# Epsilon Energy Ltd.: Form 10-K for the period ended Dec 31, 2021

- Company: [Epsilon Energy Ltd.](/companies/epsn.md) (CIK 1726126)
- Form: 10-K
- Filed: 2022-03-24
- Accepted by EDGAR: Mar 23, 2022, 20:34 ET
- Period: 2021-12-31
- Accession: 0001558370-22-004185
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1726126/000155837022004185/epsn-20211231x10k.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1726126/000155837022004185/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2021-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 12 months, 2021-01-01 to 2021-12-31 | $42.4m | us-gaap:RevenueFromContractWithCustomerIncludingAssessedTax |
| Operating income | 12 months, 2021-01-01 to 2021-12-31 | $20.6m | us-gaap:OperatingIncomeLoss |
| Interest expense | 12 months, 2021-01-01 to 2021-12-31 | $101.4k | us-gaap:InterestExpense |
| Income tax | 12 months, 2021-01-01 to 2021-12-31 | $4.4m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2021-01-01 to 2021-12-31 | $11.6m | us-gaap:NetIncomeLoss |
| Diluted EPS | 12 months, 2021-01-01 to 2021-12-31 | $0.49 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 12 months, 2021-01-01 to 2021-12-31 | $0.49 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 12 months, 2021-01-01 to 2021-12-31 | 23,857,102 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 12 months, 2021-01-01 to 2021-12-31 | $20.0m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Share repurchases | 12 months, 2021-01-01 to 2021-12-31 | $2.4m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2021-12-31 | $26.5m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2021-12-31 | $31.7m | us-gaap:AssetsCurrent |
| Total assets | at 2021-12-31 | $99.5m | us-gaap:Assets |
| Current liabilities | at 2021-12-31 | $7.5m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2021-12-31 | $20.2m | us-gaap:Liabilities |
| Shareholders' equity | at 2021-12-31 | $79.3m | us-gaap:StockholdersEquity |

## Business

As filed, 38,746 characters.

### Summary

Epsilon Energy Ltd. (the “Company” or “Epsilon” or “we”) was incorporated under the laws of the Province of Alberta, Canada March 14, 2005, pursuant to the ABCA. The Company is extra-provincially registered in Ontario pursuant to the *Business Corporations Act* (Ontario). Epsilon is a North American on-shore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves. Our primary area of operation is Pennsylvania. Our assets are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. On October 24, 2007, the Company became a publicly traded entity trading on the Toronto Stock Exchange (“TSX”) in Canada. On February 14, 2019, Epsilon’s registration statement on Form 10 was declared effective by the United States Securities and Exchange Commission and on February 19, 2019, we began trading in the United States on the NASDAQ Global Market under the trading symbol “EPSN.” Effective as of the close of trading on March 15, 2019, Epsilon voluntarily delisted its common shares from the TSX. At December 31, 2021, Epsilon’s total estimated net proved reserves were 110,969 million cubic feet (MMcf) of natural gas reserves, 819,726 barrels (Bbl) of NGL reserves, and 305,052 barrels (Bbl) of oil and other liquids. Epsilon holds leasehold rights to approximately 76,544 gross (13,176 net) acres. The Company has natural gas production in the Marcellus in Pennsylvania and oil, natural gas liquids and natural gas production 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, Dewey Energy Holdings LLC, a Delaware limited liability company, and Altolisa Holdings, LLC, a Delaware limited liability company.

Substantially all of the production from our Pennsylvania acreage (4,597 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 and maintenance of the system. We own a 35% interest in the Auburn GGS which is operated by a subsidiary of Williams Partners, LP. In 2021, we paid $1.6 million to the Auburn GGS to gather and treat our 9.8 Bcf of natural gas production in Pennsylvania ($1.8 million was paid to the Auburn GGS to gather and treat our 11.0 Bcf in 2020).

Our principal executive office is located at 16945 Northchase Drive, Suite 1610, 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 2021

### Operational Highlights

#### Marcellus Shale—Pennsylvania

- During the year ended December 31, 2021, Epsilon’s realized natural gas price was $3.04 per Mcf, a 124% increase from $1.36 for the year ended December 31, 2020.
- Total year ended December 31, 2021 natural gas production was 9.8 Bcf, as compared to 11.0 Bcf during 2020.
- Gathered and delivered 63.2 Bcf gross (22.1 Bcf net to Epsilon’s interest) during the year, or 173 MMcf/d through the Auburn Gas Gathering System.
- We participated in the drilling of 3 gross (0.42 net) and completion of 3 gross (0.27 net) Marcellus wells in 2021. These wells went into production at various times beginning in January and going through October.
- At year end, the Company had 1 gross (0.18 net) well waiting on completion.

#### Anadarko, NW STACK Trend—Oklahoma

- During 2021, Epsilon’s realized price for all Oklahoma production was $6.34 per Mcfe, a 169% increase from 2020.
- Total production for 2021 included natural gas, oil, and other liquids and was 0.73 Bcfe, as compared to 0.31 Bcfe during 2020.
- In 2021, the Company participated in the drilling of 4 gross (0.75 net) wells and completion of 2 gross (0.6 net) wells.

### Properties

As of December 31, 2021, Epsilon’s 76,544 gross (13,176 net) acres are all located in the United States and include 275 gross (35.84 net) wells.

| ​ ​ Producing Wells | ​ | ​ Gross(1) | ​ | ​ Net(2) |
| --- | --- | ---: | --- | ---: |
| Pennsylvania |  | 210 |  | 26.26 |
| Oklahoma |  | 51 |  | 6.75 |
| ​ | ​ | 261 | ​ | 33.01 |
| Non-Producing Wells | ​ | ​ | ​ | ​ |
| Pennsylvania |  | 4 |  | 1.13 |
| Oklahoma |  | 10 |  | 1.69 |
| ​ | ​ | 14 | ​ | 2.83 |
| Total Wells | ​ | ​ | ​ | ​ |
| Pennsylvania |  | 214 |  | 27.39 |
| Oklahoma | ​ | 61 | ​ | 8.44 |
| Total Wells | ​ | 275 | ​ | 35.84 |

#### Acreage

As of December 31, 2021, our leasehold inventory consisted of the following acreage amounts, rounded to the nearest acre:

| ​ ​ ​ Developed Acres | ​ ​ Gross(1) | ​ Net(2) (3) |
| --- | ---: | ---: |
| Pennsylvania | 12,913 | 4,261 |
| Oklahoma | 5,120 | 1,848 |
| ​ | 18,033 | 6,109 |
| **Undeveloped Acres** |  |  |
| Pennsylvania | 336 | 336 |
| Oklahoma | 58,175 | 6,731 |
| ​ | 58,511 | 7,067 |
| **Total Acres** |  |  |
| Pennsylvania | 13,249 | 4,597 |
| Oklahoma | 63,295 | 8,579 |
| Total acres | 76,544 | 13,176 |

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

(2) “Net” means the Company’s fractional working interest share in each leasehold tract of land on which productive wells have been drilled.

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

### Business Segments

Our operations are conducted by three operating segments for which information is provided in our consolidated financial statements for the years ended December 31, 2021 and 2020.

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.

*Corporate:* 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 in 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, 2021 and 2020, respectively, follows:

| ​ ​ ​ Revenues | ​ ​ ​ | ​ ​ Year ended December 31, 2021 | ​ | ​ ​ 2020 |
| --- | --- | ---: | --- | ---: |
| **Natural gas revenue** | **​** | **$31,708,185** | **​** | **$15,207,227** |
| Volume (MMcf) | ​ | 10,233 | ​ | 11,204 |
| Avg. Price ($/Mcf) | ​ | $3.10 | ​ | $1.36 |
| PA Exit Rate (MMcfpd) | ​ | 29.3 | ​ | 32.8 |
| **Oil and other liquids revenue** | **​** | **$2,829,982** | **​** | **$338,325** |
| Volume (MBO) | ​ | 54.4 | ​ | 14.9 |
| Avg. Price ($/Bbl) | ​ | $52.02 | ​ | $22.66 |
| **Gathering system revenue** | **​** | **$7,865,825** | **​** | **$8,879,728** |
| **Total Revenues** | **​** | **$42,403,992** | **​** | **$24,425,280** |

### 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 Equinor Pipelines, LLC (21.125%). The Anchor Shippers, Epsilon Energy, Equinor USA Onshore Properties, Inc., and Chesapeake Energy Corporation 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 an 18% contractual rate of return on invested capital. The term of this arrangement is 15 years commencing January 1, 2012 and expiring December 31, 2026. 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 approximately 44 miles of gathering pipelines, a small auxiliary compression facility and a main compression facility with three dehydration units and three Caterpillar 3612 compression units. Design capacity of the Auburn compression facility, or the Auburn CF, is approximately 330,000 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, Equinor USA Onshore Properties, Inc. and Chesapeake Energy Corporation. Revenues derived from Epsilon’s production which have been eliminated from gathering system revenues amounted to $1.6 million and $1.8 million, respectively, for the years ended December 31, 2021 and 2020.

During the years ended December 31, 2021 and 2020, the Auburn GGS delivered 63.2 Bcf and 69.5 Bcf respectively, of natural gas, or 173 and 190 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, 2021, are summarized in the table below. See Risk Factors for information relating to the uncertainties surrounding these reserve categories.

| ​ ​ ​ ​ ​ Pennsylvania-Marcellus Shale | ​ ​ Natural Gas ​ MMcf | ​ Oil and Other Liquids MBbl |
| --- | ---: | ---: |
| Proved developed producing | 70,101.6 | — |
| Proved undeveloped | 31,321.0 | — |
| Total Pennsylvania proved reserves | 101,422.6 | — |
| Oklahoma-Anadarko Basin |  |  |
| Proved developed producing | 2,123.9 | 222.7 |
| Proved undeveloped | 7,422.3 | 902.1 |
| Total Oklahoma proved reserves | 9,546.2 | 1,124.8 |
| Total proved reserves at December 31, 2021 | 110,968.8 | 1,124.8 |

We have not engaged in any exploration capital spending in 2021 or 2020. Our development capital spending to convert proved undeveloped reserves to proved developed reserves for the periods indicated is as follows:

- In 2021 in Pennsylvania, 3 gross (0.42 net) wells were drilled and 3 gross (0.27 net) completed. (Net development capital $4.1 million). Reserves of 4.6 Bcf for the 3 wells were reclassified as proved developed producing as these well were turned online at various times beginning in January and going through October of 2021. Additionally, 1 gross (0.18 net) well was drilled in 2021, but not completed (development capital $0.2 million). It is scheduled to be completed in April 2022.
- In 2021 in Oklahoma, we drilled 4 gross (0.75 net) wells and completed 2 gross (0.6 net) wells. Reserves of 2.8 Bcfe were reclassified as proved developed producing. Two gross (0.55 net) wells are scheduled to be completed in April.2022.

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

Our policies regarding internal controls over reserve estimates require reserves to be prepared by an independent engineering firm under the supervision of our Chief Executive Officer, and to be in compliance with generally accepted geologic, petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The corporate staff interacts with our internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data for the reserves estimation process.

We provide our engineering firm with property interests, production, capital budgets, current operating costs, current production prices and other information. This information is reviewed by our Chief Executive Officer and our Chief Operating Officer to ensure accuracy and completeness of the data prior to submission to our independent engineering firm. Reserves are reviewed and approved internally by our Chief 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 natural gas and oil 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 natural gas and oil 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 DeGolyer 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 natural gas and oil reserves since joining DeGolyer and MacNaughton in 2006.

### 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 Pennsylvania gas sales occur in Zone 4 of the Tennessee Gas Pipeline at the Shoemaker Dehy meter, which is the receipt point from the Auburn Compression Facility.

Epsilon uses a third-party service, ARM Energy Management LLC (“ARM”) for its natural gas marketing. In this capacity, ARM is responsible for carrying out marketing activities such as submission of nominations, receipt of payments, submission of invoices and negotiation of contracts.

For the year ended December 31, 2021, we sold natural gas through ARM to 30 unique customers. Direct Energy Business Marketing, LLC and SWN Energy Services Company, LLC each accounted for 10% or more of our total revenue. For the year ended December 31, 2020, we sold natural gas to 29 unique customers. Alta Energy Marketing LLC, EQT Energy LLC, South Jersey Resources Group LLC, and Spotlight Energy LLC each accounted for 10% or more of our total revenue.

### Geographic Locations of Operations

Approximately 93% and 97% of our production during fiscal 2021 and 2020, respectively was derived 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 and to expand our holdings in 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

### Competition

In the Marcellus Basin, we operate in a 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.

It is not uncommon in the oil and natural gas industry to experience shortages of drilling and completion rigs, equipment, pipe, services and personnel, which can cause both delays in development drilling activities and significant cost increases. We are exposed to the risk of industry competition for drilling rigs, completion rigs and availability of related equipment and services, among other goods and services required in our business.

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

### Our Status as an Emerging Growth Company

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

- an exemption from the auditor attestation requirement in the assessment of our internal controls over financial reporting required by Section 404 of the Sarbanes—Oxley Act of 2002;
- an exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;
- an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board, or the PCAOB, requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about our audit and our financial statements; and
- reduced disclosure about our executive compensation arrangements.

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

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

- the last day of our fiscal year in which we have total annual gross revenues of $1.07 billion (as such amount is indexed for inflation every five years by the SEC to reflect the change in the Consumer Price Index for All Urban Consumers published by the Bureau of Labor Statistics, setting the threshold to the nearest $1 million) or more;
- the last day of our fiscal year following the fifth anniversary of the date of our first sale of common equity securities under an effective Securities Act registration statement;
- the date on which we have, during the prior three-year period, issued more than $1 billion in non-convertible debt; or
- the date on which we are deemed to be a large accelerated filer under the rules of the Securities and Exchange Commission, or SEC, which means the market value of our common shares that is held by non-affiliates (or public float) exceeds $700 million as of the last day of our second fiscal quarter in our prior fiscal year.

### Employees

As of December 31, 2021, we had nine full-time employees (including executive officers) in Houston, Texas. None of our employees are subject to a collective bargaining agreement or represented by a union.

The foundation of our Company is our employees and our success begins with a values-driven culture and commitment to developing a skilled, agile, diverse and engaged workforce where every employee understands that they can and do make a difference. Advancing a safe, ethical, inclusive and diverse culture creates an environment that attracts and retains the high-performing workforce needed to successfully execute our strategy.

To build a better tomorrow for everyone, we continue to foster a culture that embraces inclusion and diversity and encourages collaboration. Our core values include inclusion and diversity, and we believe in equity and the value and voice of every employee.

### Legal Proceedings

On March 10, 2021, Epsilon filed a complaint against Chesapeake Appalachia, LLC (“Chesapeake”) in the United States District Court for the Middle District of Pennsylvania, Scranton, Pennsylvania. Epsilon claims that Chesapeake has breached a settlement agreement and several operating agreements (“JOAs”) to which Epsilon and Chesapeake are parties. Epsilon asserts that Chesapeake has failed to cooperate with Epsilon’s efforts to develop resources in the Auburn Development, located in North-Central Pennsylvania, as required under both the settlement agreement and JOAs.

Epsilon requested a preliminary injunction but was unsuccessful in obtaining that injunction. Epsilon filed a motion to amend its original Complaint. Chesapeake opposed. The Court ruled in Epsilon’s favor and allowed Epsilon’s amendment. Chesapeake moved to dismiss the amended Complaint. The Court granted the motion to dismiss without prejudice to Epsilon’s right to file a new lawsuit based on new proposals made after the Court’s decision. Epsilon filed a motion for reconsideration of that decision. The motion for reconsideration was fully briefed in November 2021. Epsilon filed a notice of additional evidence to the motion for reconsideration on January 4, 2022. The motion for reconsideration was denied on January 18, 2022.

Epsilon filed a notice of appeal on February 15, 2022 challenging both the motion to dismiss and motion for reconsideration decisions. Chesapeake filed a cross-appeal on March 1, 2022. A briefing schedule has not yet been set but a decision on the appeal is expected in the fourth quarter of 2022.

### Regulation

#### Environmental Regulation

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

- require the acquisition of various permits before drilling commences;
- restrict the types, quantities and concentrations of various substances, including water and waste, that can be released into the environment;
- limit or prohibit activities on lands lying within wilderness, wetlands and other protected areas; and
- require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

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

#### Climate Change

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

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

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

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

Federal agencies also have begun directly regulating emissions of methane from natural gas operations. In 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain facilities to reduce methane gas and volatile organic compound emissions. EPA published amendments to those regulations effective September 15, 2020. However, on January 20, 2021, President Biden issued an Executive Order directing EPA to consider suspending, revising or rescinding the September 15, 2020 amendments and also to consider proposing new regulations governing methane and volatile organic compound emissions from existing oil and gas sector operations.

In November 2016, the Bureau of Land Management (“BLM”) published a final rule to reduce methane emissions by regulating venting, flaring, and leaking from oil and natural gas operations on public lands. A federal district court vacated much of that rule in October 2020 and that decision is now subject to an appeal.

Internationally, in April 2016, the United States joined other countries in entering into a non-binding agreement in France for nations to limit their GHG emissions through country-determined reduction goals every five years beginning in 2020 (the “Paris Agreement”). Although the Trump Administration subsequently announced plans to withdraw from the Paris Agreement, on January 20, 2021 President Biden issued an Executive Order providing that he was accepting the Paris Agreement on behalf of the United States.

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

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

#### Hydraulic Fracturing

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

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

#### Gathering System Regulation

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

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

### Market for Our Common Equity and Related Stockholder Matters

*Market Information.* Commencing on February 19, 2019, the common shares of the Company trade on the NASDAQ Global Market with the ticker symbol ‘‘EPSN.’’ The last reported sales price of our common shares on the NASDAQ Global Market on March 22, 2022 was $5.69 per share.

*Shareholders.* We had approximately 800 shareholders of record as of December 31, 2021.

*Dividends.* We have not declared or paid any cash or stock dividends on our common shares since our inception; however, we anticipate paying quarterly cash or stock dividends beginning March 2022.

#### Securities Authorized for Issuance under Equity Incentive Plans.

The following table sets out the number of common shares available to be issued upon exercise of outstanding options issued and the changes to the options outstanding for the year pursuant to our equity compensation plans and the weighted average exercise price of outstanding options for the periods indicated:

| ​ ​ ​ ​ ​ ​ ​ | ​ ​ ​ ​ ​ ​ | ​ As of December 31, 2021 ​ Number of Options Outstanding | ​ ​ ​ | ​ ​ Weighted Average Exercise Price | ​ ​ ​ ​ ​ | ​ As of December 31, 2020 ​ Number of Options Outstanding | ​ ​ ​ | ​ ​ Weighted Average Exercise Price |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Balance at beginning of period |  | 245,000 | ​ | $5.27 |  | 245,000 | ​ | $5.27 |
| Exercised |  | (16,250) | ​ | ​ — |  | — | ​ | — |
| Expired/Forfeited |  | (10,000) | ​ | ​ — |  | — | ​ | — |
| Balance at period-end |  | 218,750 | ​ | $5.28 |  | 245,000 | ​ | $5.27 |
| ​ | ​ | ​ | ​ | ​ ​ | ​ | ​ | ​ | ​ ​ |
| **Exercisable at period-end** |  | 218,750 | ​ | $5.28 |  | 245,000 | ​ | $5.27 |

For the years ended December 31, 2021 and 2020, we had no warrants or other common share-related rights outstanding.

At December 31, 2021, under the 2020 Equity Incentive Plan (the “2020 Plan”) (See Note 6 Shareholders’ Equity of the Notes to the Consolidated Financial Statements), we are authorized to issue 2,000,000 Common Shares to employees and directors of the Company. As of that date, we had 375,834 common shares granted under the 2020 Plan. We also had, as of December 31, 2021, 56,002 unvested shares outstanding under the predecessor plan, the 2017 Stock Compensation Plan. No more shares are authorized to be issued under this plan.

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

| ​ ​ ​ ​ ​ ​ ​ | ​ ​ ​ ​ ​ ​ | ​ As of December 31, 2021 ​ Number of Shares Outstanding | ​ ​ ​ | ​ ​ Weighted Average Grant Date Market Price | ​ ​ ​ ​ ​ | ​ As of December 31, 2020 ​ Number of Shares Outstanding | ​ ​ ​ | ​ ​ Weighted Average Grant Date Market Price |
| --- | --- | ---: | --- | --- | --- | ---: | --- | ---: |
| Balance non-vested Restricted Stock at beginning of period |  | 290,070 | ​ | $3.41 |  | 346,499 | ​ | $3.76 |
| Granted |  | 48,000 | ​ | ​ 5.04 | ​ | 111,900 | ​ | ​ 3.71 |
| Vested |  | (137,668) | ​ | ​ 3.98 |  | (168,329) | ​ | 3.65 |
| Forfeited |  | (34,400) | ​ | ​ 3.68 |  | — | ​ | — |
| Balance non-vested Restricted Stock at end of period | ​ | 166,002 | ​ | $3.96 |  | 290,070 | ​ | $3.41 |

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

| ​ ​ ​ ​ ​ ​ ​ | ​ ​ ​ ​ ​ ​ | ​ As of December 31, 2021 ​ Number of Shares Outstanding | ​ ​ ​ | ​ ​ Weighted Average Grant Date Market Price | ​ ​ ​ ​ ​ | ​ As of December 31, 2020 ​ Number of Shares Outstanding | ​ ​ ​ | ​ ​ Weighted Average Grant Date Market Price |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Balance non-vested Restricted Stock at beginning of period |  | 193,167 | ​ | $3.45 |  | — | ​ | $— |
| Granted |  | 20,834 | ​ | ​ 5.04 | ​ | 214,000 | ​ | ​ 3.42 |
| Vested |  | (62,501) | ​ | ​ 4.13 |  | (20,833) | ​ | 3.22 |
| Balance non-vested Restricted Stock at end of period | ​ | 151,500 | ​ | $3.84 |  | 193,167 | ​ | $3.45 |

### Recent Developments

On February 25, 2022, the Board of Directors approved a quarterly cash dividend of $0.0625 per common share, payable on March 31, 2022, to shareholders of record at the close of business on March 8, 2022. With the initiation of a cash dividend, Epsilon intends to pay regular quarterly dividends, with future dividend payments subject to quarterly review and approval by its Board of Directors. At this quarterly dividend rate, the annual dividend rate for the fiscal year 2022 is $0.25 per share.

The Board of Directors also authorized the repurchase of up to 1,183,410 of the outstanding common shares, representing 5% of the outstanding common shares of Epsilon, for an aggregate purchase price of not more than US $8.0 million, pursuant to a normal course issuer bid, during the one-year period commencing on March 8, 2022. The program will end on March 7, 2023 unless the maximum amount of common shares is purchased before then or Epsilon provides earlier notice of termination.

## Risk factors

As filed, 56,869 characters.

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 natural gas and oil reserve quantities. If the oil and natural gas industry continues to experience low prices, we may, among other things, be unable to meet all of our financial obligations or make planned expenditures.

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

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

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

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

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

***Our 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, 2021 and 2020, 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, 2021, 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 and to expand our holdings in Pennsylvania and Oklahoma. 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, natural gas and oil prices may fall and may become and remain depressed for a long period of time, which may adversely affect our results of operations. We may be unable to obtain additional capital required to implement our business plan, which could restrict our ability to grow.***

Operations could also be adversely affected by general economic downturns or limitations on spending. An economic downturn and uncertainty may have a negative impact on our business. During 2021 and 2020, there was tremendous volatility in prices and available financing for oil and gas projects. There can be no assurance that we will be able to access capital markets to provide funding for future operations that would require additional capital beyond our current existing available capital on terms acceptable to us.

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

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

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

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

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

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

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

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

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

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

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

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

From time to time, we may enter into transactions to acquire assets or shares of other companies. These transactions may be financed partially or wholly with debt, which may increase our debt levels. Depending on future exploration and development plans, we may require additional equity and/or debt financing that may not be available or, if available, may not be available on favorable terms. Neither our articles 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 93% and 97% of our production during fiscal 2021 and 2020, respectively 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.***

Approximately 99% of our oil and natural gas properties are operated by third-party operators. As such, we will be dependent on such operators for the timing of activities related to such properties and will largely be unable to direct or control the activities of the operators. The objectives and strategy of those operators may not always be consistent with ours, and we have a limited ability to exercise influence over, and control the risks associated with, operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues from our 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 our joint venture partner fails to meet the specific requirement(s) of a particular leasehold interest, the leasehold interest may terminate or expire. There can be no assurance that any of the obligations required to maintain each leasehold interest will be met. The termination or expiration of a particular leasehold interest may have a material adverse effect on our financial condition and results of operations.

### We may incur losses as a result of title deficiencies.

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

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

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

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

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

### Risks Related to Commodity Prices, Hedging and Marketing

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

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

There have been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to promote the divestment of shares of energy companies, as well as to pressure lenders and other financial services companies to limit or curtail activities with energy companies. If these efforts are successful, our stock price and our ability to access capital markets may be negatively impacted.

Members of the investment community are also increasing their focus on sustainability practices, including practices related to GHGs and climate change, in the energy industry. As a result, we may face increasing pressure regarding our sustainability disclosures and practices. Additionally, members of the investment community may screen companies such as ours for sustainability performance before investing in our shares.

***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.

### COVID-19

Management continues to actively monitor the impact of the COVID-19 pandemic on the Company's financial condition, liquidity, operations, suppliers, industry and ability to obtain financing in future reporting periods. Given the evolution of the COVID-19 pandemic and the global responses to curb its spread, the Company is currently not able to estimate the effects of the COVID-19 pandemic on its results of operations, financial condition, or liquidity for the future. To date, the COVID-19 pandemic has had little direct effect on the Company or its financial condition.

### Risks Related to Internal Controls

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

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

- the last day of the fiscal year during which we have total annual gross revenues of $1.07 billion or more;
- the last day of the fiscal year following the fifth anniversary of our registration on February 14, 2019;
- the date on which we have, during the previous 3-year period, issued more than $1 billion in non-convertible debt; or
- the date on which we are deemed a “large accelerated filer” as defined under the federal securities laws.

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

- have an auditor report on our internal control over financial reporting pursuant to the Sarbanes-Oxley Act of 2002;
- comply with any requirement that may be adopted by the Public Company Accounting Oversight Board regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements (auditor discussion and analysis);
- submit certain executive compensation matters to shareholders parachute provisions (requiring a non-binding shareholder vote to approve golden parachute arrangements for certain executive advisory votes pursuant to the “say on frequency” and “say on pay” provisions (requiring a non-binding shareholder vote to approve compensation of certain executive officers) and the “say on golden officers in connection with mergers and certain other business combinations) of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010; and
- include detailed compensation discussion and analysis in our filings under the Exchange Act and instead may provide a reduced level of disclosure concerning executive compensation.

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

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

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

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

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

### Risks Related to Gathering System

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

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

***The gathering rate on the Auburn Gas Gathering System is subject to a cost of service model which could result in a non-competitive gathering rate and reduced throughput.***

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

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

Differential is an energy industry term that refers to the discount or premium received for the sale of a petroleum product at a specific location relative to a nationally recognized sales hub. In the Marcellus, natural gas is significantly discounted to Henry Hub and the size of the differential can be volatile. Many factors influence the size and duration of differentials including local supply / demand imbalances, seasonal fluctuations in demand, transportation availability and cost, as well as the regulatory environment as it pertains to constructing new transportation pipelines. In Northeast Pennsylvania, negative differentials have persisted for many years due to rapid increases in supply as a result of advances in well completion techniques. Despite substantial increases in local demand for natural gas coupled with pipeline expansions, optimizations, and new pipelines that have been brought into service, the natural gas differential in Northeast Pennsylvania remains significant. There is no guarantee that future demand or pipeline transportation projects will eliminate this differential, and it will therefore remain a significant risk to demand for transportation service on the Auburn GGS, and therefore Epsilon’s revenues and cash flows.

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

Although the Anchor Shippers have dedicated their acreage and reserves to the Auburn GGS, the Auburn GGS may not be chosen by other producers in these areas to gather and compress the natural gas extracted. We compete with other companies, including co-owners of the Auburn 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 existing assets, reputation, efficiency, system reliability, gathering system capacity and pricing arrangements. Our key competitors in the natural gas gathering business include independent gas gatherers and major integrated energy companies. Alternate gathering facilities are available to non-anchor shippers we serve, and those producers may also elect to construct proprietary gas gathering systems. A significant increase in competition in the gas gathering industry could have a material adverse effect on our financial position, results of operations and cash flows.

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

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

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

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

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

Our revenues, operating results, and future rate of growth depend primarily upon the price of natural gas in northeast Pennsylvania which is currently volatile and significantly discounted to natural gas at Henry Hub due to insufficient interstate pipeline capacity out of the region. This volatility and discount has adversely impacted reserve development in the past, and could do so again in the future. A slowing pace or complete halt to the development of reserves will impact our financial results, cash flows, access to capital and ability to maintain our gas gathering system.

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

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

### Our operations are subject to operational hazards and unforeseen interruptions.

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

- Hurricanes, tornadoes, floods, extreme weather conditions and other natural disasters;
- Aging infrastructure and mechanical problems;
- Damages to pipelines and pipeline blockages or other pipeline interruptions;
- Uncontrolled releases of natural gas, brine, or industrial chemicals;
- Operator error;
- Damage caused by third-party activity, such as operation of construction equipment;
- Pollution and other environmental risks;
- Fires, explosions, craterings, and blowouts; and
- Terrorist attacks on our facilities or those of other energy companies.

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial financial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe 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.

## Legal proceedings

As filed, 1,608 characters.

On March 10, 2021, Epsilon filed a complaint against Chesapeake Appalachia, LLC (“Chesapeake”) in the United States District Court for the Middle District of Pennsylvania, Scranton, Pennsylvania. Epsilon claims that Chesapeake has breached a settlement agreement and several operating agreements (“JOAs”) to which Epsilon and Chesapeake are parties. Epsilon asserts that Chesapeake has failed to cooperate with Epsilon’s efforts to develop resources in the Auburn Development, located in North-Central Pennsylvania, as required under both the settlement agreement and JOAs.

Epsilon requested a preliminary injunction but was unsuccessful in obtaining that injunction. Epsilon filed a motion to amend its original Complaint. Chesapeake opposed. The Court ruled in Epsilon’s favor and allowed Epsilon’s amendment. Chesapeake moved to dismiss the amended Complaint. The Court granted the motion to dismiss without prejudice to Epsilon’s right to file a new lawsuit based on new proposals made after the Court’s decision. Epsilon filed a motion for reconsideration of that decision. The motion for reconsideration was fully briefed in November 2021. Epsilon filed a notice of additional evidence to the motion for reconsideration on January 4, 2022. The motion for reconsideration was denied on January 18, 2022.

Epsilon filed a notice of appeal on February 15, 2022 challenging both the motion to dismiss and motion for reconsideration decisions. Chesapeake filed a cross-appeal on March 1, 2022. A briefing schedule has not yet been set but a decision on the appeal is expected in the fourth quarter of 2022.

## Management's discussion and analysis

As filed, 44,486 characters.

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 of December 31, 2021 and 2020 and for the years then ended together with accompanying notes.

### Overview

Epsilon Energy Ltd. (the “Company”) is a North American onshore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves. Our primary area of operation is Pennsylvania. Our assets are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs.

Substantially all of the production from our Pennsylvania acreage (4,597 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. Epsilon owns a 35% interest in the system which is operated by a subsidiary of Williams Partners, LP. In 2021, we paid $1.6 million to the Auburn GGS to gather and treat our 9.8 Bcf of natural gas production in Pennsylvania ($1.8 million to the Auburn GGS to gather and treat our 11.0 Bcf in 2020).

At December 31, 2021 our total estimated net proved reserves were 110,969 million cubic feet (MMcf) of natural gas reserves, 819,726 barrels (Bbl) of NGL reserves, and 305,052 barrels (Bbl) of oil and other liquids, and we held leasehold rights to approximately 76,544 gross (13,176 net) acres. We have natural gas production in Pennsylvania, and natural gas, oil and other liquid production from our operated and non-operated wells in Oklahoma.

### Business Strategy

Our business strategy is to manage the cash flow generated from our producing leasehold and midstream assets in a manner where the risked capital allocation provides attractive rates of return. Our remaining inventory of drillable locations within existing leasehold is sufficient to maintain this cash flow for several years at capital expenditure levels well within the yearly free cash flow generated from these assets. In addition, we seek to identify attractive onshore natural gas and oil properties in the United States, to acquire leasehold interests and to develop our leasehold interests with the goal of deploying capital to earn attractive rates of return.

The core Marcellus Shale is one of the most attractive dry gas resources in the United States and has attracted significant development capital. Well productivity has improved dramatically for many years due to improving techniques in drilling and completing wells, resulting in increasing initial production rates and gas recoveries. The resulting supply of natural gas at times stresses the transportation infrastructure of the Northeast US and exacerbates the local price discount to Henry Hub. In many other basins throughout the US, the increase in natural gas production had historically outpaced demand. Over the past couple of years, this over supply condition has become more balanced and demand growth from increased LNG exports and pipeline exports to Mexico have provided attractive markets improving the prices for natural gas.

The operating environment remains challenging in Northeast Pennsylvania. We implemented a number of initiatives to enhance the value of our core assets in the Marcellus including a comprehensive review of well spacing and completion productivity for both the Lower and Upper Marcellus, and we are working with our well operators to increase operating efficiency. In addition, we continue to work closely with our gathering system partners in order to optimize the operating conditions, enhance operational safety, and to preserve and grow the long-term value of our gathering system assets.

The major producers in the Appalachian region are under pressure from capital markets to demonstrate capital discipline and control costs. Several major producers have announced reduced capital programs to balance the supply-demand for the commodity. Accordingly, we expect local production during 2022 to be flat compared to 2021. Our target is to maintain our current production level or grow modestly, but only if natural gas price levels are sufficient and the capital deployed can achieve our internal hurdle rate of return.

In the longer term, we believe natural gas prices will remain constructive due to moderating supply from both dry gas regions and associated gas from oil prone basins, and incremental demand from LNG exports, exports to Mexico and further coal to gas switching for domestic electrical power generation. Specifically, LNG export capacity is expected to grow from the current ~ 13 Bcf/d to 17 Bcf/d by 2024 based only on facilities currently commissioning or under construction.

In the Northwest STACK of Oklahoma, we continue to appraise recent and historical results of the Meramec formation from both our wells and analog wells within the focus area. At December 31, 2021, our initial well continues to outperform the pre-completion type curve expectations in terms of both production-to-date and projections for ultimate recoveries. The Company has drilled, but has not yet completed, additional Meramec appraisal wells within the focus area to prove a greater area for further exploitation on an opportunistically prudent timeline.

We realized net income of $11.6 million during 2021 as compared to net income of $0.9 million for 2020. At December 31, 2021, our total estimated net proved reserves of natural gas were 110,969 MMcf, an increase of 22,311 MMcf from December 31, 2020. Our standardized measure of discounted future net cash flows as of December 31, 2021 and 2020 was $77.7 million and $16.0 million, respectively. This measure of discounted future net cash flows does not include any estimate for future cash flows generated by Epsilon’s gathering system assets.

### Results of Operations

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

### Revenues

During the year ended December 31, 2021, revenues increased $18.0 million, or 73.6%, to $42.4 million from $24.4 million during the same period in 2020 due primarily to increased prices and higher production volumes in Oklahoma with the new wells.

Revenue and volume statistics for the years ended December 31, 2021 and 2020 were as follows:

| ​ ​ ​ ​ Revenues | ​ ​ ​ ​ | ​ ​ Year ended December 31, 2021 ​ ​ | ​ ​ | ​ ​ 2020 ​ ​ |
| --- | --- | ---: | --- | ---: |
| **Natural gas revenue** | **​** | **$31,708,185** | **​** | **$15,207,227** |
| Volume (MMcf) | ​ | 10,233 | ​ | 11,204 |
| Avg. Price ($/Mcf) | ​ | $3.10 | ​ | $1.36 |
| PA Exit Rate (MMcfpd) | ​ | 29.3 | ​ | 32.8 |
| **Oil and other liquids revenue** | **​** | **$2,829,982** | **​** | **$338,325** |
| Volume (MBO) | ​ | 54.4 | ​ | 14.9 |
| Avg. Price ($/Bbl) | ​ | $52.02 | ​ | $22.66 |
| **Gathering system revenue** | **​** | **$7,865,825** | **​** | **$8,879,728** |
| **Total Revenues** | **​** | **$42,403,992** | **​** | **$24,425,280** |

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, 2021, approximately 80% of the Auburn GGS revenues earned are gathering fees, while 20% are compression fees. Third party customers represent approximately 5% of gathering revenues and 4% of compression revenues. For the year ended December 31, 2020, approximately 85% of the Auburn GGS revenues earned were gathering fees, while 15% were compression fees. Third party customers represent approximately 4% of gathering revenues and 2% of compression revenues. Revenues derived from transporting and compressing Epsilon’s production which have been eliminated from gathering system revenues amounted to $1.6 million and $1.8 million respectively for the years ended December 31, 2021 and 2020.

Upstream natural gas revenue for the year ended December 31, 2021 increased by $16.5 million, or 109%, over 2020. This was primarily a result of higher natural gas prices partially offset by lower volumes being produced due to natural decline of the wells.

Upstream oil and other liquids revenue for the year ended December 31, 2021 increased by $2.5 million, or 736% over 2020. This was a result of increased production from new wells in addition to higher oil prices.

The Company’s share of gathering system revenue decreased $1.0 million, or 11%, during the year ended December 31, 2021 over 2020. 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, 2021 and 2020:

| ​ ​ ​ | ​ ​ | ​ ​ Year ended December 31, 2021 | ​ | ​ ​ 2020 |
| --- | --- | --- | --- | --- |
| Lease operating costs | ​ | $7,897,738 | ​ | $8,052,471 |
| Gathering system operating costs | ​ | ​ 726,646 | ​ | ​ 429,749 |
| ​ | ​ | $8,624,384 | **​** | **$8,482,220** |
| ​ | ​ | ​ **​** | **​** | **​** **​** |
| Upstream operating costs—Total $/Mcfe | ​ | ​ 0.75 | ​ | ​ 0.71 |
| Gathering system operating costs $ / Mcf | ​ | ​ 0.10 | ​ | ​ 0.04 |

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

For the year ended December 31, 2021, upstream operating costs decreased by $0.2 million, or 2.1% from the same period in 2020. The decrease in total cost was primarily due to the decrease in volumes produced primarily in Pennsylvania. The $/Mcfe increased primarily due to increased cost of discretionary maintenance during the year.

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 total per unit operating costs 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 $1.6 million and $1.8 million for the years ended December 31, 2021 and 2020, respectively (see Note 12, “Operating Segments,” of the Notes to Consolidated Financial Statements).

Gathering system costs (net of intercompany elimination) for the year ended December 31, 2021 increased $0.3 million, or 69% from the same period in 2020. Although the Company’s gross share of total gathering system costs increased only $0.06 million, or 3%, for the year ended December 31, 2021 over 2020, the elimination entry decreased by $0.2, or 11% for the same period. This was due to a decrease in throughput in the gathering system resulting in a higher cost per MCF.

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

| ​ ​ ​ | ​ ​ | ​ ​ Year ended December 31, 2021 | ​ | ​ ​ 2020 |
| --- | --- | ---: | --- | ---: |
| **Depletion, depreciation, amortization and accretion** | **​** | **$6,627,016** | ​ | **$9,557,891** |

Natural gas and oil and gathering system assets are depleted and depreciated using the units of production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved and unproved properties, the reserve base used to calculate depreciation and depletion is total proved reserves. At this time, the Company has only minimal leasehold acquisition costs. For natural gas and oil development and gathering system costs, the reserve base used to calculate depletion and depreciation is proved developed reserves. A reserve report is prepared as of December 31, each year.

Depreciation expense includes amounts pertaining to our office furniture and fixtures, leasehold improvements, computer hardware. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 7 years. Also included in depreciation expense is an amount pertaining to buildings owned by the Company. Depreciation for the buildings is calculated using the straight-line method over an estimated useful life of 30 years.

Accretion expense is related to the asset retirement costs.

During the year ended December 31, 2021, DD&A expense decreased by $2.9 million, or 31%, compared to the same period in 2020. This was primarily due to the increase in reserves reported and the decrease in production volumes. The lower volumes spread over the increased reserves resulted in lower DD&A.

### Impairment

| ​ ​ ​ | ​ ​ | ​ ​ Year ended December 31, 2021 | ​ | ​ ​ 2020 |
| --- | --- | ---: | --- | ---: |
| **Impairment** | **​** | **$153,058** | ​ | **$1,760,000** |

Epsilon performs a quantitative impairment test quarterly or whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable, over proved properties using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods. When indicators of impairment are present, GAAP requires that the Company first compare expected future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required. Additionally, GAAP requires that if an exploratory well is determined not to have found proved reserves, the costs incurred, net of any salvage value, should be charged to expense.

During the three months ended March 31, 2020, the Company recognized certain indicators of impairments specific to our Oklahoma assets and determined that carrying value of those assets was not recoverable. As a result of this assessment, a $1.76 million impairment was assessed on the Company’s Oklahoma assets at March 31, 2020. No additional impairment was required as of December 31, 2020.

### Gain (Loss) on Sale of Properties

| ​ ​ ​ | ​ ​ | ​ ​ Year ended December 31, 2021 | ​ | ​ ​ 2020 |
| --- | --- | ---: | --- | ---: |
| **Gain on sale of properties** | **​** | **$484,902** | ​ | **$—** |

For the year ended December 31, 2021, the Company recorded a gain on the sale of the shallow rights leases and wells in Oklahoma. We had no sales for the year ended December 31, 2020.

### General and Administrative (“G&A”)

| ​ ​ ​ | ​ ​ | ​ ​ Year ended December 31, 2021 | ​ | ​ ​ 2020 |
| --- | --- | ---: | --- | ---: |
| **General and administrative** | **​** | **$6,831,815** | ​ | **$5,589,963** |

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 restricted shares of stock granted and the related non-cash compensation.

The G&A expenses increased by $1.2 million, or 22%, during the year ended December 31, 2021 from the same period in 2020. This was mainly due to increased legal fees related to the complaint filed against Chesapeake, the addition of a salary and benefits for the CEO, and increased stock-based compensation associated with the 2020 stock grants.

### Interest Expense

| ​ ​ ​ | ​ ​ | ​ ​ Year ended December 31, 2021 | ​ | ​ ​ 2020 |
| --- | --- | ---: | --- | ---: |
| **Interest expense** | **​** | **$101,382** | ​ | $114,515 |

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

Interest expense decreased by $0.01 million, or 11%, during the year ended December 31, 2021 from the same period in 2020. The decrease is due to the reduction in the borrowing base on our line of credit during this time.

### Net gain (loss) on commodity contracts

| ​ ​ ​ | ​ ​ | ​ ​ Year ended December 31, 2021 | ​ | ​ ​ 2020 |
| --- | --- | ---: | --- | ---: |
| **(Loss) gain on derivative contracts** | **​** | **$(4,482,909)** | **​** | **$2,503,655** |

During the years ended December 31, 2021 and 2020, Epsilon entered into NYMEX Henry Hub Natural Gas Futures swap, Dominion basis swap, and two-way costless collar derivative contracts for the purpose of hedging its physical natural gas sales revenue. The amounts recorded represent the fair value changes on our derivative instruments during the period. For the year ended December 31, 2021, the Company paid net cash settlements of $4,243,085. For the year ended December 31, 2020, the Company received $4,503,457 on the settlement of contracts.

In February 2021, the Company added Henry Hub collars totaling 3.96 Bcf and basis swaps totaling 0.31 Bcf. In August 2021, the Company added Henry Hub collars totaling 0.46 Bcf and basis swaps totaling 1.10 Bcf. NYMEX HH prices generally increased throughout 2021 resulting in large realized losses for the year ended December 31, 2021.

During 2020, the Company added 0.6 Bcf of Henry Hub swaps and 2.14 Bcf of basis swaps to its existing 2020 hedge portfolio. Both Henry Hub prices and basis prices generally declined throughout 2020 resulting in large realized gains for the year ended December 31, 2020. The Company did not add any 2021 hedges during 2020.

### Other Income (Expense)

| ​ ​ ​ | ​ ​ | ​ ​ Year ended December 31, 2021 | ​ | ​ ​ 2020 |
| --- | --- | ---: | --- | ---: |
| **Interest income and other income** | **​** | **$39,995** | **​** | **$39,155** |

For the years ended December 31, 2021 and 2020 other income consisted primarily of interest income and was consistent over the periods.

### Net Income Compared to Adjusted EBITDA

| ​ ​ ​ | ​ ​ | ​ ​ Year ended December 31, 2021 | ​ | ​ ​ 2020 |
| --- | --- | --- | --- | --- |
| **Net income** | ​ | $11,627,517 | ​ | $875,171 |
| Add Back: | ​ | ​ ​ | ​ | ​ ​ |
| Net interest expense | ​ | ​ 62,517 | ​ | ​ 70,975 |
| Income tax expense | ​ | ​ 4,440,508 | ​ | ​ 575,420 |
| Depreciation, depletion, amortization, and accretion | **​** | **​** 6,627,016 | ​ | ​ 9,557,891 |
| Impairment expense | **​** | **​** 153,058 | ​ | ​ 1,760,000 |
| Stock based compensation expense | ​ | ​ 956,084 | ​ | ​ 849,631 |
| Loss on derivative contracts net of cash received or paid on settlement | ​ | ​ 239,824 | ​ | ​ 1,999,802 |
| Foreign currency translation loss | ​ | ​ 1,454 | ​ | ​ 2,065 |
| **Adjusted EBITDA** | ​ | $24,107,978 | ​ | $15,690,955 |

Epsilon defines Adjusted EBITDA as earnings before (1) net interest expense, (2) taxes, (3) depreciation, depletion, amortization and accretion expense, (4) impairments of natural gas and oil properties, (5) non-cash stock compensation expense, (6) gain or loss on derivative contracts net of cash received or paid on settlement, 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 natural gas and oil companies providing corresponding non-U.S. GAAP financial measures or that have different financing and capital structures or tax rates. These non-U.S. GAAP financial measures should be considered in addition to, but not as a substitute for, measures for financial performance prepared in accordance with U.S. GAAP. The table above sets forth a reconciliation of 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

The primary source of cash during the year ended December 31, 2021 was funds generated from operations. For the year ended December 31, 2020, the primary source of funds was from operations in addition to cash received on the settlement of derivative contracts. For the years ended December 31, 2021 and 2020, cash was primarily used for operations, as well as the development of natural gas and oil properties, the buyback of common shares through our share repurchase program, and the pre-payment of income taxes.

At December 31, 2021, we had a working capital surplus of $24.1 million, an increase of $10.8 million from the $13.3 million surplus at December 31, 2020. The surplus increased from December 31, 2020 primarily due to the increase in realized prices during 2021. The Company anticipates its current cash balance, cash flows from operations, and available sources of liquidity to be sufficient to meet its cash requirements.

#### Year ended December 31, 2021 compared to 2020

During the year ended December 31, 2021, $20.0 million was provided by our operating activities, compared to $14.8 million in 2020, a $5.2 million, or 35%, increase. The increase was mainly due to the increase in realized prices resulting in increased revenue offset by an increase in cash paid for settlements of derivative contracts.

We used $4.4 million for investing activities during the year ended December 31, 2021, compared to $6.5 million in 2020, a $2.1 million, or 32%, decrease. This was spent primarily on development costs targeting increasing production in Pennsylvania and Oklahoma, partially offset by the proceeds from the sale of the shallow right leases and wells in Oklahoma.

During the year ended December 31, 2021, $2.3 million of cash used for financing activity was primarily related to the repurchase of common shares of Epsilon. During the year ended December 31, 2020, $9.1 million of cash used for financing activity was primarily related to the repurchase and cancellation of common shares of Epsilon.

### Credit Agreement

In addition, the Company has a senior secured credit facility which includes a total commitment of up to $100 million. The current effective borrowing base is $14 million, which is subject to semi-annual redetermination. There are currently no borrowings under the facility. If Epsilon decided to access the facility, depending on the level of borrowing, the Company might need to increase its hedging activity. Borrowings from the Facility may be used for the acquisition and development of oil and gas properties, investments in cash flow generating assets complimentary to the production of oil and gas, and for letters of credit and other general corporate purposes. Upon each advance, interest is charged at the highest of a) rate of LIBOR plus an applicable margin (2.75%-3.75% based on the percent of the line of credit utilized), b) the Prime Rate, or c) the sum of the Federal Funds Rate plus 0.5%.

Effective April 6, 2021, the agreement was amended to extend the maturity date to March 1, 2024. In addition, the agreement was amended to include a *Benchmark Replacement* definition and transition plan to be used at such time when the LIBOR rate is discontinued.

On June 28, 2021, the borrowing base was decreased from $18 million to $14 million.

On November 23, 2021, the borrowing base of $14 million was reaffirmed until May 1, 2022, the next periodic redetermination of the borrowing base . The bank has a first priority security interest in the tangible and intangible assets of Epsilon Energy USA, Inc. to secure any outstanding amounts under the agreement. Under the terms of the agreement, the Company must maintain the following covenants:

- Interest coverage ratio greater than 3 based on income adjusted for interest, taxes and non-cash amounts.
- Current ratio, adjusted for line of credit amounts used and available and non-cash amounts, greater than 1.
- Leverage ratio less than 3.5 based on income adjusted for interest, taxes and non-cash amounts.

We were in compliance with the financial covenants of the agreement as of December 31, 2021 and expect to be in compliance for the next 12 months. We expect to remain in compliance as we currently have no borrowings under the facility and have funded all operations for 2021 out of operating cash flow and cash on hand and expect to continue to do so through 2022.

| ​ ​ ​ ​ | ​ ​ ​ | ​ ​ Balance at December 31, 2021 | ​ ​ ​ | ​ ​ Balance at December 31, 2020 | ​ ​ ​ | ​ ​ ​ ​ Borrowing Base December 31, 2021 | ​ ​ ​ ​ ​ Interest Rate |
| --- | --- | ---: | --- | ---: | --- | ---: | --- |
| **Revolving line of credit** | **​** | **$—** | **​** | **$—** | **​** | **$14,000,000** | **3 mo. LIBOR + 3.25%** |

36

### Repurchase Transactions

Commencing on January 1, 2021, Epsilon has conducted a normal course issuer bid (“NCIB”) to repurchase our issued and outstanding common shares, when doing so has been accretive to management's estimates of intrinsic value per share. The NCIB ended on December 31, 2021. Since the commencement of the NCIB, Epsilon has strengthened its financial position. With sufficient cash flow from operations, it used discretionary cash to fund these repurchases. During the year ended December 31, 2021, Epsilon has repurchased 534,015 common shares of the authorized 1,193,000 purchase amount and spent $2,423,007 under the NCIB.

Commencing on May 20, 2019, Epsilon conducted a normal course issuer bid (“NCIB”) to repurchase up to 1,367,762 issued and outstanding common shares. The NCIB ended on May 19, 2020. Additionally, on May 14, 2020, the Company’s Board of Directors announced its intention to commence a substantial issuer bid/issuer tender offer to purchase for cash up to an aggregate of approximately $6.2 million of its common shares. The tender offer expired on June 30, 2020. During the year ended December 31, 2020, the Company repurchased 2,994,348 common shares and spent $9,062,089, excluding fees and expenses The Company canceled all common shares taken up and paid for under the NCIB and tender offer. The Company funded the repurchases with cash on hand.

### Derivative Transactions

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

At December 31, 2021, Epsilon’s outstanding natural gas commodity swap contracts consisted of the following:

| ​ ​ ​ ​ ​ ​ Derivative Type 2022 ​ | ​ ​ Volume (MMbtu) ​ | ​ ​ ​ ​ | ​ ​ ​ ​ Ceiling Differential ​ ​ | ​ ​ ​ ​ | ​ ​ ​ ​ Floor Price ​ ​ | ​ ​ ​ ​ | ​ ​ ​ ​ Basis Differential ​ ​ | ​ ​ ​ ​ | ​ ​ ​ ​ Fair Value of Asset December 31, 2021 ​ ​ |
| --- | ---: | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Two-way costless collar | 590,000 | ​ | $3.34 | ​ | $2.80 | ​ | $— |  | ​ (239,824) |
| ​ | 590,000 | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | $(239,824) |

### Contractual Obligations

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 the asset operator to incur the expenditures in a future period. Current commitments amounted to approximately $3.8 million, all of which we expect to incur in 2022.

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.

### Off Balance Sheet Arrangements

As of December 31, 2021 and 2020, we had no off-balance sheet arrangements.

### 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 natural gas and oil 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. We do not currently do any exploratory drilling so this does not currently come into use.

### 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. Additionally, we are required to make an entry each reporting period to eliminate the Company’s share of gathering system revenue related to the volume of gas produced by the Company and billed to the Company by the operator of the gathering system.

### Proved Natural gas and oil Reserves

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

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

### Depreciation, Depletion and Amortization of Natural gas and oil Properties and Gathering Systems

The quantities of estimated proved natural gas and oil 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 natural gas and oil 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 natural gas and oil properties, significant downward revisions of estimated proved reserve quantities or significant increases in the estimated development costs.

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

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

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

### 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 Obligations (“ARO”)

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

### Income Taxes

Tax regulations and legislation in the U.S. and Canada are subject to change and differing interpretations requiring judgment. 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.

### Recently Issued Accounting Standards

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

## Market risk

As filed, 2,789 characters.

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, 2021 and 2020, the outstanding principal balance under the credit agreement was nil.

### Derivative Contracts

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

## Controls and procedures

As filed, 3,840 characters.

### Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and our principal financial officer, evaluated, as of the end of the period covered by this Annual Report on Form 10-K, the design and effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer have concluded that as of December 31, 2021, our disclosure controls and procedures were effective at the reasonable assurance level. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and our management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

### Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting for Epsilon as such term is defined in the Securities Exchange Act of 1934. Our internal control structure is designed to provide reasonable assurance that assets are safeguarded and that transactions are properly executed and recorded. The internal control structure includes, among other things, established policies and procedures, the selection and training of qualified personnel as well as management oversight.

With the participation of our management, we performed an evaluation of the effectiveness of our internal control over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework). Based upon our evaluation under the 2013 Framework, we have concluded that as of December 31, 2021 our disclosure controls and procedures were effective.

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

### Remediation of Material Weakness

As of September 30, 2021 our disclosure controls and procedures were not effective as of such date as a result of a material weakness in our internal control over financial reporting related to the reporting of hedge losses and the related review control as of September 30, 2021.

Our management implemented a remediation plan to address the operating effectiveness control deficiencies that led to the material weakness described above. Management’s plan of remediation included incremental training with accounting software client support team, additional month end review utilizing various reporting tools, and increased communication with operations regarding monthly commodity activity. We believe the remediation to be complete.

### Changes in Internal Control Over Financial Reporting

Other than the remediation efforts discussed above, there have been no significant changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Filed Mar 24, 2022.
Source: SEC EDGAR, the filing index for accession 0001558370-22-004185. Last ingested by Listed: Oct 24, 2026, 15:15 ET. No prices; not investment advice.