Epsilon Energy Ltd. - Annual Report: 2018 (Form 10-K)

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑K

(Mark One)

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

For the fiscal year ended December 31, 2018.

OR

☐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)

 

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

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

 

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.

 

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

 

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.

 

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).

 

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.

 

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

 

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:

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:

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.

 

 

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

 

Anadarko, NW Stack Trend—Oklahoma

 

Business highlights of 2017

Operational Highlights

Marcellus Shale—Pennsylvania

 

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.

 

Acreage

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

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:

 

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.

 

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:

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:

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:

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:

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.

 

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 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:

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

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:

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.

 

 

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

NW Stack Trend—Oklahoma

Year ended December 31, 2017 Highlights

Operational Highlights

Marcellus Shale—Pennsylvania

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:

 

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:

 

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)

 

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”)

 

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

 

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

 

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

 

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:

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

 

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:

 

Contractual Obligations

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

 

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.

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.

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

 

 

Consolidated Balance Sheets