Epsilon Energy Ltd. 10-K

ITEM 1. BUSINESS. Summary Epsilon Energy Ltd. (the “Company” or “Epsilon” or “we”) was incorporated under the laws of the Province of Alberta, Canada on 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. 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.” At December 31, 2023, Epsilon’s total estimated net proved reserves were 65,916 million cubic feet of natural gas reserves, 383,174 barrels of NGL reserves, and 341,286 barrels of oil and other liquids. Epsilon holds leasehold rights to approximately 84,684 gross (15,463 net) acres, excluding the Texas acreage acquired in February 2024. The Company has natural gas production in the Marcellus Shale in Pennsylvania and oil, natural gas liquids and natural gas production in the Permian Basin in Texas and New Mexico and 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 the production from our Pennsylvania acreage (4,807 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 2023, we paid $2.5 million (after elimination) to the Auburn GGS to gather and treat our 7.9 Bcf of natural gas production in Pennsylvania ($2.8 million after elimination was paid to the Auburn GGS to gather and treat our 9.0 Bcf in 2022), including the fees paid to our subsidiary, Epsilon Midstream. Our principal executive office is located at 500 Dallas Street, Suite 1250, Houston, Texas 77002, 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 2023 Operational Highlights Marcellus Shale—Pennsylvania ● During the year ended December 31, 2023, Epsilon’s realized natural gas price was $1.74 per Mcf, excluding the impact of hedges, a 71% decrease from $5.96 for the year ended December 31, 2022. ● Total year ended December 31, 2023, natural gas sales were 7.9 Bcf, as compared to 9.0 Bcf during 2022. ● Gathered and delivered 66.2 Bcf gross (23.2 Bcf net to Epsilon’s interest) during the year, or 181 MMcf/d through the Auburn GGS. ● We participated in the drilling of 7 gross (0.74 net) and completion of 2 gross (0.02 net) Marcellus wells in 2023. The completed wells went into production in January 2023. ● At year end, the Company had 1 gross (0.01 net) well being drilled and 6 gross (0.73 net) wells waiting on completion. ​ Permian Basin—New Mexico and Texas ● During the year ended December 31, 2023, Epsilon’s realized price for all Permian Basin production was 5 ​ ​ $52.49 per BOE, excluding the impact of hedges . ● Total sales for 2023 including oil, natural gas, and other liquids was 75.7 MBOE . ● In 2023, the Company acquired 12,373 gross (3,093 net) of undeveloped leasehold acres in Ector County, Texas. ● In 2023, the Company participated in the drilling and completion of 4 gross (0.7 net) wells. These wells went into production in April 2023 (1 – New Mexico), May 2023 (1 – New Mexico) and October 2023 (2 – Texas). ​ Anadarko, NW STACK Trend—Oklahoma ● During the year ended December 31, 2023, Epsilon’s realized price for all Oklahoma production was $5.35 per Mcfe, excluding the impact of hedges, a 38% decrease from $8.68 for the year ended December 31, 2022. ● Total sales for 2023 including natural gas, oil, and other liquids was 0.60 Bcfe, as compared to 0.93 Bcfe during 2022. ● In 2023, the Company participated in the completion of 1 gross (0.11 net) well. The well went into production in May 2023. ​ Properties Wells As of December 31, 2023, Epsilon’s 84,684 gross (15,463 net) acres are all located in the United States and include 362 gross (37.47 net) wells. ​ ​ ​ ​ ​ ​ Gross (1) Net (2) Producing Wells Gas 289 31.42 Oil 29 2.68 Total Producing Wells ​ 318 ​ 34.10 Non-Producing Wells ​ 44 ​ 3.37 Total Wells ​ 362 ​ 37.47 ​ Acreage As of December 31, 2023, our leasehold inventory consisted of the following acreage amounts, rounded to the nearest acre: ​ ​ ​ ​ ​ ​ Gross (1) Net (2) (3) Developed Acres Pennsylvania 11,270 4,807 Texas 800 200 Oklahoma 5,113 991 ​ 17,183 5,998 Undeveloped Acres Pennsylvania 335 335 Texas 11,573 2,893 Oklahoma 55,593 6,237 ​ 67,501 9,465 Total Acres Pennsylvania 11,605 5,142 Texas 12,373 3,093 Oklahoma 60,706 7,228 Total acres 84,684 15,463 ​ 6 ​ ​ (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, 2023 and 2022. 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 14 “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, 2023 and 2022, respectively, follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ 2023 2022 Production Volumes ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 7,906 ​ ​ 9,026 Total (Mmcfe) ​ ​ 7,906 ​ ​ 9,026 Permian Basin ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 80 ​ ​ - Natural gas liquids (MBOE) ​ ​ 18 ​ ​ - Oil & other liquids (MBbl) ​ ​ 44 ​ ​ - Total (Mmcfe) ​ ​ 454 ​ ​ - Oklahoma ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 354 ​ ​ 477 Natural gas liquids (MBOE) ​ ​ 21 ​ ​ 44 Oil & other liquids (MBbl) ​ ​ 21 ​ ​ 32 Total (Mmcfe) ​ ​ 605 ​ ​ 933 Company Total ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 8,340 ​ ​ 9,503 Natural gas liquids (MBOE) ​ ​ 39 ​ ​ 44 Oil & other liquids (MBbl) ​ ​ 65 ​ ​ 32 Total (Mmcfe) ​ ​ 8,965 ​ ​ 9,959 ​ 7 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ 2023 2022 Revenues ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 13,733,052 ​ $ 53,759,354 Avg. Price ($/Mcf) ​ $ 1.74 ​ $ 5.96 Gathering system revenue (net of elimination) ​ $ 9,790,531 ​ $ 8,085,512 Total PA Revenues ​ $ 23,523,583 ​ $ 61,844,866 Permian Basin ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 117,112 ​ $ — Avg. Price ($/Mcf) ​ $ 1.47 ​ $ — Natural gas liquids revenue ​ $ 353,612 ​ $ — Avg. Price ($/Bbl) ​ $ 19.78 ​ $ — Oil and condensate revenue ​ $ 3,501,098 ​ $ — Avg. Price ($/Bbl) ​ $ 78.71 ​ $ — Total Permian Basin Revenues ​ $ 3,971,822 ​ $ — Oklahoma ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 1,014,050 ​ $ 3,189,380 Avg. Price ($/Mcf) ​ $ 2.87 ​ $ 6.68 Natural gas liquids revenue ​ $ 630,806 ​ $ 1,733,129 Avg. Price ($/Bbl) ​ $ 29.96 ​ $ 39.31 Oil and condensate revenue ​ $ 1,589,491 ​ $ 3,195,334 Avg. Price ($/Bbl) ​ $ 76.37 ​ $ 99.24 Total OK Revenues ​ $ 3,234,347 ​ $ 8,117,843 Total Company Revenues ​ $ 30,729,752 ​ $ 69,962,709 ​ Gathering System Operations Epsilon Energy USA is the 100% owner of Epsilon Midstream, which owns a 35% undivided interest in 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, consisting of Epsilon Energy USA, 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. During 2023, the gathering rate of the Auburn GGS was determined by a cost of service model whereby the Anchor Shippers 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 January 2027, the Auburn GGS will transition to a fixed gathering rate. Revenues from the Auburn GGS are earned primarily from the Anchor Shippers. Revenues are also earned from 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. The relative mix of Anchor Shipper gas and third-party gas is critical to the revenue and earnings of the Auburn GGS because the third-party gathering rate is only 25% of the Anchor Shipper rate. Third-party shippers must pay the gathering rate of the originating gathering system plus 25% of the Auburn GGS gathering rate. The purpose of the reduced rate is to attract additional volumes that require delivery to Tennessee Gas Pipeline when there is spare capacity at the Auburn compression facility, or the “Auburn CF”. Throughput at the Auburn CF has declined from 100.1 Bcf in 2018 to 66.2 Bcf in 2023, a decrease of 34%. However, Anchor Shipper gas as a percentage of total throughput has increased from 57% in 2018 to 74% in 2023. As a result of this shift toward a higher percentage of Anchor Shipper gas, as well as higher gathering rates charged, revenues for the gathering system have only declined 2% from 2018 to 2023. 8 ​ ​ 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. At inception, the capacity of the Auburn CF was approximately 330,000 Mcf per day at a design suction pressure of 800 psig. The design suction pressure was subsequently reduced to 550 psig in June 2020 at the request of the Anchor Shippers. This request served to minimize throughput decline during a period of low pricing in which the drilling of new wells was undesirable. Operating at the lower design suction pressure also has the benefit of reducing hydrate occurrences in the system which can pose an operational hazard. The current system capacity of the Auburn CF at this lower design pressure is approximately 220,000 Mcf per day. The facility capacity could be increased again, if required, by either adding compression units or increasing the design suction pressure. 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. During the years ended December 31, 2023 and 2022, the Auburn GGS delivered 66.2 Bcf and 66.3 Bcf respectively, of natural gas, or 181 and 182 MMcf per day. Gathering system revenues derived from Epsilon’s production, which have been eliminated from total gathering system revenues (“elimination entry”), amounted to $1.4 million and $1.5 million, respectively, for the years ended December 31, 2023 and 2022. Proved Reserves Per our reserve report prepared by independent petroleum consultants, DeGolyer and MacNaughton, our estimated proved reserves as of December 31, 2023, are summarized in the table below. See Risk Factors for information relating to the uncertainties surrounding these reserve categories. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural Gas ​ Natural Gas ​ Oil and Other ​ Total ​ MMcf Liquids MBbl Liquids MBbl MMcfe Proved developed reserves ​ 47,555 ​ 249 ​ 272 50,681 Proved undeveloped reserves ​ 18,361 ​ 134 ​ 69 19,581 Total Proved Reserves at December 31, 2023 ​ 65,916 ​ 383 ​ 341 70,262 ​ ​ ​ ​ ​ ​ ​ ​ Changes in Total Proved Undeveloped Reserves Proved undeveloped reserves at December 31, 2022 ​ 11,074 ​ 293 ​ 104 13,459 Revisions of previous estimates ​ 7,549 ​ (132) ​ (25) ​ 6,602 Transfers to proved developed ​ (262) ​ (27) ​ (10) (480) Proved undeveloped reserves at December 31, 2023 18,361 134 69 19,581 ​ Revisions to previous estimates for total proved undeveloped reserves for 2023 include additions of 14,867 MMcfe related to changes to the previously adopted development plan and reductions of 8,265 MMcfe related to commodity pricing. Transfers to proved developed relates to the development of one well in Oklahoma. We did not engage in any exploration capital spending in 2023 or 2022. Our development capital spending to convert proved undeveloped reserves to proved developed reserves for the periods indicated is as follows: ● In 2023 in Pennsylvania, we drilled 7 gross (0.74 net) wells and completed 2 gross (0.02 net) wells. (Net development capital $2.5 million). The two wells turned online in January 2023. ● In 2022 in Pennsylvania, we drilled 5 gross (0.05 net) wells and completed 4 gross (0.21 net) wells. (Net development capital $2.5 million). Reserves of 5.4 Bcf for the 1 well with proved undeveloped reserves were reclassified as proved developed producing as this well was turned online in August 2022. Additionally, 2 gross (0.02 net) wells were drilled in 2022, but not completed (development capital $0.1 million). They were completed and turned online in January 2023. ● In 2023 in Oklahoma, we completed 1 gross (0.11 net) well. (Net development capital $0.7 million). The 9 ​ ​ well turned online in May 2023. ● In 2022 in Oklahoma, we drilled 2 gross (0.26 net) wells and completed 3 gross (0.7 net) wells. (Net development capital $5.4 million). Reserves of 2.9 Bcfe for the 3 wells were reclassified as proved developed producing as these wells were turned online at various times beginning in March 2022 and going through October 2022. One gross (0.11 net) well was drilled in 2022, but not completed. It was completed in May 2023. 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 Operating 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 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 Operating Officer on a semi-annual basis. Our Chief Operating Officer holds a Bachelor of Science degree in Petroleum Engineering and received a Master’s Degree of Business Administration. He has over 30 years of experience in upstream exploration and production, and has managed all phases of drilling, completions, production and field operations. The reserve information in this report is based on estimates prepared by DeGolyer and MacNaughton, our independent petroleum consultants. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas). The person responsible for preparing the reserve report, Dilhan Ilk, is a Registered Professional Engineer (No.139334) in the State of Texas and a Senior Vice President of the firm. Mr. Ilk graduated from Texas A&M University with a Doctor in Philosophy degree in Petroleum Engineering, is a member of the Society of Petroleum Engineers, and has in excess of 13 years of experience in oil and gas reservoir studies and reserves evaluations. Marketing and Major Customers Natural gas marketing is 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 locations. 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 CF. 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, and submission of invoices. 10 ​ ​ For the year ended December 31, 2023, we sold natural gas through ARM to 33 unique customers. Direct Energy Business Marketing, LLC and EQT Energy, LLC each accounted for 10% or more of our total revenue. For the year ended December 31, 2022, we sold natural gas through ARM to 26 unique customers. Direct Energy Business Marketing, LLC and SWN Energy Services Company, LLC each accounted for 10% or more of our total revenue. Geographic Locations of Operations Approximately 77% and 88% of our revenue during fiscal years 2023 and 2022, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania. As a result of prolonged weak pricing in Zone 4 of the Tennessee Gas Pipeline and, therefore, a reduced pace of development, Epsilon’s management is striving to allocate capital to additional upstream opportunities outside of the Marcellus Shale. More specifically, the Company has allocated capital to the Permian Basin through its investments in New Mexico and Texas. Epsilon’s management expects to continue to seek opportunities outside of the Marcellus Shale in order to provide the Company the flexibility to respond to market conditions by allocating capital across multiple basins and commodities. As a result of the 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 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. Our Status as an Emerging Growth Company We are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012, or 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 (provided that this exemption will continue for such time as we are a “non-accelerated filer”); ● 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 not later than December 31, 2024. Employees As of December 31, 2023, we had ten full-time employees (including executive officers) in Houston, Texas. None 11 ​ ​ 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. 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 (“Middle District”). Epsilon claimed that Chesapeake had breached a settlement agreement and several operating agreements (“JOAs”) to which Epsilon and Chesapeake are parties. Epsilon asserted that Chesapeake had 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 on a narrow issue 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, but the court denied the motion for reconsideration on January 18, 2022. Epsilon filed a notice of appeal on February 15, 2022 challenging the District Court's rulings in the case. Following the Third Circuit's ruling to remand the case back to District court, Epsilon sought and was granted a dismissal of the case without prejudice in September 2023. 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 12 ​ ​ 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, the 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 13 ​ ​ 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 19, 2024 was $5.01 per share. Shareholders. We had approximately 975 shareholders of record as of March 1, 2024. Dividends. Epsilon made aggregate quarterly distributions of $5.6 million ($0.25 per share) during the year ended December 31, 2023. The dividend is well supported and the Company intends to maintain it going forward. 14 ​ ​ Securities Authorized for Issuance under Equity Incentive Plans. The following tables set 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: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Number of Shares to be ​ ​ Weighted Average ​ ​ ​ ​ Issued Upon Exercise or ​ ​ Exercise or Vesting Price ​ Number of Shares Remaining ​ ​ Vesting of Outstanding ​ ​ of Outstanding Options ​ Available for Future Issuance Plan Category ​ Options or Shares ​ ​ or Shares ​ Under Equity Compensation Plans Equity share options under Amended and Restated 2017 Stock Option Plan 57,500 $ 5.03 — Common shares under 2020 Equity Incentive Plan 491,536 ​ $ 5.59 957,489 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of ​ As of ​ ​ December 31, 2023 ​ December 31, 2022 ​ ​ ​ Weighted ​ Weighted ​ ​ Number of ​ Average ​ Number of ​ Average ​ ​ Options ​ Exercise ​ Options ​ Exercise ​ Outstanding Price Outstanding Price Balance at beginning of period 70,000 ​ $ 5.03 218,750 ​ $ 5.28 Exercised (12,500) ​ ​ 5.03 (138,750) ​ 5.38 Expired/Forfeited — ​ ​ — (10,000) ​ 5.51 Balance at period-end 57,500 ​ $ 5.03 70,000 ​ $ 5.03 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Exercisable at period-end 57,500 ​ $ 5.03 70,000 ​ $ 5.03 ​ For the years ended December 31, 2023 and 2022, we had no warrants or other common share-related rights outstanding. At December 31, 2023, under the 2020 Equity Incentive Plan (the “2020 Plan”) (See Note 7, “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 1,042,511 common shares granted under the 2020 Plan. No more shares are authorized to be issued under our predecessor 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: 15 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of ​ As of ​ ​ December 31, 2023 ​ December 31, 2022 ​ ​ ​ Weighted ​ Weighted ​ ​ Number of ​ Average ​ Number of ​ Average ​ ​ Shares ​ Grant Date ​ Shares ​ Grant Date ​ Outstanding Market Price Outstanding Market Price Balance non-vested Restricted Stock at beginning of period 298,210 ​ $ 6.00 166,002 ​ $ 3.96 Granted 358,546 ​ ​ 5.42 ​ 289,231 ​ ​ 6.28 Vested (165,220) ​ ​ 5.95 (157,023) ​ 4.34 Forfeited — ​ ​ — — ​ — Balance non-vested Restricted Stock at end of period ​ 491,536 ​ $ 5.59 298,210 ​ $ 6.00 ​ 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 ​ As of ​ ​ December 31, 2023 ​ December 31, 2022 ​ ​ ​ Weighted ​ Weighted ​ ​ Number of ​ Average ​ Number of ​ Average ​ ​ Shares ​ Grant Date ​ Shares ​ Grant Date ​ Outstanding Market Price Outstanding Market Price Balance non-vested Performance Shares at beginning of period 15,833 ​ $ 3.71 151,500 ​ $ 3.84 Granted — ​ ​ — ​ — ​ ​ — Vested (15,833) ​ ​ 3.71 (135,667) ​ 3.48 Balance non-vested Performance Shares at end of period ​ — ​ $ — 15,833 ​ $ 3.71 ​ ​ Recent Developments On January 30, 2024, the Company repurchased 248,700 shares at $4.82 per share (excluding commissions) under the existing share repurchase plan. ​ ​ ​