuck is currently the Principal of RR ONE LTD. an
investment holding company located in Toronto, Canada. Prior to this position, Mr. Roebuck was an investment manager
for a leading Canadian Venture Capital Firm where he was a founding investor and director of the Cronos Group.
Mr. Roebuck began his career as a top-rated equity research analyst focused on North American special situations. We
believe that Mr. Roebuck is qualified to serve as a member of our board of directors as a result of his background in the
investment banking industry and as an investment manager.

Jacob Roorda. Mr. Roorda has been a director since March 2016. He has also been a member of our Audit
Committee since March 2016, and the chair of our Conflicts Committee since February 2017. Mr. Roorda is the managing
director and chief executive officer of Windward Capital Limited, a private investment company, serving from
October 2011 to January 2015, and again since July 2017. He was the Executive Vice President of Todd Energy
International Ltd. from November 2016 to July 2017, and the Chief Executive Officer of Todd Energy Canada Ltd. from
January 2015 to November 2016. Mr. Roorda currently serves on the Audit, Compensation, and Reserves Committee of
Petroshale Inc. During the last five years, he also served on the boards of Wolf Minerals Limited and Northcliff Resources
Ltd. None of these positions are, or have ever been, with companies affiliated with the Company. Mr. Roorda has also
served on the board of Todd Energy Canada Ltd. He has been certified as a Professional Engineer by the Association of
Professional Engineers and Geoscientists of Alberta since 1981. We believe that Mr. Roorda is qualified to serve as a
member of our board of directors as a result of his experience in the oil and gas industry, including his oil and gas business
development and engineering experience, and his financial industry experience.

Tracy Stephens. Mr. Stephens has been a director since May 2017. He has also been a member of our
Compensation, Nominating and Corporate Governance Committee, and Conflicts Committee since February 2018. He is
the founder of Westminster Advisors, a CEO advisory services company, and served as its Chief Executive Officer from
January 2017. He was previously employed by Resources Global Professionals, a large business consulting company, from
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.

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 Capital 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 Committee and Nominating and Corporate Governance Committee and has
adopted a Compensation Committee Charter, and Nominating and Corporate Governance Charter to ensure the objectives
of NI 58-201 and the NASDAQ Capital Market are met.

The Board is currently composed of seven directors who provide us with a wide diversity of business experience.
Our Board has determined that Messrs. Jacob Roorda, Tracy Stephens, Adrian Montgomery and Ryan Roebuck are
independent in accordance with the listing requirements of the NASDAQ Capital Market, representing over 50% of the
Board. Each of the independent directors has no direct or indirect material relationship with us, including any business or
other relationship, that could reasonably be expected to interfere with the director’s ability to act with a view to our best
interests or that could reasonably be expected to interfere with the exercise of the director’s independent judgment.

Mr. Lovoi is the Managing Partner of JVL Advisors, LLC, beneficial owner of 20.15% of our common shares.
Mr. Dougherty is the Managing Director of Advisory Research, Inc., beneficial owner of 12.05% of our common shares.
Mr. Raleigh is our Chief Executive Officer.

The Board held seven meetings during 2018 and seven meetings during 2017. All Board meetings were conducted
with open and candid discussions. As such, the independent directors did not hold any separate meetings, other than Audit
and Compensation, Nominating and Corporate Governance Committee meetings that excluded directors who were not
independent. The chairman of the Board is not an independent director. The independent 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 independent
members of the Board. The Board 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 in particular 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 Capital 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 Capital 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
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 three committees. The committees are the Audit Committee, the Compensation, Nominating and
Corporate Governance Committee, and the Conflicts Committee. Each committee has been constituted with independent
directors.

Audit Committee. The Audit Committee consists of Ryan Roebuck (Chairman), Jacob Roorda, and Adrian
Montgomery. All members of the Audit Committee are independent and financially literate under the applicable rules and
regulations of the SEC and the NASDAQ Capital 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 its 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.

The Audit Committee operates under a written charter that satisfies the applicable standards of the SEC and The
the Audit Committee Charter can be found on our website at

NASDAQ Capital Market. A copy of
www.epsilonenergyltd.com.

Compensation, Nominating and Corporate Governance Committee. The Compensation, Nominating and
Corporate Governance Committee comprises Matthew Dougherty (chairman), Tracy Stephens and Ryan Roebuck, two of
whom, Messrs. Stephens and Roebuck, are independent directors. Before July 2013, we had separate compensation
committee and nominating and corporate governance committee. Both committees’ mandates were approved by the Board
on December 10, 2009. In July 2013, the Board consolidated the functions of the two committees for efficiency purposes.

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 Capital Market. A copy of such charter can be found on
our website at www.epsilonenergyltd.com.

Conflicts Committee. The Conflicts Committee comprises Jacob Roorda (Committee Chairman), Tracy Stephens

and Ryan Roebuck, all of whom are independent directors.

The Conflicts Committee has the power to advise the Board with respect to any matters or issues of concern to
the Conflicts Committee in connection with any corporate opportunity and the interests of a related or conflicted party that
the Conflicts Committee considers necessary or advisable.

Communications to the Board.

Shareholders may communicate directly with our Board of Directors or any director by writing to the board or a
director in care of the corporate secretary at Epsilon Energy Ltd., 16701 Greenspoint Park Drive, Suite 195, Houston,
Texas 77060, or by faxing their written communication to AeRayna Flores at (281) 668-0985. Shareholders may also
communicate to the Board of Directors 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

The named executive officers, excluding Michael Raleigh, have executed employment contracts with us.
Mr. Henry Clanton’s employment contract calls for a base pay of US$250,000 per year. Mr. B. Lane Bond’s employment
contract calls for a base pay of US$200,000 per year and contains provisions for severance payments equal to six months
of current annual salary in the event that a change of control occurred.

Mr. Michael Raleigh does not take a salary for his efforts with us and does not have an employment contract.

ITEM 11. EXECUTIVE COMPENSATION.

Summary Compensation Table

In April 2017 the Board amended and restated the 2007 Plan, which is currently called the Amended and Restated
2017 Stock Option Plan (the ‘2017 Plan’). In addition, in 2017, the Board adopted, and The Corporation’s shareholder
approved, the Share Compensation Plan. 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, 2018 and 2017. Compensation amounts in

the following table are in U.S. dollars unless stated otherwise. All share balances and income (loss) per share amounts are
presented on a post-Consolidation basis (see note 16)

Non-equity incentive
plan compensation

Bonuses

and
director fees
($) (h)

Share-based Option- based
awards (d)
Share-based Option-based incentive Incentive Pension

Long-term

awards (e)

Annual

($) (f)

awards
($) (e)

plans
(f1)

Plans
(f2)

value
($) (g)

(b)

Year Salary
($) (c)

Name and principal
position (a)
Michael Raleigh, CEO (1) 2018 $
— $
2017 $
— $
2018 $ 250,000 $
2017 $ 240,385 $
2018 $ 200,000 $
2017 $ 200,000 $

Henry Clanton, COO (2)

B. Lane Bond, CFO (3)

awards
($) (d)
748,750 $
775,000 $
104,825 $
— $
74,875 $
— $

— $
— $
75,000 $
— $
70,000 $
70,000 $

— $
— $
— $
68,627 $
— $
66,079 $

— $
— $
— $
— $
— $
— $

Total
compensation
($) (i)
748,750
775,000
429,825
309,012
344,875
336,079

— $
— $
— $
— $
— $
— $

(1) Mr. Raleigh is currently working without a salary from us; however, he was granted the following equity award in

2018 and 2017.

2018—Share award of 62,500 common shares under the Share Compensation Plan valued at $5.99 per share,
market price on the grant date, 12/31/2018, which vest evenly over a three year period. Vested shares will be
awarded on the anniversary date for each of the next three years, so long as Mr. Raleigh is still employed.

2017—Share award of 125,000 common shares under the Share Compensation Plan valued at $6.20 per share,
market price on the grant date, 10/23/2017, which vest evenly over a three year period. Vested shares will be
awarded on the anniversary date for each of the next three years, so long as Mr. Raleigh is still employed.

(2) Mr. Henry Clanton was hired as our chief operating officer in January 2017 with a base salary of US$250,000.

2018— Share award of 17,500 common shares under the Share Compensation Plan valued at $5.99 per share,
market price on the grant date, 12/31/2018, which vest evenly over a three year period. Vested shares will be
awarded on the anniversary date for each of the next three years, so long as Mr. Clanton is still employed.

2017—Options to purchase 30,000 common shares at a price of $6.70 per common share with a term of three
years and fully vested as of 1/30/2020.

(3) Mr. Bond’s current base salary is $200,000. The dollar amounts in column (e) reflect values derived from using the
Trinomial Hull White option pricing to value option - based awards. A summary of the options granted by year follows:

2018— Share award of 12,500 common shares under the Share Compensation Plan valued at $5.99 per
share, market price on the grant date, 12/31/2018, which vest evenly over a three year period. Vested shares will
be awarded on the anniversary date for each of the next three years, so long as Mr. Bond is still employed.

2017—Options to purchase 27,500 common shares at a price of $6.70 per common share with a term of three
years and fully vested as of 1/30/2020.

Description of the 2017 Plan and the Share Compensation Plan.

Amended and Restated 2017 Stock Option Plan

The 2017 Plan was approved by the Board and shareholders in April 2017 as a restatement of our Amended and

Restated 2010 Stock Option Plan.

The 2017 Plan is administered by the Board, a committee of the Board or one or more officers delegated authority
by the Board to administer the 2017 Plan. The Board has the authority in its discretion to interpret the 2017 Plan. The
Board determines to whom options are granted, the numbers of shares subject to options and all other terms and conditions
of the options.

The maximum number common shares that may be issued under the 2017 Plan is 1,000,000. As of December 31,
2018, options for 290,750 common shares were outstanding under the 2017 Plan, and 20,000 shares had previously been
issued upon the exercise of options granted under the 2017 Plan.

If options granted under the Plan expire or terminate for any reason without having been exercised, the shares
subject to such options are again available for grant under the 2017 Plan. Options granted under the 2017 Plan are not
transferable or assignable other than by will or other testamentary instrument or the laws of succession.

The exercise price of options granted under the 2017 Plan may not be less than the closing price of the common

shares on the TSX on the last trading day preceding the day on which the option is granted.

Each option granted under the 2017 Plan expires on the date specified by the applicable option agreement (not

later than ten years following grant), subject to earlier termination as provided below.

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 Corporation’s assets, or the liquidation, dissolution or winding-up of the Corporation, the Board may determine that
all unvested options will vest and be eligible for exercise within a period determined by the directors preceding the change
of control. Options not exercised within this period will terminate.

If an optionee resigns from the Corporation or is terminated by the Corporation (with or without cause), or a
consultant optionee’s contract with the Corporation expires, such optionee’s unvested options will immediately terminate
and, subject to the option expiry date, the optionee’s vested options may be exercised for a period of 30 days.

If an optionee becomes entitled to long-term disability payments pursuant to the Corporation’s disability
insurance program (or if not a participant in such program, would have been entitled to such payments if the optionee had
been a participant in such program), all of the unvested options held by the optionee will vest on the day immediately
preceding the day on which the optionee becomes entitled to long-term disability payments and the optionee will have the
right, for a period of 180 days thereafter, to exercise all of the options.

If an optionee retires pursuant to a retirement policy approved by the Board, all of the unvested options held by
the optionee will vest on the day immediately preceding the date of such optionee’s retirement, and the optionee will have
the right, for a period of 60 days thereafter, to exercise all of the options.

If an optionee dies, all of the unvested options held by the optionee will vest on the day immediately preceding
the date of such optionee’s death, and the estate of the deceased optionee will have the right, for a period of 180 days
thereafter to exercise the deceased optionee’s option.

Should the term of an option expire when the optionee cannot exercise the option pursuant to a Corporation
insider trading policy in effect at that time (a ‘‘Blackout Period’’) or within nine business days following the expiration of
a Blackout Period, option expiration date is automatically extended until the tenth business day after the end of the Blackout
Period. The ten-business-day period may not be extended by the Board.

Share Compensation Plan

The Share Compensation Plan was adopted by the Board on April 13, 2017 and approved by the shareholders on

May 24, 2017.

The Share Compensation Plan provides that up to a total of 1,000,000 common shares. As of December 31, 2018,

a total of 345,333 common shares have been issued under the Share Compensation Plan.

Under the Share Compensation Plan, the Board designates participants from among the our directors, officers,
key employees and consultants and, on the day or days of each fiscal year determined by the Board, awards to each
participant common shares in an amount up to 100% of the participant’s compensation for service during the current year
divided by the market price (as defined in the TSX Company Manual) of the common shares at the date of issuance. Upon

any participant ceasing to be our director, officer, employee or consultant for any reason, such participant’s right to be
issued common shares pursuant to the Share Compensation Plan terminates immediately.

The Board may, in its sole discretion, impose restrictions on any common shares issued pursuant to the Share
Compensation Plan. These restrictions may include, but are not limited to, vesting periods and trading restrictions for a
period of time, as determined by the Board, from the date of issuance.

The Share Compensation Plan provides that the Board may make certain amendments to the Share Compensation
Plan without the approval of our shareholders or any participant of the Share Compensation Plan in order to conform to
applicable law or regulation or the requirements of the TSX. In addition, the Board may terminate the Share Compensation
Plan at any time, subject to applicable law or regulations and the approval of any regulatory authority having jurisdiction,
and the approval of our shareholders if required by such regulatory authority.

Incentive Plan Awards for Named Executive Officers

Outstanding Share - Based Awards and Option - Based Awards as of December 31, 2018 are as follows:

Option-based Awards

Number of
securities
underlying Option
exercise
price
($) (c)

unexercised
options (#)
(b)

Value of
unexercised
in-the-money
options ($)
(e)

Option
expiration
date (d)

50,000 $ 7.34 06/05/22 $
30,000 $ 6.70 01/30/24 $
22,500 $ 7.34 06/05/22 $
27,500 $ 6.70 01/30/24 $

—
—
—
—

Number of
shares or units
of shares that
have not
vested
(#) (f)
208,333 $
17,500 $
12,500 $

Share-based Awards
Market or
payout value
of share-based
awards that
have not
vested ($) (g)

Market or
payout value of
vested share-
based awards
not paid out or
distributed ($) (h)
249,583
—
—

1,247,917 $
104,825 $
74,875 $

Name (a)
Michael Raleigh
Henry Clanton
B. Lane Bond
B. Lane Bond

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, 2018 are as

follows:

Name (a)
Michael Raleigh
Henry Clanton
B. Lane Bond

Option-based awards—Value
vested during the year
($) (b)

Share-based awards—Value
vested during the year
($) (c)

$
$
$

— $
— $
— $

Non-equity incentive plan

compensation—Value earned
during the year
($) (d)
N/A
N/A
N/A

249,583 $
— $
— $

We have adopted the 2018 Plan as an incentive - based stock option award plan applicable to all named executive

officers and employees.

Termination and Change of Control Benefits

All of our named executive officers, except Mr. Michael Raleigh, have entered into employment contracts with

us.

Mr. B. Lane Bond’s employment contract calls for a base pay of US$200,000 per year and contains provisions

for severance payments equal to six months of current annual salary amount in the event of a change of control.

Mr. Henry Clanton’s employment contract calls for a base pay of US$250,000 per year.

Change of control is defined as any event whereby any person acquires at least 50% of The Corporation’s stock

or if a group of shareholders causes at least 50% of the board members to change.

DIRECTOR COMPENSATION

The following table contains compensation earned in the year ended December 31, 2018 by our independent

directors who are not named executive officers:

Non-equity

incentive plan Pension

All other

Amounts Shown in Cdn$
Name (a)
John Lovoi*
Michael Raleigh*
Matthew Dougherty*
Adrian Montgomery
Jacob Roorda
Ryan Roebuck
Tracy Stephens

Fees earned Share-based Option‑based compensation

($) (b)

awards ($) (c)

($) (d)

($) (e)

value compensation
($) (f)

($) (g)

Total
($) (h)

53,910 $
— $
$
— $ 748,750 $
$
— $
$
— $
53,910 $
$ 40,000 $
53,910 $
$ 40,000 $
53,910 $
$ 40,000 $
53,910 $
$ 40,000 $

— $
— $
— $
— $
— $
— $
— $

— $ — $
— $ — $
— $ — $
— $ — $
— $ — $
— $ — $
— $ — $

— $ 53,910
— $ 748,750
— $
—
— $ 93,910
— $ 93,910
— $ 93,910
— $ 93,910

*
payment for their service as board members.

The three directors who are not independent, Messrs. Lovoi, Raleigh and Dougherty, choose not to receive

On a biannual 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 May 1, 2017, independent board member compensation is fixed at an annual fee of Cdn$40,000, paid semi-

annually in July and January.

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, 2018 are as follows:

Name (a)
John Lovoi
Adrian Montgomery
Ryan Roebuck
Jacob Roorda
Tracy Stephens

Option-based Awards
Number of
securities

underlying Option
unexercised exercise
price
($)
(c)

options
(#)
(b)

Value of
unexercised
in-the-money
options
($)
(e)

Option
expiration
date
(d)

Market or

Share-based Awards
Market or
payout value payout value of
vested share-
based awards
not paid out or

Number of
shares or units of share-based
awards that
have not
vested
($)
(g)
83,860 $
83,860 $
83,860 $
83,860 $
83,860 $

of shares that
have not
vested
(#)
(f)
14,000 $
14,000 $
14,000 $
14,000 $
14,000 $

—
—
—
—
—

distributed
($)
(h)
14,975
14,975
14,975
14,975
14,975

10,000 $ 7.34 6/5/2022 $
10,000 $ 7.34 6/5/2022 $
10,000 $ 7.34 6/5/2022 $
12,500 $ 6.70 1/30/2024 $
$
—

— $

The values of incentive plan awards that were vested or earned during the year ended December 31, 2018 are as

follows:

Option-based

Share-based

Non-equity
incentive plan

Name (a)
John Lovoi
Adrian Montgomery
Ryan Roebuck
Jacob Roorda

the year
($)
(b)
—
—
—
—

the year
($)
(c)
14,975
14,975
14,975
14,975

$
$
$
$

earned during
the year
($)
(d)
N/A
N/A
N/A
N/A

awards—Value awards—Value compensation—Value
vested during

vested during

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
of Cdn$20,000,000 with a deductible to us of Cdn$25,000 per loss. The annual premium for the Directors’ and Officers’
liability insurance was Cdn$50,000 and is renewed 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
December 31, 2018, 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., 16701

Greenspoint Park Drive, Suite 195, Houston, Texas 77060.

Name of Beneficial Owner
5% Stockholders
Advisory Research, Inc.(1)
JVL Advisors, LLC (2)
Oakview Capital Management, L.P.(3)
azValor Asset Management SGIIC SA (4)
Named Executive Officers and Directors
Matthew Dougherty (5)
Jacob Roorda (6)
Bruce Lane Bond (7)
John Lovoi (8)
Ryan Roebuck (9)
Tracy Stephens (10)
Adrian Montgomery (11)
Henry Clanton (12)
Michael Raleigh (13)
All executive officers and directors as a group (9 persons) (14)

Number of Percentage of

Common
Shares

Common

Shares Owned

3,197,365
5,498,419
2,909,496
4,103,523

3,295,015
78,733
117,833
5,510,919
69,525
6,900
12,500
20,000
91,667
9,203,092

11.69 %
20.10 %
10.64 %
15.00 %

12.05 %

*
*

20.15 %

*
*
*
*
*

33.64 %

Indicates beneficial ownership of less than 1% of outstanding shares.

(1) The address of Advisory Research, Inc., or ARI, is 180 North Stetson Avenue, Chicago, Illinois 60601. Advisory
Research, Inc. (“ARI”) is the general partner of Advisory Research Energy Fund, L.P., the direct beneficial holder of
2,716,809 common shares, or 9.9% of outstanding shares as of March 26, 2019. The remaining common shares are
held indirectly by ARI on behalf of investment advisory clients. ARI may be deemed to indirectly beneficially own
(i) the common shares owned by advisory clients and (ii) the common shares held by Advisory Research Energy Fund,
L.P. Mr. Dougherty, a member of our board, is a managing director of ARI.

(2) The address of JVL Advisors, LLC, or JVL, is 10000 Memorial Drive, Houston, Texas 77024. John Lovoi, the
chairman of our board of directors, and the managing partner of JVL, exercises the voting and dispositive power with
respect to the common shares held by JVL.

(3) The address of Oakview Capital Management, L.P. is 3879 Maple Avenue, Suite 300, Dallas, Texas 75219. Consists
of common shares of the Company, no par value ("Shares"), held directly by and for the benefit of third-parties in
various separately managed customer accounts and affiliated private funds (collectively, the "Clients") managed by
Oakview Capital Management, L.P. ("Oakview") in the ordinary course of business. Solely for purposes of Section
13(d) of the Securities Exchange Act of 1934, Oakview may be deemed to indirectly beneficially own the common
shares held directly by such Clients. Oakview Investments, LLC is the general partner of, and may be deemed to
indirectly beneficially own any securities owned by, Oakview. None of the Clients have beneficial ownership of more
than 5% of the common shares outstanding as of March 13, 2019.

(4) The address of azValor Asset Management SGIIC SA, or azValor, is Paseo de la Castellana 10, 3rd, Madrid, 28046,
Spain. Alvaro Guzmàn de Làzaro, Chief Investment Officer at azValor, exercises the voting and dispositive power
with respect to the common shares held by azValor.

(5)

Includes the shares held by ARI and 97,650 shares held by Mr. Dougherty individually. Mr. Dougherty is a member
of our board of directors.

(6) Mr. Roorda is a member of our board of directors. Includes 25,000 shares held by Mr. Roorda’s spouse, and 8,333

shares issuable upon the exercise of options exercisable within 60 days of March 26, 2019.

(7)

(8)

(9)

Includes 40,833 shares issuable upon the exercise of options exercisable within 60 days of March 26, 2019. Mr. Bond
is our chief financial officer.

Includes the shares held by JVL. Includes 10,000 shares issuable upon the exercise of options held by Mr. Lovoi and
exercisable within 60 days of March 26, 2019. Mr. Lovoi is the chairman of our board of directors.

Includes 10,000 shares issuable upon the exercise of options exercisable within 60 days of March 26, 2019.
Mr. Roebuck is a member of our board of directors.

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

(11) Includes 10,000 shares issuable upon the exercise of options exercisable within 60 days of March 26, 2019.

Mr. Montgomery is a member of our board of directors.

(12) Includes 20,000 shares issuable upon the exercise of options exercisable within 60 days of March 26, 2019.

Mr. Clanton is our chief operating officer.

(13) Includes 50,000 shares issuable upon the exercise of options exercisable within 60 days of March 26, 2019.

Mr. Raleigh is our chief executive officer and a member of our board of directors.

(14) Includes 149,166 shares issuable upon the exercise of options exercisable within 60 days of March 26, 2019.

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.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR

INDEPENDENCE.

Certain Relationships and Related Transactions

Since the beginning of fiscal 2015, 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

Indemnification of Officers and Directors

As permitted by Delaware law, our proposed certificate of incorporation will provides that, to the fullest extent
permitted by Delaware law, no director will be personally liable to us or our stockholders for monetary damages for breach
of fiduciary duty as a director. Pursuant to Delaware law such protection would be not available for liability:

•

for any breach of a duty of loyalty to us or our stockholders;

for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

for any transaction from which the director derived an improper benefit; or

for an act or omission for which the liability of a director is expressly provided by an applicable statute,
including unlawful payments of dividends or unlawful stock repurchases or redemptions as provided in
Section 174 of the Delaware General Corporation Law.

Our proposed certificate of incorporation provides that if Delaware law is amended after the approval by our
stockholders of the amended and restated certificate of incorporation to authorize corporate action further eliminating or
limiting the personal liability of directors, then the liability of our directors will be eliminated or limited to the fullest
extent permitted by Delaware law. In addition, the proposed bylaws of Epsilon provide that we are required to advance
expenses to our directors and officers as incurred in connection with legal proceedings against them for which they may
be indemnified and that the rights conferred in the amended and restated bylaws are not exclusive.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

The following table summarizes fees billed to us for fiscal 2018 and for fiscal 2017 by our principal auditors,

BDO USA, LLP:

Audit Fees:

Audit of financial statements
Services in connection with regulatory filings

Total Audit Fees Paid

December 31, December 31,

2018

2017

555,580 $
232,346
787,926 $

437,576
54,635
492,211

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

(a)1.

Financial Statements:

PART IV

Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2017 and December 31, 2018.
Consolidated Statements of Operations for the years ended December 31, 2017 and December 31, 2018.
Consolidated Statements of Comprehensive Income for the years ended December 31, 2017 and

December 31, 2018.

Consolidated Statements of Cash Flows for the years ended December 31, 2017 and December 31, 2018.
Consolidated Statement of Changes in Shareholders’ Equity for the years ended December 31, 2017 and

December 31, 2018.

Notes to Consolidated Financial Statements

(a)2.

Financial Statement Schedules:
There are no Financial Statement Schedules included with this filing for the reason that they are not

required.

(a)3.

Exhibits

3.1

Articles of Incorporation of Epsilon Energy Ltd. (incorporated by reference to Exhibit 3.2 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, 2018 (incorporated by reference to Exhibit 3.3 of Form 10 File

No. 001-38770, filed on December 21, 2018)

10.1

Credit Agreement, dated as of July 29, 2013, by and among Epsilon Energy USA Inc., the lenders from

time to time party thereto, Texas Capital Bank, National Association (“TCB”), as the administrative agent,
swing line lender and letter of credit issuer, and TCB as the sole lead arranger and sole book runner
(incorporated by reference to Exhibit 10.1 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.2

First Amendment to Credit Agreement, effective as of December 10, 2015 (incorporated by reference to

Exhibit 10.2 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.3

Second Amendment to Credit Agreement, effective as of October 11, 2016 ((incorporated by reference to

Exhibit 10.3 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.4

Third Amendment to Credit Agreement, effective as of February 21, 2017 (incorporated by reference to

Exhibit 10.4 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.5

Fourth Amendment to Credit Agreement, effective as of August 4, 2017 (incorporated by reference to

Exhibit 10.5 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.6*

Fifth Amendment to Credit Agreement, effective as of January 7, 2019

10.7+

Lane Bond Offer Letter (incorporated by reference to Exhibit 10.6 of Form 10 File No. 001-38770, filed on

December 21, 2018)

10.8+

Henry Clanton Offer Letter (incorporated by reference to Exhibit 10.7 of Form 10 File No. 001-38770,

filed on December 21, 2018)

10.9

Anchor Shipper Gas Gathering Agreement, effective January 1, 2012, by and between Appalachia

Midstream Services, L.L.C. and Epsilon Energy USA, Inc., as shipper and producer (incorporated by
reference to Exhibit 10.8 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.10+

Amended and Restated 2017 Stock Option Plan (incorporated by reference to Exhibit 10.9 of Form 10 File

No. 001-38770, filed on December 21, 2018)

10.11+

Share Compensation Plan (incorporated by reference to Exhibit 10.10 of Form 10 File No. 001-38770, filed

on December 21, 2018)

10.12

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)

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

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.

99.1*

Summary Reserve Report

101.INS* XBRL Instance Document.

101.SCH* XBRL Taxonomy Extension Schema Document.

101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF* XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB* XBRL Taxonomy Extension Label Linkbase Document.

101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document.

Filed herewith.

** Furnished herewith.

+ Denotes a management contract or compensatory plan or arrangement.

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 29, 2019.

SIGNATURES

EPSILON ENERGY LTD...

By: /s/ B. Lane Bond
B. Lane Bond
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

/s/ Michael Raleigh
Michael Raleigh

Chief Executive Officer and Director

(Principal Executive Officer)

Date

March 29, 2019

/s/ B. Lane Bond
B. Lane Bond

/s/ John Lovoi
John Lovoi

/s/ Matthew Dougherty
Matthew Dougherty

/s/ Adrian Montgomery
Adrian Montgomery

/s/ Ryan Roebuck
Ryan Roebuck

/s/ Jacob Roorda
Jacob Roorda

/s/ Tracy Stephens
Tracy Stephens

Chief Financial Officer

(Principal Financial and Accounting Officer)

Chairman of the Board

March 29, 2019

Director

March 29, 2019