Epsilon Energy Ltd. (Form: 10-K, Received: 03/29/2019 14:01:28)

Year ended December 31,

(in thousands of dollars)

Miscellaneous income

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑K

(Mark One)

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

For the fiscal year ended December 31, 2018.

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

For the transition period from to

Commission file number 001-38770

EPSILON ENERGY LTD.

(Exact name of registrant as specified in its charter)


Alberta, Canada		N/A
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

116701 Greenspoint Park Drive, Suite 195 Houston, Texas		77060
(Address of Principal Executive Offices)		(Zip Code)

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

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

Title of each class		Name of each exchange on which registered
Common Shares, no par value		Nasdaq Capital Market

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

NONE

(Title of class)

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

Yes ☐

No ☒

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

Yes

☐

No ☒

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

Yes ☐

No ☒

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

Yes ☒

No ☐

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

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

Large accelerated filer ☐

Accelerated filer ☐

Non‑accelerated filer ☐

Smaller reporting company ☒

Emerging growth company ☒

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

Yes ☐

No ☒

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $47.2 million. There were 27,355,247 shares of Common Shares ($0 par value) outstanding as of March 26, 2019.

PART I

FORWARD LOOKING STATEMENTS.

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

DEFINED TERMS

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

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

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

‘‘Anchor shippers’’ Parties listed in the Anchor Shipper Gas Gathering Agreement for Northern Pennsylvania, including Epsilon Midstream, LLC.

‘‘ASC’’ Accounting Standards Codification.

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

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

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

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

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

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

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

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

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

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

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

‘‘FASB’’ Financial Accounting Standards Board.

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

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

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

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

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

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

‘‘LIBOR’’ London interbank offered rate.

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

‘‘MBbl/d’’ One MBbl per day. ‘‘MBOE’’ One thousand BOE. ‘‘MBOE/d’’ One MBOE per day.

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

‘‘MMBOE’’ One million BOE.

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

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

‘‘MMcf/d’’ One MMcf per day.

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

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

‘‘NGL’’ Natural gas liquid.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

EXCHANGE RATE

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


	December 31,	December 31,
	2018	2017
Daily Closing Rate	0.7329	0.7971

Annual Average Rate	0.7718	0.7708
Yearly High Closing Rate	0.7326	0.8245
Yearly Low Closing Rate	0.8143	0.7276

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. Commencing on February 19, 2019, the common shares of the Corporation trade on the Nasdaq Global Market with the ticker symbol ‘‘EPSN.’’ Effective as of the close of trading on March 15, 2019, Epsilon voluntarily delisted its common shares from the Toronto Stock Exchange. At December 31, 2018, Epsilon’s total estimated net proved reserves were 119,116 million cubic feet (MMcf) of natural gas reserves and 30,502 barrels (Bbl) of oil and other liquids. Epsilon held leasehold rights to approximately 76,251 gross (11,601 net) acres. The Corporation has natural gas production in Pennsylvania and has also added oil and natural gas production from its recent acquisitions in the Anadarko Basin in Oklahoma.

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

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

Our principal executive office is located at 16701 Greenspoint Park Drive, Suite 195, Houston, Texas 77060, and our telephone number at that address is (281) 670‑0002. Our registered office in Alberta, Canada is located at 14505 Bannister Road SE, Suite 300, Calgary, AB, Canada T2X 3J3.

Business highlights of 2018

Operational Highlights

Marcellus Shale—Pennsylvania

During 2018, Epsilon’s realized natural gas price was $2.51 per Mcf, an 18% increase over 2017.

Total 2018 natural gas production was 7.3 Bcf, as compared to 8.9 Bcf during 2017.

Marcellus working interest (WI) gas averaged 23.0 MMcf/d for 2018.

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

Anadarko, NW Stack Trend—Oklahoma

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

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

Business highlights of 2017

Operational Highlights

Marcellus Shale—Pennsylvania

During 2017, we produced 8.9 Bcf of natural gas net to our revenue interest.

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

NW Stack Trend—Oklahoma

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

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

Properties

As of December 31, 2018, Epsilon’s 76,251 gross (11,601 net) acres are all located in the United States and include 266 gross (51.45 net) wells.


	Gross (1)	Net (2)
Producing Wells
Oil	8	0.85
Gas	150	24.18
Oil & Gas	67	14.77
Total Producing Wells	225	39.79
Non-producing Wells	41	11.66
Total Wells	266	51.45

Acreage

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


	Gross (1)	Net (2) (3)
Developed Acres
Pennsylvania	8,276	4,138
Oklahoma	5,769	601
Mississippi	627	376
	14,672	5,115
Undeveloped Acres
Pennsylvania	—	—
Oklahoma	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 Oklahoma undeveloped properties are deep rights acreage which is held by production of developed properties.

Business Segments

Our operations are conducted by three operating segments for which information is provided in our consolidated financial statements for the years ended December 31, 2018 and 2017.

The three segments are as follows:

Upstream: Activities include acquisition, exploration, development and production of oil and natural gas reserves on properties within the United States.

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

Canada: Activities include our corporate and governance functions.

For information about our segment’s revenues, profits and losses, total assets, and total liabilities, see Note 12, “Operating Segments,” of the Notes to Consolidated Financial Statements.

Oil and Natural Gas Production and Revenues and Gathering System Revenues

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


	Year ended
	December 31,
Revenues ($000)	2018		2017
Natural gas revenue	$	19,031	$	19,204
Volume (MMcf)		7,563		9,010
Avg. Price ($/Mcf)	$	2.52	$	2.13
Exit Rate (MMcfpd)		21.2		27.0
Oil and other liquids revenue	$	671	$	122
Volume (MBO)		17.1		3.1
Avg. Price ($/Bbl)	$	39.31	$	39.18
Gathering system revenue	$	9,982	$	6,432
Total Revenues	$	29,684	$	25,757

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 have been eliminated from gathering system revenues amounted to $1.1 million and $1.2 million, respectively, for the years ended December 31, 2018 and 2017.

During years ended December 31, 2018 and 2017, the Auburn GGS delivered 103 Bcf and 88 Bcf respectively, of natural gas, or 282 and 242 MMcf per day.

Proved Reserves

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


	Natural Gas	Oil and other
	MMcf	Liquids MBbl
Pennsylvania-Marcellus Shale
Proved developed producing	48,757.8	—
Proved undeveloped	68,418.0	—
Total Pennsylvania proved reserves	117,175.8	—
Oklahoma-Anadarko Basin
Proved developed producing	1,581.3	28.0
Proved developed non-producing	359.0	2.5
Total Oklahoma proved reserves	1,940.3	30.5
Total proved reserves at December 31, 2018	119,116.1	30.5

We have not engaged in any exploration capital spending in 2018 or 2017. Our development capital spending to convert proved undeveloped reserves to proved developed reserves for the periods indicated is as follows:

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

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

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

Our policies regarding internal controls over reserve estimates require reserves to be prepared by an independent engineering firm under the supervision of our Chief Executive Officer, and to be in compliance with generally accepted geologic, petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The corporate staff interacts with our internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data for the reserves estimation process. Reserves are reviewed and approved internally by our Chief Executive Officer on a semi‑annual basis. Our Chief Executive Officer holds a Bachelor of Science degree in Chemical Engineering has studied Petroleum Engineering courses on a Masters Level and completed a Masters in Business Administration. He has over 37 years of experience in various positions in the global oil and gas business, primarily holding positions in the areas of reservoir development strategy, property valuations, completions and production optimization. He has also been managing the allocation of capital in oil and gas investments and appraising the values of those assets on a quarterly basis with Domain Energy Advisors since January 2005. The reserve information in this report is based on estimates prepared by DeGoyler and MacNaughton, our independent engineering firm. The person responsible for preparing the reserve report, Gregory Graves, is a Registered Professional Engineer (No.70734) in the State of Texas and a Senior Vice President of the firm. Mr. Graves graduated from the University of Texas at Austin with a degree in Petroleum Engineering, and is a member of the Society of

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

Marketing and Major Customers

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

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

Competition

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

We are affected by industry competition for drilling rigs, completion rigs and availability of related equipment and services. It is not uncommon in the oil and natural gas industry to experience shortages of drilling and completion rigs, equipment, pipe, services and personnel, which can cause both delays in development drilling activities and significant cost increases. We are not immune to these risks.

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

Our Status as an Emerging Growth Company

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

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

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

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

reduced disclosure about our executive compensation arrangements.

We have elected to take advantage of the exemption from the adoption of new or revised financial accounting standards until they would apply to private companies.

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

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

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

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

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

Employees

As of December 31, 2018, we had eight full‑time employees (including executive officers) in Houston, Texas. None of our employees are subject to a collective bargaining agreement or represented by a union.

Legal Proceedings

We are not a party to any pending or threatened legal proceedings. From time to time, we may become involved in litigation related to claims arising from the ordinary course of our business.

Regulation

United States

Environmental Regulation

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

require the acquisition of various permits before drilling commences;

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

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

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

Compliance with environmental laws and regulations increases Epsilon’s overall cost of business, but has not had, to date, a material adverse effect on Epsilon’s operations, financial condition or results of operations. In addition, it is not anticipated, based on current laws and regulations, that Epsilon will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations. However, given that such laws and regulations are subject to change, Epsilon is unable to predict the ultimate cost of compliance or the ultimate effect on Epsilon’s operations, financial condition and results of operations.

Climate Change

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

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

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

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

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

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

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

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

Epsilon is unable to predict the timing, scope and effect of any currently proposed or future, laws, regulations or treaties regarding climate change and GHG emissions. Any limits on GHG emissions, however, could adversely affect demand for the oil and natural gas that production operators produce, some of whom are our customers, which could thereby reduce demand for our gas gathering services. We are currently unable to calculate or predict the direct and indirect costs of GHG or climate change related laws, regulations and treaties, and accordingly, we cannot assure you that any such efforts will not have a material impact on our operations, financial condition and results.

Hydraulic Fracturing

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

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

Gathering System Regulation

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

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

Market for Our Common Equity and Related Stockholder Matters

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

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

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


	CDN$
	High		Low
Year Ended December 31, 2018
Fourth Quarter	$	6.16	$	4.96
Third Quarter	$	5.76	$	4.66
Second Quarter	$	5.90	$	4.60
First Quarter	$	5.96	$	4.60
Year Ended December 31, 2017
Fourth Quarter	$	6.70	$	5.84
Third Quarter	$	6.40	$	5.80
Second Quarter	$	6.40	$	5.50
First Quarter	$	6.90	$	5.82
Year Ended December 31, 2016
Fourth Quarter	$	6.10	$	5.74
Third Quarter	$	6.78	$	5.76
Second Quarter	$	6.80	$	6.30
First Quarter	$	6.80	$	4.56

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

Dividends. We have not declared or paid any cash or stock dividends on our common shares since our inception and do not anticipate declaring or paying any cash or stock dividends in the foreseeable future.

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


	As at			As at
	December 31, 2018			December 31, 2017
		Weighted			Weighted
	Number of	Average		Number of	Average
	Options	Exercise		Options	Exercise
Exercise price in Cdn$	Outstanding	Price		Outstanding	Price
Balance at beginning of period	330,750	$	6.86	255,500	$	6.66
Granted	—		—	120,750		6.70
Exercised	—		—	(20,000)		3.26
Expired	(40,000)	$	8.00	(25,500)		7.06
Balance at period-end	290,750	$	6.70	330,750	$	6.86

Exercisable at period-end	210,249	$	6.70	161,666	$	6.82

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

ITEM 1A. RISK FACTORS.

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

Risks Related to Oil and Natural Gas Reserves

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

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

Substantial and extended declines in oil and natural gas prices may result in impairments of proved oil and gas properties or undeveloped acreage and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures, spending will be required to be reduced, assets could be sold or funds may be borrowed to fund any such shortfall.

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

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

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

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property

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

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

There are numerous uncertainties inherent in estimating quantities of oil and natural gas reserves and cash flows to be derived thereof, including many factors beyond our control. The reserve and associated cash flow information set forth herein represents estimates only. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows thereof are based upon a number of variable factors and assumptions such as historical oil and natural gas prices, production levels, capital expenditures, operating and development costs, the effects of regulation, the accuracy and reliability of the underlying engineering and geologic data, and the availability of funds; all of which may vary from actual results. For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected thereof and prepared by different engineers, or by the same engineers at different times, may vary. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves will vary from estimates thereof and such variations could be material.

In accordance with applicable securities laws, the technical report on our oil and natural gas reserves prepared by DeGolyer and MacNaughton, independent petroleum consultants, as of December 31, 2018 and 2017, or the DeGolyer Reserve Reports, used SEC guideline prices and cost estimates in calculating net cash flows from oil and natural gas reserve quantities included within the report. Actual future net revenue will be affected by other factors such as actual commodity prices, production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs. Actual production and revenues derived thereof will vary from the estimates contained in the DeGolyer Reserve Report, and such variations could be material. The DeGolyer Reserve Report is based in part on the assumed success of activities that we intend to undertake in future years. The oil and natural gas reserves and estimated cash flows to be derived therefrom contained in the DeGolyer Reserve Report will be reduced to the extent that such activities do not achieve the level of success assumed in the DeGolyer Reserve Report.

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

Risks Related to Stage of Development and Capital Resources

Currently, our activity is highly concentrated to one product in one area. Although we are attempting to expand our operations to other areas with multiple products, we may not be successful in these other areas.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Future equity transactions could result in dilution to existing stockholders.

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

Competition in the natural gas and oil industry is intense, which may hinder our ability to contract for drilling equipment, and we may not be able to control the scheduling and activities of contracted drilling equipment.

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. Past industry conditions have led to periods of extreme shortages of drilling equipment in certain areas of the United States.

On the oil and natural gas properties that we do not operate, we will be dependent on such operators for the timing of activities related to such properties and may be largely unable to direct or control the activities of the operators.

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

Our operations involve utilizing the latest drilling and completion techniques in order to maximize cumulative recoveries and generate high returns. However, high returns are not guaranteed, and the results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, a less predictable future of drilling results in these areas. Ultimately, the success of drilling and completion techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long time period. If drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, or if crude oil and natural gas prices decline, the return on our investment in these areas may not be as attractive as anticipated. Further, as a result of less than desirable results in developments we could incur material write‑downs of our oil and natural gas properties and the value of undeveloped acreage could decline in the future.

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

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

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

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

Approximately 97% of our production during fiscal 2018 and 2017 was derived from our properties in the Marcellus region of Pennsylvania. As a result of this geographic concentration, we may be disproportionately exposed to the effect of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of crude oil or natural gas. Additionally, we may be exposed to additional risks, such as changes in field‑wide rules and regulations that could cause us to permanently or temporarily shut‑in many or all of our wells within the Marcellus.

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

In addition to the usual delays in payments by purchasers of oil and natural gas to us or to the operators, and the delays by operators in remitting payment to us, payments from these parties may be delayed by restrictions imposed by lenders, accounting delays, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, adjustment for prior periods, or recovery by the operator of expenses incurred in the operation of the properties. In addition, the transition of one operator to another as the result of an operator being bought or sold could cause additional

operational delays beyond our control. Any of these delays could reduce the amount of cash flow available for our business in a given period and expose us to additional third‑party credit risks.

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

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

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

On the oil and natural gas properties that we do not operate, we will be dependent on such operators for the timing of activities related to such properties and will largely be unable to direct or control the activities of the operators. The objectives and strategy of those operators may not always be consistent with ours, and we have a limited ability to exercise influence over, and control the risks associated with, operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues from our conventional assets or could increase costs or create liability for the operator’s failure to properly maintain the well and facilities and to adhere to applicable safety and environmental standards.

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

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

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

We may incur losses as a result of title deficiencies.

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

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

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

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

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

Risks Related to Commodity Prices, Hedging and Marketing

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

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

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

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

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

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

We are exposed to risks of loss in the event of nonperformance by our counterparties to our hedging arrangements. Some of our counterparties may be highly leveraged and subject to their own operating and regulatory risks. Despite our analysis, we may experience financial losses in our dealings with these and other parties with whom we enter into

transactions as a normal part of our business activities. Any nonpayment or nonperformance by our counterparties could have a material adverse impact on our business, financial condition and results of operations.

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

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

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

If we are unable to successfully compete with the large number of oil and natural gas producers in our industry, we may not be able to achieve profitable operations.

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

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

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

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

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

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

Risks Related to Internal Controls

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

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

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

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

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

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

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

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

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

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

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

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

Because of these exemptions, some investors may find our common shares less attractive, which may result in a less active trading market for our common shares, and our shares price may be more volatile.

If we fail to establish and maintain proper disclosure or internal controls, our ability to produce accurate financial statements and supplemental information, or comply with applicable regulations could be impaired.

As we grow, we may be subject to growth‑related risks including capacity constraints and pressure on our internal systems and controls. Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to expend, train and manage our employee base.

We must maintain effective disclosure controls and procedures. We must also maintain effective internal controls over financial reporting or, at the appropriate time, our independent auditors will be unwilling or unable to provide us with an unqualified report on the effectiveness of our internal controls over financial reporting as required by Section 404(b) of the Sarbanes‑Oxley Act. If we fail to maintain effective controls, investors may lose confidence in our operating results, the price of our common shares could decline and we may be subject to litigation or regulatory enforcement actions.

Risks Related to Gathering System

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

Our natural gas gathering system is dependent upon the level of production from natural gas wells, from which production will naturally decline over time. In order to maintain or increase throughput levels on our gathering system and compression facility, we must continually obtain new supplies. The primary factors affecting our ability to obtain new supplies of natural gas is the level of successful drilling activity from the anchor shippers, of which Epsilon is one, as well as our ability to compete for volumes from successful new wells drilled by third parties proximate to our system. If we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, throughput on our pipelines and the utilization rates of our compression facility would decline, which could have an adverse effect on our business, results of operations, financial position and cash flows.

The gathering rate on the Auburn Gas Gathering System is subject to a Cost of Service model which could result in a non‑competitive gathering rate and reduced throughput.

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

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

Differential is an energy industry term that refers to the discount or premium received for the sale of a petroleum product at a specific location relative to a nationally recognized sales hub. In the Marcellus, natural gas is significantly discounted to Henry Hub and the size of the differential can be volatile. Many factors influence the size and duration of differentials including local supply / demand imbalances, seasonal fluctuations in demand, transportation availability and cost, as well as the regulatory environment as it pertains to constructing new transportation pipelines. In Northeast Pennsylvania, negative differentials have persisted for many years due to rapid increases in supply as a result of advances in well completion techniques. Despite substantial increases in local demand for natural gas coupled with pipeline expansions, optimizations, and new pipelines that have been brought into service, the natural gas differential in Northeast

Pennsylvania remains significant. There is no guarantee that future demand or pipeline transportation projects will eliminate this differential, and it will therefore remain a significant risk to Epsilon’s revenues and cash flows.

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

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

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

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

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

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

Prices for natural gas in northeast Pennsylvania are volatile and are subject to significant discounts from pricing at Henry Hub. This discount and volatility has and could continue to adversely affect our financial results, cash flows, access to capital and ability to maintain our existing businesses.

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

development in the past, and could do so again in the future. A slowing pace or complete halt to the development of reserves will impact our financial results, cash flows, access to capital and ability to maintain our gas gathering system.

The financial condition of our natural gas gathering businesses is dependent on the continued availability of natural gas supplies and demand for those supplies in the markets we serve.

Our ability to maintain and expand our natural gas gathering businesses depends on the level of drilling and production by anchor shippers and third parties in our gathering area. Production from existing wells with access to our gathering systems will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of the other anchor shippers or third‑party natural gas reserves connected to our systems and compression facilities. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. Demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy could reduce demand for natural gas in our markets and have an adverse effect on our business. A failure to obtain access to sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Our operations are subject to operational hazards and unforeseen interruptions.

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

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

Aging infrastructure and mechanical problems;

Damages to pipelines and pipeline blockages or other pipeline interruptions;

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

Operator error;

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

Pollution and other environmental risks;

Fires, explosions, craterings, and blowouts; and

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

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of our precautions, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2. PROPERTIES.

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

ITEM 3. LEGAL PROCEEDINGS.

We are not a party to any pending or threatened legal proceedings. From time to time, we may become involved in litigation related to claims arising from the ordinary course of our business.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

PART II

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

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

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

ITEM 6. SELECTED FINANCIAL DATA.

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

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


	Year ended December 31,
	2018		2017
Income Statement Data
Operating revenues	$	29,684	$	25,757
Cost of revenues		7,946		6,619
Depreciation, depletion, amortization and accretion		7,182		11,072
General and administrative expense		4,936		4,418
Income from operations		9,621		3,648
Other income (expense)		(2,217)		1,722
Income tax expense (benefit)		742		(2,066)
Net income attributable to Epsilon	$	6,662	$	7,436
Net income available to shareholders	$	6,662	$	7,436
Net income per share, basic	$	0.24	$	0.28
Net income per share, diluted	$	0.24	$	0.28
Weighted average number of shares outstanding, basic		27,462,788		26,119,927
Weighted average number of shares outstanding, diluted		27,474,125		26,133,295


	As of December 31,
	2018		2017
Balance Sheet Data
Cash and cash equivalents	$	14,401	$	9,999
Oil and gas properties		54,543		57,351
Gathering system properties		12,903		14,628
Total assets		87,898		86,406
Total long-term liabilities		11,614		16,724
Total shareholders’ equity (1)		69,944		63,731

⁽¹⁾

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

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion is intended to assist in the understanding of trends and significant changes in or results of operations and the financial condition of Epsilon Energy Ltd. and its subsidiaries for the periods presented. This section should be read in conjunction with the audited consolidated financial statements as at December 31, 2018 and 2017 and for the years then ended together with accompanying notes.

Certain statements contained in this report constitute forward‑looking statements. The use of any of the words “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” “project,” “should,” “believe,” and similar expressions and statements relating to matters that are not historical facts constitute “forward looking information” within the meaning of applicable securities laws. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated. Such forward‑looking statements are based on reasonable assumptions, but no assurance can be given that these expectations will prove to be correct and the forward‑looking statements included in this report should not be unduly relied upon. These statements are made only as of the date of this report.

Overview

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

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

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

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

Business Strategy

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

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

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

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

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

Year ended December 31, 2018 Highlights

Operational Highlights

Marcellus Shale—Pennsylvania

During the year ended December 31, 2018, Epsilon’s realized natural gas price was $2.51 per Mcf, an 18% increase from the year ended, December 31, 2017.

Total year ended December 31, 2018 production of 7.3 Bcf in Pennsylvania, as compared to 8.9 Bcf in 2017. Additionally, we added 353.4 MMcfe of gas, oil, and other liquids production in Oklahoma.

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

NW Stack Trend—Oklahoma

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

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

Year ended December 31, 2017 Highlights

Operational Highlights

Marcellus Shale—Pennsylvania

During the year ended December 31, 2017, our realized natural gas price was $2.13 per Mcf, a 53% increase from the year ended December 31, 2016.

Total year ended December 31, 2017 production was 8.9 Bcf in Pennsylvania, as compared to 11.0 Bcf in 2016. Additionally, we added 18.6 MMcfe of gas, oil, and other liquids production in Oklahoma.

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

Gathered and delivered 88.2 Bcf gross (30.9 Bcf net to our interest) during the year, or 242 MMcfe/d through the Auburn System which represents approximately 73% of maximum throughput.

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

NW Stack Trend—Oklahoma

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

Financing Highlights

Convertible Debentures

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

Results of Operations

The following review of operations for the periods presented below should be read in conjunction with our consolidated financial statements and the notes thereto.

Revenues

During the year ended December 31, 2018, revenues increased $3.9 million, or 15.2%, to $29.7 million from $25.8 million during the same period in 2017.

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


	Year ended
	December 31,
	2018		2017
Revenues ($000)
Natural gas revenue	$	19,031	$	19,204
Volume (MMcf)		7,563		9,010
Avg. Price ($/Mcf)	$	2.52	$	2.13
Exit Rate (MMcfpd)		21.2		27.0
Oil and other liquids revenue	$	671	$	122
Volume (MBO)		17.1		3.1
Avg. Price ($/Bbl)	$	39.31	$	39.18
Gathering system revenue	$	9,982	$	6,432
Total Revenues	$	29,684	$	25,757

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

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

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

Operating Costs

The following table presents total cost and cost per unit of production (Mcfe), including ad valorem, severance, and production taxes for the years ended December 31, 2018 and 2017:


	Year ended December 31,
(in thousands of dollars)	2018		2017
Lease operating costs	$	6,666	$	5,723
Gathering system operating costs		1,280		896
	$	7,946	$	6,619

Upstream operating costs—Total $/Mcfe		0.87		0.63
Gathering system operating costs $ / Mcf		0.06		0.06

Upstream operating costs consist of lease operating expenses necessary to extract gas and oil, including gathering and treating the oil and gas to ready it for sale.

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

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

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


	Year ended December 31,
(in thousands of dollars)	2018		2017
Depletion, depreciation, amortization and accretion	$	7,182	$	11,072

Oil and natural gas and gathering system assets are depleted and depreciated using the units‑of‑production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved and unproved properties, the reserve base used to calculate depreciation and depletion is total proved reserves. For oil and gas development and gathering system costs, the reserve base used to calculate depletion and depreciation is proved developed reserves. A reserve report is prepared as of December 31, each year. The depletion for the first three quarters of the next year is based on the reserve report prepared at the end of the previous year, taking into consideration the limited development of the reserves over these time periods. The fourth quarter depletion is calculated using the reserve volumes from the reserve report prepared as of December 31 of the current year.

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

Accretion expense is related to the asset retirement costs.

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

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

General and Administrative (“G&A”)


	Year ended December 31,
(in thousands of dollars)	2018		2017
General and administrative	$	4,936	$	4,418

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

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

Interest Expense


	Year ended December 31,
(in thousands of dollars)	2018		2017
Interest expense	$	141	$	903
Debenture fee amortization (debt portion)		—		53
Interest expense	$	141	$	956

Interest expense relates to the interest payable and amortization of the underwriter and administrative fees related to the convertible debentures issued in 2012, and interest on the revolving line of credit.

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

Net gain (loss) on commodity contracts


	Year ended December 31,
(in thousands of dollars)	2018		2017
Net gain (loss) on commodity contracts	$	(1,938)	$	2,624

During 2018, we entered into fixed price swap and basis swap derivative contracts. During the period, the Corporation paid $1,381,898 on the settlement of contracts due to the increase in commodity prices.

For the year ended December 31, 2017, we entered into fixed price swap, basis swap, and two‑way costless collar derivative contracts. During this period, the Corporation received $2,027,791 on the settlement of contracts.

Miscellaneous Income (Expense)

For the year ended December 31, 2018 and 2017, miscellaneous income (expense) consisted primarily of interest income, and foreign currency gains and (losses).

Net Income Compared to Adjusted EBITDA


	Year ended December 31,
	2018		2017
Net income (loss)	$	6,662	$	7,436
Add Back:
Net interest expense		129		929
Deferred income tax provision		742		(2,066)
Depreciation, depletion, amortization, and accretion		7,182		11,072
Stock based compensation expense		330		229
Net change in unrealized (gain) loss on commodity contracts		557		(596)
Other income		(2)		(4)
Adjusted EBITDA	$	15,600	$	17,000

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

Additionally, Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. Epsilon has included Adjusted EBITDA as a supplemental disclosure because its management believes that EBITDA provides useful information regarding its ability to service debt and to fund capital expenditures. It further provides investors a helpful measure for comparing operating performance on a "normalized" or recurring basis with the performance of other companies, without giving effect to certain non-cash expenses and other items. This provides management, investors and analysts with comparative information for evaluating the Company in relation to other oil and gas companies providing corresponding non-U.S. GAAP financial measures or that have different financing and capital structures or tax rates. These non-U.S. GAAP financial measures should be considered in addition to, but not as a substitute for, measures for financial performance prepared in accordance with U.S. GAAP. The table above sets forth a reconciliation of Adjusted EBITDA to net income, which is the most directly comparable measure of financial performance calculated under U.S. GAAP and should be reviewed carefully.

Capital Resources and Liquidity

Cash Flow

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

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

Year ended December 31, 2018 compared to 2017

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

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

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

Credit Agreement

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

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

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

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

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

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


	Balance at		Balance at
	December 31,		December 31,		Borrowing Base		Interest
	2018		2017		December 31, 2018		Rate
Revolving line of credit	$	—	$	2,900,000	$	13,500,000	3 mo. LIBOR + 2.75%

In January 2019 our borrowing base was increased to $23 million, resulting in available borrowing capacity under the credit agreement of $23 million as of January 7, 2019.

Derivative Transactions

We have entered into hedging arrangements to reduce the impact of natural gas price volatility on operations. By removing the price volatility from a significant portion of natural gas production, the potential effects of changing prices on operating cash flows have been mitigated, but not eliminated. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we might otherwise receive from increases in commodity prices.

At December 31, 2018, our outstanding natural gas commodity swap contracts consisted of the following:


		Weighted Average Price ($/MMbtu)
	Volume			Basis		Fair Value of Liability
Derivative Type	(Mmbtu)	Swaps		Differential		December 31, 2018
2019
Fixed price swap	3,635,000	$	2.78	$	—		(35,660)
Basis swap	3,635,000	$	—	$	(0.54)		(261,363)
						$	(297,023)

Contractual Obligations

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


	Payments Due by Period
			Less than		1 – 3		Greater than
	Total		1 Year		Years		3 Years
Derivative liabilities (1)		498,888		498,888		—		—
Asset retirement obligation, undiscounted		21,487,007		—		—		21,487,007
Capital expenditure commitments		2,317,738		2,317,738		—		—
Operating leases		87,306		80,577		6,729		—
Total future commitments	$	24,390,939	$	2,897,203	$	6,729	$	21,487,007

⁽¹⁾

The liability balance shown represents the gross liability balance of derivative contracts before being offset by contracts in an asset position.

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

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

The convertible debentures were scheduled to mature on March 31, 2017. The debentures were fully funded with cash holdings in Canada and were paid off in February 2017 for Cdn$ 39,951,435.

Off‑Balance Sheet Arrangements

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

Foreign Currency Exchange Rate Risk

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

Summary of Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements and accompany notes, which have been prepared in accordance with accounting principles generally

accepted in the United States, or GAAP, and SEC rules which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Described below are the most significant accounting policies we apply in preparing our consolidated financial statements. We also describe the most significant estimates and assumptions we make in applying these policies.

Successful Efforts Accounting

We use the successful efforts method of accounting for oil and gas operations. Under this method, the fair value of property acquired and all costs associated with successful exploratory wells and all development wells are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

Gathering System

We hold an undivided interest in a gas gathering system asset that supports our Pennsylvania operations. We account for the costs and revenue from this system using the proportionate consolidation method.

Proved Oil and Gas Reserves

Our engineers estimate proved oil and gas reserves in accordance with SEC regulations, which directly impact financial accounting estimates, including depreciation, depletion and amortization and impairments of proved properties and related assets. Proved reserves represent estimated quantities of crude oil and condensate, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Accordingly, there can be no assurance that ultimately, the reserves will be produced, nor can there be assurance that the proved undeveloped reserves will be developed within the period anticipated. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. We cannot predict the types of reserve revisions that will be required in future periods. For related discussion, see the sections titled “Risk Factors” and “Supplemental Information to Consolidated Financial Statements.”

Unproved Oil and Gas Properties

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

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

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

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

Depreciation, depletion and amortization rates are updated quarterly to reflect the addition of capital costs, reserve revisions (upwards or downwards) and additions, property acquisitions and/or property dispositions and impairments.

Depreciation and amortization of other property, plant and equipment is calculated on a straight‑line basis over the estimated useful life of the asset.

Impairments

The carrying value of unproved and proved oil and natural gas properties and gathering system assets are reviewed for impairment whenever events indicate that the carrying amounts for those assets may not be recoverable. Such indicators include changes in our business plans, changes in commodity prices leading to unprofitable performance, and, for oil and gas properties, significant downward revisions of estimated proved reserve quantities or significant increases in the estimated development costs.

We compare expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on our estimates of (and assumptions regarding) future oil and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC based on estimated discounted net cash flows. Estimates of future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. In addition, such assumptions and estimates are reasonably likely to change in the future. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices and (iv) a market‑based weighted average cost of capital rate.

Under ASC 360, we evaluate impairment of proved and unproved oil and gas properties on an area basis. On this basis, certain fields may be impaired because they are not expected to recover their entire carrying value from future net cash flows. The basis for future depletion, depreciation, amortization, and accretion will take into account the reduction in the value of the asset as a result of any accumulated impairment losses.

When circumstances indicate that the gathering system properties may be impaired, Epsilon compares expected undiscounted future cash flows related to the gathering system to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC, which considers estimated discounted future cash flows.

Derivative Financial Instruments

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

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

Asset Retirement Obligation (“ARO”)

We recognize asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires legal obligations associated with the retirement of long‑lived assets to be recognized at their fair value at the time that the obligations are incurred. These obligations consist of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas or gathering system asset. The initial recognition of an ARO fair value requires that management make numerous assumptions regarding such factors as the amounts and timing of settlements; the credit‑adjusted risk‑free discount rate; and the inflation rate. In periods subsequent to the initial measurement of an ARO, period‑to‑period changes are recognized in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and gas property or gathering system asset.

Income Taxes

Tax regulations and legislation in the U.S. and Canada are subject to change and differing interpretations requiring judgment. Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in future periods, which requires judgment. Deferred tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax authorities in future periods, which requires judgment. Income tax filings are subject to audits and re‑assessments. Changes in facts, circumstances, and interpretations of the standards may result in a material increase or decrease in our provision for income taxes.

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

Recently Issued Accounting Standards

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

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

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

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

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

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

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

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

Gathering System Revenue Risk

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

Interest Rate Risk

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

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

Commodity Contracts

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

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

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

Report of Independent Registered Public Accounting Firm

Shareholders and Board of Directors

Epsilon Energy Ltd.

Houston, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Epsilon Energy Ltd. and subsidiaries (the “Company”) as of December 31, 2018 and 2017, and the related consolidated statements of operations and comprehensive income, changes in shareholders’ equity, and cash flows for each of the two years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2018 and 2017, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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

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

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

/s/ BDO USA LLP

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

Houston, Texas

March 29, 2019

EPSILON ENERGY LTD.

Consolidated Balance Sheets


	December 31,		December 31,
	2018		2017
ASSETS
Current assets
Cash and cash equivalents	$	14,401,257	$	9,998,853
Accounts receivable		5,042,134		3,334,895
Fair value of derivatives		—		259,544
Prepaid income taxes		205,711		—
Other current assets		244,233		276,431
Total current assets		19,893,335		13,869,723
Non-current assets
Property and equipment:
Oil and gas properties, successful efforts method
Proved properties		118,851,574		118,524,693
Unproved properties		19,498,666		17,451,552
Accumulated depletion, depreciation, and amortization		(83,807,401)		(78,625,589)
Total oil and gas properties, net		54,542,839		57,350,656
Gathering system		41,040,847		40,880,503
Accumulated depletion, depreciation, and amortization		(28,137,573)		(26,252,385)
Total gathering system, net		12,903,274		14,628,118
Other property and equipment, net		—		299
Total property and equipment, net		67,446,113		71,979,073
Other assets:
Restricted cash		558,261		556,864
Total non-current assets		68,004,374		72,535,937
Total assets	$	87,897,709	$	86,405,660

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable trade	$	2,585,324	$	2,008,229
Royalties payable		1,300,539		1,029,678
Other accrued liabilities		2,156,304		1,895,917
Income taxes payable		—		1,017,194
Fair value of derivatives		297,023		—
Total current liabilities		6,339,190		5,951,018
Non-current liabilities
Revolving line of credit		—		2,900,000
Other non-current liabilities		—		1,615,313
Asset retirement obligation		1,625,154		1,646,601
Deferred income taxes		9,989,278		10,561,683
Total non-current liabilities		11,614,432		16,723,597
Total liabilities		17,953,622		22,674,615
Commitments and contingencies (See Note 10)
Shareholders' equity
Common shares, no par, unlimited shares authorized and 27,385,133 shares and 27,522,852 shares issued at December 31, 2018 and December 31, 2017 respectively. At December 31, 2018 Epsilon held 26,953 shares of stock.		143,611,023		144,292,238
Additional paid-in capital		6,519,028		6,171,525
Deficit		(89,983,894)		(96,645,954)
Accumulated other comprehensive income		9,797,930		9,913,236
Total shareholders' equity		69,944,087		63,731,045
Total liabilities and shareholders' equity	$	87,897,709	$	86,405,660

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

EPSILON ENERGY LTD.

Consolidated Statements of Operations and Comprehensive Income


	Year ended December 31,
	2018		2017
Revenues:
Oil, gas, NGLs and condensate revenue	$	19,702,643	$	19,325,528
Gas gathering and compression revenue		9,981,562		6,431,563
Total revenue		29,684,205		25,757,091

Operating costs and expenses:
Lease operating expenses		6,665,856		5,723,298
Gathering system operating expenses		1,279,821		896,089
Depletion, depreciation, amortization, and accretion		7,181,753		11,071,759
General and administrative expenses:
Stock based compensation expense		330,232		229,223
Other general and administrative expenses		4,605,506		4,189,065
Total operating costs and expenses		20,063,168		22,109,434
Operating income (loss)		9,621,037		3,647,657

Other income and (expense):
Interest income		12,087		26,520
Interest expense		(140,615)		(955,698)
Gain (loss) on derivative contracts		(1,938,465)		2,623,687
Other income (expense)		(149,559)		27,313
Other income (expense), net		(2,216,552)		1,721,822

Income before tax		7,404,485		5,369,479
Income tax (benefit) expense		742,425		(2,066,426)
NET INCOME	$	6,662,060	$	7,435,905
Currency translation adjustments		(115,306)		566,381
NET COMPREHENSIVE INCOME	$	6,546,754	$	8,002,286

Net income per share, basic	$	0.24	$	0.28
Net income per share, diluted	$	0.24	$	0.28
Weighted average number of shares outstanding, basic		27,462,788		26,119,927
Weighted average number of shares outstanding, diluted		27,474,125		26,133,295

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

EPSILON ENERGY LTD.

Consolidated Statements of Changes in Shareholders’ Equity


					Accumulated
					Other				Total
	Share		Additional		Comprehensive				Shareholders'
	Capital		paid-in Capital		Income (Loss)		Deficit		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		—		—		—		6,662,060		6,662,060
Stock-based compensation expenses		—		330,232		—		—		330,232
Buyback and retirement of common shares		(586,797)		17,271		—		—		(569,526)
Buyback of common shares not yet retired		(94,418)		—		—		—		(94,418)
Other comprehensive loss		—		—		(115,306)		—		(115,306)
Balance at December 31, 2018	$	143,611,023	$	6,519,028	$	9,797,930	$	(89,983,894)	$	69,944,087

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

EPSILON ENERGY LTD.

Consolidated Statements of Cash Flows


	Year ended December 31,
	2018		2017
Cash flows from operating activities:
Net income	$	6,662,060	$	7,435,905
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		7,181,753		11,071,759
Debenture fee amortization		—		52,924
(Gain) loss on derivatives		1,938,465		(2,623,687)
Cash received (paid) from settlements of derivatives		(1,381,898)		2,027,791
Stock-based compensation expense		330,232		229,223
Deferred income tax benefit		(572,405)		(2,530,136)
Changes in current assets and liabilities:		—		—
Accounts receivable		(1,707,239)		1,052,593
Prepaid income taxes and other current assets		(173,513)		(136,440)
Accounts payable and accrued liabilities		(545,286)		1,503,231
Other long-term liabilities		(1,615,313)		(529,684)
Net cash provided by operating activities		10,116,856		17,553,479
Cash flows from investing activities:
Acquisition of unproved oil and gas properties		(260,000)		(17,451,552)
Additions to unproved oil and gas properties		(1,787,114)		—
Acquisition of proved oil and gas properties		(4,992)		(1,643,735)
Refunds of cash calls, net of additions to proved oil and gas properties		166,661		(34,457)
Additions to gathering system properties		(148,360)		(200,689)
Changes in restricted cash		(1,397)		(26,328)
Net cash used in investing activities		(2,035,202)		(19,356,761)
Cash flows from financing activities:
Buyback of common shares		(663,944)		—
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
Repayment of revolving line of credit		(2,900,000)		(9,560,000)
Net cash used in financing activities		(3,563,944)		(21,066,761)
Effect of currency rates on cash and cash equivalents		(115,306)		1,382,303
Increase (decrease) in cash and cash equivalents		4,402,404		(21,487,740)
Cash and cash equivalents, beginning of year		9,998,853		31,486,593
Cash and cash equivalents, end of year	$	14,401,257	$	9,998,853

Supplemental cash flow disclosures:
Income taxes paid	$	4,130,493	$	—
Interest paid	$	136,833	$	1,477,899

Non-cash investing activities:
Change in proved properties accrued in accounts payable and accrued liabilities	$	(587,472)	$	—
Change in gathering system accrued in accounts payable and accrued liabilities	$	(48,961)	$	(55,950)
Conversion of debentures to shares (Cdn$1,000)		—		869
Asset retirement obligation asset additions and adjustments	$	(135,900)	$	74,755

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

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements

For the years ended December 31, 2018 and 2017

1. Description of Business

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

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

2. Basis of Preparation

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

Principles of Consolidation

The Corporation’s consolidated financial statements include the accounts of the Corporation and its wholly owned subsidiary, Epsilon Energy USA, Inc. and its wholly owned subsidiaries, Epsilon Midstream, LLC, Dewey Energy GP, LLC, and Dewey Energy Holdings, LLC. With regard to the gathering system, in which Epsilon owns an undivided interest in the asset, proportionate consolidation accounting is used. All inter-company transactions have been eliminated.

Use of Estimates

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

3. Summary of Significant Accounting Policies

Cash, Cash Equivalents and Restricted Cash

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

Restricted cash consists of amounts deposited to back bonds or letters of credit for potential well liabilities.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are primarily from purchasers of oil and natural gas, counterparties to our financial instruments, and revenues earned for compression and gathering services. Both oil and natural gas receivables are generally collected within 30 days after the end of the month. Compression and gathering receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. Our allowance for doubtful accounts was nil as of December 31, 2018 and 2017. There was no bad debt expense recognized for the years ended December 31, 2018 and 2017.

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

Oil and Natural Gas Properties

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

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

Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether Epsilon has discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized (see Note 4).

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

When circumstances indicate that proved oil and natural gas properties may be impaired, Epsilon compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on Epsilon’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC, which considers estimated discounted future cash flows.

Gas Gathering System Properties

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

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

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

Revenue Recognition

Revenue associated with the sale of crude oil and natural gas owned by the Corporation is recognized when title is transferred from the Corporation to its customers. Revenue is measured at the fair value of the consideration received

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

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

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

The Corporation retains no continuing managerial involvement to the degree usually associated with ownership or effective control over the goods sold;

The amount of revenue can be measured reliably;

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

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

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

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

Other Property and Equipment

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

Financial Instruments and Fair Value

Epsilon’s financial instruments consist of cash and cash equivalents, commodity derivative contracts, accounts receivable, accounts payable, accrued liabilities, convertible debentures, and long‑term debt.

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

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

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

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

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

Cash, cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities are carried at cost, which approximates their fair value because of the short‑term maturity of these instruments. The Corporation’s revolving line of credit has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates and the applicable margins represent market rates. Convertible debentures are carried at amortized cost.

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

Commodity derivative instruments consist of fixed‑price swaps, costless collars, and basis swap contracts for natural gas. The Corporation’s derivative contracts are valued based on an income approach. The model considers various assumptions, such as quoted forward prices for commodities, time value and volatility factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The Corporation utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.

Derivative Instruments

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

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

Collars—where we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor (long put) on a notional quantity.

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

Derivative assets and liabilities are initially measured at fair value and then re‑valued at each reporting period. Using this method, derivative instruments are recorded on the consolidated balance sheets at fair value as either current or non‑current assets or liabilities based on their anticipated settlement date. Gains or losses on derivative contracts are recorded in gain (loss) on commodity contracts in the consolidated statements of operations and comprehensive income.

Asset Retirement Obligations

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

Concentrations of Credit Risk

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

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

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

Income Taxes

Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. Epsilon assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate (see Note 9).

Foreign Currency Transactions

The United States dollar is the functional currency for all of Epsilon’s consolidated subsidiaries. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. Gains and losses on translation of balances denominated in Canadian dollars are included in accumulated other comprehensive income.

Stock‑Based Compensation

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

Leases

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

Joint Interests

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

Recently Issued Accounting Standards

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

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

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

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

4. Property and Equipment

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


	December 31,		December 31,
	2018		2017
Property and equipment:
Oil and gas properties, successful efforts method
Proved properties	$	118,851,574	$	118,524,693
Unproved properties		19,498,666		17,451,552
Accumulated depletion, depreciation, and amortization		(83,807,401)		(78,625,589)
Total oil and gas properties, net		54,542,839		57,350,656
Gathering system		41,040,847		40,880,503
Accumulated depletion, depreciation, and amortization		(28,137,573)		(26,252,385)
Total gathering system, net		12,903,274		14,628,118
Other property and equipment, net		—		299
Total property and equipment, net	$	67,446,113	$	71,979,073

Property Acquisitions

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

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

Property Impairment

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

5. Convertible Debentures

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

The following table sets forth a reconciliation of the convertible debentures for the year ended December 31, 2017:


	Balance		Balance
	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 December 31, 2017	$	—	$	—

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

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.

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

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

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

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

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

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

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


	Balance at		Balance at
	December 31,		December 31,		Current		Interest Rate
	2018		2017		Borrowing Base		3 mo.
Revolving line of credit	$	—	$	2,900,000	$	23,000,000		LIBOR + 2.75% (1)

⁽¹⁾

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

7. Shareholders’ Equity

(a)

Authorized shares

The Corporation is authorized to issue an unlimited number of Common Shares with no par value and an unlimited number of Preferred Shares with no par value.

(b)

Issued

The following table summarizes the components of share capital for the years ended December 31, 2018 and 2017.


	Number of shares
	issued	Amount
Balance at January 1, 2017	22,918,932	$	126,303,679
Conversion of debenture to shares	112		614
Exercise of stock options	20,000		80,759
Shares issued through rights offering (net of issuance costs of $77,478)	4,583,808		17,907,186
Balance at December 31, 2017	27,522,852	$	144,292,238
Buyback of Shares (net of 26,953 shares of stock not yet retired)	(137,719)		(586,797)
Balance at December 31, 2018	27,385,133	$	143,705,441

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

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

(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 of Common Shares available under the Plan from a limit of 10% of the total issued and outstanding Common Shares to a fixed maximum of 1,000,000 Common Shares, and (ii) deleted some redundant definitions and clarified existing wording in the Plan.

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

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


	Year ended			Year ended
	December 31, 2018			December 31, 2017
		Weighted				Weighted
	Number of	Average		Number of		Average
	Options	Exercise		Options		Exercise
Exercise price in Cdn$	Outstanding	Price		Outstanding		Price
Balance at beginning of period	330,750	$	6.86		255,500	$	6.66
Granted	—	$	—		120,750	$	6.70
Exercised	—	$	—		(20,000)	$	3.26
Expired	(40,000)	$	8.00		(25,500)	$	7.06
Balance at period-end	290,750	$	6.70		330,750	$	6.86

Exercisable at period-end	210,249	$	6.70		161,666	$	6.82

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

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

During the year ended December 31, 2018, the Corporation awarded no stock options (During the year ended December 31, 2017: 120,750 stock options).

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

The following table summarizes information for stock options outstanding at December 31, 2018 (exercise price in Cdn$):


					Weighted
			Option		Average
	Number of	Number of	Pricing		Remaining
	Options	Options	Model		Contractual Life
Exercise Price	Outstanding	Exercisable	Valuations		(in years)
As at December 31, 2018:
$2.90	25,000	25,000	$	28,647	0.61
$6.70	42,500	14,167		73,789	5.02
$6.80	78,250	26,082		138,114	5.07
$7.34	145,000	145,000		547,608	3.43
Total	290,750	210,249	$	788,158	3.86

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

(d)

Share Compensation Plan

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

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

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

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


	Year ended		Year ended
	December 31, 2018		December 31, 2017
		Weighted		Weighted
	Number of	Average	Number of	Average
	Shares	Remaining Life	Shares	Remaining Life
	Outstanding	(years)	Outstanding	(years)
Balance non-vested Restricted Stock at beginning of period	162,500	1.87	—	—
Granted	174,500	2.00	162,500	2.00
Vested	(54,167)	—	—	—
Balance non-vested Restricted Stock at end of period	282,833	2.56	162,500	1.87

8. Accumulated Other Comprehensive Income

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


	Year Ended December 31,
	2018		2017
Balance at beginning of period	$	9,913,236	$	9,346,855
Translation loss convertible debentures		—		(815,922)
Translation gain other		(115,306)		1,382,303
	$	9,797,930	$	9,913,236

9. Income Taxes

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


	Year ended December 31,
	2018		2017
Foreign		(665,924)	$	(1,488,296)
U.S.		8,070,409		6,857,775
	$	7,404,485	$	5,369,479

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

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

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

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

as of the date of this filing. As a result of the Tax Act, further clarifications and new regulations to the Tax Act continue to be issued at times. The Corporation will continue to monitor these new regulations and analyze their applicability and impact on the Corporation.

We believe that we have appropriate support for the income tax positions taken and to be taken on the Corporation’s tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Corporation’s tax returns are open to audit under the statute of limitations for the years ending December 31, 2015 through December 31, 2018.

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


	Year ended December 31,
	2018		2017
Current:
Federal	$	1,742,898	$	304,070
State		(428,068)		159,640
Total current income tax expense		1,314,830		463,710
Deferred:
Federal		(392,574)		(2,539,621)
State		(179,831)		9,485
Total deferred tax (benefit)		(572,405)		(2,530,136)
Income tax provision	$	742,425	$	(2,066,426)

The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate to the income tax provision in our financial statements. Our effective tax rate for 2018 differs from the statutory rate due to the reduction in our uncertain tax position. For 2017 our effective tax rate differs from the statutory rate due to state taxes and the valuation allowance on the Canadian loss, but primarily due to the revaluation of the Corporation’s deferred tax balances for the federal tax rate reduction of 34% to 21% under the Act.


	Year Ended				Year Ended
	December 31,		Effective		December 31,		Effective
	2018		Tax Rate		2017		Tax Rate
Income tax provision computed at the statutory federal tax rate	$	1,554,942	21.00	%	$	1,825,623	34.00	%
Difference in Canadian and U.S. tax rate		(30,633)	(0.41)	%		111,622	2.08	%
Valuation allowance on Canadian loss		170,477	2.30	%		394,398	7.35	%
Return to provision adjustment		(179,120)	(2.42)	%		(13,576)	(0.25)	%
Change in US federal rate—tax reform		—	—	%		(4,625,262)	(86.14)	%
State taxes		349,643	4.72	%		452,040	8.42	%
Miscellaneous other items		28,860	0.39	%		75,312	1.40	%
Change in uncertain tax position		(1,151,744)	(15.55)	%		(286,583)	(5.34)	%
Income tax expense (benefit)	$	742,425	10.03	%	$	(2,066,426)	(38.48)	%

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

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

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

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


	As at December 31,
	2018		2017
Deferred tax assets:
State net operating loss carryforwards	$	465,496	$	684,097
Canadian net operating loss carryforwards		12,113,684		11,943,207
Other		91,646		120,654
Gross deferred tax assets		12,670,826		12,747,958
Valuation allowance		(12,113,684)		(11,943,207)
Total deferred tax assets		557,142		804,751
Deferred tax liabilities:
Oil and gas property		(7,407,828)		(8,182,788)
Partnership		(3,138,592)		(3,183,646)
Total deferred tax liabilities		(10,546,420)		(11,366,434)
Net deferred tax liability	$	(9,989,278)	$	(10,561,683)

We have recorded a valuation allowance against the Canadian net operating losses as we do not feel that it is more likely than not that they will be utilized.

We are subject to taxation in the United States and various state jurisdictions, including Pennsylvania. The Corporation determined that it has uncertain tax positions relating to certain U.S. Federal and Pennsylvania income tax filings as summarized in the table below. As of December 31, 2018 and 2017, the gross liability for income taxes associated with uncertain tax positions was $0 and $1,199,553, respectively. The Corporation recognizes interest expense and penalties related to the uncertain tax position in the income tax expense line in the accompanying consolidated statements of operations and comprehensive loss. Accrued interest and penalties are included in other non-current liabilities in the consolidated balance sheets and were $0 and $415,760 as of December 31, 2018 and 2017, respectively. As of December 31, 2018, tax years ending December 31, 2015, 2016 and 2017 are subject to examination by the tax authorities.

Changes in the balance of unrecognized tax benefits on uncertain positions were as follows for each of the two years ended December 31, 2018:


Uncertain Tax Position:
Balance at December 31, 2016	$	1,878,397
Lapse of statute of limitations		(678,844)
Balance at December 31, 2017		1,199,553
Lapse of statute of limitations		(1,199,553)
Balance at December 31, 2018	$	—

10. Commitments and Contingencies

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


Year ended
December 31,	Payments
2019		80,577
2020		6,729
	$	87,306

The Corporation enters into commitments for capital expenditures in advance of the expenditures being made. As of December 31, 2018, we had commitments of $2.3 million for capital expenditures.

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

Litigation

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

11. Net Income Per Share

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

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

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


	Year ended December 31,
	2018	2017
Basic weighted-average number of shares outstanding	27,462,788	26,119,927
Dilutive stock options	11,337	13,368
Diluted weighted average shares outstanding	27,474,125	26,133,295

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


	Year ended December 31,
	2018	2017
Anti dilutive options	279,413	317,382
Unvested shares of restricted stock	282,833	108,333
Total Anti-dilutive shares	562,246	425,715

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:

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

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

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

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017


	Upstream			Gas Gathering		Canada		Corporate			Elimination		Consolidated
As at and for the year ended December 31, 2018
Operating revenue
Natural gas	$	19,031,422		$	—	$		$			$		$	19,031,422
Natural gas liquids		295,142			—									295,142
Oil and condensate		376,079			—									376,079
Gathering and compression fees		—			11,087,507							(1,105,945)		9,981,562
Total operating revenue	$	19,702,643	(1)	$	11,087,507	$	—	$	—		$	(1,105,945)		29,684,205

Net earnings for the period	$	7,742,587		$	6,814,188	$	—	$	(7,894,715)	(3)		—	$	6,662,060
Operating costs		6,665,856			2,385,766		—		—			(1,105,945)		7,945,677
Depletion, deprec., amortization and accretion		5,294,200			1,887,553		—		—			—		7,181,753

Segment assets	$	71,350,546		$	15,440,047	$	1,107,116	$	—			—	$	87,897,709
Capital expenditures (2)		2,472,917			197,321		—		—			—		2,670,238
Proved properties		35,044,173			—		—		—			—		35,044,173
Unproved properties		19,498,666			—		—		—			—		19,498,666
Gathering system		—			12,903,274		—		—			—		12,903,274
Other property and equipment		—			—		—		—			—		—

As at and for the year ended December 31, 2017
Operating revenue
Natural gas	$	19,203,543		$	—	$		$			$		$	19,203,543
Natural gas liquids		24,018			—									24,018
Oil and condensate		97,967			—									97,967
Gathering and compression fees		—			7,614,075							(1,182,512)		6,431,563
Total operating revenue	$	19,325,528	(1)	$	7,614,075	$	—	$	—		$	(1,182,512)		25,757,091

Net earnings for the period	$	5,544,931		$	2,521,014	$	—	$	—	(3)	$	—	$	8,065,946
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

⁽¹⁾

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

⁽²⁾

Capital expenditures for Upstream consist primarily of the drilling and completing of wells while Gas Gathering consists of expenditures relating to the expansion and completion of the compression facility.

⁽³⁾

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

13. Risk Management Activities

Commodity Price Risks

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

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

Inherent in the Corporation’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Corporation’s counterparty to a contract. The Corporation does not currently require collateral from any of its counterparties nor does its counterparties require collateral from the Corporation.

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

Epsilon has historically elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for these financial commodity derivative contracts using the mark‑to‑market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as g ain (loss) on derivative contracts on the consolidated statements of operations and comprehensive income. The related cash flow impact is reflected in cash flows from operating activities. During 2018, Epsilon recognized losses on financial commodity derivative contracts of $1,938,465. This amount included cash paid on settlements of these contracts of $1,381,898. For 2017, Epsilon recognized gains of $2,623,687, which included cash received on settlements of natural gas derivative contracts of $2,027,791.

Commodity Derivative Contracts

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



		Weighted Average Price ($/MMbtu)					Fair Value
	Volume				Basis		December 31,
Derivative Type	(Mmbtu)		Swaps		Differential		2018
2019
Fixed price swap	3,635,000		$	2.78	$	—		(35,660)
Basis swap	3,635,000		$	—	$	(0.54)		(261,363)
							$	(297,023)

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


	Fair Value of Derivative Assets
	December 31,		December 31,
	2018		2017
Current
Basis swap	$	76,075	$	203,841
Fixed price swap		125,790		22,191
Two-way costless collar		—		45,949
	$	201,865	$	271,981

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017


	Fair Value of Derivative Liabilities
	December 31,		December 31,
	2018		2017
Current
Basis swap	$	(337,438)	$	—
Fixed price swap		(161,450)		—
Two-way costless collar		—		(12,437)
	$	(498,888)	$	(12,437)


Net Fair Value of Derivatives	$	(297,023)	$	259,544

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



	Year ended		Year ended
		December 31,		December 31,
	2018		2017

Fair value of asset (liability), beginning of year	$	259,544	$	(336,352)
Gains (losses) on derivatives included in earnings		(1,938,465)		2,623,686
Settlement of commodity derivative contracts		1,381,898		(2,027,791)
Fair value of asset (liability), end of year	$	(297,023)	$	259,544

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

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



	Year ended		Year ended
		December 31,		December 31,
	2018		2017

Balance beginning of period	$	1,646,601	$	1,468,635
Liabilities from drilling of new wells		1,590		90,827
Change in estimates		(137,490)		(16,073)
Accretion		114,453		103,212
Balance end of period	$	1,625,154	$	1,646,601

Epsilon Energy Ltd.

Notes to the Consolidated Financial Statements (Continued)

For the years ended December 31, 2018 and 2017

15. Fair Value Measurements

The methodologies used to determine the fair value of our financial assets and liabilities were the same at December 31, 2018 and 2017.

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

Commodity derivative instruments consist of fixed-price swaps, costless collars, and basis swap contracts for natural gas. The Corporation’s derivative contracts are valued based on an income approach. The model considers various assumptions, such as quoted forward prices for commodities, time value and volatility factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The Corporation utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.

16. Consolidation of Common Shares

EPSILON ENERGY LTD.

Supplemental Information to Consolidated Financial Statements

(Unaudited)

OIL AND GAS PRODUCING ACTIVITIES

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

Oil and Gas Reserves

Users of this information should be aware that the process of estimating quantities of ‘‘proved,’’ ‘‘proved developed’’ and ‘‘proved undeveloped’’ crude oil, natural gas liquids (NGLs) and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity; evolving production history; crude oil and condensate, NGL and natural gas prices; and continual reassessment of the viability of production under varying economic conditions.

Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved reserves represent estimated quantities of crude oil, NGLs and natural gas, which, by analysis of geoscience and engineering data, can be estimated, with reasonable certainty, to be economically producible from a given date forward from known reservoirs under then-existing economic conditions, operating methods and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

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

Proved undeveloped reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. PUDs can be recorded in respect of a particular undrilled location only if the location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the date that the PUDs are to be recorded, unless specific factors (such as those described in interpretative guidance issued by the Staff of the SEC) justify a longer timeframe. Likewise, absent any such specific factors, PUDs associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond five years from the date that the PUDs were recorded. Epsilon has formulated development plans for all drilling locations associated with its PUDs at December 31, 2018. Under these plans, each PUD location will be drilled within five years from the date it was recorded.

Estimates for PUDs are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

The following tables set forth Epsilon’s net proved reserves at December 31, 2018 and 2017 and changes for each of the two years in the period ended December 31, 2018. Net proved reserves at December 31 are estimated by the Corporation’s independent petroleum engineers, DeGolyer and MacNaughton.

EPSILON ENERGY LTD.

Supplemental Information to Consolidated Financial Statements

(Unaudited)

NET PROVED RESERVE SUMMARY


	Natural
All reserves located in United States	Gas	Oil	Total
	(MMcf)	(MBbl)	(MMcfe)
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)	(9,029)
Net proved reserves at December 31, 2017	215,588	37	215,812
Revisions of previous estimates (1)(2)(5)	(89,558)	(1)	(89,564)
Improved recoveries (3)	717	—	717
Production	(7,631)	(6)	(7,665)
Net proved reserves at December 31, 2018	119,116	31	119,299


Proved developed reserves:
At December 31, 2016	48,463	—	48,463
At December 31, 2017	60,571	37	60,795
At December 31, 2018	50,698	31	50,881
Proved undeveloped reserves:
At December 31,2016	934	—	934
At December 31, 2017	155,017	—	155,017
At December 31, 2018	68,418	—	68,418

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

(2) Revisions of previous estimates in the proved undeveloped category is attributable to undeveloped well locations being removed due to lease expiration and revised spacing assumptions.

(3) Reduced recoveries in the proved producing category are primarily attributable to minor revisions to the expected production curves from the previous year.

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

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

EPSILON ENERGY LTD.

Supplemental Information to Consolidated Financial Statements

(Unaudited)

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table sets forth the capitalized costs relating to Epsilon’s crude oil and natural gas producing activities at December 31, 2018 and 2017:


	Year ended December 31,
	2018		2017
Proved properties	$	118,851,574	$	118,524,693
Unproved properties		19,498,666		17,451,552
Gathering system properties		41,040,847		40,880,503
Total Oil & Gas Properties		179,391,087		176,856,748
Accumulated depreciation, depletion and amortization		(111,944,974)		(104,877,974)
Net capitalized costs	$	67,446,113	$	71,978,774

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

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


	Year ended December 31,
	2018		2017
Oil and Natural Gas Activities:
Proved acquisition costs	$	4,992	$	1,734,509
Unproved acquisition costs		2,047,114		17,451,552
Development costs (1)		321,890		20,758
Total costs incurred for oil and natural gas activities		2,373,996		19,206,819
Gathering System development costs		160,344		142,418
Total costs incurred	$	2,534,340	$	19,349,237

(1)

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

Results of Operations for Oil and Gas Producing Activities

The following table sets forth results of operations for gas producing activities for the years ended December 31, 2018 and 2017:


	Year ended December 31,
	2018		2017
Oil and gas producing activities:
Gas sales	$	19,031,422	$	19,203,543
Oil and other liquid sales		671,221		121,985
Total revenues		19,702,643		19,325,528
Lease operating costs		(6,665,856)		(5,723,298)
Depreciation, depletion, amortization, and accretion		(5,294,200)		(8,057,299)
Total costs		(11,960,056)		(13,780,597)
Results of operations from oil and gas producing activities	$	7,742,587	$	5,544,931

EPSILON ENERGY LTD.

Supplemental Information to Consolidated Financial Statements

(Unaudited)

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

The following information has been developed utilizing procedures prescribed by the Extractive Industries—Oil and Gas Topic of the ASC and based on natural gas reserves and production volumes estimated by the reserve engineers of DeGolyer and MacNaughton. The commodity prices estimated below were based on a 12-month average of first-day-of-the-month commodity prices for the years 2018 and 2017. The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating Epsilon or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of Epsilon.

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

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

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

The following table sets forth the standardized measure of discounted future net cash flows from projected production of Epsilon’s gas reserves as of December 31, 2018 and 2017.


	Year ended December 31,
	2018		2017
Future cash inflows	$	314,768,187	$	444,906,724
Future production costs		(113,557,103)		(168,489,681)
Future development costs (1)		(35,324,796)		(92,026,760)
Future income taxes (2)		(45,050,385)		(49,347,763)
10% annual discount for estimated timing of cash flows		(61,761,091)		(85,326,963)
Standardized measure of discounted future net cash flows	$	59,074,812	$	49,715,557

⁽¹⁾

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

⁽²⁾

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

EPSILON ENERGY LTD.

Supplemental Information to Consolidated Financial Statements

(Unaudited)

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2018 and 2017:


	Year ended December 31,
	2018		2017
Beginning balance	$	49,715,557	$	16,387,269
Revenue less production and other costs		(13,042,411)		(13,634,107)
Changes in price, net of production costs		44,764,807		26,136,085
Development costs incurred		512,314		34,457
Net changes in future development costs		50,335,213		(68,608,621)
Revisions of previous quantity estimates (1)		(75,979,298)		111,557,578
Accretion of discount		7,382,905		1,390,234
Net change in income taxes		(3,192,058)		(19,722,823)
Purchases of reserves in place		—		786,392
Timing differences and other technical revisions (1)		(1,422,217)		(4,610,907)
Ending balance	$	59,074,812	$	49,715,557

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

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

None.

ITEM 9A. CONTROLS AND PROCEDURES.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and our principal financial officer, evaluated, as of the end of the period covered by this Annual Report on Form 10-K, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer have concluded that as of December 31, 2018, our disclosure controls and procedures were effective at the reasonable assurance level. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and our management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Management’s Report on Internal Control Over Financial Reporting

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

Changes in Internal Control Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION.

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Directors and Executive Officers. The names, ages, business experience (for at least the past five years) and positions of our directors and executive officers as of December 31, 2018, are set out below. Our Board of Directors consisted of seven members at such date. All directors serve until the next annual meeting of shareholders or until their successors are elected or appointed and qualified. The Board of Directors appoints the executive officers annually.


Director or Executive Officer	Age	Position with us
Michael Raleigh	62	Chief Executive Officer and Director
B. Lane Bond	60	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 chief executive officer and a director for Epsilon Energy Ltd. since July 2013. Before becoming chief executive officer at Epsilon Energy Ltd., he acted in various positions in the global oil and gas business for 35 years, primarily holding positions in the areas of reservoir development strategy, property valuations, completions and production. He has also been managing investments with Domain Energy Advisors since January 2005. Mr. Raleigh has been a member of the board of directors of Roan Resources, Inc,. an Anadarko Basin-focussed exploration and production company, since September 2018. He has also been managing investments with Domain Energy Advisors since January 2005. We believe that Mr. Raleigh is qualified to serve as a member of our board of directors as a result of his background in engineering, including reserve, acquisitions and valuation engineering, and his experience in the development and appraisal of oil and gas fields. Mr. Raleigh received a Bachelor of Science degree in Chemical Engineering from Queens University in Canada and received his Master of Business Administration degree from the University of Colorado.

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

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

John Lovoi. Mr. Lovoi has been chairman of our board of directors since July 2013. Mr. Lovoi has been the managing partner of JVL Advisors, LLC, a private oil and gas investment advisor, since November 2002. He is a Director of Helix Energy Solutions Group, an operator of offshore oil and gas properties and production facilities, the Chairman of Dril-Quip, Inc., a provider of subsea, surface and offshore rig equipment, and a Director of Roan Resources, Inc., an Anadarko Basin-focused exploration and production company. We believe that Mr. Lovoi is qualified to serve as a member of our board of directors as a result of his background in investment banking, equity research, and asset management, with an emphasis on the global oil and gas practice.

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

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

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

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

Tracy Stephens. Mr. Stephens has been a director since May 2017. He has also been a member of our Compensation, Nominating and Corporate Governance Committee, and Conflicts Committee since February 2018. He is the founder of Westminster Advisors, a CEO advisory services company, and served as its Chief Executive Officer from January 2017. He was previously employed by Resources Global Professionals, a large business consulting company, from July 2001 to December 2016, and was the Chief Operating Officer the last three years. We believe that Mr. Stephens is qualified to serve as a member of our board of directors as a result of his extensive experience with public companies.

Corporate Governance Practices and Policies

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

The Board of Directors

The Board is committed to a high standard of corporate governance practices. The Board believes that this commitment is not only in the best interests of the shareholders but that it also promotes effective decision-making at the Board level. The Board is of the view that its approach to corporate governance is appropriate and complies with the objectives and guidelines relating to corporate governance set out in National Instrument 58-201 adopted by the Canadian

securities administrators, or NI 58-201, as well as the governance requirements of the NASDAQ Capital Market. In addition, the Board monitors and considers for implementation the corporate governance standards that are proposed by various Canadian regulatory authorities or that are published by various non-regulatory organizations in Canada. The Board has also established a Compensation Committee and Nominating and Corporate Governance Committee and has adopted a Compensation Committee Charter, and Nominating and Corporate Governance Charter to ensure the objectives of NI 58-201 and the NASDAQ Capital Market are met.

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

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

The Board held seven meetings during 2018 and seven meetings during 2017. All Board meetings were conducted with open and candid discussions. As such, the independent directors did not hold any separate meetings, other than Audit and Compensation, Nominating and Corporate Governance Committee meetings that excluded directors who were not independent. The chairman of the Board is not an independent director. The independent members of the Board have the ability to meet on their own and are authorized to retain independent financial, legal and other experts as required whenever, in their opinion, matters come before the Board that require an independent analysis by the independent members of the Board. The Board intends to hold at least four regular meetings each year, as well as additional meetings as required. The Board has not established any required attendance levels for the Board and committee meetings. In setting the regular meeting schedule, care is taken to ensure that meeting dates are set to accommodate directors’ schedules so as to encourage full attendance.

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

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

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

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

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

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

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

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

Board Diversity . Our Compensation, Nominating and Corporate Governance Committee is responsible for reviewing with the board of directors, on an annual basis, the appropriate characteristics, skills and experience required for the board of directors as a whole and its individual members. In evaluating the suitability of individual candidates (both new candidates and current members), the nominating and corporate governance committee, in recommending candidates for election, and the board of directors, in approving (and, in the case of vacancies, appointing) such candidates, will take into account many factors, including the following:

personal and professional integrity, ethics and values;

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

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

strong finance experience;

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

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

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

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

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

Board Committees

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

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

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

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

The Audit Committee operates under a written charter that satisfies the applicable standards of the SEC and The 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:

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;

Study and evaluate appropriate compensation mechanisms and criteria;

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

Evaluate senior management;

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

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

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

Recommend to the Board members and chairpersons for each committee;

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

10.

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

These responsibilities include reporting and making recommendations to the Board for their consideration and approval. Corporate governance also relates to the activities of the Board, the members of which are elected by and are

accountable to the shareholders, and takes into account the role of the individual members of management who are appointed by the Board and who are charged with the day-to-day management of us. The Board is committed to sound corporate governance practices, which are both in the interest of its shareholders and contribute to effective and efficient decision making.

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

Conflicts Committee . The Conflicts Committee comprises Jacob Roorda (Committee Chairman), Tracy Stephens and Ryan Roebuck, all of whom are independent directors.

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

Communications to the Board.

Shareholders may communicate directly with our Board of Directors or any director by writing to the board or a director in care of the corporate secretary at Epsilon Energy Ltd., 16701 Greenspoint Park Drive, Suite 195, Houston, Texas 77060, or by faxing their written communication to AeRayna Flores at (281) 668-0985. Shareholders may also communicate to the Board of Directors or any director by calling Ms. Flores at (281) 670-0002. Ms. Flores will review any communication before forwarding it to the board or director, as the case may be.

Employment Agreements

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

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

ITEM 11. EXECUTIVE COMPENSATION.

Summary Compensation Table

In April 2017 the Board amended and restated the 2007 Plan, which is currently called the Amended and Restated 2017 Stock Option Plan (the ‘2017 Plan’). In addition, in 2017, the Board adopted, and The Corporation’s shareholder approved, the Share Compensation Plan. The following table sets out information concerning the compensation paid to our principal executive officer and our two most highly compensated executive officers other than our principal executive officer, or our named executive officers for the two years ended December 31, 2018 and 2017. Compensation amounts in

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


										Non-equity incentive
										plan compensation
						Share-based		Option- based		($) (f)
				Bonuses		awards (d)		awards (e)		Annual		Long-term
				and		Share-based		Option-based		incentive		Incentive		Pension		Total
Name and principal	Year	Salary		director fees		awards		awards		plans		Plans		value		compensation
position (a)	(b)	($) (c)		($) (h)		($) (d)		($) (e)		(f1)		(f2)		($) (g)		($) (i)
Michael Raleigh, CEO (1)	2018	$	—	$	—	$	748,750	$	—	$	—	$	—	$	—	$	748,750
	2017	$	—	$	—	$	775,000	$	—	$	—	$	—	$	—	$	775,000
Henry Clanton, COO (2)	2018	$	250,000	$	75,000	$	104,825	$	—	$	—	$	—	$	—	$	429,825
	2017	$	240,385	$	—	$	—	$	68,627	$	—	$	—	$	—	$	309,012
B. Lane Bond, CFO (3)	2018	$	200,000	$	70,000	$	74,875	$	—	$	—	$	—	$	—	$	344,875
	2017	$	200,000	$	70,000	$	—	$	66,079	$	—	$	—	$	—	$	336,079

⁽¹⁾

Mr. Raleigh is currently working without a salary from us; however, he was granted the following equity award in 2018 and 2017.

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

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

⁽²⁾

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

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

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

⁽³⁾

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

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

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

Description of the 2017 Plan and the Share Compensation Plan.

Amended and Restated 2017 Stock Option Plan

The 2017 Plan was approved by the Board and shareholders in April 2017 as a restatement of our Amended and Restated 2010 Stock Option Plan.

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

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

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

The exercise price of options granted under the 2017 Plan may not be less than the closing price of the common shares on the TSX on the last trading day preceding the day on which the option is granted.

Each option granted under the 2017 Plan expires on the date specified by the applicable option agreement (not later than ten years following grant), subject to earlier termination as provided below.

In the event we undergo a change of control by a reorganization, acquisition, amalgamation or merger (or a plan or arrangement in connection with any of these) with respect to which all or substantially all of the persons who were the beneficial owners of the common shares immediately prior to such transaction do not, following such transaction, beneficially own, directly or indirectly more than 50% of the resulting voting power, a sale of all, or substantially all, of the Corporation’s assets, or the liquidation, dissolution or winding-up of the Corporation, the Board may determine that all unvested options will vest and be eligible for exercise within a period determined by the directors preceding the change of control. Options not exercised within this period will terminate.

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

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

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

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

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

Share Compensation Plan

The Share Compensation Plan was adopted by the Board on April 13, 2017 and approved by the shareholders on May 24, 2017.

The Share Compensation Plan provides that up to a total of 1,000,000 common shares. As of December 31, 2018, a total of 345,333 common shares have been issued under the Share Compensation Plan.

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

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

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

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

Incentive Plan Awards for Named Executive Officers

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


Option-based Awards									Share-based Awards
	Number of						Number of	Market or		Market or
	securities				Value of		shares or units	payout value		payout value of
	underlying	Option			unexercised		of shares that	of share-based		vested share-
	unexercised	exercise		Option	in-the-money		have not	awards that		based awards
	options (#)	price		expiration	options ($)		vested	have not		not paid out or
Name (a)	(b)	($) (c)		date (d)	(e)		(#) (f)	vested ($) (g)		distributed ($) (h)
Michael Raleigh	50,000	$	7.34	06/05/22	$	—	208,333	$	1,247,917	$	249,583
Henry Clanton	30,000	$	6.70	01/30/24	$	—	17,500	$	104,825	$	—
B. Lane Bond	22,500	$	7.34	06/05/22	$	—	12,500	$	74,875	$	—
B. Lane Bond	27,500	$	6.70	01/30/24	$	—

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, 2018 are as follows:


						Non-equity incentive plan
		Option-based awards—Value		Share-based awards—Value		compensation—Value earned
		vested during the year		vested during the year		during the year
Name (a)		($) (b)		($) (c)		($) (d)
Michael Raleigh	$	—	$	249,583	$	N/A
Henry Clanton	$	—	$	—	$	N/A
B. Lane Bond	$	—	$	—	$	N/A

We have adopted the 2018 Plan as an incentive‑based stock option award plan applicable to all named executive officers and employees.

Termination and Change of Control Benefits

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

Mr. B. Lane Bond’s employment contract calls for a base pay of US$200,000 per year and contains provisions for severance payments equal to six months of current annual salary amount in the event of a change of control.

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

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

DIRECTOR COMPENSATION

The following table contains compensation earned in the year ended December 31, 2018 by our independent directors who are not named executive officers:


							Non-equity
							incentive plan		Pension		All other
Amounts Shown in Cdn$	Fees earned		Share-based		Option ‑ based		compensation		value		compensation		Total
Name (a)	($) (b)		awards ($) (c)		($) (d)		($) (e)		($) (f)		($) (g)		($) (h)
John Lovoi*	$	—	$	53,910	$	—	$	—	$	—	$	—	$	53,910
Michael Raleigh*	$	—	$	748,750	$	—	$	—	$	—	$	—	$	748,750
Matthew Dougherty*	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Adrian Montgomery	$	40,000	$	53,910	$	—	$	—	$	—	$	—	$	93,910
Jacob Roorda	$	40,000	$	53,910	$	—	$	—	$	—	$	—	$	93,910
Ryan Roebuck	$	40,000	$	53,910	$	—	$	—	$	—	$	—	$	93,910
Tracy Stephens	$	40,000	$	53,910	$	—	$	—	$	—	$	—	$	93,910

* 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.

As of May 1, 2017, independent board member compensation is fixed at an annual fee of Cdn$40,000, paid semi-annually in July and January.

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

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


							Share-based Awards
Option-based Awards								Market or		Market or
	Number of						Number of	payout value		payout value of
	securities				Value of		shares or units	of share-based		vested share-
	underlying	Option			unexercised		of shares that	awards that		based awards
	unexercised	exercise		Option	in-the-money		have not	have not		not paid out or
	options	price		expiration	options		vested	vested		distributed
	(#)	($)		date	($)		(#)	($)		($)
Name (a)	(b)	(c)		(d)	(e)		(f)	(g)		(h)
John Lovoi	10,000	$	7.34	6/5/2022	$	—	14,000	$	83,860	$	14,975
Adrian Montgomery	10,000	$	7.34	6/5/2022	$	—	14,000	$	83,860	$	14,975
Ryan Roebuck	10,000	$	7.34	6/5/2022	$	—	14,000	$	83,860	$	14,975
Jacob Roorda	12,500	$	6.70	1/30/2024	$	—	14,000	$	83,860	$	14,975
Tracy Stephens	—	$	—		$	—	14,000	$	83,860	$	14,975

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


						Non-equity
		Option-based		Share-based		incentive plan
		awards—Value		awards—Value		compensation—Value
		vested during		vested during		earned during
		the year		the year		the year
		($)		($)		($)
Name (a)		(b)		(c)		(d)
John Lovoi	$	—	$	14,975	$	N/A
Adrian Montgomery	$	—	$	14,975	$	N/A
Ryan Roebuck	$	—	$	14,975	$	N/A
Jacob Roorda	$	—	$	14,975	$	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 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The table set forth below is information with respect to beneficial ownership of common shares as of December 31, 2018, by our named executive officers, by each of our directors, by all our current executive officers and directors as a group, and by each person known to us who beneficially own 5% or more of the outstanding common shares. To our knowledge, each person named in the table has sole voting and investment power with respect to the common shares identified as beneficially owned.

Unless otherwise indicated, the address of each of the individuals named below is c/o Epsilon Energy Ltd., 16701 Greenspoint Park Drive, Suite 195, Houston, Texas 77060.


	Number of	Percentage of
	Common	Common
Name of Beneficial Owner	Shares	Shares Owned
5% Stockholders
Advisory Research, Inc. (1)	3,197,365	11.69	%
JVL Advisors, LLC (2)	5,498,419	20.10	%
Oakview Capital Management, L.P. (3)	2,909,496	10.64	%
azValor Asset Management SGIIC SA (4)	4,103,523	15.00	%
Named Executive Officers and Directors
Matthew Dougherty (5)	3,295,015	12.05	%
Jacob Roorda (6)	78,733	*
Bruce Lane Bond (7)	117,833	*
John Lovoi (8)	5,510,919	20.15	%
Ryan Roebuck (9)	69,525	*
Tracy Stephens (10)	6,900	*
Adrian Montgomery (11)	12,500	*
Henry Clanton (12)	20,000	*
Michael Raleigh (13)	91,667	*
All executive officers and directors as a group (9 persons) (14)	9,203,092	33.64	%

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

⁽¹⁾

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

⁽²⁾

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

⁽³⁾

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

⁽⁴⁾

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

⁽⁵⁾

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

⁽⁶⁾

Mr. Roorda is a member of our board of directors. Includes 25,000 shares held by Mr. Roorda’s spouse, and 8,333 shares issuable upon the exercise of options exercisable within 60 days of March 26, 2019.

⁽⁷⁾

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

⁽⁸⁾

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

⁽⁹⁾

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

⁽¹⁰⁾

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

⁽¹¹⁾

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

⁽¹²⁾

Includes 20,000 shares issuable upon the exercise of options exercisable within 60 days of March 26, 2019. Mr. Clanton is our chief operating officer.

⁽¹³⁾

Includes 50,000 shares issuable upon the exercise of options exercisable within 60 days of March 26, 2019. Mr. Raleigh is our chief executive officer and a member of our board of directors.

⁽¹⁴⁾

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

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

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

Certain Relationships and Related Transactions

Since the beginning of fiscal 2015, there has not been, nor is there currently proposed, any transaction or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our voting securities, or any member of the immediate family of any of the foregoing persons, had or will have a direct or indirect material interest, except for the compensation and other arrangements described in “Executive Compensation” and “Director Compensation” elsewhere in this document and the transactions described below.

Independence of the Board of Directors

Indemnification of Officers and Directors

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

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

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

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

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

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

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

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


	December 31,		December 31,
	2018		2017
Audit Fees:
Audit of financial statements	$	555,580	$	437,576
Services in connection with regulatory filings		232,346		54,635
Total Audit Fees Paid	$	787,926	$	492,211

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.


(a)1.		Financial Statements:
		Report of Independent Registered Public Accounting Firm
		Consolidated Balance Sheets as of December 31, 2017 and December 31, 2018.
		Consolidated Statements of Operations for the years ended December 31, 2017 and December 31, 2018.
		Consolidated Statements of Comprehensive Income for the years ended December 31, 2017 and December 31, 2018. Consolidated Statements of Cash Flows for the years ended December 31, 2017 and December 31, 2018.
		Consolidated Statement of Changes in Shareholders’ Equity for the years ended December 31, 2017 and December 31, 2018.
		Notes to Consolidated Financial Statements

(a)2.		Financial Statement Schedules:
		There are no Financial Statement Schedules included with this filing for the reason that they are not required.

(a)3.		Exhibits


3.1		Articles of Incorporation of Epsilon Energy Ltd. (incorporated by reference to Exhibit 3.2 of Form 10, File No. 001-38770, filed on December 21, 2018)

3.2		Bylaws of Epsilon Energy Ltd. (incorporated by reference to Exhibit 3.2 of Form 10, File No. 001-38770, filed on December 21, 2018)

3.3		Articles of Amendment dated December 19, 2018 (incorporated by reference to Exhibit 3.3 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.1		Credit Agreement, dated as of July 29, 2013, by and among Epsilon Energy USA Inc., the lenders from time to time party thereto, Texas Capital Bank, National Association (“TCB”), as the administrative agent, swing line lender and letter of credit issuer, and TCB as the sole lead arranger and sole book runner (incorporated by reference to Exhibit 10.1 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.2		First Amendment to Credit Agreement, effective as of December 10, 2015 (incorporated by reference to Exhibit 10.2 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.3		Second Amendment to Credit Agreement, effective as of October 11, 2016 ((incorporated by reference to Exhibit 10.3 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.4		Third Amendment to Credit Agreement, effective as of February 21, 2017 (incorporated by reference to Exhibit 10.4 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.5		Fourth Amendment to Credit Agreement, effective as of August 4, 2017 (incorporated by reference to Exhibit 10.5 of Form 10 File No. 001-38770, filed on December 21, 2018)

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

10.7+		Lane Bond Offer Letter (incorporated by reference to Exhibit 10.6 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.8+		Henry Clanton Offer Letter (incorporated by reference to Exhibit 10.7 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.9		Anchor Shipper Gas Gathering Agreement, effective January 1, 2012, by and between Appalachia Midstream Services, L.L.C. and Epsilon Energy USA, Inc., as shipper and producer (incorporated by reference to Exhibit 10.8 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.10+		Amended and Restated 2017 Stock Option Plan (incorporated by reference to Exhibit 10.9 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.11+		Share Compensation Plan (incorporated by reference to Exhibit 10.10 of Form 10 File No. 001-38770, filed on December 21, 2018)

10.12		Agreement for the Construction, Ownership, and Operation of Midstream Assets in AMI Area D of Northern Pennsylvania effective the 1st day of January, 2012, by and between Statoil Pipelines, LLC, a Delaware limited liability company formerly known as StatoilHydro Pipelines, LLC, Epsilon Midstream LLC, a Pennsylvania limited liability company, and Appalachia Midstream Services, L.L.C., an Oklahoma limited liability company (incorporated by reference to Exhibit 10.11 of Form 10 File No. 001-38770, filed on December 21, 2018)

21.1		Subsidiaries of the Registrant (incorporated by reference to Exhibit 21.1 of Form 10 File No. 001-38770, filed on December 21, 2018)

23.1*		Consent of DeGolyer and MacNaughton

31.1*		Rule 13a‑14(a)/15d‑14(a) Certification.

31.2*		Rule 13a‑14(a)/15d‑14(a) Certification.

32.1**		Section 1350 Certifications.

32.2**		Section 1350 Certifications.

99.1*		Summary Reserve Report

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.


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

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on March 29, 2019.


	Epsilon Energy Ltd . . .

	By: /s/ B. Lane Bond
	B. Lane Bond
	Chief Financial Officer
	(duly authorized to sign on behalf of the registrant)

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


Signature	Title	Date

/s/ Michael Raleigh	Chief Executive Officer and Director	March 29, 2019
Michael Raleigh	(Principal Executive Officer)

/s/ B. Lane Bond	Chief Financial Officer	March 29, 2019
B. Lane Bond	(Principal Financial and Accounting Officer)

/s/ John Lovoi	Chairman of the Board	March 29, 2019
John Lovoi

/s/ Matthew Dougherty	Director	March 29, 2019
Matthew Dougherty

/s/ Adrian Montgomery	Director	March 29, 2019
Adrian Montgomery

/s/ Ryan Roebuck	Director	March 29, 2019
Ryan Roebuck

/s/ Jacob Roorda	Director	March 29, 2019
Jacob Roorda

/s/ Tracy Stephens	Director	March 29, 2019
Tracy Stephens

4820-6132-3131v.3 13278-291

FIFTH AMENDMENT TO CREDIT AGREEMENT

This FIFTH AMENDMENT TO CREDIT AGREEMENT (this “ Amendment ”) is entered into as of January 7, 2019 (the “ Fifth Amendment Execution Date ”), among EPSILON ENERGY USA INC (“ Borrower ”), the lenders (as hereinafter defined), and TEXAS CAPITAL BANK, NATIONAL ASSOCIATION , as administrative agent for the Lenders (in such capacity, “ Administrative Agent ”).

WHEREAS, Borrower, the financial institutions party thereto (collectively, together with their respective successors and assigns, the “ Lenders ”), and Administrative Agent are parties to that certain Credit Agreement dated as of July 29, 2013, as amended by First Amendment to Credit Agreement dated as of December 10, 2015, Second Amendment to Credit Agreement dated as of October 11, 2016, Third Amendment to Credit Agreement dated as of February 21, 2017, and Fourth Amendment to Credit Agreement dated as of August 4, 2017 (as so amended, the “ Credit Agreement ”);

WHEREAS, Borrower has requested that Administrative Agent and the Lenders amend the Credit Agreement as hereinafter provided;

WHEREAS, subject to the terms and conditions set forth herein, Administrative Agent and the Lenders are willing to agree to such amendment; and

WHEREAS, Borrower, the Lenders and Administrative Agent acknowledge that the terms of this Amendment constitute an amendment and modification of, and not a novation of, the Credit Agreement.

NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

SECTION 1. Definitions . Unless otherwise defined in this Amendment, capitalized terms used in this Amendment that are defined in the Credit Agreement shall have the meanings assigned to such terms in the Credit Agreement.

SECTION 2. Amendment to the Credit Agreement . Subject to satisfaction of the conditions of effectiveness set forth in Section 3 of this Amendment, the parties hereto agree that:

Section 1.1 of the Credit Agreement is hereby amended to amend and restate the following definition in its entirety to read as follows:

“ Maturity Date ” means March 1, 2022, or such earlier date on which the Commitment of each Revolving Credit Lender terminates as provided in this Agreement; provided , however , that if such date is not a Business Day, the Maturity Date shall be the next succeeding Business Day.

SECTION 3. Conditions of Effectiveness . The amendment set forth in Section 2 of this Amendment, as well as any other terms and conditions set forth herein, shall be effective as of date Administrative Agent shall have received each of the following, which shall be in form and substance satisfactory to Administrative Agent:

Fifth Amendment to Credit Agreement

Page 1

(a) a counterpart of this Amendment executed by Borrower, Guarantors, the Lenders and Administrative Agent;

(b) (i) joinders to the Guaranty and each applicable Security Document (collectively, the “ Joinders ”) executed by Dewey Energy Holdings, LLC and Dewey Energy GP, LLC (collectively, the “ New Guarantors ”), (ii) officer’s certificates, attaching authorizing resolutions, incumbencies and Constituent Documents, with respect to the New Guarantors, (iii) certificates of the appropriate governmental officials of the state of organization of each New Guarantor as to the existence and good standing of each New Guarantor, and (iv) the results of a UCC searches on the New Guarantors showing all financing statements and other documents or instruments on file against the New Guarantors in the appropriate filing offices;

(c) evidence that Borrower has entered into Acceptable Commodity Hedging Transactions at prices acceptable to Administrative Agent as are necessary to cover at least 50% of Projected Production of natural gas for calendar year 2019 and 25% of Projected Production of natural gas for calendar year 2020, in each case, from the Oil and Gas Properties of Borrower and its Subsidiaries used in determining the Borrowing Base;

(d) all fees and expenses required to be paid pursuant to the Loan Documents, including, without limitation, the fees and expenses of Winstead PC invoiced on or prior to the Fifth Amendment Execution Date; and

(e) such other certificates, documents, consents or opinions as the Administrative Agent reasonably may require.

SECTION 4. Increase of Borrowing Base . Subject to the satisfaction of the conditions of effectiveness set forth in Section 3 of this Amendment and effective as of the Fifth Amendment Execution Date, the Borrowing Base is hereby increased from $13,500,000 to $23,000,000. The foregoing redetermination of the Borrowing Base is a periodic redetermination of the Borrowing Base under Section 2.10(b) of the Credit Agreement. The Borrowing Base as so adjusted shall remain in effect until the next periodic redetermination of the Borrowing Base under Section 2.10(b) of the Credit Agreement, unless otherwise adjusted pursuant to the other provisions of Section 2.10 of the Credit Agreement.

SECTION 5. Post-Closing Covenant . On or before January 17, 2019, Borrower shall pay to Administrative Agent a Borrowing Base increase and extension fee in an amount equal to $172,500.

SECTION 6. Acknowledgment and Ratification . As a material inducement to Administrative Agent and the Lenders to execute and deliver this Amendment, each Obligated Party acknowledges and agrees that the execution, delivery, and performance of this Amendment shall, except as expressly provided herein, in no way release, diminish, impair, reduce, or otherwise affect the obligations of any Obligated Party under the Loan Documents, which Loan Documents shall remain in full force and effect.

SECTION 7. Borrower’s Representations and Warranties . As a material inducement to Administrative Agent and the Lenders to execute and deliver this Amendment, each Obligated Party represents and warrants to Administrative Agent and the Lenders (with the knowledge and

Fifth Amendment to Credit Agreement

Page 2

intent that Administrative Agent and the Lenders are relying upon the same in entering into this Amendment) that, as of the Fifth Amendment Execution Date:

(a) The execution, delivery, and performance by such Person of this Amendment and the Joinders to the extent party thereto and compliance with the terms and provisions hereof and thereof have been duly authorized by all requisite action on the part of such Person and do not and will not (i) violate or conflict with, or result in a breach of, or require any consent under (A) the Constituent Documents of such Person, (B) any applicable law, rule, or regulation or any order, writ, injunction, or decree of any Governmental Authority or arbitrator which could result in a Material Adverse Event, or (C) any agreement or instrument to which such Person is a party or by which it or any of its Properties is bound or subject which could result in a Material Adverse Event, or (i) constitute a default under any such agreement or instrument which could result in a Material Adverse Event, or result in the creation or imposition of any Lien upon any of the revenues or assets of such Person.

(b) This Amendment and the Joinders constitute legal, valid, and binding obligations of such Person to the extent that it is a party thereto, enforceable against such Person in accordance with their respective terms, except as limited by Debtor Relief Laws.

(c) No authorization, approval, or consent of, and no filing or registration with, any Governmental Authority or third party is or will be necessary for the execution, delivery, or performance by such Person of this Amendment or the Joinders to the extent party thereto or the validity or enforceability hereof or thereof.

(d) All of the representations and warranties contained in Article 6 of the Credit Agreement are true and correct on and as of the Fifth Amendment Execution Date with the same force and effect as if such representations and warranties had been made on and as of the Fifth Amendment Execution Date, except to the extent that such representations and warranties specifically refer to an earlier date, in which case they are true and correct as of such earlier date, and except that for purposes of this Section 7(d) , the representations and warranties contained in Section 6.2 of the Credit Agreement shall be deemed to refer to the most recent statements furnished pursuant to Section 7.1(a) and (b) of the Credit Agreement, respectively.

(e) At the time of and after giving effect to this Amendment, no Default exists.

SECTION 8. Effect of Amendment . This Amendment, except as expressly provided herein, (a) shall not be deemed to be a consent to the modification or a waiver of any other term or condition of the Credit Agreement, any Security Document or any other Loan Document, (b) shall not prejudice any right or rights which Administrative Agent or the Lenders may now or hereafter have under or in connection with the Credit Agreement, any Security Document or any other Loan Document, and (c) shall not be deemed to be a waiver of any existing or future Default under the Credit Agreement, any Security Document or any other Loan Document.

SECTION 9. Miscellaneous . This Amendment shall be governed by, and construed in accordance with, the law of the State of Texas. The captions in this Amendment are for convenience of reference only and shall not define or limit the provisions hereof. This Amendment may be executed in separate counterparts, each of which when so executed and delivered shall be

Fifth Amendment to Credit Agreement

Page 3

an original, but all of which together shall constitute one instrument. In evidencing this Amendment, it shall not be necessary to produce or account for more than one such counterpart. This Amendment, and any documents required or requested to be delivered pursuant to Section 3 hereof, may be delivered by facsimile or pdf transmission of the relevant signature pages hereof and thereof, as applicable.

SECTION 10. Ratification . Each Obligated Party ratifies and acknowledges that the Loan Documents to which it is a party are valid, subsisting and enforceable.

SECTION 11. NOTICE OF FINAL AGREEMENT . THIS AMENDMENT, THE OTHER LOAN DOCUMENTS AND THE INTERCREDITOR AGREEMENT REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES RELATING TO THE SUBJECT MATTER HEREOF AND THEREOF AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.

[Remainder of page intentionally left blank. Signature pages follow.]

Fifth Amendment to Credit Agreement

Page 4

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorized officers as of the Fifth Amendment Execution Date.

EPSILON ENERGY USA INC ,

as Borrower


By:	/s/ B. Lane Bond
Name:	B. Lane Bond
Title:	CFO

ACKNOWLEDGED AND AGREED:

EPSILON ENERGY LTD. ,

as a Guarantor


By:	/s/ B. Lane Bond
Name:	B. Lane Bond
Title:	CFO

EPSILON MIDSTREAM, LLC ,

as a Guarantor

By: Epsilon Energy USA Inc,

its Managing Member


By:	/s/ B. Lane Bond
Name:	B. Lane Bond
Title:	CFO

Fifth Amendment to Credit Agreement- Signature Page

ACKNOWLEDGED AND AGREED:

DEWEY ENERGY HOLDINGS, LLC ,

as a Guarantor


By:	/s/ B. Lane Bond
Name:	B. Lane Bond
Title:	CFO

DEWEY ENERGY GP, LLC ,

as a Guarantor


By:	/s/ B. Lane Bond
Name:	B. Lane Bond
Title:	CFO

Fifth Amendment to Credit Agreement- Signature Page

TEXAS CAPITAL BANK, NATIONAL ASSOCIATION ,

as Administrative Agent and a Lender


By:	/s/ James E. Hibbert, Jr.
Name:	James E. Hibbert, Jr.
Title:	Assistant Vice President

Fifth Amendment to Credit Agreement- Signature Page

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

March 29, 2019

Epsilon Energy Ltd.

16701 Greenspoint Park Drive, Suite 195

Houston, Texas 77060

Ladies and Gentlemen:

We hereby consent to the reference to DeGolyer and MacNaughton and to the incorporation of the estimates contained in our reports entitled “Report as of December 31, 2018 on Reserves and Revenue of Certain Properties with interests attributable to Epsilon Energy Ltd.” and “Report as of December 31, 2017 on Reserves and Revenue of Certain Properties owned by Epsilon Energy Ltd.” in Part 1 and in the “Notes to Consolidated Financial Statements” portion of the Annual Report on Form 10-K of Epsilon Energy Ltd. for the year ended December 31, 2018 (the Annual Report). We further consent to the inclusion of our report of third party dated March 13, 2019, relating to our independent evaluation of the estimated proved oil, condensate, and gas reserves, as of December 31, 2018, attributable to Epsilon Energy Ltd. in the Annual Report.

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

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

I, Michael Raleigh, Chief Executive Officer of Epsilon Energy Ltd., certify that:

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

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

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

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

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

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

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

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

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

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

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

9
Date: March 29, 2019

/s/ Michael Raleigh
Michael Raleigh
Chief Executive Officer

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

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

I, B. Lane Bond, Chief Financial Officer of Epsilon Energy Ltd., certify that:

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

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

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

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

9
Date: March 29, 2019

/s/ B. Lane Bond
B. Lane Bond
Chief Financial Officer

Exhibit 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

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

In connection with the Annual Report of Epsilon Energy Ltd. (the “Corporation”) on Form 10-K for the period ending December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1)

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

(2)

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


Date: March 29, 2019

/s/ Michael Raleigh
Michael Raleigh
Chief Executive Officer

Exhibit 32.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

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

(1)

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

(2)

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


Date: March 29, 2019

/s/ B. Lane Bond
B. Lane Bond
Chief Financial Officer

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

March 13, 2019

Epsilon Energy Ltd.

16701 Greenspoint Park Drive

Suite 195

Houston, Texas 77060

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2018, of the extent and value of the estimated net proved oil, condensate, and gas reserves of certain properties in which Epsilon Energy Ltd. (Epsilon) has represented it holds an interest. This evaluation was completed on March 13, 2019. The properties evaluated herein consist of working and royalty interests located in Oklahoma and Pennsylvania. Epsilon has represented that these properties account for 100 percent on a net gas equivalent basis of Epsilon’s net proved reserves as of December 31, 2018. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by Epsilon.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2018. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Epsilon after deducting all interests held by others.

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

DeGolyer and MacNaughton

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

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

Information used in the preparation of this report was obtained from Epsilon and from public sources. Additionally, this information includes data supplied by IHS Markit Inc; Copyright 2018 IHS Markit Inc. In the preparation of this report we have relied, without independent verification, upon information furnished by Epsilon with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Definition of Reserves

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

DeGolyer and MacNaughton

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

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

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

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

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

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

DeGolyer and MacNaughton

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

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

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

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

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

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

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

DeGolyer and MacNaughton

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by Epsilon, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

DeGolyer and MacNaughton

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

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

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

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

Data provided by Epsilon from wells drilled through December 31, 2018, and made available for this evaluation were used to prepare the reserves estimates herein. Reserves estimates for wells located in Pennsylvania were based on consideration of monthly production data available for certain properties through October 2018. Estimated cumulative production, as of December 31, 2018, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 2 months for properties in Pennsylvania. Additional reserves estimates for wells and overriding royalty interests located in Oklahoma were based on consideration of monthly production data available for certain properties only through March 2018, due primarily to these data not being available in the public domain. Estimated cumulative production, as of December 31, 2018, was deducted from the estimated gross ultimate recovery to estimate gross reserves, requiring that production be estimated for up to 9 months for properties in Oklahoma. Epsilon has represented that properties with monthly production data only through March 2018 were producing as of December 31, 2018.

DeGolyer and MacNaughton

Oil and condensate reserves estimated herein are those to be recovered by normal field separation. Oil and condensate reserves included in this report are expressed in thousands of barrels (Mbbl) representing 42 United States gallons per barrel. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

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

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

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

Primary Economic Assumptions

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

Oil and Condensate Prices

Epsilon has represented that the oil and condensate prices were based on West Texas Intermediate (WTI) pricing, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end

DeGolyer and MacNaughton

of the reporting period, unless prices are defined by contractual agreements. The oil and condensate prices were calculated using differentials furnished by Epsilon to the reference price of $65.48 per barrel and held constant thereafter. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $66.09 per barrel of oil and condensate.

Gas Prices

Epsilon has represented that the gas prices were based on Henry Hub pricing, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12‑month period prior to the end of the reporting period, unless prices are defined by contractual agreements. The gas prices were calculated for each property using differentials furnished by Epsilon to the reference price of $3.33 per million Btu and held constant thereafter. Btu factors provided by Epsilon were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $2.626 per thousand cubic feet of gas.

Production Taxes and Impact Fees

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

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses, provided by Epsilon and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were estimated using 2018 values, provided by Epsilon, and were not adjusted for inflation. In certain cases, future expenditures, either higher or

DeGolyer and MacNaughton

lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by Epsilon for all properties and were not adjusted for inflation. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of undeveloped reserves estimated herein.

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

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

DeGolyer and MacNaughton

Summary of Conclusions

The estimated net proved reserves, as of December 31, 2018, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and millions of cubic feet of gas equivalent (MMcfe):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2018
	Oil and Condensate (Mbbl)	Sales Gas (MMcf)	Gas Equivalent (MMcfe)

Proved Developed	31	50,698	50,881
Proved Undeveloped	0	68,418	68,418

Total Proved	31	119,116	119,299

Note: Liquid reserves estimated herein were converted to gas equivalent using an energy equivalent factor of 1 barrel of liquids per 6,000 cubic feet of gas equivalent.

The estimated future revenue to be derived from the production and sale of the net proved reserves, as of December 31, 2018, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):

	Proved Developed (M$)	Total Proved (M$)

Future Gross Revenue	135,732	314,768
Production Taxes and Impact Fees	2,895	5,243
Operating Expenses	60,230	108,314
Capital Costs	165	31,679
Abandonment Costs	3,158	3,646
Future Net Revenue	69,284	165,886
Present Worth at 10 Percent	41,091	81,990

Note: Future income taxes have not been taken into account in the preparation of these estimates.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2018, estimated reserves.

DeGolyer and MacNaughton

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

Submitted,

/s/DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716


	/s/ Gregory K. Graves, P.E.
	Gregory K. Graves, P.E.
	Senior Vice President
	DeGolyer and MacNaughton

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

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

That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to Epsilon dated
March 13, 2019, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.

That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 34 years of experience in oil and gas reservoir studies and reserves evaluations.


	/s/ Gregory K. Graves, P.E.
	Gregory K. Graves, P.E.
	Senior Vice President
	DeGolyer and MacNaughton