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CONFIDENTIAL TREATMENT
As confidentially submitted to the Securities and Exchange Commission on October 31, 2018. This draft registration statement has not been publicly filed with the Securities and Exchange Commission, and all information herein remains strictly confidential.

File No.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10

General Form for Registration of Securities
Pursuant to Section 12(b) or (g) of the Securities Exchange Act of 1934

Epsilon Energy Ltd.

(Exact name of registrant as specified in its charter)

Alberta, Canada (State or other jurisdiction of incorporation) |  | N/A (I.R.S. Employer Identification No.)

16701 Greenspoint Park Drive, Suite 195
Houston, Texas 77060

(Address of principal executive offices, including zip code)

(281) 670-0002

(Registrant's telephone number, including area code)

Copies to:
Gislar Donnenberg
DLA Piper LLP (US)
1000 Louisiana Street, Suite 2800
Houston, Texas 77002
(713) 425-8400

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

Title of each class to be so registered |  | Name of exchange on which each class is to be registered
--- | --- | ---
Common Shares, no par value |  | Nasdaq Capital Market

Securities to be registered pursuant to Section 12(g) of the Exchange Act: None.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or emerging growth company. See 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 o |  | Accelerated filer o |  | Non-Accelerated filer o |  | Smaller reporting company ý Emerging Growth Company ý

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 7(a)(2)(B) of the Securities Act. o

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EXPLANATORY NOTE

Epsilon Energy Ltd. ("we," "Epsilon" or the "Corporation") was incorporated March 14, 2005, pursuant to the ABCA. We completed our initial public offering in Canada in October of 2007. The common shares of the Corporation trade on the Toronto Stock Exchange under the symbol "EPS." We are filing this registration statement on Form 10 pursuant to Section 12(b) of the Exchange Act to submit to Exchange Act reporting in the United States. We have applied for listing on the Nasdaq Capital Market under the ticker symbol "EPSN".

Once the registration of our common shares becomes effective, we will be subject to the requirements of Section 13(a) of the Exchange Act, including the rules and regulations promulgated thereunder, which will require us to file, among other things, annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and proxy or information statements with the SEC.

Unless otherwise indicated, references herein to "$" or "dollars" are expressed in U.S. dollars (US$). References in this document to Canadian dollars are noted as "Cdn$."

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.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

From time to time, we may publish "forward-looking statements" and forward-looking information. We generally identify forward-looking statements and information with the words "plan," "expect," "anticipate," "estimate," "may," "will," "should" and similar expressions. We base these forward-looking statements and information on our current expectations and projections about future events.

We caution readers that a variety of factors could cause our actual results to differ materially from those discussed in, or implied by, these forward-looking statements and information. These risks and uncertainties, many of which are beyond our control, include, but are not limited to, the risk factors described in the section titled "Risk Factors" on page 10, which include, but are not limited to:

•
  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;
•
  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;
•
  our proved reserve estimates may be inaccurate, and future net cash flows as well as our ability to replace any reserves are uncertain;
•
  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;
•
  if there is a sustained economic downturn or recession in the United States or globally, oil and natural 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;
•
  substantial capital, which may not be available to us in the future, is required to replace and grow reserves;
•
  the borrowing base under our credit facility may be reduced in light of commodity price declines, which could limit us in the future;

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•
  the terms of our revolving credit facility may restrict our operations, particularly our ability to respond to changes or to take certain actions;
•
  depending on forces outside our control, we may need to allocate our available capital in ways that we did not anticipate;
•
  we may issue debt to acquire assets or for working capital;
•
  future equity transactions could result in dilution to existing stockholders;
•
  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;
•
  results of our drilling are uncertain, and we may not be able to generate high returns;
•
  extensive government legislation and regulatory initiatives could increase costs and impose burdensome operating restrictions that may cause operational delays;
•
  our operations are currently geographically concentrated and therefore subject to regional economic, regulatory and capacity risks;
•
  delays in business operations may reduce cash flows and subject us to 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;
•
  we depend on third party operators and our key personnel, and competition for experienced, technical personnel may negatively affect our operations;
•
  our leasehold interests are subject to termination or expiration under certain conditions;
•
  we may incur losses as a result of title deficiencies;
•
  we may be exposed to third party credit risk, and defaults by third parties could adversely affect us;
•
  we may not be insured against all of the operating risks to which we are exposed;
•
  natural gas and oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business;
•
  hedging transactions may limit our potential gains or cause us to lose money;
•
  market conditions or operation impediments may hinder our access to natural gas and oil markets or delay our production;
•
  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;
•
  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;
•
  environmental and health and safety risks may adversely affect our business;
•
  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;

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•
  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;
•
  because of the natural decline in production from existing wells, our success depends on the anchor shippers' economically developing the remaining Marcellus reserves;
•
  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;
•
  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;
•
  we compete with other operators in our gas gathering energy businesses;
•
  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;
•
  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;
•
  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;
•
  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; and
•
  our operations are subject to operational hazards and unforeseen interruptions.

The foregoing list should not be construed as exhaustive. Many factors could cause our actual results, performance or achievements to be materially different from any results, performance or achievements that may be expressed or implied by such forward-looking statements, including those set forth under the headings "Risk Factors" and "Business." Should one or more of these risks or uncertainties materialize, or should the assumptions underlying the forward-looking statements or information prove incorrect, actual results may vary materially from those described in this document as intended, planned, anticipated, believed, estimated or expected. We do not intend, and do not assume, any obligation to update these forward-looking statements or information.

See "Item 1A. Risk Factors" for a more detailed description of these and other factors that may affect the forward-looking statements in this document. When considering forward-looking statements, you should keep in mind the risk factors described in "Item 1A. Risk Factors." Such risk factors could cause actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation, other than as required by applicable law, to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

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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.

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"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.

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"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

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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.

|  | December 31, 2016 |  | December 31, 2017 |  | June 30, 2017 |  | June 30, 2018 |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Daily Closing Rate |  |  | 0.7448 |  |  | 0.7971 |  |  | 0.7706 |  |  | 0.7594 |

|  | 2016 |  | 2017 |  |  |  |  |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Annual Average Rate |  |  | 0.7550 |  |  | 0.7708 |  |  |  |  |  |  |
Yearly High Closing Rate |  |  | 0.7977 |  |  | 0.8245 |  |  |  |  |  |  |
Yearly Low Closing Rate |  |  | 0.6869 |  |  | 0.7276 |  |  |  |  |  |  |

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TABLE OF CONTENTS

|  |  |  | Page
--- | --- | --- | --- | ---
EXPLANATORY NOTE |  | i
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS |  | i
DEFINED TERMS |  | iv
INFORMATION REQUIRED IN REGISTRATION STATEMENT |  | 1
ITEM 1. |  | BUSINESS |  | 1
|  | Summary |  | 1
|  | Properties |  | 2
|  | Business Segments |  | 3
|  | Competition |  | 6
|  | Our Status as an Emerging Growth Company |  | 7
|  | Employees |  | 7
|  | Legal Proceedings |  | 7
|  | Regulation |  | 8
ITEM 1A. |  | RISK FACTORS |  | 10
|  | Risks Related to Oil and Natural Gas Reserves |  | 10
|  | Risks Related to Internal Controls |  | 19
|  | Risks Related to the Gathering System |  | 20
ITEM 2. |  | FINANCIAL INFORMATION |  | 23
|  | Selected Historical Financial Information |  | 23
|  | Management's Discussion and Analysis of Financial Condition and Results of Operation |  | 24
|  | Quantitative and Qualitative Disclosures About Market Risk |  | 39
ITEM 3. |  | PROPERTIES |  | 40
ITEM 4. |  | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT |  | 40
ITEM 5. |  | DIRECTORS AND EXECUTIVE OFFICERS |  | 42
ITEM 6. |  | EXECUTIVE COMPENSATION |  | 48
|  | Summary Compensation Table |  | 48
|  | Director Compensation |  | 52
ITEM 7. |  | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |  | 53
|  | Certain Relationships and Related Transactions |  | 53
|  | Independence of the Board of Directors |  | 53
ITEM 8. |  | LEGAL PROCEEDINGS |  | 54
ITEM 9. |  | MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS |  | 54
ITEM 10. |  | RECENT SALES OF UNREGISTERED SECURITIES |  | 55
ITEM 11. |  | DESCRIPTION OF REGISTRANT'S SECURITIES TO BE REGISTERED |  | 55
ITEM 12. |  | INDEMNIFICATION OF DIRECTORS AND OFFICERS |  | 60
ITEM 13. |  | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |  | 61
ITEM 14. |  | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |  | 61
ITEM 15. |  | FINANCIAL STATEMENTS AND EXHIBITS |  | 63

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INFORMATION REQUIRED IN REGISTRATION STATEMENT

ITEM 1. BUSINESS.

Summary

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. The common shares of the Corporation trade on the TSX with the ticker symbol "EPS". At December 31, 2017, Epsilon's total estimated net proved reserves were 215,588 million cubic feet (MMcf) of natural gas reserves and 37,317 barrels (Bbl) of oil and other liquids. Epsilon held leasehold rights to approximately 76,171 gross (11,522 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 the six months ended June 30, 2018, we paid $0.58 million to the Auburn GGS to gather and treat our 3.6 Bcf of natural gas production in Pennsylvania ($0.64 million for 4.8 Bcf of natural gas in the six months ended June 30, 2017). In 2017, we paid $1.2 million to the Auburn GGS to gather and treat our 8.9 Bcf of 2017 natural gas production in Pennsylvania.

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 2017

Marcellus Shale—Pennsylvania

In 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

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

Six Months Ended June 30, 2018 Highlights

Operational Highlights

Marcellus Shale—Pennsylvania

•
  During the six months ended June 30, 2018, Epsilon's realized natural gas price was $2.24 per Mcf, a 9% decrease over the six months ended June 30, 2017.
•
  Total six months ended June 30, 2018 natural gas production was 3.56 Bcf, as compared to 4.79 Bcf during the same period in 2017. Added oil and other liquid production of 0.17 Bcfe from Oklahoma acquisitions made during 2017 for a total of 3.73 Bcfe of production for the six months ended June 30, 2018.
•
  Marcellus working interest (WI) gas averaged 23.4 MMcf/d for the first half of 2018.
•
  Gathered and delivered 49.7 Bcf gross (17.4 Bcf net to Epsilon's interest) during the first half of 2018 through the Auburn System which represents approximately 86% of maximum throughput.

Anadarko, NW Stack Trend—Oklahoma

•
  During the six months ended June 30, 2018, Epsilon's realized price for all production was $3.87 per Mcfe.
•
  Total production for the six months ended June 30, 2018 included natural gas, oil, and other liquids and was 0.17 Bcfe.

Properties

As of June 30, 2018, our 76,251 gross (11,601 net) acres are all located in the United States and include 260 gross (53.3 net) wells.

|  | Gross |  | Net |
--- | --- | --- | --- | --- | ---
Producing Wells |  |  |  |  |  |  |
Oil |  |  | 9 |  |  | 0.98 |
Gas |  |  | 168 |  |  | 34.44 |
Oil & Gas |  |  | 35 |  |  | 7.89 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total Producing Wells |  |  | 212 |  |  | 43.31 |
Non-producing Wells |  |  | 48 |  |  | 10.00 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total Wells |  |  | 260 |  |  | 53.31 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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Acreage

As of June 30, 2018, our leasehold inventory consisted of the following acreage amounts, rounded to the nearest acre:

|  | Gross(1) |  | Net(2) |
--- | --- | --- | --- | --- | ---
Developed Acres |  |  |  |  |  |  |
Pennsylvania |  |  | 8,276 |  |  | 4,138 |
Oklahoma |  |  | 5,769 |  |  | 601 |
Mississippi |  |  | 627 |  |  | 376 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
|  |  | 14,672 |  |  | 5,115 |
Undeveloped Acres |  |  |  |  |  |  |
Pennsylvania |  |  | — |  |  | — |
Oklahoma(3) |  |  | 61,579 |  |  | 6,486 |
Mississippi |  |  | — |  |  | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
|  |  | 61,579 |  |  | 6,486 |
Total Acres |  |  |  |  |  |  |
Pennsylvania |  |  | 8,276 |  |  | 4,138 |
Oklahoma |  |  | 67,348 |  |  | 7,087 |
Mississippi |  |  | 627 |  |  | 376 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total acres |  |  | 76,251 |  |  | 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 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 unaudited consolidated financial statements for the six months ended June 30, 2018 and 2017, and our consolidated financial statements for the years ended December 31, 2017 and 2016.

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 listing and governance functions.

For information about our segment's revenues, profits and losses, total assets, and total liabilities, see Note 11, "Operating Segments," of the Notes to the Unaudited Consolidated Financial Statements. For the Six Months Ended June 30, 2018 and 2017, and Note 12, "Operating Segments," of the Notes to the Consolidated Financial Statements For the Years Ended December 31, 2017 and 2016.

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Oil and Natural Gas Production and Revenues and Gathering System Revenues

A summary of our net oil and natural gas production, average oil and natural gas prices and related revenues and our gathering system revenues for the six months ended June 30, 2018 and 2017, and years ended December 31, 2017 and 2016, respectively, follows:

|  | Six months ended June 30, |  | Twelve months ended December 31, |
--- | --- | --- | --- | --- | ---
Revenue by product-total period ($000) |  | 2018 |  | 2017 |  | 2017 |  | 2016 |
Natural gas revenue ($000) |  | $ | 8,261 |  | $ | 11,774 |  | $ | 19,204 |  | $ | 15,263 |
Volume (MMcfe) |  |  | 3,683 |  |  | 4,792 |  |  | 9,010 |  |  | 11,016 |
Avg. Price ($/Mcfe) |  | $ | 2.24 |  | $ | 2.46 |  | $ | 2.13 |  | $ | 1.39 |
Exit Rate (MMcfepd) |  |  | 23.7 |  |  | 30.0 |  |  | 27.0 |  |  | 32.5 |
Oil and condensate revenue ($000) |  | $ | 217 |  | $ | — |  | $ | 122 |  | $ | — |
Volume (MBOE) |  |  | 3.48 |  |  | — |  |  | 3.10 |  |  | — |
Avg. Price ($/Bbl) |  | $ | 62.46 |  | $ | — |  | $ | 39.35 |  | $ | — |
Natural gas liquids revenue ($000) |  | $ | 125 |  | $ | — |  | $ | — |  | $ | — |
Volume (MBOE) |  |  | 5.68 |  |  | — |  |  | — |  |  | — |
Avg. Price ($/Mcfe) |  | $ | 22.07 |  | $ | — |  | $ | — |  | $ | — |
Midstream gathering system revenue ($000) |  | $ | 5,340 |  | $ | 3,602 |  | $ | 6,431 |  | $ | 8,437 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total Revenues |  | $ | 13,943 |  | $ | 15,376 |  | $ | 25,757 |  | $ | 23,700 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

Gathering System Operations

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

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have been eliminated from gathering system revenues amounted to $0.58 million and $0.64 million, respectively, for the six months ended June 30, 2018 and 2017, and $1.2 million and $1.7 million, respectively, for the years ended December 31, 2017 and 2016.

During the six months ended June 30, 2018 and 2017, the Auburn GGS delivered 51.1 Bcf and 50.8 Bcf respectively, of natural gas.

Proved Reserves

Per our reserve report prepared by independent petroleum consultants DeGolyer and MacNaughton, our estimated proved reserves as of December 31, 2017, are summarized in the table below. See Risk Factors for information relating to the uncertainties surrounding these reserve categories.

|  | Natural Gas Mmcf |  | Oil and other Liquids MBbl |
--- | --- | --- | --- | --- | ---
Pennsylvania-Marcellus Shale |  |  |  |  |  |  |
Proved developed producing |  |  | 57,510.2 |  |  | — |
Proved developed non-producing |  |  | 876.5 |  |  | — |
Proved undeveloped |  |  | 155,017.0 |  |  | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total Pennsylvania proved reserves |  |  | 213,403.7 |  |  | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oklahoma-Anadarko Basin |  |  |  |  |  |  |
Proved developed producing |  |  | 1,829.7 |  |  | 34.8 |
Proved developed non-producing |  |  | 354.5 |  |  | 2.5 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total Oklahoma proved reserves |  |  | 2,184.2 |  |  | 37.3 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total proved reserves at December 31, 2017 |  |  | 215,587.9 |  |  | 37.3 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

We have not engaged in any exploration capital spending in the six months ended June 30, 2018, or year ended December 31, 2017. Our development capital spending to convert proved undeveloped reserves to proved developed reserves for the periods indicated is as follows:

•
  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.
•
  In the six months ended June 30, 2018 no wells were completed or brought online.

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

Our policies regarding internal controls over reserve estimates require reserves to be prepared by an independent engineering firm under the supervision of our Chief 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 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

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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 document 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 six months ended June 30, 2018, we sold natural gas to 25 unique customers. Spotlight Energy, LLC, Repsol Energy North America Corporation, and Citadel Energy Marketing, LLC each accounted for 10% or more of 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.

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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 pursuant to an effective registration statement under the Securities Act of 1933, as amended;
•
  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 June 30, 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.

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Regulation

United States

Environmental Regulation

We are subject to various federal, state and local laws and regulations covering the discharge of materials into the environment or otherwise relating to the protection of 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 our overall cost of business, but has not had, to date, a material adverse effect on our operations, financial condition or results of operations. In addition, it is not anticipated, based on current laws and regulations, that we 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, we are unable to predict the ultimate cost of compliance or the ultimate effect on our operations, financial condition and results of operations.

Climate Change

Local, state, national and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues. In August 2015, the EPA issued final rules outlining the Clean Power Plan ("CPP"), which was developed in accordance with the Administration's Climate Action Plan announced the previous year. Under the CPP, carbon pollution from power plants must be reduced over 30% below 2005 levels by 2030. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs 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. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, it is uncertain if they would have an adverse effect on our financial condition and operations.

We are unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such investigations, laws, regulations and treaties (if enacted) could materially and adversely affect our operations, financial condition and results of operations.

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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. Further, the Department of the Interior has 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. Legislation has 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.

We are 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 the direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect our operations, financial condition and results of operations.

Gathering System Regulation

Regulation of gathering facilities may affect certain aspects of our business and the market for our 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 us, as well as the revenues received for sales of our 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.

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ITEM 1A. RISK FACTORS.

Risks Relating 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.

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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, 2017 and 2016, 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

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development efforts will result in the discovery and development of additional commercial accumulations of oil and natural gas.

Risks Relating 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 June 30, 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 natural 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 natural gas sector substantial setbacks. As recently as 2015 and 2016, oil and natural gas prices decreased to a point as to make almost all investment in oil and natural 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

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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

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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.

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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 99% of our production during fiscal 2017 and 2016 and 95% of our production during the six month ended June 30, 2018 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

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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.

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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 Relating 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

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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

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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 Relating 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 the first sale of common equity securities pursuant to an effective registration statement under the Securities Act of 1933, as amended;
•
  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);
•
  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.

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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 stock 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 Relating 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 we are 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 we are 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, 2026, 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.

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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 our 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

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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, tomadoes, 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;

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•
  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 2. FINANCIAL INFORMATION.

Selected Financial Information

The tables below present our selected consolidated financial data for the six months ended June 30, 2018 and 2017, and years ended December 31, 2017 and 2016, which are derived from our unaudited consolidated financial statements and our audited consolidated financial statements, respectively. Our audited consolidated financial statements 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 financial statements included in this document have been prepared in accordance with United States generally accepted accounting principles, or GAAP. Amounts are expressed in thousands of dollars, except share and per-share amounts.

|  | Six months ended June 30, |  | Years ended December 31, |
--- | --- | --- | --- | --- | ---
|  | 2018 |  | 2017 |  | 2017 |  | 2016 |
Income statement Data |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenues |  | $ | 13,943 |  | $ | 15,376 |  | $ | 25,757 |  | $ | 23,700 |
Cost of revenues |  |  | 4,238 |  |  | 3,045 |  |  | 6,619 |  |  | 7,356 |
Depreciation, depletion, amortization and accretion |  |  | 3,472 |  |  | 6,344 |  |  | 11,072 |  |  | 20,967 |
General and administrative expense |  |  | 1,637 |  |  | 1,972 |  |  | 4,418 |  |  | 2,048 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Income (loss) from operations |  |  | 4,596 |  |  | 4,015 |  |  | 3,648 |  |  | (6,671 | )
Other income (expense) |  |  | (555 | ) |  | 338 |  |  | 1,722 |  |  | (3,593 | )
Income tax benefit |  |  | (1,319 | ) |  | (2,520 | ) |  | (2,066 | ) |  | (2,696 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) attributable to Epsilon |  |  | 2,722 |  |  | 1,833 |  | $ | 7,436 |  | $ | (7,568 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) available to shareholders |  | $ | 2,722 |  | $ | 1,833 |  | $ | 7,436 |  | $ | (7,568 | )
Net income (loss) per share, basic |  | $ | 0.05 |  | $ | 0.04 |  | $ | 0.14 |  | $ | (0.16 | )
Net income (loss) per share, diluted |  | $ | 0.05 |  | $ | 0.04 |  | $ | 0.14 |  | $ | (0.16 | )
Weighted average number of shares outstanding, basic |  |  | 55,002,193 |  |  | 49,387,496 |  |  | 52,239,854 |  |  | 45,882,030 |
Weighted average number of shares outstanding, diluted |  |  | 55,024,517 |  |  | 49,414,352 |  |  | 52,266,589 |  |  | 45,882,030 |

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|  |  |  | As of December 31, |
--- | --- | --- | --- | --- | ---
|  | June 30, 2018 |
|  | 2017 |  | 2016 |
Balance sheet data |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 11,827 |  | $ | 9,999 |  | $ | 31,487 |
Oil and gas properties |  |  | 55,080 |  |  | 57,351 |  |  | 46,099 |
Gathering system properties |  |  | 13,779 |  |  | 14,628 |  |  | 17,498 |
Total assets |  |  | 85,216 |  |  | 86,406 |  |  | 100,143 |
Total long-term liabilities |  |  | 13,489 |  |  | 16,724 |  |  | 29,165 |
Total shareholders' equity(1) |  |  | 66,291 |  |  | 63,731 |  |  | 37,541 |

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

Management's Discussion and Analysis of Financial Condition and Results of Operation

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 unaudited consolidated financial statements as of June 30, 2018 and 2017 and for the six months then ended together with accompanying notes, and audited consolidated financial statements as of December 31, 2017 and 2016 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 the six months ended June 30, 2018, we paid $0.58 million to the Auburn GGS to gather and treat our 3.6 Bcf of natural gas production in Pennsylvania ($0.64 million for 4.8 Bcf of natural gas in the six months ended June 30, 2017). In 2017, we paid $1.2 million to the Auburn GGS to gather and treat our 8.9 Bcf of natural gas production in Pennsylvania.

Our common shares trade on the TSX under the ticker symbol "EPS."

At December 31, 2017, our total estimated net proved reserves were 215,588 million cubic feet (MMcf) of natural gas reserves, 37,317 barrels (Bbl) of oil and other liquids, and leasehold rights to approximately 76,171 gross (11,522 net) acres. We have natural gas production in Pennsylvania, and natural gas and oil production from our operated and non-operated wells in Oklahoma.

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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 June 30, 2018, we had $11.8 million in cash, and $12.6 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. We expect that the completion of large infrastructure projects will begin to have a positive impact on the local natural gas price.

We realized net income of $2.7 million during the six months ended June 30, 2018 as compared to net income of $1.8 million for the six months ended June 30, 2017. For the year ended December 31, 2017 we realized net income of $7.4 million as compared to net loss of $7.6 million for 2016. At December 31, 2017, our total estimated net proved reserves of natural gas were 215,588 million cubic feet, or MMcf, an increase of 166,191 MMcf from December 31, 2016. Our standardized measure of discounted future net cash flows as of December 31, 2017 and 2016 was $49.7 million and $16.4 million, respectively.

Six Months Ended June 30, 2018 Highlights

Operational Highlights

Marcellus Shale—Pennsylvania

•
  During the six months ended June 30, 2018, Epsilon's realized natural gas price was $2.24 per Mcf, a 9% decrease over the six months ended June 30, 2017.
•
  Total six months ended June 30, 2018 natural gas production of 3.56 Bcf, as compared to 4.79 Bcf during the same period in 2017. Added oil and other liquid production of 0.17 Bcfe from Oklahoma acquisitions made during 2017 for a total of 3.73 Bcfe of production for the six months ended June 30, 2018.
•
  Marcellus working interest (WI) gas averaged 23.4 MMcf/d for the first half of 2018.

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•
  Gathered and delivered 49.7 Bcf gross (17.4 Bcf net to Epsilon's interest) during the first half of 2018 through the Auburn System which represents approximately 86% of maximum throughput.

Anadarko, NW Stack Trend—Oklahoma

•
  During the six months ended June 30, 2018, Epsilon's realized price for all production was $3.87 per Mcfe.
•
  Total production for the six months ended June 30, 2018 included natural gas, oil, and other liquids and was 0.17 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

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Cdn$40 million debentures, less Cdn$36,000 in conversions, less Cdn$1.5 million repurchased by us 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 six months ended June 30, 2018, revenues decreased $1.4 million, or 9%, to $13.9 million from $15.4 million during the same period of 2017, and during the year ended December 31, 2017, revenues increased $2.1 million, or 8.7%, to $25.8 million from $23.7 million during the same period in 2016.

Revenue and volume statistics for the six months ended June 30, 2018 and 2017, and years ended December 31, 2017 and 2016 were as follows:

|  | Six months ended June 30, |  | Twelve months ended December 31, |
--- | --- | --- | --- | --- | ---
|  | 2018 |  | 2017 |  | 2017 |  | 2016 |
Revenue by product—total period ($000) |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas revenue ($000) |  | $ | 8,261 |  | $ | 11,774 |  | $ | 19,204 |  | $ | 15,263 |
Volume (MMcfe) |  |  | 3,683 |  |  | 4,792 |  |  | 9,010 |  |  | 11,016 |
Avg. Price ($/Mcfe) |  | $ | 2.24 |  | $ | 2.46 |  | $ | 2.13 |  | $ | 1.39 |
Exit Rate (MMcfepd) |  |  | 23.7 |  |  | 30.0 |  |  | 27.0 |  |  | 32.5 |
Oil and condensate revenue ($000) |  | $ | 217 |  | $ | — |  | $ | 122 |  | $ | — |
Volume (MBOE) |  |  | 3.48 |  |  | — |  |  | 3.10 |  |  | — |
Avg. Price ($/Bbl) |  | $ | 62.46 |  | $ | — |  | $ | 39.35 |  | $ | — |
Natural gas liquids revenue ($000) |  | $ | 125 |  | $ | — |  | $ | — |  | $ | — |
Volume (MBOE) |  |  | 5.68 |  |  | — |  |  | — |  |  | — |
Avg. Price ($/Mcfe) |  | $ | 22.07 |  | $ | — |  | $ | — |  | $ | — |
Midstream gathering system revenue ($000) |  | $ | 5,340 |  | $ | 3,602 |  | $ | 6,431 |  | $ | 8,437 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total Revenues |  | $ | 13,943 |  | $ | 15,376 |  | $ | 25,757 |  | $ | 23,700 |
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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 six months ended June 30, 2018, approximately 85% of the Auburn GGS revenues earned were gathering fees, while 15% were compression fees. Third-party customers represented approximately 7% of gathering revenues and 3% of compression revenues. For the six months ended June 30, 2017, approximately 80% of the Auburn GGS revenues earned were gathering fees, while 20% were compression fees. Third party customers represented approximately 10% of gathering revenues and 5% of compression revenues. Revenues derived from Epsilon's production which have been eliminated from gathering system revenues amounted to $0.58 million and $0.64 million respectively for the six months ended June 30, 2018 and 2017, and to $1.2 million and $1.7 million respectively for the years ended December 31, 2017 and 2016.

Upstream natural gas revenue for the six months ended June 30, 2018 decreased by $3.5 million, or 29.8%, over the same period in 2017 as a result of lower volumes produced and lower natural gas prices. Volumes were lower during the six months ended June 30, 2018 because no wells were drilled or completed during this time, and wells with minimal working interest to Epsilon were completed in

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2017. Also, the natural decline of production rates over time occurred. The end of the quarter daily production rate for gas in Pennsylvania was 23.7 MMcf as a result of higher natural gas prices, offset somewhat by lower volumes. Volumes were lower during 2017 because no wells were drilled or completed during 2016 and wells with minimal working interest to Epsilon were completed in 2017. Also, the natural decline of production rates over time occurred. The end of the year daily production rate for gas in Pennsylvania was 27.0 MMcf.

Gathering system revenue increased $1.7 million, or 48.3%, during the six months ended June 30, 2018, due to a 39% increase in the volumes flowing through the system and an increase in the gathering and compression rate charged. Revenue decreased $2.0 million, or 23.8%, during the year ended December 31, 2017, due to a decrease 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), net of ad valorem, severance, and production taxes for the six months ended June 30, 2018 and 2017, and years ended December 31, 2017 and 2016:

|  | Six months ended June 30, |  | Years ended December 31, |
--- | --- | --- | --- | --- | ---
(in thousands of dollars) |  | 2018 |  | 2017 |  | 2017 |  | 2016 |
Lease operating costs |  | $ | 3,522 |  | $ | 2,658 |  | $ | 5,700 |  | $ | 6,582 |
Gathering system operating costs |  |  | 716 |  |  | 387 |  |  | 896 |  |  | 773 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
|  | $ | 4,238 |  | $ | 3,045 |  | $ | 6,596 |  | $ | 7,355 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
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Upstream operating costs—Total $/Mcfe |  | $ | 0.94 |  | $ | 0.55 |  | $ | 0.63 |  | $ | 0.60 |
Gathering system operating costs $ / Mcf of throughput |  |  | 0.07 |  |  | 0.05 |  | $ | 0.14 |  | $ | 0.09 |

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 $0.58 million and $0.64 million for the six months ended June 30, 2018 and 2017, respectively (see Note 11, "Operating Segments," of the Notes to Unaudited Consolidated Financial Statements), as well as $1.2 million and $1.7 million for the years ended December 31, 2017 and 2016, respectively (see Note 12, "Operating Segments," of the Notes to Consolidated Financial Statements).

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Upstream operating costs for the six months ended June 30, 2018 increased $0.9 million, or 32.5%, 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 six months ended June 30, 2018 increased $0.3 million over the same period in 2017 because of costs related to higher throughput volumes and maintenance costs for the system. For the year ended December 31, 2017, operating costs decreased by $0.8 million, or 10.3%. Upstream cost per Mcf stayed consistent for the years ended December 31, 2017 and 2016. The overall decrease was mainly due to the decrease in volumes produced.

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

|  | Six months ended June 30, |  | Years ended December 31, |
--- | --- | --- | --- | --- | ---
(in thousands of dollars) |  | 2018 |  | 2017 |  | 2017 |  | 2016 |
Depletion, depreciation, amortization and accretion |  | $ | 3,472 |  | $ | 6,345 |  | $ | 11,072 |  | $ | 20,967 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
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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 six months ended June 30, 2018, DD&A expense decreased by $2.9 million, or 45.3%, 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 was primarily due to higher natural gas prices in 2017. Also contributing to the lower DD&A expense in 2018 was lower natural gas production volumes. During the year ended December 31, 2017, DD&A expense decreased by $9.9 million, or 47.2%, compared to the same period in 2016 mainly due to a large increase in the amount of reserves reported in the December 31, 2016 reserve report as compared to the December 31, 2015 reserve report. This increase resulted from the gain of proved reserves primarily as a result of higher natural gas prices in 2016. Also contributing to the lower DD&A expense in 2017 was lower production volumes.

General and Administrative (G&A)

|  | Six months ended June 30, |  | Years ended December 31, |
--- | --- | --- | --- | --- | ---
(in thousands of dollars) |  | 2018 |  | 2017 |  | 2017 |  | 2016 |
General and administrative |  | $ | 1,637 |  | $ | 1,972 |  | $ | 4,418 |  | $ | 2,048 |
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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.

G&A expenses decreased by $0.3 million, or 17.0%, during the six months ended June 30, 2018 compared to the same period in 2017, mainly due to decreased consulting and legal costs required for the effort to obtain a listing on a major U.S. stock exchange. As we finalize our efforts, the costs are diminishing. The G&A expenses increased by $2.4 million, or 115.7%, during the year ended December 31, 2017 from the same period in 2016, mainly due to increased personnel costs related to the hiring of a COO, and a VP of Exploration, and increased consulting and legal costs required for the effort to obtain a listing on a major U.S. stock exchange.

|  | Six months ended June 30, |  | Years ended December 31, |
--- | --- | --- | --- | --- | ---
(in thousands of dollars) |  | 2018 |  | 2017 |  | 2017 |  | 2016 |
Interest expense |  | $ | 96 |  | $ | 808 |  | $ | 903 |  | $ | 2,762 |
Debenture fee amortization |  |  | — |  |  | 53 |  |  | 53 |  |  | 322 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Interest expense |  | $ | 96 |  | $ | 861 |  | $ | 956 |  | $ | 3,084 |
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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 six months ended June 30, 2018 from $0.9 million for the six months ended June 30, 2017 to $0.1 million. This was due to the maturing and payoff of the convertible debentures in February 2017. Interest expense decreased during the year ended December 31, 2017 from $3.1 million for the year ended December 31, 2016 to $0.96 million, or 69.0%. This was due to the maturing and payoff of the convertible debentures in February 2017.

Net Gain (Loss) on Commodity Contracts

|  | Six months ended June 30, |  | Years ended December 31, |
--- | --- | --- | --- | --- | ---
(in thousands of dollars) |  | 2018 |  | 2017 |  | 2017 |  | 2016 |
Net gain (loss) on commodity contracts |  | $ | (474 | ) | $ | 1,169 |  | $ | 2,624 |  | $ | (488 | )
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For the six months ended June 30, 2018 and 2017, we entered into fixed price swap and basis swap derivative contracts. During the periods, the company received $119,373 and $387,975, respectively, on the settlement of contracts.

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 company received $2,027,791 on the settlement of contracts.

During 2016, we entered into fixed price swap derivative contracts. During the period, the company paid $151,198 on the settlement of contracts.

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Miscellaneous Income (Expense)

|  | Six months ended June 30, |  | Years ended December 31, |
--- | --- | --- | --- | --- | ---
(in thousands of dollars) |  | 2018 |  | 2017 |  | 2017 |  | 2016 |
Miscellaneous income (expense) |  | $ | 15 |  | $ | 31 |  | $ | 54 |  | $ | (21 | )
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Miscellaneous income (expense) consists primarily of interest income, and gains and losses on foreign currency transactions.

For the six months ended June 30, 2018 miscellaneous income consisted primarily of a state income tax refund and interest income and in 2017, it consisted primarily of interest income, and for the year ended December 31, 2017 and 2016, miscellaneous income (expense) consisted primarily of interest income, and foreign currency gains and (losses).

Capital Resources and Liquidity

Cash Flow

Our primary source of cash during the six months ended June 30, 2018 and 2017 was funds generated from operations. In addition to operations, the primary uses of cash for the six months ended June 30, 2018 were income tax pre-payments and payments on the revolving line of credit. For 2017, funds were used for acquisition and development expenditures, for the payoff of our convertible debentures, and payments on the revolving line of credit in addition to operations.

Our primary source of cash during the year ended December 31, 2016, was funds generated from operations. 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, 2016, were funds used in operations, development expenditures, the buyback of Epsilon common shares, and the buyback of Epsilon convertible debentures. 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 June 30, 2018, we had a working capital surplus of $10.4 million, an increase of $2.5 million over the $7.9 million surplus at June 30, 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, partially offset by the classification of the credit facility as current as of March 31, 2018.

At December 31, 2017, we had a working capital surplus of $7.9 million, an increase of $5.3 million over the $2.6 million surplus at December 31, 2016. The surplus increased over the last year because of the completion of the rights offering, a consistent increase of revenues due to higher natural gas prices, and the reduction of large interest payments due to the payoff of the convertible debentures in February 2017.

Six months ended June 30, 2018 compared to 2017

During the six months ended June 30, 2018, $4.5 million was provided by the Corporation's operating activities, compared to $9.9 million provided during the same period in 2017, a $5.4 million, and 55.1% decrease. The decrease was mainly due to estimated tax payments of $3.5 million and a decrease in revenue as discussed previously.

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The Corporation used $0.3 million of cash for investing activities during the six months ended June 30, 2018. This was spent primarily on leashold costs in Oklahoma and Pennsylvania, and the acquisition of a piece of unproved property in Oklahoma. For the six months ended June 30, 2017, the Corporation used $6.9 million, mainly on the acquisition in the Anadarko Basin.

The $2.2 million of cash used for financing activity during the six months ended June 30, 2018 was related to the repurchase of common shares of the Corporation and the repayment of the revolving line of credit. The $21.1 million spent during the six months ended June 30, 2017, was used for the redemption of the convertible debentures and the payoff of the Corporation's line of credit, offset by common shares issued through a rights offering.

Year ended December 31, 2017 compared to 2016

During the year ended December 31, 2017, $17.5 million was provided by our operating activities, compared to $11.1 million in 2016, a $6.4 million, or 57%, increase. The increase was due to increased revenue from higher natural gas prices.

We used $19.3 million for investing activities during the year ended December 31, 2017 primarily for the acquisition of oil and gas properties in the Anadarko basin. During the same period of 2016, we used $1.3 million, mainly for further development of the gathering system.

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.

During the year ended December 31, 2016, financing activities provided us net cash of $4.3 million primarily due to a net draw of $5.5 million on our revolving line of credit. This was offset by the buyback of our common shares.

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 $13.5 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 February 21, 2017 the agreement was amended to extend the maturity date to March 1, 2019. At that time, the Corporation expects to renew the agreement.

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.

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We were in compliance with the financial covenants of the agreement as of June 30, 2018 and December 31, 2017.

|  | Balance as at June 30, 2018 |  | Balance as at December 31, 2017 |  | Borrowing Base June 30, 2018 |  | Interest Rate
--- | --- | --- | --- | --- | --- | --- | --- | ---
Revolving line of credit |  | $ | 900,000 |  | $ | 2,900,000 |  | $ | 13,500,000 |  | 3 mo LIBOR + 2.75%
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

In December 2017 our borrowing base was reduced to $13.5 million, resulting in available borrowing capacity under the credit agreement of $12.6 million as of June 30, 2018.

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 June 30, 2018, our outstanding natural gas commodity swap contracts consisted of the following:

|  |  |  | Weighted Average Price ($/Mmbtu) |  |  |
--- | --- | --- | --- | --- | --- | --- | ---
Derivative Type |  | Volume (Mmbtu) |  | Swaps |  | Basis Differential |  | Fair Value of Asset June 30, 2018 |
2018 |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed price swap |  |  | 2,372,500 |  | $ | 2.88 |  | $ | — |  |  | (142,180 | )
Basis swap |  |  | 2,372,500 |  | $ | — |  | $ | (0.55 | ) |  | (11,683 | )
2019 |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed price swap |  |  | 1,350,000 |  | $ | 3.02 |  | $ | — |  |  | (84,615 | )
Basis swap |  |  | 1,350,000 |  | $ | — |  | $ | (0.48 | ) |  | (95,437 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
|  |  |  |  |  |  |  |  |  |  | $ | (333,915 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

Contractual Obligations

The following table summarizes our contractual obligations at June 30, 2018:

|  | Payments Due by Period |  |  |  |  |
--- | --- | --- | --- | --- | --- | --- | ---
|  | Total |  | Less than 1 Year |  | 1 - 3 Years |  | Greater than 3 Years |
Revolving line of credit |  | $ | 900,000 |  | $ | 900,000 |  | $ | — |  | $ | — |
Derivative liabilities |  |  | 445,308 |  |  | 445,308 |  |  | — |  |  | — |
Asset retirement obligation, undiscounted |  |  | 12,025,568 |  |  | — |  |  | — |  |  | 12,025,568 |
Operating leases |  |  | 126,645 |  |  | 79,542 |  |  | 47,103 |  |  | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total future commitments |  | $ | 13,497,521 |  | $ | 1,424,850 |  | $ | 47,103 |  | $ | 12,025,568 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

The revolving line of credit amount included in commitments is principal only as the interest rate is variable. At June 30, 2018, the rate was 5.1%.

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

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incur the expenditures in a future period. This commitment has not been included in the commitment table above as it is of a routine nature and is part of normal course of operations for active oil and gas companies. As of June 30, 2018, we have no material commitments for capital expenditures.

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 June 30, 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.

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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. 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.

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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, we compare 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,

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option pricing models, futures prices, volatility, time to maturity, and credit risk. The values reported in our 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 Company has 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 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

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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.

In July 2018, the FASB issued ASU 2018-09, "Codification Improvements." Periodically, the Financial Accounting Standards Board (FASB) updates the Accounting Standards Codification for minor technical corrections and clarifications that are deemed necessary. These changes are made to clarify the Codification, correct unintended application of guidance, and make minor improvements to the Codification that are not expected to have a significant effect on current accounting practice. We have examined the provisions and do not anticipate any of them to materially affect our financial statements.

In May 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 company 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. 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 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, 2019. 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

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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)."

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 June 30, 2018, the outstanding principal balance under the credit agreement was $0.9 million, and the weighted average interest rate on the outstanding principal balance was 5.1%. The carrying amount approximated fair market value. Assuming a constant debt level of $0.9 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 $0.01 million over a 12-month time period. At December 31, 2017, the outstanding principal balance under the credit agreement was $2.9 million, and the weighted average interest rate

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on the outstanding principal balance was 4.1%. At December 31, 2017, 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

Our 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. We have 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 us to losses or gains, entering into these contracts helps to stabilize cash flows and support our capital spending program.

Financial Statements and Supplementary Data

Our consolidated balance sheet as of June 30, 2018 and as of December 31, 2017 and 2016, and the consolidated statements of operations and comprehensive income (loss), changes in shareholders' equity and cash flows for the six months ended June 30, 2018 and 2017, and years ended December 31, 2017 and 2016 included in this document have been prepared in accordance with U.S. GAAP.

ITEM 3. PROPERTIES.

The information required by Item 3 is contained in "Item 1. Business."

ITEM 4. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

The table set forth below is information with respect to beneficial ownership of common shares as of June 30, 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.

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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 |  | Number of Shares of Common Shares |  | Percentage of Common Shares Owned |
--- | --- | --- | --- | --- | ---
5% Stockholders |  |  |  |  |  |  |
Advisory Research, Inc.(1) |  |  | 6,621,026 |  |  | 12.06 | %
JVL Advisors, LLC(2) |  |  | 10,996,837 |  |  | 20.02 | %
Oakview Capital Management, L.P.(3) |  |  | 6,319,465 |  |  | 11.51 | %
azValor Asset Management SGIIC SA(4) |  |  | 10,305,237 |  |  | 18.76 | %
Named Executive Officers and Directors |  |  |  |  |  |  |
Matthew Dougherty(5) |  |  | 6,816,326 |  |  | 12.42 | %
Jacob Roorda(6) |  |  | 115,000 |  |  | * |
Bruce Lane Bond(7) |  |  | 198,300 |  |  | * |
John Lovoi(8) |  |  | 11,016,837 |  |  | 20.07 | %
Ryan Roebuck(9) |  |  | 134,050 |  |  | * |
Tracy Stephens(10) |  |  | 0 |  |  | * |
Adrian Montgomery(11) |  |  | 20,000 |  |  | * |
Henry Clanton(12) |  |  | 20,000 |  |  | * |
Michael Raleigh(13) |  |  | 100,000 |  |  | * |
All executive officers and directors as a group (9 persons)(14) |  |  | 18,420,513 |  |  | 33.55 | %

*
  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. Matthew Dougherty, a member of our board of directors, is a managing director of ARI, exercises the voting and dispositive power with respect to the common shares held by 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. Jay Singhania exercises the voting and dispositive power with respect to the common shares held by Oakview Capital Management, L.P.
(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 195,300 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 50,000 shares held by Mr. Roorda's spouse, and 6,700 shares issuable upon the exercise of options exercisable within 60 days of June 30, 2018.
(7)
  Includes 63,300 shares issuable upon the exercise of options exercisable within 60 days of June 30, 2018. Mr. Bond is our chief financial officer.
(8)
  Includes the shares held by JVL. Includes 20,000 shares issuable upon the exercise of options held by Mr. Lovoi and exercisable within 60 days of June 30, 2018. Mr. Lovoi is the chairman of our board of directors.
(9)
  Includes 20,000 shares issuable upon the exercise of options exercisable within 60 days of June 30, 2018. Mr. Roebuck is a member of our board of directors.
(10)
  Mr. Stephens is a member of our board of directors.

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(11)
  Includes 20,000 shares issuable upon the exercise of options exercisable within 60 days of June 30, 2018. 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 June 30, 2018. Mr. Clanton is our chief operating officer.
(13)
  Includes 100,000 shares issuable upon the exercise of options exercisable within 60 days of June 30, 2018. Mr. Raleigh is our chief executive officer and a member of our board of directors.
(14)
  Includes 250,000 shares issuable upon the exercise of options exercisable within 60 days of June 30, 2018.

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 5. DIRECTORS AND EXECUTIVE OFFICERS.

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 June 30, 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 |  | 62 |  | Chief Executive Officer and Director
B. Lane Bond |  | 59 |  | Chief Financial Officer
Henry Clanton |  | 56 |  | Chief Operating Officer
John Lovoi |  | 57 |  | Chairman of the Board and Director
Matthew Dougherty |  | 37 |  | Director
Adrian Montgomery |  | 45 |  | Director
Ryan Roebuck |  | 33 |  | Director
Jacob Roorda |  | 61 |  | Director
Tracy Stephens |  | 58 |  | Director

Biographies of Corporate Directors and Executive Officers.

Michael Raleigh. Mr. Raleigh has served as our chief executive officer and a director since July 2013. Before becoming our chief executive officer, 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. 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.

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 Company 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.

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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 the manager of Lobo Baya, LLC, a Director of Helix Energy Solutions Group, an operator of offshore oil and gas properties and production facilities and the Chairman of Dril-Quip, Inc., a provider of subsea, surface and offshore rig equipment. 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 and equity research 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 has been an investment manager of XDR Capital Group, a private investment firm located in Toronto, Canada, since August 2011. Mr. Roebuck has been the Chief Financial Officer of NextBlock Global Limited, a leading blockchain investment company since July 2017. He currently serves as a director of Apollo Acquisition Corporation and has served as a director and member of the Audit Committee of Cronos Group. He previously worked in investment banking as a research analyst covering North American equities. 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 as an investment manager and financial analyst.

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 Chief Executive Officer 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 and Reserves Committees of Petroshale Inc., Argosy Energy Inc. and Angle Energy Inc. He also currently serves on the boards of Wolf Minerals Limited, Northcliff Resources Ltd., South Louisiana Methanol GP LLC and TSL Methanol LLC. 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.

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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, owner of 20.02% of our common shares. Mr. Dougherty is the Managing Director of Advisory Research, Inc., owner of 12.06% of our common shares. Mr. Raleigh is our Chief Executive Officer.

The Board held four meetings during the six months ended June 30, 2018, seven meetings during 2017, and nine meetings during 2016. 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

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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

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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 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

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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 NASDAQ Capital Market. A copy of the Audit Committee Charter can be found on our website at www.epsilonenergyltd.com.

Compensation, Nominating and Corporate Governance Committee. The Compensation, Nominating and Corporate Governance Committee 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.

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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 and contains provisions for severance payments equal to six months of current annual salary in the event that a change of control occurred. 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 6. 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 our shareholders 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

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executive officers for the two years ended December 31, 2017 and 2016. Compensation amounts in the following table are in U.S. dollars unless stated otherwise.

|  |  |  |  |  | Share-based awards |  | Option-based awards |  | Non-equity incentive plan compensation ($) |  |  |  |  |  |  |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
|  |  |  |  |  |  |  | Bonuses and director fees ($) |  |  |
Name and principal position |  | Year |  | Salary ($) |  | Share-based awards ($) |  | Option-based awards ($) |  | Annual Incentive plans |  | Long-term Incentive plans |  | Pension value ($) |  | Total compensation ($) |
Michael Raleigh, CEO(1) |  |  | 2017 |  |  | — |  |  | 775,000 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 775,000 |
|  |  | 2016 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Henry Clanton, COO(2) |  |  | 2017 |  |  | 250,000 |  |  | — |  |  | 68,627 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 318,627 |
|  |  | 2016 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
B. Lane Bond, CFO(3) |  |  | 2017 |  |  | 200,000 |  |  | — |  |  | 66,079 |  |  | — |  |  | — |  |  | — |  |  | 70,000 |  |  | 336,079 |
|  |  | 2016 |  |  | 198,077 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 50,000 |  |  | 248,077 |

(1)
  Mr. Raleigh is currently working without a salary from us; however, he was granted the following equity award in 2017.

  2017—Share award of 250,000 Common Shares under the Share Compensation Plan valued at $3.10 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.

  2016—No stock options were granted.

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

  2017—Options to purchase 60,000 Common Shares at a price of $3.27 per Common Share with a term of three years and fully vested as of 1/09/2020.

(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:

  2017—Options to purchase 55,000 Common Shares at a price of $3.40 per Common Share with a term of three years and fully vested as of 1/26/2020.

  2016—No stock options were granted.

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 2,000,000. As of June 30, 2018, options for 581,500 common shares were outstanding under the 2017 Plan, and 40,000 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.

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In the event we undergo a change of control by a reorganization, acquisition, amalgamation or merger (or a plan or arrangement in connection with any of these) with respect to which all or substantially all of the persons who were the beneficial owners of the Common Shares immediately prior to such transaction do not, following such transaction, beneficially own, directly or indirectly more than 50% of the resulting voting power, a sale of all, or substantially all, of the 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 2,000,000 Common Shares. As of June 30, 2018, a total of 325,000 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.

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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 June 30, 2018, are as follows:

|  |  |  |  |  |  |  |  |  | Share-based Awards |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Option-based Awards |
| Number of shares or units of shares that have not vested (#) |  | Market or payout value of share-based awards that have not vested ($) |
Name |  | Number of securities underlying unexercised options (#) |  | Option exercise price ($) |  | Option expiration date |  | Value of unexercised in-the-money options ($) |
Michael Raleigh |  |  | 100,000 |  |  | 3.67 |  |  | 06/05/22 |  |  | — |  |  | 250,000 |  |  | 775,000 |
Henry Clanton |  |  | 60,000 |  |  | 3.27 |  |  | 01/09/24 |  |  | — |  |  | — |  |  | — |
B. Lane Bond |  |  | 45,000 |  |  | 3.67 |  |  | 06/05/22 |  |  | — |  |  | — |  |  | — |
B. Lane Bond |  |  | 55,000 |  |  | 3.40 |  |  | 01/26/24 |  |  | — |  |  | — |  |  | — |

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, 2017 are as follows:

Name |  | Option-based awards—Value vested during the year ($) |  | Share-based awards—Value vested during the year ($) |  | Non-equity incentive plan compensation—Value earned during the year ($)
--- | --- | --- | --- | --- | --- | ---
Michael Raleigh |  | N/A |  | N/A |  | N/A
Henry Clanton |  | N/A |  | N/A |  | N/A
B. Lane Bond |  | N/A |  | N/A |  | N/A

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

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

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Director Compensation

The following table contains compensation earned in the year ended December 31, 2017 by our independent directors who are not named executive officers:

Amounts Shown in Cdn$ Name (a) |  | Fees earned ($) (b) |  | Share-based awards ($) (c) |  | Option-based ($) (d) |  | Non-equity incentive plan compensation ($) (e) |  | Pension value ($) (f) |  | All other compensation ($) (g) |  | Total ($) (h) |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
John Lovoi* |  | $ | — |  | $ | 43,800 |  | $ | — |  | $ | — |  | $ | — |  | $ | — |  | $ | 43,800 |
Michael Raleigh* |  | $ | — |  | $ | 250,000 |  | $ | — |  | $ | — |  | $ | — |  | $ | — |  | $ | 250,000 |
Matthew Dougherty* |  | $ | — |  | $ | — |  | $ | — |  | $ | — |  | $ | — |  | $ | — |  | $ | — |
Adrian Montgomery |  | $ | 38,000 |  | $ | 43,800 |  | $ | — |  | $ | — |  | $ | — |  | $ | — |  | $ | 81,800 |
Jacob Roorda |  | $ | 35,250 |  | $ | 43,800 |  | $ | 28,595 |  | $ | — |  | $ | — |  | $ | — |  | $ | 107,645 |
Ryan Roebuck |  | $ | 40,750 |  | $ | 43,800 |  | $ | — |  | $ | — |  | $ | — |  | $ | — |  | $ | 84,550 |
Tracy Stephens |  | $ | 26,666 |  | $ | 43,800 |  | $ | — |  | $ | — |  | $ | — |  | $ | — |  | $ | 70,466 |

*
  The three directors who are not independent, Messrs. Lovoi, Raleigh and Dougherty, choose not to receive payment for their service as board members.

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.

For the four months ended April 30, 2017, the independent directors were compensated in cash for their services as follows:

Annual Retainer Fee (Cdn$) |  |  |  |
Board member fees |  | $ | 27,000 |
Committee chair fees (except audit) |  |  | — |
Audit committee chair fee |  | $ | 7,500 |
Committee membership (except audit) |  | $ | 5,000 |
Audit committee membership |  | $ | 4,000 |
Attendance Fees (Cdn$) |  |  |  |
Chairman of the Board |  |  | — |
Director |  | $ | 12,000 |
Committee chair fees (except audit) |  |  | — |
Audit committee chairman |  | $ | 6,000 |
Committee member (except audit) |  | $ | 3,000 |
Audit committee member |  | $ | 4,000 |

On April 13, 2017, the Board of Directors revised the requirements for compensation of independent directors. 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.

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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, 2017 are as follows:

Option-based Awards |  | Share-based Awards |
--- | --- | --- | ---
Name |  | Number of securities underlying unexercised options (#) |  | Option exercise price ($) |  | Option expiration date |  | Value of unexercised in-the-money options ($) |  | Number of shares or units of shares that have not vested (#) |  | Market or payout value of share-based awards that have not vested ($) |
John Lovoi |  |  | 20,000 |  |  | 3.67 |  |  | 6/5/2022 |  |  | — |  |  | 15,000 |  |  | 43,800 |
Adrian Montgomery |  |  | 20,000 |  |  | 3.67 |  |  | 6/5/2022 |  |  | — |  |  | 15,000 |  |  | 43,800 |
Ryan Roebuck |  |  | 20,000 |  |  | 3.67 |  |  | 6/5/2022 |  |  | — |  |  | 15,000 |  |  | 43,800 |
Jacob Roorda |  |  | 25,000 |  |  | 3.27 |  |  | 1/9/2024 |  |  | — |  |  | 15,000 |  |  | 43,800 |
Tracy Stephens |  |  | — |  |  | — |  |  |  |  |  | — |  |  | 15,000 |  |  | 43,800 |

The values of incentive plan awards that were vested or earned during the year ended December 31, 2017are as follows:

Name |  | Option-based awards—Value vested during the year ($) |  | Share-based awards—Value vested during the year ($) |  | Non-equity incentive plan compensation—Value earned during the year ($)
--- | --- | --- | --- | --- | --- | ---
John Lovoi |  | N/A |  | N/A |  | N/A
Adrian Montgomery |  | N/A |  | N/A |  | N/A
Ryan Roebuck |  | N/A |  | N/A |  | N/A
Jacob Roorda |  | N/A |  | N/A |  | N/A

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 7. 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.

Independence of the Board of Directors

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

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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. See "Item 5. Directors and Executive Officers."

ITEM 8. 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 9. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT'S 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 TSX. The prices reflect inter-dealer prices without regard to retail markups, markdowns or commissions and do not necessarily reflect actual transactions. As of October 23, 2018, the Federal Reserve Bank of New York noon buying rate was $1.3098 Canadian dollars per U.S. dollar.

|  | Cdn$ |
--- | --- | --- | ---
|  | High |  | Low |
Year Ended December 31, 2018 |  |  |  |  |  |  |
Fourth Quarter (through October 30, 2018) |  | $ | 2.58 |  | $ | 2.48 |
Third Quarter |  | $ | 2.88 |  | $ | 2.33 |
Second Quarter |  | $ | 2.95 |  | $ | 2.30 |
First Quarter |  | $ | 2.98 |  | $ | 2.30 |
Year Ended December 31, 2017 |  |  |  |  |  |  |
Fourth Quarter |  | $ | 3.35 |  | $ | 2.92 |
Third Quarter |  | $ | 3.20 |  | $ | 2.90 |
Second Quarter |  | $ | 3.20 |  | $ | 2.75 |
First Quarter |  | $ | 3.45 |  | $ | 2.91 |
Year Ended December 31, 2016 |  |  |  |  |  |  |
Fourth Quarter |  | $ | 3.05 |  | $ | 2.87 |
Third Quarter |  | $ | 3.39 |  | $ | 2.88 |
Second Quarter |  | $ | 3.40 |  | $ | 3.15 |
First Quarter |  | $ | 3.40 |  | $ | 2.28 |

Shareholders. We had approximately 1,400 shareholders of record as of June 30, 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 June 30, 2018, we were authorized to issue options covering up to 2,000,000 common shares. As of that date, we had issued options to purchase 581,500 common shares, leaving a maximum amount of 1,418,500 common shares available for future option issuances. The following table sets out the number of common shares to be

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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:

|  | Six months ended June 30, 2018 |  | Year ended December 31, 2017 |
--- | --- | --- | --- | --- | ---
Exercise price in Cdn$ |  | Number of Options Outstanding |  | Weighted Average Exercise Price |  | Number of Options Outstanding |  | Weighted Average Exercise Price |
Balance at beginning of period |  |  | 661,500 |  | $ | 3.43 |  |  | 511,000 |  | $ | 3.33 |
Granted |  |  | — |  | $ | — |  |  | 241,500 |  | $ | 3.35 |
Exercised |  |  | — |  | $ | — |  |  | (40,000 | ) | $ | 1.63 |
Expired |  |  | (80,000 | ) | $ | 4.00 |  |  | (51,000 | ) | $ | 3.53 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at period-end |  |  | 581,500 |  | $ | 3.35 |  |  | 661,500 |  | $ | 3.43 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Exercisable at period-end |  |  | 420,498 |  | $ | 3.35 |  |  | 323,333 |  | $ | 3.41 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

As of June 30, 2018, we had no warrants or other common share-related rights outstanding.

ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES.

Within the last three years, the Company has sold the following securities which were not registered under the Securities Act:

•
  On February 15, 2017, we issued 224 common shares as repayment for Cdn$1,000 of the debenture.
•
  On April 21, 2017, we issued 9,167,617 common shares with respect to a rights offerings. The subscription price was $2.68 per share, with gross proceeds of $17,984,664.
•
  On June 12, 2017, we issued 40,000 common shares to Paul Atwood, upon the exercise of options which were issued under the Share Compensation Plan. The common shares were issued at an exercise price of Cdn$1.63 per share.

ITEM 11. DESCRIPTION OF REGISTRANT'S SECURITIES TO BE REGISTERED.

The following description of our capital stock is a summary only and is qualified in its entirety by reference to our Articles and Bylaws, which are included as Exhibits 3.1 and 3.2 of this registration statement.

This registration statement relates to the registration of the common shares under Section 12(b) of the Exchange Act, and a summary of the material terms of the common shares appears below.

The holders of common shares are entitled to notice of and to vote at all meetings of shareholders (except meetings at which only holders of a specified class or series of shares are entitled to vote) and are entitled to one vote per common share. There are no restrictions on foreign holders voting our common shares. Holders of common shares are entitled to receive, if, as and when declared by the board of directors, such dividends as may be declared thereon by the board of directors from time to time. In the event of our liquidation, dissolution or winding-up, or any other distribution of assets among its shareholders for the purpose of winding-up its affairs, holders of common shares, are entitled to share equally on a pro rata basis, in the remaining property.

Capital Structure. Under our Alberta articles of incorporation, we have the authority to issue an unlimited number of common shares and an unlimited number of preferred shares. Under Alberta law, there is no franchise tax on our authorized capital stock.

Shareholder Approval; Vote on Extraordinary Corporate Transactions. Under the ABCA, certain extraordinary corporate actions, such as a name change, amalgamations (other than with certain

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affiliated corporations), continuances to another jurisdiction and sales, leases or exchanges of all, or substantially all, of the property of a corporation (other than in the ordinary course of business), and other extraordinary corporate actions such as liquidations, dissolutions and arrangements (if ordered by a court), are required to be approved by a "special resolution" of shareholders.

A "special resolution" is a resolution (1) passed by not less than two-thirds of the votes cast by the shareholders who voted in respect of the resolution at a meeting duly called and held for that purpose or (2) signed by all shareholders entitled to vote on the resolution. In specified cases, a special resolution to approve an extraordinary corporate action is also required to be approved separately by the holders of a class or series of shares, including in certain cases a class or series of shares not otherwise carrying voting rights (unless in certain cases the share provisions with respect to such class or series of shares provide otherwise).

Amendments to the Governing Documents. Under the ABCA, amendments to the articles of incorporation generally requires approval by special resolution of the voting shares. If the proposed amendment would affect a particular class of securities in certain specified ways, the holders of shares of that class would be entitled to vote separately as a class on the proposed amendment, whether or not the shares otherwise carry the right to vote.

The ABCA allows the directors, by resolution, to make, amend or repeal any bylaws that regulate the business or affairs of the corporation. When directors make, amend or repeal a bylaw, they are required under the ABCA to submit the change to shareholders at the next meeting of shareholders. Shareholders may confirm, reject or amend the bylaw, the amendment or the repeal with the approval of a majority of the votes cast by shareholders who voted on the resolution. If a bylaw, or an amendment or a repeal of a bylaw, is rejected by the shareholders, or if the directors do not submit a bylaw, or an amendment or a repeal of a bylaw, to the shareholders, the bylaw, amendment or repeal ceases to be effective and no subsequent resolution of the directors to make, amend or repeal a bylaw having substantially the same purpose or effect is effective until it is confirmed or confirmed as amended by the shareholders.

Place of Meetings. Pursuant to the ABCA, if the articles of the corporation so provide, meetings of shareholders may be held outside of Alberta. The Corporation's articles provide that meetings of shareholders may be held outside of Alberta at any place within Canada or the United States as the Board so determines.

Quorum of Shareholders. The ABCA provides that, unless the bylaws provide otherwise, a quorum of shareholders is present at a meeting of shareholders (irrespective of the number of persons actually present at the meeting) if holders of a majority of the shares entitled to vote at the meeting are present in person or represented by proxy. The bylaws provide that a quorum is present if there are at least two persons present holding or representing by proxy in the aggregate not less than 5% of the share entitled to be voted at the meeting.

Calling Meetings. The ABCA provides that the directors shall call an annual meeting of shareholders not later than 15 months after the last preceding annual meeting, and may at any time call a special meeting of shareholders. The registered holders or beneficial owners of not less than 5% of the issued shares of a corporation that carry the right to vote at a meeting sought to be held may requisition the directors to call a meeting of shareholders for the purposes stated in the requisition, but the beneficial owners of shares do not hereby acquire the direct right to vote at the meeting that is the subject of the requisition.

Shareholder Consent in Lieu of Meeting. Under the ABCA, a resolution in writing signed by all of the shareholders entitled to vote on that resolution is as valid as if it had been passed at a meeting of shareholders.

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Director Election, Qualification and Number. The ABCA provides for the election of directors by a majority of votes cast at an annual meeting of shareholders. The ABCA states that a corporation shall have one or more directors but a distributing corporation whose shares are held by more than one person shall have not fewer than 3 directors, at least 2 of whom are not officers or employees of the corporation or its affiliates. Additionally, at least one fourth of the directors must be Canadian residents unless the corporation has fewer than four directors, in which case at least one director must be a Canadian resident.

Vacancies on Board of Directors. Under the ABCA, a vacancy among the directors created by the removal of a director may be filled at a meeting of shareholders at which the director is removed. The ABCA also allows a vacancy on the board to be filled by a quorum of directors, except when the vacancy is a result of a failure to elect the number or minimum number of directors required by the articles. In addition, the ABCA authorizes the directors to, if the articles so provide, between annual general meetings, appoint one or more additional directors of the corporation to serve until the next annual general meeting, so long as the number of additional directors shall not at any time exceed 1/3 of the number of directors who held office at the expiration of the last annual meeting of the corporation.

Removal of Directors; Terms of Directors. Under the ABCA, provided that the articles of a corporation do not provide for cumulative voting, shareholders of the corporation may, by ordinary resolution passed at a special meeting, remove any director or directors from office. If holders of a class or series of shares have the exclusive right to elect one or more directors, a director elected by them may only be removed by an "ordinary resolution" at a meeting of the shareholders of that class or series.

An "ordinary resolution" means a resolution (1) passed by a majority of the votes cast by the shareholders who voted in respect of that resolution, or (2) signed by all the shareholders entitled to vote on that resolution.

Fiduciary Duty of Directors. Directors of a corporation incorporated under the ABCA have fiduciary obligations to the corporation. The ABCA requires directors and officers of an Alberta corporation, in exercising their powers and discharging their duties, to act honestly and in good faith with a view to the best interests of the corporation and exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances.

Indemnification of Officers and Directors. Under the ABCA and pursuant to the Corporation's bylaws, the Corporation will indemnify present or former directors or officers against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment that is reasonably incurred by the individual in relation to any civil, criminal, administrative, investigative or other proceeding in which the individual is involved because of his or her association with us. In order to qualify for indemnification such directors or officers must:

1)
  have acted honestly and in good faith with a view to the best interests of the corporation; and
2)
  in the case of a criminal or administrative action or proceeding enforced by a monetary penalty, have had reasonable grounds for believing that his conduct was lawful.

The Corporation carries liability insurance for the Corporation's and its subsidiaries' officers and directors.

The ABCA also provides that such persons are entitled to indemnity from the corporation in respect of all costs, charges and expenses reasonably incurred in connection with the defense of any such proceeding if the person was not judged by the court or other competent authority to have committed any fault or omitted to do anything that the person ought to have done, and otherwise meets the qualifications for indemnity described above.

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Dissent or Dissenters' Appraisal Rights. The ABCA provides that shareholders of a corporation entitled to vote on certain matters are entitled to exercise dissent rights and demand payment for the fair value of their shares in connection with specified matters, including, among others:

•
  an amendment to our articles of incorporation to add, change or remove any provisions restricting the issue or transfer of shares;
•
  amend our articles to add, change or remove any restrictions on the business or businesses that the corporation may carry on;
•
  any amalgamation with another corporation (other than with certain affiliated corporations);
•
  a continuance under the laws of another jurisdiction; and
•
  a sale, lease or exchange of all or substantially all the property of the corporation other than in the ordinary course of business.

However, a shareholder is not entitled to dissent if an amendment to the articles is effected by a court order approving a reorganization or by a court order made in connection with an action for an oppression remedy.

Oppression Remedy.

The ABCA provides an oppression remedy that enables a court to make any order, whether interim or final, to rectify matters that are oppressive or unfairly prejudicial to or that unfairly disregard the interests of any security holder, creditor, director or officer of the corporation if an application is made to a court by a "complainant."

A "complainant" with respect to a corporation means any of the following:

•
  a present or former registered holder or beneficial owner of a security of the corporation or any of its affiliates,
•
  a present or former director or officer of the corporation or of any of its affiliates,
•
  a creditor in respect of an application under a derivative action; or
•
  any other person who, in the discretion of the court, is a proper person to make the application.

The oppression remedy provides the court with very broad and flexible powers to intervene in corporate affairs to protect shareholders and other complainants. While conduct that is in breach of fiduciary duties of directors or that is contrary to the legal right of a complainant will normally trigger the court's jurisdiction under the oppression remedy, the exercise of that jurisdiction does not depend on a finding of a breach of those legal and equitable rights.

Derivative Actions. Under the ABCA, a complainant may also apply to the court for permission to bring an action in the name of, and on behalf of, the corporation, or to intervene in an existing action to which the corporation or its subsidiary is a party, for the purpose of prosecuting, defending or discontinuing an action on the corporation's behalf or on behalf of its subsidiary. Under the ABCA, no action may be brought and no intervention in an action may be made unless a court is satisfied that:

(1)
  the complainant has given reasonable notice to the directors of the corporation or its subsidiary of the complainant's intention to apply to the court if the directors of the corporation or its subsidiary do not bring, diligently prosecute, defend or discontinue the action,
(2)
  the complainant is acting in good faith, and
(3)
  it appears to be in the interests of the corporation or its subsidiary that the action be brought, prosecuted, defended or discontinued.

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Under the ABCA, the court in a derivative action may make any order it sees fit including orders pertaining to the control or conduct of the lawsuit by the complainant or the making of payments to former and present shareholders and payment of reasonable legal fees incurred by the complainant.

Examination of Corporate Records. Under the ABCA, upon payment of a reasonable fee, a person is entitled during usual business hours to examine certain corporate records, such as the securities register and a list of shareholders, and to make copies of or extracts from such documents.

Other Important Ownership and Exchange Controls

There is no limitation imposed by applicable Alberta law or by our articles on the right of a non-resident to hold or vote our common shares, other than as discussed herein.

Competition Act. Limitations on the ability to acquire and hold our common shares may be imposed by the Competition Act (Canada). This legislation permits the Commissioner of Competition, or Commissioner, to review any acquisition or establishment, directly or indirectly, including through the acquisition of shares, of control over or of a significant interest in us. This legislation grants the Commissioner jurisdiction, for up to one year after the acquisition has been substantially completed, to seek a remedial order, including an order to prohibit the acquisition or require divestitures, from the Canadian Competition Tribunal, which order may be granted where the Competition Tribunal finds that the acquisition substantially prevents or lessens, or is likely to substantially prevent or lessen, competition.

This legislation also requires any person or persons who intend to acquire more than 20% of our voting shares or, if such person or persons already own more than 20% of our voting shares prior to the acquisition, more than 50% of voting our shares, to file a notification with the Canadian Competition Bureau if certain financial thresholds are exceeded. Where a notification is required, unless an exemption is available, the legislation prohibits completion of the acquisition until the expiration of the applicable statutory waiting period, unless the Commissioner either waives or terminates such waiting period.

Investment Canada Act. The Investment Canada Act requires each "non-Canadian" (as defined in the Investment Canada Act) who acquires "control" of an existing "Canadian business", where the acquisition of control is not a reviewable transaction, to file a notification in prescribed form with the responsible federal government department or departments not later than 30 days after closing. Subject to certain exemptions, a transaction that is reviewable under the Investment Canada Act may not be implemented until an application for review has been filed and the responsible Minister of the federal cabinet has determined that the investment is likely to be of "net benefit to Canada" taking into account certain factors set out in the Investment Canada Act.

Under the Investment Canada Act, an investment in our common shares by a non-Canadian who is a World Trade Organization member country investor, including a United States investor would be reviewable only if it were an investment to acquire control of us pursuant to the Investment Canada Act and the enterprise value of our assets (as determined pursuant to the Investment Canada Act) was equal to or greater than $600 million. The Investment Canada Act contains various rules to determine if there has been an acquisition of control. For example, for purposes of determining whether an investor has acquired control of a corporation by acquiring shares, the following general rules apply, subject to certain exceptions: the acquisition of a majority of the undivided ownership interests in the voting shares of the corporation is deemed to be acquisition of control of that corporation; the acquisition of less than a majority, but one-third or more, of the voting shares of a corporation or of an equivalent undivided ownership interest in the voting shares of the corporation is presumed to be acquisition of control of that corporation unless it can be established that, on the acquisition, the corporation is not controlled in fact by the acquirer through the ownership of voting shares; and the acquisition of less than one third of the voting shares of a corporation or of an equivalent undivided

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ownership interest in the voting shares of the corporation is deemed not to be acquisition of control of that corporation.

Under the Investment Canada Act, review on a discretionary basis may also be undertaken by the federal government in respect to a much broader range of investments by a non-Canadian to "acquire, in whole or part, or to establish an entity carrying on all or any part of its operations in Canada." No financial threshold applies to a national security review. The relevant test is whether such investment by a non-Canadian could be "injurious to national security." The federal government has broad discretion to determine whether an investor is a non-Canadian and therefore subject to national security review. Review on national security grounds is at the discretion of the Canadian government, and may occur on a pre- or post-closing basis.

Certain transactions relating to our common shares will generally be exempt from the Investment Canada Act, subject to the federal government's prerogative to conduct a national security review, including:

(1)
  the acquisition of our common shares by a person in the ordinary course of that person's business as a trader or dealer in securities;
(2)
  the acquisition of control of us in connection with the realization of security granted for a loan or other financial assistance and not for any purpose related to the provisions of the Investment Canada Act; and
(3)
  the acquisition of control of us by reason of an amalgamation, merger, consolidation or corporate reorganization following which the ultimate direct or indirect control in fact of us, through ownership of our common shares, remains unchanged.

Other. There is no law, governmental decree or regulation in Alberta that restricts the export or import of capital, or that would affect the remittance of dividends (if any) or other payments by us to non-resident holders of our common shares, other than withholding tax requirements.

Stock Exchange Listing

We have applied to list our common shares on the Nasdaq Capital Market under the ticker symbol "EPSN."

ITEM 12. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

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

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

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proceeding, (ii) fulfills the Indemnification Conditions, and (iii) is fairly and reasonably entitled to indemnity. We may advance funds to an Indemnified Person for the costs, charges and expenses of a proceeding; however, the Indemnified Person shall repay the moneys if such individual does not fulfill the Indemnification Conditions. The indemnification may be made in connection with a derivative action only with court approval and only if the Indemnification Conditions are met.

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

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

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

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

ITEM 13. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Our financial statements appear on pages F-1 through F-56 of this registration statement.

ITEM 14. 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.

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On July 20, 2017, we engaged a new independent registered public accounting firm for the re-audit of the financial statements under U.S. GAAP for the years ended December 31, 2015 and 2016. A new firm was engaged as we intend to register in the United States and so need U.S. accountants. The change of our independent registered public accounting firm was approved unanimously by our Board of Directors. We continue to engage our Canadian public accounting firm to perform audits and reviews of our financial statements prepared in accordance with IFRS for purposes of maintaining our listing on the TSX.

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ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS.

(a)
  Financial Statements

Our financial statements appear on pages F-1 through F-56 of this registration statement.

(b)
  Exhibits

Exhibit No. |  | Exhibit or Financial Statement Schedule
--- | --- | ---
| 3.1 | * | Articles of Incorporation of Epsilon Energy Ltd.
| 3.2 | * | Bylaws of Epsilon Energy Ltd.
| 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.
| 10.2 | * | First Amendment to Credit Agreement, effective as of December 10, 2015
| 10.3 | * | Second Amendment to Credit Agreement, effective as of October 11, 2016
| 10.4 | * | Third Amendment to Credit Agreement, effective as of February 21, 2017
| 10.5 | * | Fourth Amendment to Credit Agreement, effective as of August 4, 2017
| 10.6 | * | Lane Bond Offer Letter
| 10.7 | * | Henry Clanton Offer Letter
| 10.8 | * | 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
| 10.9 | * | Amended and Restated 2017 Stock Option Plan
| 10.10 | * | Share Compensation Plan
| 10.11 | * | 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.
| 21.1 | * | Subsidiaries of the Registrant
| 99.1 | * | Report of DeGolyer and MacNaughton

*
  Filed herewith

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SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized.

|  | EPSILON ENERGY LTD.
Dated: |  | By: |  | B. Lane Bond Chief Financial Officer (Principal Financial and Accounting Officer, Controller and Chief Accounting Officer, and Duly Authorized Officer)

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INDEX TO FINANCIAL STATEMENTS

Index |  |  | F-1 |
Unaudited Condensed Consolidated Financial Statements as of June 30, 2018 and December 31, 2017 and for the six months then ended June 30, 2018 and 2017 |  |  | F-2 |
Notes to Unaudited Condensed Consolidated Financial Statements |  |  | F-6 |
Report of Independent Registered Public Accounting Firm |  |  | F-23 |
Consolidated Financial Statements as of December 31, 2017 and 2016 and for the years then ended |  |  | F-24 |
Notes to Consolidated Financial Statements |  |  | F-28 |

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EPSILON ENERGY LTD.

Unaudited Condensed Consolidated Balance Sheets

|  | June 30, 2018 |  | December 31, 2017 |
--- | --- | --- | --- | --- | ---
ASSETS |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 11,826,828 |  | $ | 9,998,853 |
Accounts receivable |  |  | 3,037,744 |  |  | 3,334,895 |
Fair value of derivatives |  |  | — |  |  | 259,544 |
Prepaid income taxes |  |  | 801,080 |  |  | — |
Other current assets |  |  | 134,361 |  |  | 276,431 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total current assets |  |  | 15,800,013 |  |  | 13,869,723 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Non-current assets |  |  |  |  |  |  |
Property and equipment: |  |  |  |  |  |  |
Oil and gas properties, successful efforts method |  |  |  |  |  |  |
Proved properties |  |  | 118,205,562 |  |  | 118,524,693 |
Unproved properties |  |  | 18,006,834 |  |  | 17,451,552 |
Accumulated depletion, depreciation, and amortization |  |  | (81,132,334 | ) |  | (78,625,589 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total oil and gas properties, net |  |  | 55,080,062 |  |  | 57,350,656 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Gathering system |  |  | 40,940,057 |  |  | 40,880,503 |
Accumulated depletion, depreciation, and amortization |  |  | (27,161,440 | ) |  | (26,252,385 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total gathering system, net |  |  | 13,778,617 |  |  | 14,628,118 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other property and equipment, net |  |  | 55 |  |  | 299 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total property and equipment, net |  |  | 68,858,734 |  |  | 71,979,073 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other assets: |  |  |  |  |  |  |
Restricted cash |  |  | 557,403 |  |  | 556,864 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total non-current assets |  |  | 69,416,137 |  |  | 72,535,937 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total assets |  | $ | 85,216,150 |  | $ | 86,405,660 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
LIABILITIES AND SHAREHOLDERS' EQUITY |  |  |  |  |  |  |
Current liabilities |  |  |  |  |  |  |
Accounts payable trade |  | $ | 1,610,305 |  | $ | 2,008,229 |
Royalties payable |  |  | 993,977 |  |  | 1,029,678 |
Accrued US listing costs |  |  | 100,552 |  |  | 427,654 |
Other accrued liabilities |  |  | 1,497,641 |  |  | 1,468,263 |
Income taxes payable |  |  | — |  |  | 1,017,194 |
Fair value of derivatives |  |  | 333,915 |  |  | — |
Revolving line of credit |  |  | 900,000 |  |  | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total current liabilities |  |  | 5,436,390 |  |  | 5,951,018 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Non-current liabilities |  |  |  |  |  |  |
Revolving line of credit |  |  | — |  |  | 2,900,000 |
Other non-current liabilities |  |  | 1,660,721 |  |  | 1,615,313 |
Asset retirement obligation |  |  | 1,703,046 |  |  | 1,646,601 |
Deferred income taxes |  |  | 10,125,451 |  |  | 10,561,683 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total non-current liabilities |  |  | 13,489,218 |  |  | 16,723,597 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total liabilities |  |  | 18,925,608 |  |  | 22,674,615 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Commitments and contingencies (See Note 9) |  |  |  |  |  |  |
Shareholders' equity |  |  |  |  |  |  |
Common shares, no par, unlimited shares authorized and 54,923,289 shares and 55,045,705 shares issued at June 30, 2018 and December 31, 2017 respectively |  |  | 144,031,668 |  |  | 144,292,238 |
Additional paid-in capital |  |  | 6,360,754 |  |  | 6,171,525 |
Deficit |  |  | (93,924,419 | ) |  | (96,645,954 | )
Accumulated other comprehensive income |  |  | 9,822,539 |  |  | 9,913,236 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total shareholders' equity |  |  | 66,290,542 |  |  | 63,731,045 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total liabilities and shareholders' equity |  | $ | 85,216,150 |  | $ | 86,405,660 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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

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EPSILON ENERGY LTD.
Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income

|  | Six months ended June 30, |
--- | --- | --- | ---
|  | 2018 |  | 2017 |
Revenues: |  |  |  |  |  |  |
Oil, gas, NGLs and condensate revenue |  | $ | 8,602,533 |  | $ | 11,774,427 |
Gas gathering and compression revenue |  |  | 5,340,323 |  |  | 3,601,758 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total revenue |  |  | 13,942,856 |  |  | 15,376,185 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating costs and expenses: |  |  |  |  |  |  |
Lease operating expenses |  |  | 3,521,608 |  |  | 2,657,865 |
Gathering system operating expenses |  |  | 716,054 |  |  | 386,766 |
Depletion, depreciation, amortization, and accretion |  |  | 3,472,094 |  |  | 6,344,551 |
General and administrative expenses: |  |  |  |  |  |  |
Stock based compensation expense |  |  | 171,959 |  |  | 90,802 |
Other general and administrative expenses |  |  | 1,465,538 |  |  | 1,881,193 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total operating costs and expenses |  |  | 9,347,253 |  |  | 11,361,177 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating income |  |  | 4,595,603 |  |  | 4,015,008 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other income and (expense): |  |  |  |  |  |  |
Interest income |  |  | 2,432 |  |  | 25,756 |
Interest expense |  |  | (95,910 | ) |  | (861,386 | )
Gain (loss) on commodity contracts |  |  | (474,086 | ) |  | 1,168,562 |
Other income |  |  | 12,442 |  |  | 5,170 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other income (expense), net |  |  | (555,122 | ) |  | 338,102 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Income before tax |  |  | 4,040,481 |  |  | 4,353,110 |
Income tax expense |  |  | 1,318,946 |  |  | 2,519,599 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
NET INCOME |  | $ | 2,721,535 |  | $ | 1,833,511 |
Currency translation adjustments |  |  | (90,697 | ) |  | 488,480 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
NET COMPREHENSIVE INCOME |  | $ | 2,630,838 |  | $ | 2,321,991 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income per share, basic |  | $ | 0.05 |  | $ | 0.04 |
Net income per share, diluted |  | $ | 0.05 |  | $ | 0.04 |
Weighted average number of shares outstanding, basic |  |  | 55,002,193 |  |  | 49,387,496 |
Weighted average number of shares outstanding, diluted |  |  | 55,024,517 |  |  | 49,414,352 |

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

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EPSILON ENERGY LTD.
Unaudited Condensed Consolidated Statements of Change in Shareholders' Equity

|  | Share Capital |  | Additional paid-in Capital |  | Accumulated Other Comprehensive Income (Loss) |  | Deficit |  | Total Shareholders' Equity |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Balance at December 31, 2016 |  | $ | 126,303,679 |  | $ | 5,972,563 |  | $ | 9,346,855 |  | $ | (104,081,859 | ) | $ | 37,541,238 |
Net income |  |  | — |  |  | — |  |  | — |  |  | 7,435,905 |  |  | 7,435,905 |
Rights offering shares issued |  |  | 17,984,664 |  |  | — |  |  | — |  |  | — |  |  | 17,984,664 |
Rights offering issue costs |  |  | (77,478 | ) |  | — |  |  | — |  |  | — |  |  | (77,478 | )
Stock-based compensation expenses |  |  | — |  |  | 229,223 |  |  | — |  |  | — |  |  | 229,223 |
Stock options exercised |  |  | 80,759 |  |  | (30,516 | ) |  | — |  |  | — |  |  | 50,243 |
Conversion of debentures to common shares |  |  | 614 |  |  | 255 |  |  | — |  |  | — |  |  | 869 |
Other comprehensive income |  |  | — |  |  | — |  |  | 566,381 |  |  | — |  |  | 566,381 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at December 31, 2017 |  |  | 144,292,238 |  |  | 6,171,525 |  |  | 9,913,236 |  |  | (96,645,954 | ) |  | 63,731,045 |
Net income |  |  | — |  |  | — |  |  | — |  |  | 2,721,535 |  |  | 2,721,535 |
Stock-based compensation expenses |  |  | — |  |  | 171,959 |  |  | — |  |  | — |  |  | 171,959 |
Buyback and retirement of common shares |  |  | (260,570 | ) |  | 17,270 |  |  | — |  |  | — |  |  | (243,300 | )
Other comprehensive income |  |  | — |  |  | — |  |  | (90,697 | ) |  | — |  |  | (90,697 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at June 30, 2018 |  | $ | 144,031,668 |  | $ | 6,360,754 |  | $ | 9,822,539 |  | $ | (93,924,419 | ) | $ | 66,290,542 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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

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EPSILON ENERGY LTD.
Unaudited Condensed Consolidated Statements of Cash Flows

|  | Six months ended June 30, |
--- | --- | --- | ---
|  | 2018 |  | 2017 |
Cash flows from operating activities: |  |  |  |  |  |  |
Net income |  | $ | 2,721,535 |  | $ | 1,833,511 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |
Depletion, depreciation, amortization, and accretion |  |  | 3,472,094 |  |  | 6,344,551 |
Debenture fee amortization |  |  | — |  |  | 52,924 |
(Gain) loss on derivatives |  |  | 474,086 |  |  | (1,168,562 | )
Cash received from settlements of derivatives |  |  | 119,373 |  |  | 387,975 |
Stock-based compensation expense |  |  | 171,958 |  |  | 90,802 |
Deferred income tax expense (benefit) |  |  | (436,232 | ) |  | 942,008 |
Changes in current assets and liabilities: |  |  |  |  |  |  |
Accounts receivable |  |  | 297,151 |  |  | 684,411 |
Other current assets |  |  | (659,010 | ) |  | 77,580 |
Accounts payable and accrued liabilities |  |  | (1,747,626 | ) |  | 592,725 |
Other long-term liabilities |  |  | 45,408 |  |  | 94,482 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net cash provided by operating activities |  |  | 4,458,737 |  |  | 9,932,407 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from investing activities: |  |  |  |  |  |  |
Acquisition of unproved oil and gas properties |  |  | (260,000 | ) |  | (4,699,951 | )
Additions to unproved oil and gas properties |  |  | (295,281 | ) |  | — |
Acquisition of proved oil and gas properties |  |  | — |  |  | (1,088,000 | )
Additions to proved oil and gas properties |  |  | 324,526 |  |  | (15,590 | )
Additions to gathering system properties |  |  | (65,471 | ) |  | (126,954 | )
Deposits on acquisitions |  |  | — |  |  | (900,000 | )
Changes in restricted cash |  |  | (539 | ) |  | (25,335 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net cash used in investing activities |  |  | (296,765 | ) |  | (6,855,830 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from financing activities: |  |  |  |  |  |  |
Buyback of common shares |  |  | (243,300 | ) |  | — |
Common shares issued through rights offering (net of issuance costs) |  |  | — |  |  | 17,907,186 |
Redemption of convertible debentures |  |  | — |  |  | (29,464,190 | )
Exercise of stock options |  |  | — |  |  | 50,243 |
Repayment of revolving line of credit |  |  | (2,000,000 | ) |  | (9,560,000 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net cash used in financing activities |  |  | (2,243,300 | ) |  | (21,066,761 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Effect of currency rates on cash and cash equivalents |  |  | (90,697 | ) |  | 1,304,402 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Increase (decrease) in cash and cash equivalents |  |  | 1,827,975 |  |  | (16,685,782 | )
Cash and cash equivalents, beginning of period |  |  | 9,998,853 |  |  | 31,486,593 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents, end of period |  | $ | 11,826,828 |  | $ | 14,800,811 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Supplemental cash flow disclosures: |  |  |  |  |  |  |
Income taxes paid |  | $ | 3,505,493 |  | $ | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Interest paid |  | $ | 95,910 |  | $ | 1,383,587 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Non-cash investing activities: |  |  |  |  |  |  |
Change in proved properties accrued in accounts payable and accrued liabilities |  | $ | (5,000 | ) | $ | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Change in gathering system accrued in accounts payable and accrued liabilities |  | $ | 5,917 |  | $ | 51,337 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Conversion of debentures to shares (Cdn$1,000) |  |  | — |  |  | 869 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Change in asset retirement obligations |  | $ | 395 |  | $ | 52 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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

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Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements

For the six months ended June 30, 2018 and 2017

1. Description of Business

Epsilon Energy Ltd. (the "Corporation" or "Epsilon") was incorporated under the laws of the Province of Alberta on March 14, 2005. On October 24, 2007, the Corporation became a publicly traded entity on the Toronto Stock Exchange under the trading symbol "EPS." The Corporation is engaged in the acquisition, development, gathering and production of primarily natural gas reserves in the U.S.

2. Basis of Preparation

Interim Financial Statements

The accompanying unaudited consolidated condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and with the appropriate rules and regulations of the SEC. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations. All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included. The interim financial information and notes hereto should be read in conjunction with the Corporation's consolidated financial statements as of and for the years ended December 31, 2017 and 2016 included in this document. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.

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 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 the calculations of depletion and impairment associated with 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.

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Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

2. Basis of Preparation (Continued)

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.

In July 2018, the FASB issued ASU 2018-09, "Codification Improvements." Periodically, the Financial Accounting Standards Board (FASB) updates the Accounting Standards Codification for minor technical corrections and clarifications that are deemed necessary. These changes are made to clarify the Codification, correct unintended application of guidance, and make minor improvements to the Codification that are not expected to have a significant effect on current accounting practice. We have examined the provisions and do not anticipate any of them to materially affect our financial statements.

In May 2018, the FASB issued 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 company 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. 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

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Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

2. Basis of Preparation (Continued)

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, 2019. 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)."

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Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

3. Property and Equipment

The following table summarizes the Corporation's property and equipment as of June 30, 2018 and December 31, 2017:

|  | June 30, 2018 |  | December 31, 2017 |
--- | --- | --- | --- | --- | ---
Property and equipment: |  |  |  |  |  |  |
Proved properties |  | $ | 118,205,562 |  | $ | 118,524,693 |
Unproved properties |  |  | 18,006,834 |  |  | 17,451,552 |
Accumulated depletion, depreciation, and amortization |  |  | (81,132,334 | ) |  | (78,625,589 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total oil and gas properties, net |  |  | 55,080,062 |  |  | 57,350,656 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Gathering system |  |  | 40,940,057 |  |  | 40,880,503 |
Accumulated depletion, depreciation, and amortization |  |  | (27,161,440 | ) |  | (26,252,385 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total gathering system, net |  |  | 13,778,617 |  |  | 14,628,118 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other property and equipment |  |  | 55 |  |  | 299 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total property and equipment |  | $ | 68,858,734 |  | $ | 71,979,073 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

Property Additions and 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 six months ended June 30, 2018, the Corporation acquired additional acres 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 June 30, 2018 and December 31, 2017, the Corporation evaluated its proved and unproved oil and gas properties, and its gathering system assets for impairment. As a result of these assessments, no impairment was required as of June 30, 2018 and December 31, 2017.

4. Convertible Debentures

On February 28, 2012, the Corporation completed a public offering of Cdn$40 million aggregate principal amount of convertible, unsecured subordinated debentures ("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 with an original maturity date of March 31, 2017 (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

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Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

4. Convertible Debentures (Continued)

equal to Cdn$4.45 per Common Share. Upon redemption or maturity, the Corporation could repay the outstanding principal of the Convertible Debentures through the issuance of Common Shares.

Prior to the redemption of the debentures in February 2017, 1,000 debentures were converted to shares of common shares at Cdn$4.45 per share. The convertible debentures were scheduled to mature on March 31, 2017. The remaining interest and principal were paid off 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. The debentures were fully funded with cash holdings in Canada.

The following table sets forth a reconciliation of the convertible debentures for the six months ended June 30, 2017.

|  | US$ |  | Cdn$ |
--- | --- | --- | --- | --- | ---
Balance at January 1, 2017 |  | $ | 28,596,213 |  | $ | 38,394,491 |
Conversion of Convertible Debenture |  |  | (869 | ) |  | (1,000 | )
Amortization of fees |  |  | 52,924 |  |  | 70,509 |
Translation adjustment at February 16, 2017 |  |  | 815,922 |  |  | — |
Redemption of Convertible Debenture |  |  | (29,464,190 | ) |  | (38,464,000 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at June 30, 2017 |  | $ | — |  | $ | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

5. Revolving Line of Credit

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, 2015, 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, 2015. 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, 2016.

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.

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Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

5. Revolving Line of Credit (Continued)

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.

In December 2017 a redetermination of the borrowing base was executed reducing it to $13.5 million. In May 2018, the borrowing base was reaffirmed at $13.5 million.

The bank has a first priority security interest in the tangible and intangible assets, including the gathering system, of Epsilon Energy USA to secure any outstanding amounts under the agreement. Under the terms of the agreement, the Corporation 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.

The Corporation was in compliance with the financial covenants of the Credit Facility as of June 30, 2018 and December 31, 2017 and we expect to be in compliance with the financial covenants for the next 12 months.

|  | June 30, 2018 |  | December 31, 2017 |  | Borrowing Base June 30, 2018 |  | Interest Rate 3 mo
--- | --- | --- | --- | --- | --- | --- | --- | ---
Revolving line of credit |  | $ | 900,000 |  | $ | 2,900,000 |  | $ | 13,500,000 |  | LIBOR + 2.75%(1)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

(1)
  At June 30, 2018, the interest rate was 5.1%.

6. 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.

F-11

Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

6. Shareholders' Equity (Continued)

(b) Issued

The following table summarizes the components of share capital for the six months ended June 30, 2018 and the year ended December 31, 2017.

|  | Number of shares issued |  | Amount |
--- | --- | --- | --- | --- | ---
Balance at January 1, 2017 |  |  | 45,837,864 |  | $ | 126,303,679 |
Conversion of debenture to shares |  |  | 224 |  |  | 614 |
Exercise of stock options |  |  | 40,000 |  |  | 80,759 |
Shares issued through rights offering (net of issuance costs of $77,478) |  |  | 9,167,617 |  |  | 17,907,186 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at December 31, 2017 |  |  | 55,045,705 |  | $ | 144,292,238 |
Buyback of Shares |  |  | (122,416 | ) |  | (260,570 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at June 30, 2018 |  |  | 54,923,289 |  | $ | 144,031,668 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

Through a normal-course issuer bid ("NCIB") program, the Corporation repurchased 122,416 common shares through the six months ended June 30, 2018. The repurchased shares had an average price of Cdn$2.54 per share. The average share price on the TSX during the six months ended June 30, 2018 was Cdn$2.62 (for the year ended December 31, 2017, Cdn$3.12).

(c) Stock Options

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. 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 Common Shares available under the Plan from a limit of 10% of the total issued and outstanding Common Shares to a fixed maximum of 2,000,000 Common Shares, and (ii) deleted some redundant definitions and clarified existing wording in the Plan.

Through June 30, 2018, the Corporation had issued stock options covering 581,500 Common Shares at an overall average price of Cdn$3.35 per Common Share to directors, officers, and employees of the Corporation and its subsidiaries.

F-12

Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

6. Shareholders' Equity (Continued)

At June 30, 2018, the Corporation was authorized to issue options covering up to 2,000,000 shares of stock. As of that date, the Corporation had issued options covering 581,500 Common Shares, leaving a maximum amount of 1,418,500 Common Shares available for future option issuances.

The following table summarizes stock option activity for the six months ended June 30, 2018 and the year ended December 31, 2017:

|  | Six months ended June 30, 2018 |  | Year ended December 31, 2017 |
--- | --- | --- | --- | --- | ---
Exercise price in Cdn$ |  | Number of Options Outstanding |  | Weighted Average Exercise Price |  | Number of Options Outstanding |  | Weighted Average Exercise Price |
Balance at beginning of period |  |  | 661,500 |  | $ | 3.43 |  |  | 511,000 |  | $ | 3.33 |
Granted |  |  | — |  | $ | — |  |  | 241,500 |  | $ | 3.35 |
Exercised |  |  | — |  | $ | — |  |  | (40,000 | ) | $ | 1.63 |
Expired |  |  | (80,000 | ) | $ | 4.00 |  |  | (51,000 | ) | $ | 3.53 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at period-end |  |  | 581,500 |  | $ | 3.35 |  |  | 661,500 |  | $ | 3.43 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Exercisable at period-end |  |  | 420,500 |  | $ | 3.35 |  |  | 323,333 |  | $ | 3.41 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

At June 30, 2018, the Corporation had unrecognized stock based compensation of $73,421 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 June 30, 2018 was Cdn$67,500 (at December 31, 2017: Cdn$79,500).

The average share price during the six months ended June 30, 2018 was Cdn$2.62 (for the year ended December 31, 2017: Cdn$3.12). The average exchange rate for the six months ended June 30, 2018 was Cdn$0.7825 to US$1.

During the six months ended June 30, 2018, the Corporation awarded no stock options (During the year ended December 31, 2017: 241,500 stock options).

(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, 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 October 2017, 250,000 Common Shares of Restricted Stock were awarded to the Corporation's Chief Executive Officer. In December 2017, an additional 75,000 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

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Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

6. Shareholders' Equity (Continued)

Corporation on the date of grant. Stock compensation expense for the granted Restricted Stock is recognized over the vesting period.

The following table summarizes Restricted Stock activity for the six months ended June 30, 2018, and the year ended December 31, 2017:

|  | Six months ended June 30, 2018 |  | Year ended December 31, 2017 |
--- | --- | --- | --- | --- | ---
|  | Number of Shares Outstanding |  | Weighted Average Remaining Life (years) |  | Number of Shares Outstanding |  | Weighted Average Remaining Life (years) |
Balance non-vested Restricted Stock at beginning of period |  |  | 325,000 |  |  | 1.87 |  |  | — |  |  | — |
Granted |  |  | — |  |  | — |  |  | 325,000 |  |  | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance non-vested Restricted Stock at end of period |  |  | 325,000 |  |  | 1.37 |  |  | 325,000 |  |  | 1.87 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

7. Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) includes certain transactions that have generally been reported in the consolidated statements of changes in shareholders' equity. Activity within Accumulated other comprehensive income (loss) for the six months ended June 30, 2018 and 2017 consisted of the following:

|  | Six Months Ended June 30, |
--- | --- | --- | ---
|  | 2018 |  | 2017 |
Translation loss convertible debentures |  |  | — |  |  | (815,922 | )
Translation gain other |  |  | (90,697 | ) |  | 1,304,402 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
|  | $ | (90,697 | ) | $ | 488,480 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

F-14

Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

8. Income Taxes

Income tax provisions for the six months ended June 30, 2018 and 2017 are as follows:

|  | Six months ended June 30, |
--- | --- | --- | ---
|  | 2018 |  | 2017 |
Current: |  |  |  |  |  |  |
Federal |  | $ | 1,305,663 |  | $ | 953,370 |
State |  |  | 449,514 |  |  | 624,221 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total current income tax expense |  |  | 1,755,177 |  |  | 1,577,591 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Deferred: |  |  |  |  |  |  |
Federal |  |  | (451,640 | ) |  | 965,695 |
State |  |  | 15,409 |  |  | (23,687 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total deferred income expense (benefit) tax expense |  |  | (436,231 | ) |  | 942,008 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Income tax provision |  | $ | 1,318,946 |  | $ | 2,519,599 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

We file federal income tax returns in the United States and Canada, and various returns in state and local jurisdictions. We believe we have appropriate support for the income tax positions taken and to be taken on our tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of various 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, 2014 through December 31, 2017. To the extent we utilize net operating losses generated in earlier years, such earlier years may also be subject to audit.

Our effective tax rate will typically differ from the statutory federal rate as a result of state income taxes and the valuation allowance against the Canadian net operating loss. The effective tax rate for the six months ended June 30, 2018 was slightly higher than the statutory federal rate as a result of the state income taxes and the valuation allowance against the Canadian net operating loss.

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 completed the accounting for the effects of the Act during 2017. Our financial statements for the year ended December 31, 2017 reflected certain effects of the Act and included a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018 on our net deferred tax liability. 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 for the quarter ended December 31, 2017. The federal rate for 2018 activity has been adjusted to reflect the new corporate tax rate of 21%.

The Corporation follows the guidance in SEC Staff Accounting Bulletin 118 ("SAB 118"), which provides 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 provides for a measurement period beginning in the reporting period that includes the Act's enactment date and ending when the

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Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

8. Income Taxes (Continued)

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. We have calculated the impact of the Act in our 2017 year end income tax provision in accordance with our understanding of the Act and guidance available as of the date of that filing. We will continue to gather and evaluate the income tax impact of the Act. The ultimate impact of the Act on our reported results in 2017 and beyond may differ, possibly materially, due to, among other things, changes in interpretations and assumptions we have made, guidance that may be issued, and other actions we may take as a result of the Act.

9. Commitments and Contingencies

The Corporation's future minimum lease commitments as of June 30, 2018 are summarized in the following table:

Year ended December 31, |  | Payments |
--- | --- | --- | ---
2018 |  | $ | 39,339 |
2019 |  |  | 80,577 |
2020 |  |  | 6,729 |
​ | ​ | ​ | ​ | ​
|  | $ | 126,645 |
​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​

The Corporation enters into commitments for capital expenditures in advance of the expenditures being made. At a given point in time, it is estimated that the Corporation has committed to capital expenditures equal to approximately one quarter of its capital budget by means of giving the necessary authorizations to incur the expenditures in a future period.

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.

10. Net Income (Loss) Per Share

Basic net income (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income (loss) 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 is as follows:

|  | Six months ended June 30, |
--- | --- | --- | ---
|  | 2018 |  | 2017 |
Net income available to shareholders |  | $ | 2,721,535 |  | $ | 1,833,511 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

F-16

Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

10. Net Income (Loss) Per Share (Continued)

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

|  | Six months ended June 30, |
--- | --- | --- | ---
|  | 2018 |  | 2017 |
Basic weighted-average number of shares outstanding |  |  | 55,002,193 |  |  | 49,387,496 |
Dilutive stock options |  |  | 22,324 |  |  | 26,856 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Diluted weighted average shares outstanding |  |  | 55,024,517 |  |  | 49,414,352 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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

|  | Six months ended June 30, |
--- | --- | --- | ---
|  | 2018 |  | 2017 |
Anti-dilutive options |  |  | 559,176 |  |  | 659,644 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

11. Operating Segments

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 income and expense, 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 oil, natural gas, and other liquid 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

F-17

Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

11. Operating Segments (Continued)

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

|  | Upstream |  | Gas Gathering |  | Canada |  | Corporate |  | Elimination |  | Consolidated |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
As at and for the six months ended June 30, 2018 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  | $ | 8,602,533 | (1) | $ | 5,916,854 |  | $ | — |  | $ | — |  | $ | (576,531 | ) | $ | 13,942,856 |
Net earnings for the period |  | $ | 2,519,144 |  | $ | 3,713,956 |  | $ | — |  | $ | (3,511,564) | (3) |  | — |  | $ | 2,721,535 |
Operating costs |  |  | 3,521,608 |  |  | 1,292,585 |  |  | — |  |  | — |  |  | (576,531 | ) |  | 4,237,662 |
Depletion, deprec., amortization and accretion |  |  | 2,561,781 |  |  | 910,313 |  |  | — |  |  | — |  |  | — |  |  | 3,472,094 |
Segment assets |  | $ | 64,631,361 |  | $ | 18,803,503 |  | $ | 1,781,286 |  | $ | — |  |  | — |  | $ | 85,216,150 |
Capital expenditures(2) |  |  | 235,755 |  |  | 59,554 |  |  | — |  |  | — |  |  | — |  |  | 295,309 |
Proved properties |  |  | 37,073,228 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 37,073,228 |
Unproved properties |  |  | 18,006,834 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 18,006,834 |
Gathering system |  |  | — |  |  | 13,778,617 |  |  | — |  |  | — |  |  | — |  |  | 13,778,617 |
Other property and equipment |  |  | 55 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 55 |
As at and for the six months ended June 30, 2017 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  | $ | 11,774,427 | (1) | $ | 4,241,525 |  | $ | — |  | $ | — |  | $ | (639,767 | ) | $ | 15,376,185 |
Net earnings for the period |  | $ | 4,509,641 |  | $ | 1,477,362 |  | $ | — |  | $ | (4,153,492) | (3) | $ | — |  | $ | 1,833,511 |
Operating costs |  |  | 2,657,865 |  |  | 1,026,533 |  |  | — |  |  | — |  |  | (639,767 | ) |  | 3,044,631 |
Depletion, deprec., amortization and accretion |  |  | 4,606,921 |  |  | 1,737,630 |  |  | — |  |  | — |  |  | — |  |  | 6,344,551 |
Segment assets |  | $ | 61,289,111 |  | $ | 19,871,102 |  | $ | 2,488,862 |  | $ | — |  | $ | — |  | $ | 83,649,075 |
Capital expenditures(2) |  |  | 5,803,541 |  |  | 75,617 |  |  | — |  |  | — |  |  | — |  |  | 5,879,158 |
Proved properties |  |  | 42,645,090 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 42,645,090 |
Unproved properties |  |  | 4,699,951 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 4,699,951 |
Gathering system |  |  | — |  |  | 15,836,873 |  |  | — |  |  | — |  |  | — |  |  | 15,836,873 |
Other property and equipment |  |  | 756 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 756 |

(1)
  Segment operating revenue represents revenues generated from the operations of the segment. Inter-segment sales during the six months ended June 30, 2018 and 2017 have been eliminated upon consolidation. For the six months ended June 30, 2018, Epsilon sold natural gas to 25 unique customers. Spotlight Energy, LLC, Repsol Energy North America Corporation, and Citadel Energy Marketing, LLC each accounted for 10% or more of total revenue. For the six months ended June 30, 2017, Epsilon sold natural gas to 18 unique customers. DTE Energy Trading, Inc., Repsol Energy North America Corporation, Twin Eagle Resource Management, LLC, and South Jersey Resources Group, LLC each accounted for 10% or more of our total revenue.
(2)
  Capital expenditures for Upstream segment consist primarily of the drilling and completing of wells while Gas Gathering consists of expenditures relating to the expansion and completion of the gathering and 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, both gains and (losses) from commodity hedging contracts, or income tax amounts as they are managed on a group basis and are instead included in the corporate column for reconciliation purposes.

F-18

Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

12. Risk Management Activities

Commodity Price Risks

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

Inherent in the 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 do its counterparties require collateral from the Corporation.

The Corporation enters into certain commodity derivative instruments, including fixed price swaps, basis swaps and costless collars, 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 commodity derivative contracts as accounting hedges and, accordingly, accounts for these 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 commodity contracts on the consolidated statements of operations and comprehensive income (loss). The related cash flow impact is reflected in cash flows from operating activities. During the six months ended June 30, 2018, Epsilon recognized losses on commodity derivative contracts of $474,086. This amount included cash received on settlements of these contracts of $119,373. For the six months ended June 30, 2017, Epsilon recognized gains of $1,168,562, which were net of cash received on settlements of natural gas derivative contracts of $387,975.

F-19

Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

12. Risk Management Activities (Continued)

Commodity Derivative Contracts

Presented below is a summary of Epsilon's natural gas price and basis swap contracts as of June 30, 2018.

|  |  |  | Weighted Average Price ($/Mmbtu) |  |  |
--- | --- | --- | --- | --- | --- | --- | ---
Derivative Type |  | Volume (Mmbtu) |  | Swaps |  | Basis Differential |  | Fair Value June 30, 2018 |
2018 |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed price swap |  |  | 2,372,500 |  | $ | 2.88 |  | $ | — |  | $ | (142,180 | )
Basis swap |  |  | 2,372,500 |  | $ | — |  | $ | (0.55 | ) |  | (11,683 | )
2019 |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed price swap |  |  | 1,350,000 |  | $ | 3.02 |  | $ | — |  |  | (84,615 | )
Basis swap |  |  | 1,350,000 |  | $ | — |  | $ | (0.48 | ) |  | (95,437 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
|  |  |  |  |  |  |  |  |  |  | $ | (333,915 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

As of June 30, 2018, all of the Corporation's derivative contracts 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. Certain of our commodity derivatives are presented on a net basis due on the consolidated balance sheets due to the right of offset. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our consolidated balance sheets as of the dates indicated below:

|  | Fair Value of Derivative Assets |
--- | --- | --- | ---
|  | June 30, 2018 |  | December 31, 2017 |
Current |  |  |  |  |  |  |
Basis swap |  | $ | 92,945 |  | $ | 203,840 |
Fixed price swap |  |  | 18,448 |  |  | 22,191 |
Two-way costless collar |  |  | — |  |  | 45,950 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
|  | $ | 111,393 |  | $ | 271,981 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

F-20

Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

12. Risk Management Activities (Continued)

|  | Fair Value of Derivative Liabilities |
--- | --- | --- | ---
|  | June 30, 2018 |  | December 31, 2017 |
Current |  |  |  |  |  |  |
Basis swap |  | $ | (200,065 | ) | $ | — |
Fixed price swap |  |  | (245,243 | ) |  | — |
Two-way costless collar |  |  | — |  |  | (12,437 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
|  | $ | (445,308 | ) | $ | (12,437 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net Fair Value of Derivatives |  | $ | (333,915 | ) | $ | 259,544 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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

|  | Six months ended June 30, 2018 |  | Year ended December 31, 2017 |
--- | --- | --- | --- | --- | ---
Fair value of asset (liability), beginning of period |  | $ | 259,544 |  | $ | (336,352 | )
(Loss) gain on derivatives included in earnings |  |  | (474,086 | ) |  | 2,623,687 |
Settlement of commodity derivative contracts |  |  | (119,373 | ) |  | (2,027,791 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Fair value of asset (liability), end of period |  | $ | (333,915 | ) | $ | 259,544 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Settlement of commodity derivative contracts |  |  | (119,373 | ) |  | (2,027,791 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Fair value of asset (liability), end of period |  | $ | (333,915 | ) | $ | 259,544 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

13. Asset Retirement Obligations

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.

The following tables summarize the changes in asset retirement obligations for the periods indicated:

|  | Six months ended June 30, 2018 |  | Year ended December 31, 2017 |
--- | --- | --- | --- | --- | ---
Balance beginning of period |  | $ | 1,646,601 |  | $ | 1,468,635 |
Liabilities acquired |  |  | 395 |  |  | 90,827 |
Change in estimates |  |  | — |  |  | (16,073 | )
Accretion |  |  | 56,050 |  |  | 103,212 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance end of period |  | $ | 1,703,046 |  | $ | 1,646,601 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

F-21

Table of Contents

Epsilon Energy Ltd.

Notes to the Unaudited Condensed Consolidated Financial Statements (Continued)

For the six months ended June 30, 2018 and 2017

14. Fair Value Measurements

The methodologies used to determine the fair value of our financial assets and liabilities at June 30, 2018 were the same as those used at December 31, 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 option 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.

15. Subsequent Events

The Company has evaluated subsequent events through Oct. 31, 2018, and there were none.

F-22

Table of Contents

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, 2017 and 2016, and the related consolidated statements of operations and comprehensive income (loss), changes in shareholders' equity, and cash flows for each of the two years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2017, 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
April 12, 2018

F-23

Table of Contents

EPSILON ENERGY LTD.
Consolidated Balance Sheets

|  | December 31, 2017 |  | December 31, 2016 |
--- | --- | --- | --- | --- | ---
ASSETS |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 9,998,853 |  | $ | 31,486,593 |
Accounts receivable |  |  | 3,334,895 |  |  | 4,387,488 |
Fair value of derivatives |  |  | 259,544 |  |  | — |
Other current assets |  |  | 276,431 |  |  | 139,991 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total current assets |  |  | 13,869,723 |  |  | 36,014,072 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Non-current assets |  |  |  |  |  |  |
Property and equipment: |  |  |  |  |  |  |
Oil and gas properties, successful efforts method |  |  |  |  |  |  |
Proved properties |  |  | 118,524,693 |  |  | 116,769,430 |
Unproved properties |  |  | 17,451,552 |  |  | — |
Accumulated depletion, depreciation, and amortization |  |  | (78,625,589 | ) |  | (70,670,124 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total oil and gas properties, net |  |  | 57,350,656 |  |  | 46,099,306 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Gathering system |  |  | 40,880,503 |  |  | 40,738,085 |
Accumulated depletion, depreciation, and amortization |  |  | (26,252,385 | ) |  | (23,240,450 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total gathering system, net |  |  | 14,628,118 |  |  | 17,497,635 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other property and equipment, net |  |  | 299 |  |  | 1,443 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total property and equipment, net |  |  | 71,979,073 |  |  | 63,598,384 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other assets: |  |  |  |  |  |  |
Restricted cash |  |  | 556,864 |  |  | 530,536 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total non-current assets |  |  | 72,535,937 |  |  | 64,128,920 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total assets |  | $ | 86,405,660 |  | $ | 100,142,992 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
LIABILITIES AND SHAREHOLDERS' EQUITY |  |  |  |  |  |  |
Current liabilities |  |  |  |  |  |  |
Accounts payable trade |  | $ | 2,008,229 |  | $ | 2,638,298 |
Royalties payable |  |  | 1,029,678 |  |  | 1,025,813 |
Accrued interest |  |  | — |  |  | 575,125 |
Accrued US listing costs |  |  | 427,654 |  |  | — |
Other accrued liabilities |  |  | 1,468,263 |  |  | 264,501 |
Income taxes payable |  |  | 1,017,194 |  |  | — |
Fair value of derivatives |  |  | — |  |  | 336,352 |
Convertible debentures |  |  | — |  |  | 28,596,213 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total current liabilities |  |  | 5,951,018 |  |  | 33,436,302 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Non-current liabilities |  |  |  |  |  |  |
Revolving line of credit |  |  | 2,900,000 |  |  | 12,460,000 |
Other non-current liabilities |  |  | 1,615,313 |  |  | 2,144,997 |
Asset retirement obligation |  |  | 1,646,601 |  |  | 1,468,635 |
Deferred income taxes |  |  | 10,561,683 |  |  | 13,091,820 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total non-current liabilities |  |  | 16,723,597 |  |  | 29,165,452 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total liabilities |  |  | 22,674,615 |  |  | 62,601,754 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Commitments and contingencies (See Note 10) |  |  |  |  |  |  |
Shareholders' equity |  |  |  |  |  |  |
Common shares, no par, unlimited shares authorized and 55,045,705 shares and 45,837,864 shares issued at December 31, 2017 and 2016, respectively |  |  | 144,292,238 |  |  | 126,303,679 |
Additional paid-in capital |  |  | 6,171,525 |  |  | 5,972,563 |
Deficit |  |  | (96,645,954 | ) |  | (104,081,859 | )
Accumulated other comprehensive income |  |  | 9,913,236 |  |  | 9,346,855 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total shareholders' equity |  |  | 63,731,045 |  |  | 37,541,238 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total liabilities and shareholders' equity |  | $ | 86,405,660 |  | $ | 100,142,992 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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

F-24

Table of Contents

EPSILON ENERGY LTD.
Consolidated Statements of Operations and Comprehensive Income (Loss)

|  | Years ended December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Revenues: |  |  |  |  |  |  |
Oil, gas, NGLs and condensate revenue |  | $ | 19,325,528 |  | $ | 15,263,438 |
Gas gathering and compression revenue |  |  | 6,431,563 |  |  | 8,436,835 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total revenue |  |  | 25,757,091 |  |  | 23,700,273 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating costs and expenses: |  |  |  |  |  |  |
Lease operating expenses |  |  | 5,723,298 |  |  | 6,582,039 |
Gathering system operating expenses |  |  | 896,089 |  |  | 773,865 |
Depletion, depreciation, amortization, and accretion |  |  | 11,071,759 |  |  | 20,967,275 |
General and administrative expenses: |  |  |  |  |  |  |
Stock based compensation expense |  |  | 229,223 |  |  | 139,232 |
Other general and administrative expenses |  |  | 4,189,065 |  |  | 1,908,572 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total operating costs and expenses |  |  | 22,109,434 |  |  | 30,370,983 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating income (loss) |  |  | 3,647,657 |  |  | (6,670,710 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other income and (expense): |  |  |  |  |  |  |
Interest income |  |  | 26,520 |  |  | 75,474 |
Interest expense |  |  | (955,698 | ) |  | (3,084,565 | )
Gain (loss) on commodity contracts |  |  | 2,623,687 |  |  | (487,550 | )
Other income (expense) |  |  | 27,313 |  |  | (96,950 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net other income (expense) |  |  | 1,721,822 |  |  | (3,593,591 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Income (loss) before tax |  |  | 5,369,479 |  |  | (10,264,301 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Income tax benefit |  |  | (2,066,426 | ) |  | (2,696,518 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
NET INCOME (LOSS) |  | $ | 7,435,905 |  | $ | (7,567,783 | )
Currency translation adjustments |  |  | 566,381 |  |  | (491,328 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
NET COMPREHENSIVE INCOME (LOSS) |  | $ | 8,002,286 |  | $ | (8,059,111 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) per share, basic |  | $ | 0.14 |  | $ | (0.16 | )
Net income (loss) per share, diluted |  | $ | 0.14 |  | $ | (0.16 | )
Weighted average number of shares outstanding, basic |  |  | 52,239,854 |  |  | 45,882,030 |
Weighted average number of shares outstanding, diluted |  |  | 52,266,589 |  |  | 45,882,030 |

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

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EPSILON ENERGY LTD.
Consolidated Statements of Changes in Shareholders' Equity

|  | Share Capital |  | Additional paid-in Capital |  | Accumulated Other Comprehensive Income (Loss) |  | Deficit |  | Total Shareholders' Equity |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Balance at December 31, 2015 |  | $ | 127,359,759 |  | $ | 5,833,331 |  | $ | 9,838,183 |  | $ | (96,789,815 | ) | $ | 46,241,458 |
Net loss |  |  | — |  |  | — |  |  | — |  |  | (7,567,783 | ) |  | (7,567,783 | )
Buyback and retirement of common shares |  |  | (1,056,080 | ) |  | — |  |  | — |  |  | 275,739 |  |  | (780,341 | )
Stock-based compensation expenses |  |  | — |  |  | 139,232 |  |  | — |  |  | — |  |  | 139,232 |
Other comprehensive loss |  |  | — |  |  | — |  |  | (491,328 | ) |  | — |  |  | (491,328 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at December 31, 2016 |  | $ | 126,303,679 |  | $ | 5,972,563 |  | $ | 9,346,855 |  | $ | (104,081,859 | ) | $ | 37,541,238 |
Net income |  |  | — |  |  | — |  |  | — |  |  | 7,435,905 |  |  | 7,435,905 |
Rights offering shares issued |  |  | 17,984,664 |  |  | — |  |  | — |  |  | — |  |  | 17,984,664 |
Rights offering issue costs |  |  | (77,478 | ) |  | — |  |  | — |  |  | — |  |  | (77,478 | )
Stock-based compensation expenses |  |  | — |  |  | 229,223 |  |  | — |  |  | — |  |  | 229,223 |
Stock options exercised |  |  | 80,759 |  |  | (30,516 | ) |  | — |  |  | — |  |  | 50,243 |
Conversion of debentures to common shares |  |  | 614 |  |  | 255 |  |  | — |  |  | — |  |  | 869 |
Other comprehensive income |  |  | — |  |  | — |  |  | 566,381 |  |  | — |  |  | 566,381 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at December 31, 2017 |  | $ | 144,292,238 |  | $ | 6,171,525 |  | $ | 9,913,236 |  | $ | (96,645,954 | ) | $ | 63,731,045 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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

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EPSILON ENERGY LTD.
Consolidated Statements of Cash Flows

|  | Years ended December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Cash flows from operating activities: |  |  |  |  |  |  |
Net income (loss) |  | $ | 7,435,905 |  | $ | (7,567,783 | )
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |  |  |  |  |  |  |
Depletion, depreciation, amortization, and accretion |  |  | 11,071,759 |  |  | 20,967,275 |
Debenture fee amortization |  |  | 52,924 |  |  | 322,251 |
(Gain) loss on derivatives |  |  | (2,623,687 | ) |  | 487,550 |
Cash received (paid) from settlements on derivatives |  |  | 2,027,791 |  |  | (151,198 | )
Stock-based compensation expense |  |  | 229,223 |  |  | 139,232 |
Deferred income tax benefit |  |  | (2,530,136 | ) |  | (2,829,781 | )
Changes in current assets and liabilities: |  |  |  |  |  |  |
Accounts receivable |  |  | 1,052,593 |  |  | (1,173,080 | )
Other current assets |  |  | (136,440 | ) |  | (1,006 | )
Accounts payable and accrued liabilities |  |  | 1,503,231 |  |  | 876,818 |
Other long-term liabilities |  |  | (529,684 | ) |  | 109,463 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net cash provided by operating activities |  |  | 17,553,479 |  |  | 11,179,741 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from investing activities: |  |  |  |  |  |  |
Acquisition of unproved oil and gas properties |  |  | (17,451,552 | ) |  | — |
Acquisition of proved oil and gas properties |  |  | (1,643,735 | ) |  | — |
Additions to proved oil and gas properties |  |  | (34,457 | ) |  | (99,908 | )
Additions to gathering system properties |  |  | (200,689 | ) |  | (684,046 | )
Changes in restricted cash |  |  | (26,328 | ) |  | (530,537 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net cash (used in) provided by investing activities |  |  | (19,356,761 | ) |  | (1,314,491 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from financing activities: |  |  |  |  |  |  |
Buyback of common shares |  |  | — |  |  | (780,341 | )
Common stock issued through rights offering (net of issuance costs) |  |  | 17,907,186 |  |  | — |
Redemption of convertible debentures |  |  | (29,464,190 | ) |  | — |
Exercise of stock options |  |  | 50,243 |  |  | — |
Purchase of convertible debenture |  |  | — |  |  | (372,203 | )
Proceeds from revolving line of credit |  |  | — |  |  | 22,000,000 |
Repayment of revolving line of credit |  |  | (9,560,000 | ) |  | (16,540,000 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net cash (used in) provided by financing activities |  |  | (21,066,761 | ) |  | 4,307,456 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Effect of currency rates on cash and cash equivalents |  |  | 1,382,303 |  |  | 359,223 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Increase (decrease) in cash and cash equivalents |  |  | (21,487,740 | ) |  | 14,531,929 |
Cash and cash equivalents, beginning of period |  |  | 31,486,593 |  |  | 16,954,664 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents, end of period |  | $ | 9,998,853 |  | $ | 31,486,593 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Supplemental cash flow disclosures: |  |  |  |  |  |  |
Income taxes paid |  | $ | — |  | $ | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Interest paid |  | $ | 1,477,899 |  | $ | 2,738,367 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Non-cash investing activities: |  |  |  |  |  |  |
Change in proved properties accrued in accounts payable and accrued liabilities |  | $ | — |  | $ | (251,924 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Change in gathering system accrued in accounts payable and accrued liabilities |  | $ | (55,950 | ) | $ | (217,241 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Conversion of debentures to shares (Cdn$1,000) |  | $ | 869 |  | $ | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Change in asset retirement obligations |  | $ | 74,755 |  | $ | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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

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Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements

For the years ended December 31, 2017 and 2016

1. Description of Business

Epsilon Energy Ltd. (the "Corporation" or "Epsilon") was incorporated under the laws of the Province of Alberta on March 14, 2005. On October 24, 2007, the Corporation became a publicly traded entity on the Toronto Stock Exchange under the trading symbol "EPS." The Corporation is engaged in the acquisition, development, gathering and production of primarily natural gas reserves in the United States.

Epsilon is a publicly traded company, incorporated and domiciled in Canada. 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").

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 subsidiary, Epsilon Midstream, 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.

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Table of Contents

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

3. Summary of Significant Accounting Policies (Continued)

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, 2017 and 2016. There was no bad debt expense recognized for the years ended December 31, 2017 and 2016.

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 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.

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Table of Contents

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

3. Summary of Significant Accounting Policies (Continued)

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.

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.

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 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.

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Table of Contents

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

3. Summary of Significant Accounting Policies (Continued)

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. The carrying values of cash and cash equivalents, commodity derivative contracts (see Note 13), accounts receivable, accounts payable, accrued liabilities, convertible debentures, and long-term debt approximate fair value.

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.

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 option 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.

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Table of Contents

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

3. Summary of Significant Accounting Policies (Continued)

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 (loss).

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 (loss).

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Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

3. Summary of Significant Accounting Policies (Continued)

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 liabilities for counterparties with a legal right of offset. At December 31, 2017 and 2016, 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 (loss).

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

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Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

3. Summary of Significant Accounting Policies (Continued)

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

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 January 2017, the FASB issued Accounting Standards Update (ASU) 2017-01 "Business Combinations (Topic 805): Clarifying the Definition of a Business" (ASU 2017-01), which clarifies the definition of a business to provide guidance in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 provides a screen to determine when a set of assets is not a business, requiring that when substantially all fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set of assets is not a business. A framework is provided to assist in evaluating whether both an input and a substantive process are present for the set to be a business. ASU 2017-01 is effective for annual periods beginning after December 15, 2018, and interim periods within annual periods beginning after December 15, 2019. No disclosures are required at transition and early adoption is permitted. Epsilon is evaluating ASU 2017-01 to determine the impact on its consolidated financial statements and related disclosures.

In November 2016, the FASB issued Accounting Standards Update No. 2016-18, Statement of Cash Flows: Restricted Cash ("ASU 2016-18"). This ASU amends ASC Topic 230, Statement of Cash Flows, to clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. ASU 2016-18 is effective for fiscal years beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019, and must be applied retrospectively. Early adoption is permitted.

In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230)—Classification of Certain Cash Receipts and Cash Payments" (ASU 2016-15). ASU 2016-15 reduces existing diversity in practice by providing guidance on the classification of eight specific cash receipts and cash payments transactions in the statement of cash flows. The new standard is effective for fiscal years beginning after December 15, 2018, and interim periods within annual periods beginning after December 15, 2019. Early adoption is permitted. Epsilon does not intend to early adopt ASU 2016-15. Epsilon does not expect the adoption of ASU 2016-15 to have a material impact on its consolidated financial statements and related disclosures.

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Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

3. Summary of Significant Accounting Policies (Continued)

In June 2016, the FASB issued ASU 2016-13 "Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking "expected loss" model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for fiscal years beginning after December 15, 2020, and interim periods within fiscal years beginning after December 15, 2021. Early adoption is permitted. ASU 2016-13 requires varying transition methods for the different categories of amendments. Epsilon does not expect ASU 2016-13 to have a significant impact on our financial statements.

In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting" (ASU 2016-09), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures and minimum statutory tax withholdings and prescribes certain disclosures to be made in the period the new standard is adopted. ASU 2016-09 is effective for annual periods beginning after December 15, 2017 and interim periods within annual periods beginning after December 15, 2018. Epsilon adopted ASU 2016-09 effective January 1, 2018. There will be no impact to accumulated deficit with respect to excess tax benefits.

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 virtually 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.

In November 2015, the FASB issued ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes" (ASU 2015-17), which simplifies the presentation of deferred taxes in a classified balance sheet by eliminating the requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. Instead, ASU 2015-17 requires that all deferred tax liabilities and assets be shown as noncurrent in a classified balance sheet. ASU 2015-17 is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within annual periods beginning after December 15, 2018, and early application is permitted. Epsilon adopted ASU 2015-17 effective January 1, 2017, but this had no effect on the Balance Sheet.

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

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Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

3. Summary of Significant Accounting Policies (Continued)

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)."

4. Property and Equipment

The following table summarizes the Corporation's oil and natural gas property and other equipment as at December 31, 2017 and 2016:

|  | December 31, 2017 |  | December 31, 2016 |
--- | --- | --- | --- | --- | ---
Oil and gas properties: |  |  |  |  |  |  |
Proved properties |  | $ | 118,524,693 |  | $ | 116,769,430 |
Unproved properties |  |  | 17,451,552 |  |  | — |
Accumulated depletion, depreciation, and amortization |  |  | (78,625,589 | ) |  | (70,670,124 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total oil and gas properties, net |  |  | 57,350,656 |  |  | 46,099,306 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Gathering system |  |  | 40,880,503 |  |  | 40,738,085 |
Accumulated depletion, depreciation, and amortization |  |  | (26,252,385 | ) |  | (23,240,450 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total gathering system, net |  |  | 14,628,118 |  |  | 17,497,635 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other property and equipment |  |  | 299 |  |  | 1,443 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total property and equipment |  | $ | 71,979,073 |  | $ | 63,598,384 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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Table of Contents

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

4. Property and Equipment (Continued)

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.

Property Impairment

At December 31, 2017 and 2016, 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, 2017 and 2016.

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.

The following table sets forth a reconciliation of the convertible debentures for the years ending December 31, 2017 and 2016:

|  | Balance US$ |  | Balance Cdn$ |
--- | --- | --- | --- | --- | ---
Balance at January 1, 2016 |  | $ | 27,795,613 |  | $ | 38,471,437 |
Purchase of Convertible Debenture |  |  | (385,500 | ) |  | (500,000 | )
Amortization of fees |  |  | 322,251 |  |  | 423,054 |
Translation adjustment at December 31, 2016 |  |  | 863,849 |  |  | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at December 31, 2016 |  | $ | 28,596,213 |  | $ | 38,394,491 |
Conversion of Convertible Debenture |  |  | (869 | ) |  | (1,000 | )
Amortization of fees |  |  | 52,924 |  |  | 70,509 |
Translation adjustment at February 16, 2017 |  |  | 815,922 |  |  | — |
Redemption of Convertible Debenture |  |  | (29,464,190 | ) |  | (38,464,000 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at December 31, 2017 |  | $ | — |  | $ | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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Table of Contents

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

6. Revolving Line of Credit

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.

In December, 2017 a redetermination of the borrowing base was executed reducing it to $13.5 million.

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Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

6. Revolving Line of Credit (Continued)

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, the Corporation 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.

The Corporation was in compliance with the financial covenants of the Credit Facility as of December 31, 2017 and 2016 and we expect to be in compliance with the financial covenants for the next 12 months.

|  | Balance as at December 31, |  |  |  |
--- | --- | --- | --- | --- | --- | ---
|  | Borrowing Base December 31, 2017 |  |
|  | 2017 |  | 2016 |  | Interest Rate
Revolving line of credit |  | $ | 2,900,000 |  | $ | 12,460,000 |  | $ | 13,500,000 |  | 3 mo LIBOR + 2.75%(1)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

(1)
  At December 31, 2017, the interest rate was 4.1%.

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, 2017 and 2016.

|  | Number of shares issued |  | Amount |
--- | --- | --- | --- | --- | ---
Balance at December 31, 2015 |  |  | 46,220,264 |  | $ | 127,359,759 |
Buyback of Shares |  |  | (382,400 | ) |  | (1,056,080 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at December 31, 2016 |  |  | 45,837,864 |  | $ | 126,303,679 |
Conversion of debenture to shares |  |  | 224 |  |  | 614 |
Exercise of stock options |  |  | 40,000 |  |  | 80,759 |
Shares issued through rights offering (net of issuance costs of $77,478) |  |  | 9,167,617 |  |  | 17,907,186 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at December 31, 2017 |  |  | 55,045,705 |  | $ | 144,292,238 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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Table of Contents

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

7. Shareholders' Equity (Continued)

Through a normal-course issuer bid ("NCIB") program, the Corporation repurchased 382,400 shares of common stock throughout the year ended December 31, 2016. The repurchased stock had an average price of Cdn$2.86 per share and was canceled upon repurchase.

(c) Stock Options

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 Common Shares available under the Plan from a limit of 10% of the total issued and outstanding Common Shares to a fixed maximum of 2,000,000 Common Shares, and (ii) deleted some redundant definitions and clarified existing wording in the Plan.

On June 28, 2018, our shareholders approved the Epsilon Energy, Inc. Equity Incentive Plan, which will become effective upon completion of the domestication.

Through December 31, 2017, the Corporation had issued stock options covering 661,500 Common Shares at an overall average price of Cdn$3.43 per Common Share to directors, officers, employees and consultants of the Corporation and its subsidiaries.

At December 31, 2017, the Corporation was authorized to issue options covering up to 2,000,000 shares of stock. As of that date, the Corporation had issued options covering 661,500 Common Shares, leaving a maximum amount of 1,338,500 Common Shares available for future option issuances.

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Table of Contents

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

7. Shareholders' Equity (Continued)

The following table summarizes stock option activity for the years ended December 31, 2017 and 2016:

|  | Year ended December 31, 2017 |  | Year ended December 31, 2016 |
--- | --- | --- | --- | --- | ---
Exercise price in Cdn$ |  | Number of Options Outstanding |  | Weighted Average Exercise Price |  | Number of Options Outstanding |  | Weighted Average Exercise Price |
Balance at beginning of period |  |  | 511,000 |  | $ | 3.33 |  |  | 511,000 |  | $ | 3.33 |
Granted |  |  | 241,500 |  | $ | 3.35 |  |  | — |  |  | — |
Exercised |  |  | (40,000 | ) | $ | 1.63 |  |  | — |  |  | — |
Expired |  |  | (51,000 | ) | $ | 3.53 |  |  | — |  |  | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance at period-end |  |  | 661,500 |  | $ | 3.43 |  |  | 511,000 |  | $ | 3.33 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Exercisable at period-end |  |  | 323,333 |  | $ | 3.41 |  |  | 317,667 |  | $ | 3.12 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

At December 31, 2017, the Corporation had unrecognized stock based compensation of $117,520 to be recognized over a weighted average period of 1.2 years (for the year ended December 31, 2016: $76,577 over 1.5 years). The aggregate intrinsic value at December 31, 2017 was $79,500 (at December 31, 2016: $124,200).

The average share price during the year ended December 31, 2017 was Cdn$3.12 (for the year ended December 31, 2016: Cdn$3.04). The average exchange rate for the year ended December 31, 2017 was Cdn$0.78 to US$1 (for the year ended December 31, 2016, Cdn$0.76).

The following table summarizes information for stock options outstanding at December 31, 2017 (exercise price in Cdn$):

Exercise Price |  | Number of Options Outstanding |  | Number of Options Exercisable |  | Option Pricing Model Valuations |  | Weighted Average Remaining Contractual Life (in years) |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
As at December 31, 2017: |  |  |  |  |  |  |  |  |  |  |  |  |
$1.45 |  |  | 50,000 |  |  | 50,000 |  | $ | 57,294 |  |  | 1.61 |
$3.27 |  |  | 85,000 |  |  | — |  |  | 40,772 |  |  | 6.02 |
$3.40 |  |  | 156,500 |  |  | — |  |  | 72,494 |  |  | 6.07 |
$3.67 |  |  | 290,000 |  |  | 193,333 |  |  | 481,191 |  |  | 4.43 |
$4.00 |  |  | 80,000 |  |  | 80,000 |  |  | 142,765 |  |  | 0.21 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total |  |  | 661,500 |  |  | 323,333 |  | $ | 794,515 |  |  | 4.30 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

During the year ended December 31, 2017, the Corporation awarded 241,500 stock options (none during the year ended December 31, 2016). Of the options awarded, 85,000 have an exercise price of Cdn$3.27 and 156,500 have an exercise price of Cdn$3.40. One-third of the options vest each year on the anniversary of the grant date. For 85,000 of the options granted, the weighted average fair value was $1.15 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 156,500 of the

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Table of Contents

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

7. Shareholders' Equity (Continued)

options granted, the weighted average fair value was $1.19 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.

8. Accumulated Other Comprehensive Income (Loss)

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 (Loss) during the years ended December 31, 2017 and 2016 consisted of the following:

|  | Foreign Currency Translation Adjustment |
--- | --- | --- | ---
Balance January 1, 2016 |  | $ | 9,838,183 |
Translation loss-convertible debentures |  |  | (863,849 | )
Translation gain-other |  |  | 372,521 |
​ | ​ | ​ | ​ | ​
Balance December 31, 2016 |  | $ | 9,346,855 |
Translation loss-convertible debentures |  |  | (815,922 | )
Translation gain-other |  |  | 1,382,303 |
​ | ​ | ​ | ​ | ​
Balance December 31, 2017 |  | $ | 9,913,236 |
​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​

9. Income Taxes

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

|  | Years ended December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Foreign |  |  | (1,488,296 | ) | $ | (3,199,276 | )
U.S. |  |  | 6,857,775 |  |  | (7,065,025 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
|  | $ | 5,369,479 |  | $ | (10,264,301 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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Table of Contents

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

9. Income Taxes (Continued)

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 has 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.

The Corporation follows the guidance in SEC Staff Accounting Bulletin 118 ("SAB 118"), which provides 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 provides for a measurement period beginning in the reporting period that includes 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. We have calculated the impact of the Act in our year end income tax provision in accordance with our understanding of the Act and guidance available as of the date of this filing. We will continue to gather and evaluate the income tax impact of the Act. The ultimate impact of the Act on our reported results in 2018 and beyond may differ, possibly materially, due to, among other things, changes in interpretations and assumptions we have made, guidance that may be issued, and other actions we may take as a result of the Act.

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, 2014 through December 31, 2017. To the extent we utilize net operating losses generated in earlier years, such earlier years may also be subject to audit.

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Table of Contents

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

9. Income Taxes (Continued)

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

|  | Years ended December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Current: |  |  |  |  |  |  |
Federal |  | $ | 304,070 |  | $ | 81,194 |
State |  |  | 159,640 |  |  | 52,069 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total curent income tax expense |  |  | 463,710 |  |  | 133,263 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Deferred: |  |  |  |  |  |  |
Federal |  |  | (2,539,621 | ) |  | (2,123,798 | )
State |  |  | 9,485 |  |  | (705,983 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total deferred income tax benefit |  |  | (2,530,136 | ) |  | (2,829,781 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Income tax benefit |  | $ | (2,066,426 | ) | $ | (2,696,518 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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 2016 differs from the statutory rate primarily due to state taxes and the valuation allowance on the Canadian loss. In addition to state taxes and valuation allowance on the Canadian loss, our effective tax rate for 2017 differs from the statutory rate 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, 2017 |  | Effective Tax Rate |  | Year Ended December 31, 2016 |  | Effective Tax Rate |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Income tax provision computed at the statutory federal tax rate |  | $ | 1,825,623 |  |  | 34.00 | % | $ | (3,489,863 | ) |  | 34.00 | %
Difference in Canadian and U.S. tax rate |  |  | 111,622 |  |  | 2.08 | % |  | 239,946 |  |  | –2.34 | %
Valuation allowance on Canadian loss |  |  | 394,398 |  |  | 7.35 | % |  | 847,808 |  |  | –8.26 | %
2016 return to provision adjustment |  |  | (13,576 | ) |  | –0.25 | % |  | — |  |  | 0.00 | %
Change in US federal rate—tax reform |  |  | (4,625,262 | ) |  | –86.14 | % |  | — |  |  | 0.00 | %
State taxes |  |  | 452,040 |  |  | 8.42 | % |  | (465,780 | ) |  | 4.54 | %
Miscellanous other items |  |  | 75,312 |  |  | 1.40 | % |  | (1,339 | ) |  | 0.00 | %
Change in uncertain tax position |  |  | (286,583 | ) |  | –5.34 | % |  | 172,710 |  |  | –1.68 | %
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Income tax benefit |  | $ | (2,066,426 | ) |  | –38.48 | % | $ | (2,696,518 | ) |  | 26.26 | %
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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, 2017, we have no federal net operating loss carry-forwards and state net operating loss carry-forwards of approximately $8.7 million, 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.

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Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

9. Income Taxes (Continued)

Net deferred tax liabilities consisted of the following at December 31, 2017 and 2016:

|  | As at December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Deferred tax assets: |  |  |  |  |  |  |
U.S. federal and state net operating loss carryforwards |  | $ | 684,097 |  | $ | 3,268,410 |
Canadian net operating loss carryforwards |  |  | 11,943,207 |  |  | 11,548,808 |
AMT credit |  |  | — |  |  | 435,981 |
Other |  |  | 120,654 |  |  | 490,421 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Gross deferred tax assets |  |  | 12,747,958 |  |  | 15,743,620 |
Valuation allowance |  |  | (11,943,207 | ) |  | (11,548,808 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total deferred tax assets |  |  | 804,751 |  |  | 4,194,812 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Deferred tax liabilities: |  |  |  |  |  |  |
Oil and gas property |  |  | (8,182,788 | ) |  | (12,455,537 | )
Partnership |  |  | (3,183,646 | ) |  | (4,831,095 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total deferred tax liabilities |  |  | (11,366,434 | ) |  | (17,286,632 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net deferred tax liability |  | $ | (10,561,683 | ) | $ | (13,091,820 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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. Upon domestication to the US, it is expected that some or all of the Canadian NOLs could be utilized, which would allow for the removal of the valuation allowance.

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, 2017 and 2016, the gross liability for income taxes associated with uncertain tax positions was $1,199,553 and $1,878,397, respectively. If recognized, $931,627 of unrecognized tax benefits would affect our effective tax rate. 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 income (loss). Accrued interest and penalties are included in other non-current liabilities in the consolidated balance sheets and were $415,760 and $365,221 as of December 31, 2017 and 2016, respectively. As of December 31, 2017, tax years ending December 31, 2013, 2014 and 2015 are subject to examination by the tax authorities. The remaining balance of the uncertain tax positions will expire in 2018.

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Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

9. Income Taxes (Continued)

Changes in the balance of unrecognized tax benefits on uncertain positions were as follows for each of the two years ended December 31, 2017:

Uncertain Tax Position: |  |  |  |
Balance at December 31, 2015 |  | $ | 1,917,843 |
Lapse of statute of limitations |  |  | (39,446 | )
​ | ​ | ​ | ​ | ​
Balance at December 31, 2016 |  |  | 1,878,397 |
Lapse of statute of limitations |  |  | (678,844 | )
​ | ​ | ​ | ​ | ​
Balance at December 31, 2017 |  | $ | 1,199,553 |
​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​

10. Commitments and Contingencies

The Corporation's future minimum lease commitments as of December 31, 2017 are summarized in the following table:

Year ended December 31, |  | Payments |
--- | --- | --- | ---
2018 |  |  | 78,506 |
2019 |  |  | 80,577 |
2020 |  |  | 6,729 |
​ | ​ | ​ | ​ | ​
|  | $ | 165,812 |
​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​

The Corporation enters into commitments for capital expenditures in advance of the expenditures being made. At a given point in time, it is estimated that the Corporation has committed to capital expenditures equal to approximately one quarter of its capital budget by means of giving the necessary authorizations to incur the expenditures in a future period. As of December 31, 2017, we had no material commitments for capital expenditures.

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 (Loss) Per Share

Basic net income (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income (loss) 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 loss used in the calculation of basic and diluted net loss per share are as follows:

|  | Years ended December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Net income (loss) available to shareholders |  | $ | 7,435,905 |  | $ | (7,567,783 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

11. Net Income (Loss) Per Share (Continued)

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

|  | Years ended December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Basic weighted-average number of shares outstanding |  |  | 52,239,854 |  |  | 45,882,030 |
Dilutive effect of stock options |  |  | 26,735 |  |  | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Diluted weighted average shares outstanding |  |  | 52,266,589 |  |  | 45,882,030 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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

|  | Years ended December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Anti-dilutive, or out-of-the-money options |  |  | 634,765 |  |  | 511,000 |
Convertible debenture conversion shares |  |  | 1,080,478 |  |  | 8,643,820 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total anti-dilutive shares |  |  | 1,715,243 |  |  | 9,154,820 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

12. Operating Segments

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

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Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

12. Operating Segments (Continued)

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

|  | Upstream |  | Gas Gathering |  | Canada |  | Corporate |  | Elimination |  | Consolidated |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
As at and for the twelve months ended December 31, 2017 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  | $ | 19,325,528 | (1) | $ | 7,614,075 |  | $ | — |  | $ | — |  | $ | (1,182,512 | ) | $ | 25,757,091 |
Net (loss) earnings for the period |  | $ | 5,544,931 |  | $ | 2,521,014 |  | $ | — |  | $ | (630,040) | (3) |  |  |  | $ | 7,435,905 |
Operating costs |  |  | 5,723,298 |  |  | 2,078,601 |  |  | — |  |  | — |  |  | (1,182,512 | ) |  | 6,619,387 |
Depletion, deprec., amortization and accretion |  |  | 8,057,299 |  |  | 3,014,460 |  |  | — |  |  | — |  |  |  |  |  | 11,071,759 |
Segment assets |  | $ | 65,704,141 |  | $ | 18,222,609 |  | $ | 2,478,910 |  | $ | — |  |  |  |  | $ | 86,405,660 |
Capital expenditures(2) |  |  | 19,129,745 |  |  | 200,689 |  |  | — |  |  | — |  |  |  |  |  | 19,330,434 |
Proved properties |  |  | 39,899,104 |  |  | — |  |  | — |  |  | — |  |  |  |  |  | 39,899,104 |
Unproved properties |  |  | 17,451,552 |  |  | — |  |  |  |  |  |  |  |  |  |  |  | 17,451,552 |
Gathering system |  |  |  |  |  | 14,628,118 |  |  |  |  |  |  |  |  |  |  |  | 14,628,118 |
Other property and equipment |  |  | 299 |  |  | — |  |  |  |  |  |  |  |  |  |  |  | 299 |
As at and for the twelve months ended December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenue |  | $ | 15,263,438 | (1) | $ | 10,132,911 |  | $ | — |  | $ | — |  | $ | (1,696,076 | ) | $ | 23,700,273 |
Net (loss) earnings for the period |  | $ | (6,564,166 | ) | $ | 1,941,261 |  | $ | — |  | $ | (2,944,878) | (3) | $ | — |  | $ | (7,567,783 | )
Operating costs |  |  | 6,582,039 |  |  | 2,469,941 |  |  | — |  |  | — |  |  | (1,696,076 | ) |  | 7,355,904 |
Depletion, deprec., amortization and accretion |  |  | 15,245,566 |  |  | 5,721,709 |  |  | — |  |  | — |  |  | — |  |  | 20,967,275 |
Segment assets |  | $ | 50,558,020 |  | $ | 19,463,503 |  | $ | 30,121,469 |  | $ | — |  | $ | — |  | $ | 100,142,992 |
Capital expenditures(2) |  |  | (12,024 | ) |  | 684,046 |  |  | — |  |  | — |  |  | — |  |  | 672,022 |
Proved properties |  |  | 46,099,306 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 46,099,306 |
Gathering system |  |  | — |  |  | 17,497,635 |  |  | — |  |  | — |  |  | — |  |  | 17,497,635 |

(1)
  Segment operating revenue represents revenues generated from the operations of the segment. Inter-segment sales during the years ended December 31, 2017 and 2016 have been eliminated upon consolidation. For the year ended December 31, 2017, Epsilon 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 total revenue. For the year ended December 31, 2016, Epsilon sold natural gas to 22 unique customers. DTE Energy Trading, Inc., Repsol Energy North America Corporation and Twin Eagle Resource Management, LLC each accounted for 10% or more of our 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 (loss) 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.

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.

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Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

13. Risk Management Activities (Continued)

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 g ain (loss) on commodity contracts on the consolidated statements of operations and comprehensive income (loss). The related cash flow impact is reflected in cash flows from operating activities. During 2017, Epsilon recognized gains on financial commodity derivative contracts of $2,623,687. This amount included cash received on settlements of these contracts of $2,027,791. For 2016, Epsilon recognized losses of $487,550, which included cash paid on settlements of natural gas derivative contracts of $151,198.

Commodity Derivative Contracts

Epsilon's outstanding natural gas price swap contracts as of December 31, 2017 consisted of:

|  |  |  | Weighted Average Price ($/Mmbtu) |  |  |
--- | --- | --- | --- | --- | --- | --- | ---
Derivative Type |  | Volume (Mmbtu) |  | Swaps |  | Ceiling Price |  | Floor Price |  | Basis Differential |  | Fair Value December 31, 2017 |
2018 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed price swap |  |  | 3,673,500 |  | $ | 2.88 |  | $ | — |  | $ | — |  | $ | — |  | $ | 203,840 |
Basis swap |  |  | 4,175,000 |  | $ | — |  | $ | — |  | $ | — |  | $ | (0.51 | ) |  | 22,191 |
Two-way costless collar |  |  | 501,500 |  | $ | — |  | $ | 4.36 |  | $ | 2.70 |  | $ | — |  |  | 33,513 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
|  |  | 8,350,000 |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 259,544 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

As of December 31, 2017 and 2016, 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

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Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

13. Risk Management Activities (Continued)

non-performance by such counterparties. None of the Corporation's derivative instruments contains credit-risk related contingent features.

|  | Fair Value of Derivative Assets |
--- | --- | --- | ---
|  | December 31, 2017 |  | December 31, 2016 |
Current |  |  |  |  |  |  |
Fixed price swap |  | $ | 203,840 |  | $ | — |
Basis swap |  |  | 22,191 |  |  | — |
Two-way costless collar |  |  | 45,950 |  |  | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
|  | $ | 271,981 |  | $ | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

|  | Fair Value of Derivative Liabilities |
--- | --- | --- | ---
|  | December 31, 2017 |  | December 31, 2016 |
Current |  |  |  |  |  |  |
Fixed price swap |  | $ | — |  | $ | (336,352 | )
Two-way costless collar |  |  | (12,437 | ) |  | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
|  | $ | (12,437 | ) | $ | (336,352 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net Fair Value of Derivatives |  | $ | 259,544 |  | $ | (336,352 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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

|  | Years ended December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Fair value of asset (liability), beginning of period |  | $ | (336,352 | ) | $ | — |
Gain (loss) on derivatives |  |  | 2,623,686 |  |  | (487,550 | )
Cash (received from) paid for settlements on derivatives |  |  | (2,027,791 | ) |  | 151,198 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Fair value of asset (liability), end of period |  | $ | 259,544 |  | $ | (336,352 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

14. Asset Retirement Obligations

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, 2017 ($1.5 million at December 31, 2016) based on a total net future undiscounted liability of approximately $12.0 million ($8.4 million at December 31, 2016). Each year we review, and to the extent necessary, revise our asset retirement obligation estimates. During 2017 and 2016, we reviewed the actual

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Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2017 and 2016

14. Asset Retirement Obligations (Continued)

abandonment costs with previous estimates and, as a result, estimates remained unchanged, we did, however, add to our liability, amounts relating to the recent acquisition of properties in Oklahoma.

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

|  | Years ended December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Balance beginning of period |  | $ | 1,468,635 |  | $ | 1,373,187 |
Liabilities acquired |  |  | 90,827 |  |  | — |
Change in estimates |  |  | (16,072 | ) |  | — |
Accretion |  |  | 103,211 |  |  | 95,448 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance end of period |  | $ | 1,646,601 |  | $ | 1,468,635 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

15. Subsequent Events

The Company has evaluated subsequent events through May 4, 2018, which is the date these consolidated financial statements were available for issuance.

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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, 2017. 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

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

NET PROVED RESERVE SUMMARY

All reserves located in United States

|  | Natural Gas (MMcf) |  | Oil (MBbl) |  | Total (MMcfe) |
--- | --- | --- | --- | --- | --- | --- | ---
Net proved reserves at December 31, 2015 |  |  | 39,988 |  |  | — |  |  | 39,988 |
Revisions of previous estimates(1)(2) |  |  | 13,634 |  |  | — |  |  | 13,634 |
Improved recoveries(3) |  |  | 6,791 |  |  | — |  |  | 6,791 |
Production |  |  | (11,016 | ) |  | — |  |  | (11,016 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net proved reserves at December 31, 2016 |  |  | 49,397 |  |  | — |  |  | 49,397 |
Revisions of previous estimates(1)(2)(5) |  |  | 163,261 |  |  | — |  |  | 163,261 |
Improved recoveries(3) |  |  | 9,756 |  |  | — |  |  | 9,756 |
Acquisitions(4) |  |  | 2,184 |  |  | 40 |  |  | 2,426 |
Production |  |  | (9,010 | ) |  | (3 | ) |  | (9,028 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net proved reserves at December 31, 2017 |  |  | 215,588 |  |  | 37 |  |  | 215,812 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Proved developed reserves: |  |  |  |  |  |  |  |  |  |
At Decemeber 31, 2105 |  |  | 39,988 |  |  | — |  |  | 39,988 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
At Decemeber 31, 2016 |  |  | 48,463 |  |  | — |  |  | 48,463 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
At Decemeber 31, 2017 |  |  | 60,571 |  |  | 37 |  |  | 60,795 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Proved undeveloped reserves: |  |  |  |  |  |  |  |  |  |
At Decemeber 31, 2015 |  |  | — |  |  | — |  |  | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
At Decemeber 31,2016 |  |  | 934 |  |  | — |  |  | 934 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
At Decemeber 31, 2017 |  |  | 155,017 |  |  | — |  |  | 155,017 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

(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 entirely attributable to undeveloped well locations becoming economic due to increases in the price of natural gas.
(3)
  Improved recoveries in the proved producing category are primarily attributable to actual production from the wells exceeding the expected production curves from the previous year.
(4)
  Acquisitions are entirely attributable to the Company's purchase of leases and associated production in Oklahoma.
(5)
  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.

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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, 2017 and 2016:

|  | Years ended December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Proved properties |  | $ | 118,524,693 |  | $ | 116,769,430 |
Unproved properties |  |  | 17,451,552 |  |  | — |
Gathering system properties |  |  | 40,880,503 |  |  | 40,738,085 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total Oil & Gas Properties |  |  | 176,856,748 |  |  | 157,507,515 |
Accumulated depreciation, depletion and amortization |  |  | (104,877,974 | ) |  | (93,910,574 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net capitalized costs |  | $ | 71,978,774 |  | $ | 63,596,941 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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.

|  | Years ended December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Oil and Natural Gas Activities |  |  |  |  |  |  |
Proved acquisition costs |  | $ | 1,734,509 |  | $ | — |
Unproved acquisition costs |  |  | 17,451,552 |  |  | — |
Development costs(1) |  |  | 20,758 |  |  | (152,016 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total costs incurred for oil and natural gas activities |  |  | 19,206,819 |  |  | (152,016 | )
Gathering System development costs |  |  | 142,418 |  |  | 466,805 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total costs incurred |  | $ | 19,349,237 |  | $ | 314,789 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

(1)
  Negative amount in 2016 primarily related to the reversal of an overaccrual in the prior year.

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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, 2017 and 2016:

|  | Years ended December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Oil and gas producing activities: |  |  |  |  |  |  |
Gas sales |  | $ | 19,203,543 |  | $ | 15,263,438 |
Oil and other liquid sales |  |  | 121,985 |  |  | — |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total revenues |  |  | 19,325,528 |  |  | 15,263,438 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating costs |  |  | (5,723,298 | ) |  | (6,582,039 | )
Depreciation, depletion, amortization, and accretion |  |  | (8,057,299 | ) |  | (15,245,400 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total costs |  |  | (13,780,597 | ) |  | (21,827,439 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Results of operations from oil and gas producing activities |  | $ | 5,544,931 |  | $ | (6,564,001 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

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 2017 and 2016. 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. Such estimates will not be impacted by the planned domestication because all of the Corporation's properties are located in the United States. 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.

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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, 2017 and 2016:

|  | As of December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Future cash inflows |  | $ | 444,906,724 |  | $ | 65,797,522 |
Future production costs |  |  | (168,489,681 | ) |  | (40,341,660 | )
Future development costs(1) |  |  | (92,026,760 | ) |  | (2,132,099 | )
Future income taxes(2) |  |  | (49,347,763 | ) |  | — |
10% annual discount for estimated timing of cash flows |  |  | (85,326,963 | ) |  | (6,936,494 | )
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Standardized measure of discounted future net cash flows |  | $ | 49,715,557 |  | $ | 16,387,269 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

(1)
  Costs associated with the abandonment of proved properties are included in future development costs.
(2)
  Future income taxes for 2017 were estimated using a combined federal and state statutory tax rate of approximately 27.6% which includes the reduced corporate tax rate of 21% enacted on December 22, 2017 via the Tax Cuts and Jobs Act. Future income taxes for 2016 were estimated using a combined federal and state statutory tax rate of 40.6% which includes a corporate tax rate of 34%. No future income taxes were estimated for 2016 due to sufficient existing tax basis and net operating losses.

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, 2017 and 2016:

|  | For the years ended December 31, |
--- | --- | --- | ---
|  | 2017 |  | 2016 |
Beginning balance |  | $ | 16,387,269 |  | $ | 6,859,394 |
Revenue less production and other costs |  |  | (13,634,107 | ) |  | (8,681,399 | )
Changes in price, net of production costs |  |  | 26,136,085 |  |  | 9,915,102 |
Development costs incurred |  |  | 34,457 |  |  | (152,016 | )
Net changes in future development costs |  |  | (68,608,621 | ) |  | (15,233 | )
Revisions of previous quantity estimates(1) |  |  | 111,557,578 |  |  | 7,196,831 |
Accretion of discount |  |  | 1,390,234 |  |  | 582,876 |
Net change in income taxes |  |  | (19,722,823 | ) |  | — |
Purchases of reserves in place |  |  | 786,392 |  |  | — |
Timing differences and other technical revisions(1) |  |  | (4,610,907 | ) |  | 681,714 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Ending balance |  | $ | 49,715,557 |  | $ | 16,387,269 |
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

(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.

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