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What changed in Epsilon Energy Ltd.'s 10-K — 2022 vs 2023

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Paragraph-level year-over-year comparison of Epsilon Energy Ltd.'s 2022 and 2023 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2023 report.

+232 added−243 removedSource: 10-K (2024-03-21) vs 10-K (2023-03-24)

Top changes in Epsilon Energy Ltd.'s 2023 10-K

232 paragraphs added · 243 removed · 177 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

52 edited+11 added−13 removed53 unchanged
Biggest changeThese wells went into production at various times in August and September. ● At year end, the Company had 2 gross (0.02 net) wells waiting on completion. 5 ​ ​ ​ ​ Anadarko, NW STACK Trend—Oklahoma ● During the year ended December 31, 2022, Epsilon’s realized price for all Oklahoma production was $8.68 per Mcfe, a 37% increase from $6.34 for the year ended December 31, 2021. ● Total production for 2022 included natural gas, oil, and other liquids and was 0.93 Bcfe, as compared to 0.73 Bcfe during 2021. ● In 2022, the Company participated in the drilling of 2 gross (0.26 net) wells and completion of 3 gross (0.70 net) wells. ● At year end, the Company had 1 gross (0.11 net) well waiting on completion. ​ Properties As of December 31, 2022, Epsilon’s 75,954 gross (13,625 net) acres are all located in the United States and include 351 gross (36.33 net) wells. ​ ​ ​ ​ ​ ​ Gross (1) Net (2) Producing Wells Gas 283 31.18 Oil 27 2.18 Total Producing Wells ​ 310 ​ 33.36 Non-Producing Wells ​ 41 ​ 2.97 Total Wells ​ 351 ​ 36.33 ​ Acreage As of December 31, 2022, our leasehold inventory consisted of the following acreage amounts, rounded to the nearest acre: ​ ​ ​ ​ ​ ​ Gross (1) Net (2) (3) Developed Acres Pennsylvania 12,963 4,763 Oklahoma 7,063 2,290 ​ 20,026 7,053 Undeveloped Acres Pennsylvania 335 335 Oklahoma 55,593 6,237 ​ 55,928 6,572 Total Acres Pennsylvania 13,298 5,098 Oklahoma 62,656 8,527 Total acres 75,954 13,625 (1) “Gross” means one-hundred percent of the working interest ownership in each leasehold tract of land.
Biggest changeThe 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.
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.
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.
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.
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.
The Department of the Interior had released final regulations governing hydraulic fracturing on 14 ​ ​ ​ 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.
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.
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.
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.
Performance-based methodology primarily includes 10 ​ ​ ​ (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).
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).
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 customers.
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.
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 13 ​ ​ ​ an adverse effect on our financial condition and results of operations.
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.
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 8 ​ ​ ​ fixed gathering rate. Revenues from the Auburn GGS are earned primarily from the Anchor Shippers.
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.
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 11 years of experience in oil and gas reservoir studies and reserves evaluations.
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.
Proved Reserves Per our reserve report prepared by independent petroleum consultants, DeGolyer and MacNaughton, our estimated proved reserves as of December 31, 2022, are summarized in the table below.
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.
All of Epsilon’s Oklahoma undeveloped properties are deep rights acreage which is held by production of developed properties. ​ 6 ​ ​ ​ 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, 2022 and 2021.
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.
Substantially all the production from our Pennsylvania acreage (5,098 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.
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.
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 66.3 Bcf in 2022, a decrease of 34%.
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%.
The gathering rate of the Auburn GGS is 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.
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.
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, 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.
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.
Reserves of 2.9 Bcfe for the 3 wells were reclassified as proved developed producing as these wells were tuned 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.
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.
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 11 ​ ​ ​ 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.
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.
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, 2022, we sold natural gas through ARM to 26 unique customers.
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.
At December 31, 2022, 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 449,131 common shares granted under the 2020 Plan.
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.
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, 2023 was $5.11 per share. Shareholders. We had approximately 675 shareholders of record as of February 21, 2023. Dividends.
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 $5.01 per share. Shareholders. We had approximately 975 shareholders of record as of March 1, 2024. Dividends.
For information about our segment’s revenues, profits and losses, total assets, and total liabilities, see Note 12 Operating Segments in the Notes to Consolidated Financial Statements.
For information about our segment’s revenues, profits and losses, total assets, and total liabilities, see Note 14 “Operating Segments” in the Notes to Consolidated Financial Statements.
Price ($/Bbl) ​ $ 99.24 ​ $ 70.70 Total OK Revenues ​ $ 8,117,843 ​ $ 4,628,516 Total Company Revenues ​ $ 69,962,709 ​ $ 42,403,992 ​ 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%).
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%).
Geographic Locations of Operations Approximately 91% and 93% of our production during fiscal 2022 and 2021, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania.
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.
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.
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.
Our development capital spending to convert proved undeveloped reserves to proved developed reserves for the periods indicated is as follows: ● In 2022 in Pennsylvania, 5 gross (0.05 net) wells were drilled and 4 gross (0.21 net) completed. (Net development capital $2.5 million).
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).
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).
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.
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 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.
Business highlights of 2022 Operational Highlights Marcellus Shale—Pennsylvania ● During the year ended December 31, 2022, Epsilon’s realized natural gas price was $5.96 per Mcf, a 96% increase from $3.04 for the year ended December 31, 2021. ● Total year ended December 31, 2022 natural gas production was 9.0 Bcf, as compared to 9.8 Bcf during 2021. ● Gathered and delivered 66.3 Bcf gross (23.2 Bcf net to Epsilon’s interest) during the year, or 182 MMcf/d through the Auburn GGS. ● We participated in the drilling of 5 gross (0.05 net) and completion of 4 gross (0.21 net) Marcellus wells in 2022.
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.
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.
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.
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: 15 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of ​ As of ​ ​ December 31, 2022 ​ December 31, 2021 ​ ​ ​ Weighted ​ Weighted ​ ​ Number of ​ Average ​ Number of ​ Average ​ ​ Options ​ Exercise ​ Options ​ Exercise ​ Outstanding Price Outstanding Price Balance at beginning of period 218,750 ​ $ 5.28 245,000 ​ $ 5.27 Exercised (138,750) ​ ​ 5.38 (16,250) ​ 5.25 Expired/Forfeited (10,000) ​ ​ 5.51 (10,000) ​ 5.50 Balance at period-end 70,000 ​ $ 5.03 218,750 ​ $ 5.28 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Exercisable at period-end 70,000 ​ $ 5.03 218,750 ​ $ 5.28 ​ For the years ended December 31, 2022 and 2021, we had no warrants or other common share-related rights outstanding.
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.
Transfers to proved developed relates to the development 9 ​ ​ ​ of one well in Pennsylvania and three wells in Oklahoma. We have not engaged in any exploration capital spending in 2022 or 2021.
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.
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 ​ As of ​ ​ December 31, 2022 ​ December 31, 2021 ​ ​ ​ 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 166,002 ​ $ 3.96 290,070 ​ $ 3.41 Granted 289,231 ​ ​ 6.28 ​ 48,000 ​ ​ 5.04 Vested (157,023) ​ ​ 4.34 (137,668) ​ 3.98 Forfeited — ​ ​ — (34,400) ​ 3.68 Balance non-vested Restricted Stock at end of period ​ 298,210 ​ $ 6.00 166,002 ​ $ 3.96 ​ 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, 2022 ​ December 31, 2021 ​ ​ ​ 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 151,500 ​ $ 3.84 193,167 ​ $ 3.45 Granted — ​ ​ — ​ 20,834 ​ ​ 5.04 Vested (135,667) ​ ​ 3.48 (62,501) ​ 4.13 Balance non-vested Performance Shares at end of period ​ 15,833 ​ $ 3.71 151,500 ​ $ 3.84 ​ ​ ​ ​ 16 ​ ​ ​ Recent Developments None. ​ ​ ​
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. ​ ​ ​
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 October 24, 2007, the Company became a publicly traded entity trading on the Toronto Stock Exchange (“TSX”) in Canada.
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.
Additionally, 1 gross (0.18 net) well was drilled in 2021, but not completed (development capital $0.2 million). ● 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).
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).
Epsilon made aggregate quarterly distributions of $5.9 million ($0.25 per share) during the year ended December 31, 2022. Securities Authorized for Issuance under Equity Incentive Plans.
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.
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, 2022 and 2021, respectively, follows: 7 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ 2022 2021 Production Volumes ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 9,026 ​ ​ 9,830 Total (Mmcfe) ​ ​ 9,026 ​ ​ 9,830 ​ ​ ​ ​ ​ ​ ​ Oklahoma ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 477 ​ ​ 403 Natural gas liquids (MBbl) ​ ​ 44 ​ ​ 29 Oil & other liquids (MBbl) ​ ​ 32 ​ ​ 25 Total (Mmcfe) ​ ​ 935 ​ ​ 727 ​ ​ ​ ​ ​ ​ ​ Company Total ​ ​ ​ ​ ​ ​ Natural gas (MMcf) ​ ​ 9,503 ​ ​ 10,233 Natural gas liquids (MBbl) ​ ​ 44 ​ ​ 29 Oil & other liquids (MBbl) ​ ​ 32 ​ ​ 25 Total (Mmcfe) ​ ​ 9,961 ​ ​ 10,557 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ ​ 2022 2021 Revenues ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 53,759,354 ​ $ 29,909,651 Avg.
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.
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.
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.
We own a 35% interest in the Auburn GGS which is operated by a subsidiary of Williams Partners, LP. In 2022, we paid $1.5 million to the Auburn GGS to gather and treat our 9.0 Bcf of natural gas production in Pennsylvania ($1.6 million was paid to the Auburn GGS to gather and treat our 9.8 Bcf in 2021).
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 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”).
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.
They were completed and turned online in January 2023. ● 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).
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).
During the years ended December 31, 2022 and 2021, the Auburn GGS delivered 66.3 Bcf and 63.2 Bcf respectively, of natural gas, or 182 and 173 MMcf per day. Revenues derived from Epsilon’s production which have been eliminated from gathering system revenues amounted to $1.5 million and $1.6 million, respectively, for the years ended December 31, 2022 and 2021.
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.
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, but the court denied the motion for reconsideration on January 18, 2022.
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.
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 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.
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.
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 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 Northeast Pennsylvania, as required under both the settlement agreement and JOAs.
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.
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 ​ 78,966 ​ 198 ​ 107 80,795 Proved undeveloped reserves ​ 11,074 ​ 293 ​ 104 13,459 Total Proved Reserves at December 31, 2022 ​ 90,040 ​ 491 ​ 211 94,254 ​ ​ ​ ​ ​ ​ ​ ​ Changes in Total Proved Undeveloped Reserves Proved undeveloped reserves at December 31, 2021 ​ 38,743 ​ 663 ​ 239 44,155 Revisions of previous estimates ​ (21,598) ​ (220) ​ (74) ​ (23,362) Extensions and discoveries ​ — ​ — ​ — ​ — Transfers to proved developed ​ (6,071) ​ (150) ​ (61) (7,334) Proved undeveloped reserves at December 31, 2022 11,074 293 104 13,459 ​ Revisions to previous estimates for total proved undeveloped reserves for 2022 include reductions of 23,505 MMcfe related to changes to the previously adopted development plan, additions of 226 MMcfe related to commodity pricing, and reductions of 83 MMcfe related to well performance.
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.
However, Anchor Shipper gas as a percentage of total throughput has increased from 57% in 2018 to 71% in 2022. As a result of this shift toward a higher percentage of Anchor Shipper gas, revenues and earnings for the gathering system have only declined 21% and 15%, respectively, from 2018 to 2022.
However, Anchor Shipper gas as a percentage of total throughput has increased from 57% in 2018 to 74% in 2023.
Price ($/Mcf) ​ $ 5.96 ​ $ 3.04 Gathering system revenue ​ $ 8,085,512 ​ $ 7,865,825 Total PA Revenues ​ $ 61,844,866 ​ $ 37,775,476 Oklahoma ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 3,189,380 ​ $ 1,798,534 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.
The Company has natural gas production in the Marcellus Shale in Pennsylvania and oil, natural gas liquids and natural gas production in the Anadarko Basin in Oklahoma.
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.
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.
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.
Price ($/Mcf) ​ $ 6.68 ​ $ 4.46 Natural liquids revenue ​ $ 1,733,129 ​ $ 1,053,486 Avg. Price ($/Bbl) ​ $ 39.31 ​ $ 35.98 Oil and condensate revenue ​ $ 3,195,334 ​ $ 1,776,496 Avg.
Price ($/Bbl) ​ $ 29.96 ​ $ 39.31 Oil and condensate revenue ​ $ 1,589,491 ​ $ 3,195,334 Avg.
Removed
At December 31, 2022, Epsilon’s total estimated net proved reserves were 90,040 million cubic feet of natural gas reserves, 491,226 barrels of NGL reserves, and 211,059 barrels of oil and other liquids. Epsilon holds leasehold rights to approximately 75,954 gross (13,625 net) acres.
Added
We own a 35% interest in the Auburn GGS which is operated by a subsidiary of Williams Partners, LP.
Removed
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.
Added
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.
Removed
Reserves of 4.6 Bcf for the 3 wells were reclassified as proved developed producing as these wells were turned online at various times beginning in January and going through October of 2021.
Added
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.
Removed
It is scheduled to be completed in April 2023. ● In 2021 in Oklahoma, we drilled 4 gross (0.75 net) wells and completed 2 gross (0.6 net) wells. (Net development capital $3.0 million). Reserves of 2.8 Bcfe were reclassified as proved developed producing.
Added
Price ($/Mcf) ​ $ 1.47 ​ $ — Natural gas liquids revenue ​ $ 353,612 ​ $ — Avg. Price ($/Bbl) ​ $ 19.78 ​ $ — Oil and condensate revenue ​ $ 3,501,098 ​ $ — Avg.
Removed
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.
Added
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.
Removed
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 $1.235 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 issuance of common equity securities under an effective Securities Act registration statement (December 31, 2019); ● 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 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.
Added
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.
Removed
Employees As of December 31, 2022, 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.
Added
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.
Removed
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 12 ​ ​ ​ Epsilon’s amendment. Chesapeake moved to dismiss the amended Complaint.
Added
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.
Removed
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 was set and briefing closed October 14, 2022. Oral argument was held in January 2023. A decision on the appeal is not expected until mid-2023.
Added
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.
Removed
Epsilon re-filed a complaint against Chesapeake in the Middle District on May 9, 2022.
Added
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.
Removed
Epsilon generally asserts similar claims as in the previous suit, pursuing declaratory judgment claims regarding Chesapeake’s obligation to Epsilon to cooperate with Epsilon’s efforts in the Auburn Development and regarding Chesapeake’s obstruction of Epsilon’s efforts with the Pennsylvania Department of Environmental Protection permitting process but not based on specific well proposals.
Added
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.
Removed
Chesapeake filed a motion to stay pending a decision on the Third Circuit appeal, which was granted. The matter is stayed pending a decision from the Third Circuit.
Removed
On February 24, 2022, the Board of Directors approved a quarterly cash dividend of $0.0625 per common share. 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.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

55 edited+14 added−7 removed116 unchanged
Biggest changeBecause 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. 25 ​ ​ ​ 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.
Biggest changeIf 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.
(Ohio corporation) may be a U.S. real property holding corporation (a “USRPHC”) for U.S. federal income tax purposes if it is determined, at any time, that the fair market value of its assets that consist of “United States real property interests,” as defined in the Internal Revenue Code, and applicable Treasury regulations, constitute at least 50% of the combined fair market value of our real estate interests and other business assets.
(Ohio corporation) may be a U.S. real property holding corporation (a “USRPHC”) for U.S. federal income tax purposes if it is determined, at any time, that the fair market value of its assets that consist of “United States real property interests,” as defined in the Internal Revenue Code, and applicable Treasury regulations, constitute at least 50% of the combined fair market value of our real property interests and other business assets.
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 20 ​ ​ ​ as anticipated.
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.
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, once we become subject to those requirements.
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 25 ​ ​ the Sarbanes-Oxley Act, once we become subject to those requirements.
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 27 ​ ​ ​ down or write off accounts receivable.
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.
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.
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. 26 ​ ​ We compete with other operators in our gas gathering energy businesses.
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.
Additionally, members of the investment community may screen companies such as ours for sustainability performance before investing in our shares. 23 ​ ​ 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.
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 Shale, natural gas is significantly discounted to Henry Hub and the size of the differential can be volatile.
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 Shale, natural gas is significantly discounted to Henry Hub pricing and the size of the differential can be volatile.
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 24 ​ ​ ​ 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.
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.
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.
Several of our assets that 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.
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.
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, 16 ​ ​ cash flows, results of operations, liquidity or ability to finance planned capital expenditures.
Although the Anchor Shippers have dedicated their reserves to the Auburn GGS, they are under no obligation to develop the reserves. 26 ​ ​ ​ Because of the large supply of gas, and limited availability of transportation out of the Marcellus Shale area, our gas is subject to a price differential.
Although the Anchor Shippers have dedicated their reserves to the Auburn GGS, they are under no obligation to develop the reserves. Because of the large supply of gas, and limited availability of transportation out of the Marcellus Shale area, our gas is subject to a price differential.
While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production 17 ​ ​ ​ 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.
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.
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 of our board of directors.
Certain of our directors 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 of our board of directors.
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.
Also, prices for 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.
Distributions made out of earnings and profits are not expected to be subject to the FIRPTA tax but would be subject to U.S. withholding tax. Our operations are currently geographically concentrated and therefore subject to regional economic, regulatory and capacity risks.
Distributions made out of earnings and profits are not expected to be subject to the FIRPTA tax but would be subject to U.S. withholding tax. 20 ​ ​ Our operations are currently geographically concentrated and therefore subject to regional economic, regulatory and capacity risks.
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.
Hydraulic fracturing, which involves the injection of water, sand and chemicals under pressure into deep rock formations to stimulate oil or natural gas production, is often used in the completion of unconventional oil and natural gas wells.
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.
If the oil and natural gas industry continues to experience low prices, we may, among other things, be unable to meet all our financial obligations or make planned expenditures.
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.
In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom 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.
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.
There 22 ​ ​ 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.
During 2022 and 2021, 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.
During 2023 and 2022, 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.
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.
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 makes it extremely difficult to predict future oil and natural gas price movements.
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.
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 effect 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.
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.
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 therefrom and prepared by different engineers, or by the same engineers at different times, may vary.
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.
There are numerous uncertainties inherent in estimating quantities of oil and natural gas reserves and cash flows to be derived therefrom, including many factors beyond our control. The reserve and associated cash flow information set forth herein represents estimates only.
Although gross throughput at the Auburn CF has declined from 2018-2022, the share of Anchor Shipper gas has increased. The gathering rate on the Auburn GGS is subject to a cost-of-service model which could result in a non-competitive gathering rate and reduced throughput.
Although gross throughput at the Auburn CF has declined from 2018-2023, the share of Anchor Shipper gas has increased. The gathering rate on the Auburn GGS is subject to a cost-of-service model which could result in a non-competitive gathering rate and reduced throughput.
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.
Actual production and revenues derived therefrom 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.
Despite our analysis, we may experience financial losses in our dealings with these and other parties with whom we enter into 23 ​ ​ ​ 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.
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 effect on our business, financial condition and results of operations.
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 shareholder approval (requiring a non-binding shareholder vote to approve golden parachute arrangements in connection with mergers and certain other business combinations, and advisory votes on executive compensation pursuant to the “say on frequency” and “say on pay” provisions under the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010; and ● include detailed compensation discussion and analysis in our filings under the Securities Exchange Act of 1934 (the “Exchange Act”) and instead may provide a reduced level of disclosure concerning executive compensation.
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 (provided that this exemption will continue to apply for so long as we are a “non-accelerated filer”); ● 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 shareholder approval (requiring a non-binding shareholder vote to approve golden parachute arrangements in connection with mergers and certain other business combinations, and advisory votes on executive compensation pursuant to the “say on frequency” and “say on pay” provisions under the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010; and ● include detailed compensation discussion and analysis in our filings under the Securities Exchange Act of 1934 (the “Exchange Act”) and instead may provide a reduced level of disclosure concerning executive compensation.
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.
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 our third-party operating partners and may delay exploration and development activities.
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.
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.
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.
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.
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. 19 ​ ​ ​ In addition, the restrictive covenants in our revolving credit facility require us to maintain specified financial ratios and satisfy other financial condition tests.
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.
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.
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.
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. 22 ​ ​ ​ We may be exposed to third-party credit risk, and defaults by third parties could adversely affect us.
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.
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.
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.
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 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 21 ​ ​ for management.
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. 18 ​ ​ ​ Risks Related to Stage of Development, Structure and Capital Resources 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.
Risks Related to Stage of Development, Structure and Capital Resources 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.
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.
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. 18 ​ ​ The borrowing base under our credit facility may be reduced in light of commodity price declines, which could limit us in the future.
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, 2022 and 2021, or the DeGolyer Reserve Report, used SEC guideline prices and cost estimates in calculating net cash flows from oil and natural gas reserve quantities included within the report.
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. 17 ​ ​ 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, 2023 and 2022, or the DeGolyer Reserve Report, used SEC guideline prices and cost estimates in calculating net cash flows from oil and natural gas reserve quantities included within the report.
As an “emerging growth company” as defined in the JOBS Act, we are permitted to, and intend to, rely on exemptions from certain disclosure requirements.
As an “emerging growth company” as defined in the JOBS Act, we are permitted to, and intend to, rely on exemptions from certain disclosure requirements. We will cease being an emerging growth company not later than December 31, 2024.
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 train and manage our employee base. We must maintain effective disclosure controls and procedures.
Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to train and manage our employee base. We must maintain effective disclosure controls and procedures.
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.
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.
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. 21 ​ ​ ​ We depend on the successful acquisition, exploration and development of oil and natural gas properties to develop any future reserves and grow production and revenue in the future, and assessments of our assets may be subject to uncertainty.
We depend on 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.
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.
We may make future acquisitions or enter into financing or other transactions involving the issuance of securities, which may be dilutive to existing security holders. 19 ​ ​ Competition in the natural gas and oil industry is intense, which may hinder our ability, and the ability of our third-party operating partners, to contract for drilling equipment, and we may not be able to control the scheduling and activities of contracted drilling equipment.
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.
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.
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.
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.
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.
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 third-party natural gas reserves flowing into our systems and compression facilities.
As a result of this election, our financial statements may not be comparable to public companies that comply with new or revised accounting standards.
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.
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.
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.
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.
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.
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.
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.
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 expand our natural gas gathering business primarily depends on the level of drilling and production by the Anchor Shippers.
A slowing pace of or complete halt to the development of Anchor Shipper reserves will impact our financial results, cash flows, and access to capital. 27 ​ ​ 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.
Approximately 91% and 93% of our production during fiscal 2022 and 2021, respectively was derived from our properties in the Marcellus Shale region of Pennsylvania.
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.
This volatility and discount has adversely impacted reserve development in the past, and could do so again in the future. A slowing pace relative to the cost of service model forecast or complete halt to the development of Anchor Shipper reserves will impact our financial results, cash flows, and access to capital.
This volatility and discount has adversely impacted reserve development in the past, and could do so again in the future.
Removed
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.
Added
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.
Removed
The borrowing base under our credit facility may be reduced in light of commodity price declines, which could limit us in the future.
Added
Future equity transactions could result in dilution to existing stockholders.
Removed
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.
Added
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.
Removed
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 Shale. Delays in business operations may reduce cash flows and subject us to credit risks.
Added
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.
Removed
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 $1.235 billion or more; ● the last day of the fiscal year following the fifth anniversary of the date of our first issuance of common equity securities under an effective Securities Act registration statement (December 31, 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.
Added
Delays in business operations may reduce cash flows and subject us to credit risks.
Removed
We do not obtain independent evaluations of the third-party natural gas reserves flowing into our systems and compression facilities. Demand for our services is dependent on the demand for gas in the markets we serve.
Added
Risks Related to Cybersecurity We may be subject to interruptions or failures in our information technology systems. We rely on sophisticated information technology systems and infrastructure to support our business, including process control technology.
Removed
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 28 ​ ​ ​ to be appropriate.
Added
Any of these systems are susceptible to outages due to fire, floods, power loss, telecommunications failures, usage errors by employees, computer viruses, cyberattacks or other security breaches or similar events. The failure of any of our information technology systems may cause disruptions in our operations, which could adversely affect our revenue and profitability. We are subject to cybersecurity risks.
Added
A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
Added
We depend on information technology systems that we manage, and others that are managed by third-party service and equipment providers, to conduct our day-to-day operations, including critical systems, and these systems are subject to risks associated with cyber incidents or attacks, especially originating from countries such as China, Russia, Iran, and North Korea as broadly reported in the media.
Added
Our technology systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches.
Added
A cyber incident could negatively impact the Company in a number of ways, including but not limited to: (i) remediation costs, such as liability for stolen assets or information and repairs of system damage; (ii) increased cybersecurity protection costs, which may include the costs of making organizational changes, deploying additional personnel and protection technologies, training employees, and engaging third-party experts and consultants; (iii) lost revenue resulting from downtime, operational disruptions, the unauthorized use of proprietary information or the failure to retain or attract customers following an attack; (iv) litigation and legal risks, including regulatory actions by state and federal governmental authorities and non-U.S. authorities and related investigation costs; (v) increased insurance premiums; (vi) reputational 24 ​ ​ damage that adversely affects customer or investor confidence; (vii) the loss, theft, corruption or unauthorized release of intellectual property, proprietary information, customer and vendor data or other critical data and (viii) damage to the Company’s competitiveness, stock price, and long-term stockholder value.
Added
Certain cyber incidents, such as surveillance, may remain undetected for an extended period of time. As the sophistication of cyber incidents continues to evolve, we will likely be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.
Added
Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.
Added
Our ability to expand our natural gas gathering business primarily depends on the level of drilling and production by the Anchor Shippers. Production from existing wells with access to our gathering systems will naturally decline over time.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

3 edited+1 added−3 removed1 unchanged
Biggest changeEpsilon 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 both the motion to dismiss and motion for reconsideration decisions. Chesapeake filed a cross-appeal on March 1, 2022.
Biggest changeEpsilon 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.
ITEM 3. 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 claims that Chesapeake has breached a settlement agreement and several operating agreements (“JOAs”) to which Epsilon and Chesapeake are parties.
ITEM 3. 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 asserts that Chesapeake has failed to cooperate with Epsilon’s efforts to develop resources in the Auburn Development, located in Northeast 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.
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.
Removed
A briefing schedule was set and briefing closed October 14, 2022. Oral argument was held in January 2023. A decision on the appeal is not expected until mid-2023. Epsilon re-filed a complaint against Chesapeake in the Middle District on May 9, 2022.
Added
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. 29 ​ ​
Removed
Epsilon generally asserts similar claims as in the previous suit, pursuing declaratory judgment claims regarding Chesapeake’s obligation to Epsilon to cooperate with Epsilon’s efforts in the Auburn Development and regarding Chesapeake’s obstruction of Epsilon’s efforts with the Pennsylvania Department of Environmental Protection permitting process but not based on specific well proposals.
Removed
Chesapeake filed a motion to stay pending a decision on the Third Circuit appeal, which was granted. The matter is stayed pending a decision from the Third Circuit.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

3 edited+6 added−1 removed2 unchanged
Biggest changeThe awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act. Commencing on March 8, 2022, the Company entered into a share repurchase program conducted in accordance with Rule 10b-18 promulgated under the Exchange Act.
Biggest changeThe awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act.
Business .’’ On April 6, 2022 and December 31, 2022, our Board made grants to our directors and employees, entitling them to receive an aggregate of 89,925 common shares and 43,096 common shares, respectively, which shall not be issued to the award recipients unless certain time or performance based vesting criteria, as applicable, are met, in which case the vesting will occur in three equal parts on the succeeding periods ending on December 31.
On December 31, 2023, our Board made grants to our management and employees entitling them to receive an aggregate of 213,982 common shares which shall not be issued to the award recipients unless certain time or performance based vesting criteria, as applicable, are met, in which case the vesting will occur in three equal parts on the succeeding periods ending on December 31.
On July 1, 2022, our Board made grants to a director of 18,000 common shares, and to our new CEO and CFO, entitling them to receive an aggregate of 138,210 common shares which shall not be issued to the award recipients unless certain time or performance based vesting criteria, as applicable, are met, in which case the vesting will occur in equal parts over a three-year and four-year period, respectively.
Business .’’ On July 1, 2023, our Board made grants to our CEO and CFO, entitling them to receive an aggregate of 79,589 common shares which shall not be issued to the award recipients unless certain time or performance based vesting criteria, as applicable, are met, in which case the vesting will occur in three equal parts on the succeeding periods ending on July 1.
Removed
The Company was authorized to repurchase up to 1,183,410 of its outstanding common shares, representing 5% of the outstanding common shares of the Company as of February 24, 2022. The program ended on March 7, 2023. The Company funded the purchases out of available cash and did not incur debt to fund the share repurchase program.
Added
On July 3, 2023, our Board made grants to our directors entitling them to receive an aggregate of 64,975 common shares which shall not be issued to the award recipients unless certain time or performance based vesting criteria, as applicable, are met, in which case the vesting will occur in three equal parts on the succeeding periods ending on December 31.
Added
The awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act.
Added
The awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act.
Added
On March 9, 2023, the Board of Directors authorized a new share repurchase program of up to 2,292,644 common shares, representing 10% of the outstanding common shares of Epsilon at that time, for an aggregate purchase price of not more than US $15.0 million.
Added
The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act. The program commenced on March 27, 2023 and will end on March 26, 2024. The Company funded the purchases out of available cash and did not incur debt to fund the share repurchase program.
Added
The following table provides information with respect to the common share purchases made by the Company during the three months ended December 31, 2023. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total number of ​ Maximum number ​ ​ ​ ​ ​ ​ shares purchased ​ of shares that ​ ​ ​ ​ ​ ​ as part of ​ may yet be ​ ​ Total number ​ Average price ​ publicly ​ purchased under ​ ​ of shares ​ paid per ​ announced plans ​ the plans or Period purchased ​ share or programs programs December 2023 ​ 70,874 ​ $ 5.06 ​ ​ ​ ​ ​ Total ​ 70,874 ​ $ 5.06 ​ 968,149 ​ ​ 1,324,495 ​ ​ ​

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

63 edited+23 added−39 removed19 unchanged
Biggest changeUnder the terms of the agreement, the Company must maintain the following covenants: ● I nterest coverage ratio greater than 3 (income adjusted for interest, taxes and non-cash amounts / cash interest expense) ● Current ratio greater than 1 (current assets / current liabilities) ● Leverage ratio less than 3.5 (total debt / income adjusted for interest, taxes and non-cash amounts) We were in compliance with the financial covenants of the agreement as of December 31, 2022. ​ Repurchase Transactions Commencing on March 8, 2022, we implemented a plan to repurchase our issued and outstanding common shares and to return capital to our shareholders.
Biggest changeUnder the terms of the facility, the Company must adhere to the following financial covenants: ● Current ratio of 1.0 to 1.0 (current assets / current liabilities) 37 ​ ​ ● Leverage ratio of less than 2.5 to 1.0 (total debt / income adjusted for interest, taxes and non-cash amounts) Additionally, if the leverage ratio is greater than 1.0 to 1.0, or the borrowing base utilization is greater than 50%, the Company is required to hedge 50% of the anticipated production from PDP reserves for a rolling 24 month period.
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.
Management routinely discusses the development, selection and disclosure of each of the critical accounting estimates. 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.
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.
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 estimates cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown.
We consider all positive and negative evidence, including historical operating results, the existence of cumulative losses, estimates of future operating income, and the reversal of existing taxable temporary differences in assessing the need for a valuation allowance. Income tax filings are subject to audits and 40 ​ ​ ​ re-assessments.
We consider all positive and negative evidence, including historical operating results, the existence of cumulative losses, estimates of future operating income, and the reversal of existing taxable temporary differences in assessing the need for a valuation allowance. Income tax filings are subject to audits and re-assessments.
During the year ended December 31, 2022, $12.0 million of cash used for financing activity was related to the repurchase of our common shares and the payment of quarterly dividends. This was offset by $0.7 million of proceeds from the exercise of stock options.
During the year ended December 31, 2022, $12.0 million of cash used for financing activity was primarily related to the repurchase of our common shares and the payment of quarterly dividends. This was offset by $0.7 million of proceeds from the exercise of stock options.
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.
Significant 39 ​ ​ 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 natural gas and oil properties on an area basis.
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.
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.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The following discussion is intended to assist in the understanding of trends and significant changes in or results of operations and the financial condition of Epsilon Energy Ltd. and its subsidiaries for the periods presented.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The following discussion is intended to assist in the understanding of trends and significant changes in our 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, 2022 and 2021 and for the years then ended together with accompanying notes. Overview Epsilon Energy Ltd.
This section should be read in conjunction with the audited consolidated financial statements as of December 31, 2023 and 2022 and for the years then ended together with accompanying notes. 31 ​ ​ Overview Epsilon Energy Ltd.
On March 9, 2023, the Board of Directors authorized a new share repurchase program of up to 2,292,644 common shares, representing 10% of the outstanding common shares of Epsilon, for an aggregate purchase price of not more than US $15.0 million.
Repurchase Transactions On March 9, 2023, the Board of Directors authorized a new share repurchase program of up to 2,292,644 common shares, representing 10% of our outstanding common shares, for an aggregate purchase price of not more than US $15.0 million.
This increase was primarily due to the utilization of additional financial instruments with higher prevailing interest rates in 2022.
This increase was primarily due to the utilization of additional financial instruments with higher prevailing interest rates in 2023.
We have natural gas production in Pennsylvania, and natural gas, oil and other liquid production from our operated and non-operated wells in Oklahoma. We are committed to disciplined capital allocation which could include shareholder returns in the form of dividends and/or share buybacks.
We have natural gas production from our non-operated wells in Pennsylvania, and natural gas, oil and other liquids production from our non-operated wells in the Permian Basin and Oklahoma. We are committed to disciplined capital allocation which could include shareholder returns in the form of dividends and/or share buybacks.
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. ​
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. ​ 40 ​ ​
Additionally, Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We have included Adjusted EBITDA as a supplemental disclosure because its management believes that EBITDA provides useful information regarding our ability to service debt and to fund capital expenditures.
GAAP or as a measure of profitability or liquidity. 36 ​ ​ Additionally, Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We have included Adjusted EBITDA as a supplemental disclosure because its management believes that EBITDA provides useful information regarding our ability to service debt and to fund capital expenditures.
General and Administrative (“G&A”) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2022 2021 General and administrative ​ $ 7,346,438 ​ $ 6,831,816 ​ 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.
General and Administrative (“G&A”) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 General and administrative ​ $ 7,311,496 ​ $ 7,346,438 ​ 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.
We seek to maintain a strong balance sheet and liquidity to allow us to opportunistically invest in both our existing project areas and potential new projects. 30 ​ ​ ​ To date, our investments have been focused on the Marcellus Shale unconventional reservoir in Pennsylvania (“PA”). Our PA assets are supported by our 35% ownership in the Auburn GGS.
We plan to maintain a strong balance sheet and liquidity position to allow us to opportunistically invest in both our existing project areas and potential new projects. Historically, our investments have been focused on our position in the prolific Marcellus unconventional reservoir in Pennsylvania (“PA”). Our PA assets are supported by our 35% ownership in the Auburn GGS.
We used cash on hand to fund these repurchases. During the year ended December 31, 2022, we repurchased 982,500 common shares of the maximum of 1,183,410 authorized for repurchase and spent $6,234,879 under the plan. The repurchased stock had an average price of $6.32 per share (excluding commissions) and was subsequently retired during the year ended December 31, 2022.
During the year ended December 31, 2022, we repurchased 982,500 common shares of the maximum of 1,183,410 authorized for repurchase and spent $6,234,879 under the plan. The repurchased stock had an average price of $6.32 per share (excluding commissions) and was subsequently retired during the year ended December 31, 2022.
Depletion, Depreciation, Amortization and Accretion (DD&A) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2022 2021 Depletion, depreciation, amortization and accretion ​ $ 6,438,511 ​ $ 6,627,016 ​ Natural gas and oil and gathering system assets are depleted and depreciated using the units of production method aggregating properties on a field basis.
Depletion, Depreciation, Amortization and Accretion (DD&A) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 Depletion, depreciation, amortization and accretion ​ $ 7,685,084 ​ $ 6,438,511 ​ Natural gas and oil and gathering system assets are depleted and depreciated using the units of production method aggregating properties on a field basis.
Summary of Critical Accounting 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.
As of December 31, 2023, our commitments for capital expenditures were nil. ​ Summary of Critical Accounting Estimates The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements and accompanying 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.
Gathering system operating costs consist primarily of rental payments for the natural gas fueled compression units and overhead fees due to the system’s operator. For the year ended December 31, 2022, gathering system operating costs decreased by $0.03 million, or 1.4% from the same period in 2021.
Gathering system operating costs consist primarily of rental payments for the natural gas fueled compression units and overhead fees due to the system’s operator. For the year ended December 31, 2023, gathering system operating costs increased by $0.2 million, or 7.5% from the same period in 2022.
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.
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.
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.
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. A reserve report is prepared as of December 31, each year.
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 $0.8 million, all of which we expect to incur in 2023.
At a given point in time, it is estimated that we have committed to capital expenditures equal to approximately one quarter of our capital 38 ​ ​ budget by means of giving the necessary authorizations to the asset operator to incur the expenditures in a future period.
Interest Expense ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2022 2021 Interest expense ​ $ 50,782 ​ $ 101,382 ​ Interest expense relates to the interest and commitment fees paid on the revolving line of credit. Interest expense decreased by $0.05 million, or 50%, during the year ended December 31, 2022 from 2021.
Interest Expense ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 Interest expense ​ $ 80,379 ​ $ 50,782 ​ Interest expense relates to the interest and commitment fees paid on the revolving line of credit. Interest expense increased by $0.03 million, or 58%, during the year ended December 31, 2023 from 2022.
If the expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach, which considers estimated discounted future cash flows.
If the expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach, which considers estimated discounted future cash flows. Asset Retirement Obligations (“ARO”) We recognize asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations.
Impairments The carrying value of unproved and proved oil and natural gas properties and gathering system assets are reviewed for impairment whenever events indicate that the carrying amounts for those assets may not be recoverable.
For related discussion, see the sections titled “Risk Factors” and “Supplemental Information to Consolidated Financial Statements.” Impairments The carrying value of unproved and proved oil and natural gas properties and gathering system assets are reviewed for impairment whenever events indicate that the carrying amounts for those assets may not be recoverable.
At December 31, 2022, Epsilon’s outstanding natural gas commodity swap contracts consisted of the following: 37 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average Price ($/MMbtu) ​ ​ ​ ​ ​ Volume ​ ​ ​ ​ Basis ​ Fair Value of Asset Derivative Type (MMbtu) Swaps Differential December 31, 2022 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NYMEX Henry Hub swap 1,070,000 ​ $ 5.21 ​ $ — $ 1,219,865 Tennessee Z4 basis swap 1,070,000 ​ $ — ​ $ (1.25) ​ 2,225 ​ 2,140,000 ​ ​ ​ ​ ​ ​ ​ $ 1,222,090 ​ Contractual Obligations We enter into commitments for capital expenditures in advance of the expenditures being made.
At December 31, 2023, Epsilon’s outstanding natural gas commodity swap contracts consisted of the following: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average ​ ​ ​ ​ ​ Volume ​ Price ($/MMbtu) ​ Fair Value of Asset Derivative Type (MMbtu) Swaps December 31, 2023 2024 ​ ​ ​ ​ ​ ​ ​ ​ NYMEX Henry Hub swap 1,905,000 ​ $ 3.25 $ 1,353,668 Tennessee Z4 basis swap 1,905,000 ​ $ (1.10) $ (253,413) ​ 3,810,000 ​ ​ ​ ​ $ 1,100,255 ​ Contractual Obligations We enter into commitments for capital expenditures in advance of the expenditures being made.
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.
Depreciation expense includes amounts pertaining to our office furniture and fixtures, leasehold improvements and 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.
At December 31, 2022, the Company had outstanding NYMEX HH swaps totaling 1.07 Bcf with a trade price of $5.212 and Tennessee Z4 basis swaps totaling 1.07 Bcf with a trade price of ($1.25) to hedge a portion of expected volumes for the contract period of April 2023 to October 2023.
For the year ended December 31, 2022, the Company paid net cash settlements of $1,225,837. 35 ​ ​ At December 31, 2022, the Company had outstanding NYMEX HH swaps totaling 1.07 Bcf with a strike price of $5.212 and Tennessee Z4 basis swaps totaling 1.07 Bcf with a strike price of ($1.25) to hedge a portion of expected volumes for the contract period of April 2023 to October 2023. ​ In September 2023, the Company added NYMEX HH swaps totaling 0.38 Bcf with a strike price of $3.315 and Tennessee Z4 basis swaps totaling 0.38 Bcf with a strike price of ($0.73) to hedge a portion of the expected volumes for the contract period of November 2023 to March 2024.
Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues amounted to $1.5 million and $1.6 million, respectively, for the years ended December 31, 2022 and 2021., 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, 2022 and 2021: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2022 2021 Lease operating costs ​ $ 7,128,631 ​ $ 6,303,055 Gathering system operating costs ​ ​ 2,287,763 ​ ​ 2,321,329 ​ ​ $ 9,416,394 ​ $ 8,624,384 ​ ​ ​ ​ ​ ​ ​ Upstream operating costs—Total $/Mcfe ​ ​ 0.72 ​ ​ 0.60 Gathering system operating costs $/Mcf ​ ​ 0.15 ​ ​ 0.30 ​ 32 ​ ​ ​ Operating costs include the effects of elimination entries to remove the gathering fees paid to Epsilon’s ownership in the gathering system.
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, 2023 and 2022: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 Lease operating costs (net of elimination) ​ $ 6,405,281 ​ $ 7,128,631 Gathering system operating costs ​ ​ 2,459,694 ​ ​ 2,287,763 ​ ​ $ 8,864,975 ​ $ 9,416,394 ​ ​ ​ ​ ​ ​ ​ Upstream operating costs—Total $/Mcfe ​ ​ 0.71 ​ ​ 0.72 Gathering system operating costs $/Mcf ​ ​ 0.15 ​ ​ 0.15 ​ Operating costs include the effects of elimination entries to remove the gathering fees paid to Epsilon’s ownership in the gathering system.
Our standardized measure of discounted future net cash flows as of December 31, 2022 and 2021 was $145.8 million and $77.7 million, respectively. This measure of discounted future net cash flows does not include any estimate for future cash flows generated by our gathering system assets.
This measure of discounted future net cash flows does not include any estimate for future cash flows generated by our gathering system assets.
An increase of $27.5 million was due to higher natural gas prices partially offset by a reduction of $2.3 million due to lower volumes being produced due to natural decline of the wells. Upstream natural gas liquids revenue for the year ended December 31, 2022 increased by $0.7 million, or 65% over 2021.
A decrease of $0.5 million was due to lower natural gas liquids prices and a reduction of $0.2 million was due to lower produced volumes. Upstream oil and condensate revenue for the year ended December 31, 2023 increased by $1.9 million, or 59% over 2022.
(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.
(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 areas of operations are the Marcellus Shale section of the Appalachian Basin in Pennsylvania, the Permian Basin in Texas and New Mexico, and the NW Anadarko Basin in Oklahoma.
Net gain (loss) on commodity contracts ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2022 2021 Gain (loss) on derivative contracts ​ $ 236,077 ​ $ (4,482,909) ​ During the years ended December 31, 2022 and 2021, we entered into NYMEX Henry Hub (“HH”) Natural Gas Futures swaps, Dominion basis swaps, and two-way costless collar derivative contracts for the purpose of hedging our physical natural gas sales revenue.
Net gain (loss) on commodity contracts ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 Gain on derivative contracts ​ $ 3,130,055 ​ $ 236,077 ​ During the year ended December 31, 2023, the Company had NYMEX Henry Hub (“HH”) Natural Gas Futures swaps and Tennessee Gas Pipeline Zone 4 basis swap derivative contracts for the purpose of hedging a portion of its physical natural gas sales revenue.
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.
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. 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.
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.
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.
Net Income Compared to Adjusted EBITDA ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2022 2021 Net income ​ $ 35,354,679 ​ $ 11,627,517 Add Back: ​ ​ ​ ​ ​ ​ Net interest expense ​ ​ (402,095) ​ ​ 62,517 Income tax expense ​ ​ 12,157,487 ​ ​ 4,440,508 Depreciation, depletion, amortization, and accretion ​ ​ 6,438,511 ​ ​ 6,627,016 Impairment expense ​ ​ — ​ ​ 153,058 Stock based compensation expense ​ ​ 1,021,026 ​ ​ 956,084 (Gain) loss on derivative contracts net of cash received or paid on settlement ​ ​ (1,461,914) ​ ​ 239,824 Foreign currency translation loss ​ ​ (845) ​ ​ 1,454 Adjusted EBITDA ​ $ 53,106,849 ​ $ 24,107,978 ​ We define 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.
This decrease was primarily due to a decrease in taxable income as a result of lower realized commodity prices. ​ Net Income Compared to Adjusted EBITDA ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 Net income ​ $ 6,945,153 ​ $ 35,354,679 Add Back: ​ ​ ​ ​ ​ ​ Interest (income) expense, net ​ ​ (1,592,862) ​ ​ (402,095) Income tax expense ​ ​ 3,200,447 ​ ​ 12,157,487 Depreciation, depletion, amortization, and accretion ​ ​ 7,685,084 ​ ​ 6,438,511 Stock based compensation expense ​ ​ 1,018,262 ​ ​ 1,021,026 Gain (loss) on sale of assets ​ ​ 1,449,871 ​ ​ (221,642) Loss (gain) on derivative contracts net of cash received or paid on settlement ​ ​ 121,835 ​ ​ (1,461,914) Foreign currency translation loss ​ ​ (278) ​ ​ (850) Adjusted EBITDA ​ $ 18,827,512 ​ $ 52,885,202 ​ We define 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 sale of assets, (7) gain or loss on derivative contracts net of cash received or paid on settlement, and (8) other income.
Consequently, material revisions (upward or downward) 38 ​ ​ ​ 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.
We cannot predict the types of reserve revisions that will be required in future periods.
Price ($/Mcf) ​ $ 6.68 ​ $ 4.46 Natural liquids revenue ​ $ 1,733,129 ​ $ 1,053,486 Volume (MBO) ​ 44.1 ​ 29.3 Avg. Price ($/Bbl) ​ $ 39.31 ​ $ 35.98 Oil and condensate revenue ​ $ 3,195,334 ​ $ 1,776,496 Volume (MBO) ​ 32.2 ​ 25.1 Avg.
Price ($/Mcf) ​ $ 2.87 ​ $ 6.68 Natural gas liquids revenue ​ $ 630,806 ​ $ 1,733,129 Volume (MBOE) ​ 21.1 ​ 44.1 Avg. Price ($/Bbl) ​ $ 29.96 ​ $ 39.31 Oil and condensate revenue ​ $ 1,589,491 ​ $ 3,195,334 Volume (MBbl) ​ 20.8 ​ 32.2 Avg.
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.
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, 2023, DD&A expense increased by $1.2 million, or 19%, compared to the same period in 2022.
Price ($/Bbl) ​ $ 99.24 ​ $ 70.70 Total OK Revenues ​ $ 8,117,843 ​ $ 4,628,516 Total Revenues ​ $ 69,962,709 ​ $ 42,403,992 ​ Upstream natural gas revenue for the year ended December 31, 2022 increased by $25.2 million, or 80%, over 2021.
Price ($/Bbl) ​ $ 76.37 ​ $ 99.24 Total OK Revenues ​ $ 3,234,347 ​ $ 8,117,843 Total Revenues ​ $ 30,729,752 ​ $ 69,962,709 ​ Upstream natural gas revenue for the year ended December 31, 2023 decreased by $42.1 million, or 74%, from 2022.
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. 39 ​ ​ ​ 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.
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.
For the year ended December 31, 2022, upstream operating costs increased by $0.8 million, or 13.1% from the same period in 2021. The increase was due to extraordinary plugging and abandonment costs related to atypical wellbore conditions in two older vintage wells in Pennsylvania, which is not representative of the other wells.
Operating costs in 2022 were higher due to higher produced volumes and extraordinary plugging and abandonment costs related to atypical wellbore conditions in two older vintage wells in Pennsylvania, which is not representative of the other wells.
Other Income (Expense) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2022 2021 Interest income and other income ​ $ 353,408 ​ $ 39,995 ​ During the year ended December 31, 2022, interest income increased by $0.4 million, or 877%, during the year ended December 31, 2022 from the same period in 2021.
Interest Income ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2023 2022 Interest income ​ $ 1,673,241 ​ $ 452,877 ​ During the year ended December 31, 2023, interest income increased by $1.2 million, or 269%, from the same period in 2022.
At December 31, 2022 our total estimated net proved reserves were 90,040 MMcf of natural gas reserves, 491,226 Bbls of NGL reserves, and 211,059 Bbls of oil and other liquids, and we held leasehold rights to approximately 75,954 gross (13,625 net) acres.
At December 31, 2023 our total estimated net proved reserves were 65,916 MMcf of natural gas reserves, 383,174 Bbls of NGL reserves, and 341,286 Bbls of oil and condensate, and we held leasehold rights to approximately 84,684 gross (15,463 net) acres.
This was a result of increased production from new wells in addition to higher NGL prices. Upstream oil and other liquids revenue for the year ended December 31, 2022 increased by $1.4 million, or 80% over 2021. This was a result of increased production from new wells in addition to higher oil prices.
An increase of $3.3 million was due to increased production from new wells in the Permian Basin offset by a reduction of $1.4 million due to lower oil prices. Gathering system revenue for the year ended December 31, 2023 increased by $1.7 million, or 21% over 2022.
As a non-operating working interest owner, we often do not have direct control or visibility over the pace of investment in our assets by the operator. We anticipate reevaluating these reserves once we have line of sight on development timing.
The primarily price-related decrease in our total proved developed reserves was partially offset by increases in proved undeveloped reserves in PA from wells currently in progress. As a non-operating working interest owner, we often do not have direct control or visibility over the pace of investment in our assets by the operator.
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.
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.
During the year ended December 31, 2022, DD&A expense was generally consistent compared to the same period in 2021, decreasing by $0.2 million, or 3%.
G&A expenses were generally consistent compared to the same period in 2022, decreasing by $0.03 million, or 0%.
The table above sets forth a reconciliation of net income to Adjusted EBITDA, which is the most directly comparable measure of financial performance calculated under U.S.
The table above sets forth a reconciliation of net income to Adjusted EBITDA, 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 years ended December 31, 2023 and 2022 was funds generated from operations.
The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act.
The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act. The program commenced on March 27, 2023, and will end on March 26, 2024, unless the maximum amount of common shares is purchased before then or Epsilon provides earlier notice of termination.
Revenues During the year ended December 31, 2022, revenues increased $27.6 million, or 65%, to $70.0 million from $42.4 million during the year ended December 31, 2021 due primarily to increased prices. 31 ​ ​ ​ Revenue and volume statistics for the years ended December 31, 2022 and 2021 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ 2022 2021 Revenues ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 53,759,354 ​ $ 29,909,651 Volume (MMcf) ​ 9,026 ​ 9,830 Avg.
Revenue and volume statistics for the years ended December 31, 2023 and 2022 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ 2023 2022 Revenues ​ ​ ​ ​ ​ ​ Pennsylvania ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 13,733,052 ​ $ 53,759,354 Volume (MMcf) ​ 7,906 ​ 9,026 Avg.
In 2023, we repurchased 190,700 common shares at an average price of $5.82 per share (excluding commissions) before the plan terminated on March 7, 2023. Commencing on January 1, 2021, we implemented a plan to repurchase our issued and outstanding common shares. The plan terminated on December 31, 2021. We used cash on hand to fund these repurchases.
In 2023, we repurchased and retired 190,700 common shares and spent $1,115,306 at an average price of $5.82 per share (excluding commissions) before the plan terminated on March 7, 2023. In 2023, the Company repurchased 1,158,849 shares and spent $6,055,601 at an average price of $5.20 per share (excluding commissions) under the two consecutive repurchase programs.
To be consistent with the current presentation, the prior year elimination of $1.6 million has been reclassed as well. 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.
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, 2023, upstream operating costs decreased by $0.7 million, or 10.1% from the same period in 2022.
The amounts recorded represent the fair value changes on our derivative instruments during the year. For the year ended December 31, 2022, the Company paid net cash settlements of $1,225,837. For the year ended December 31, 2021, the Company paid net cash settlements of $4,243,085.
During the year ended December 31, 2022, the Company had NYMEX HH two-way collars and Tennessee Gas Pipeline Zone 4 basis swap derivative contracts for the same hedging purpose. The amounts recorded represent the fair value changes on our derivative instruments during the year. For the year ended December 31, 2023, the Company received net cash settlements of $3,251,890.
The program will commence on March 27, 2023 and end on March 26, 2024, unless the maximum amount of common shares is purchased before then or Epsilon provides earlier notice of termination. ​ Derivative Transactions The Company has entered into hedging arrangements to reduce the impact of natural gas price volatility on operations.
The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act. The program will commence on March 27, 2024 and end on March 26, 2025, unless the maximum amount of common shares is purchased before then or Epsilon provides earlier notice of termination.
During the year ended December 31, 2021, we repurchased 534,015 common shares of the maximum of 1,193,000 authorized for repurchase and spent $2,423,007 under the plan. The repurchased stock had an average price of $4.51 per share (excluding commissions) and was subsequently retired during the year ended December 31, 2022.
During the year ended December 31, 2023, we repurchased 968,149 common shares and spent $4,940,295 at an average price of $5.08 per share (excluding commissions) under the new plan. The previous share repurchase program commenced on March 8, 2022.
Price ($/Mcf) ​ $ 5.96 ​ $ 3.04 Gathering system revenue ​ $ 8,085,512 ​ $ 7,865,825 Total PA Revenues ​ $ 61,844,866 ​ $ 37,775,476 Oklahoma ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 3,189,380 ​ $ 1,798,534 Volume (MMcf) ​ 477 ​ 403 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 ​ $ — Volume (MMcf) ​ 80 ​ — Avg.
During 2022, we realized net income of $35.4 million as compared to net income of $11.6 million for 2021. At December 31, 2022, our total estimated net proved developed reserves were 80,795 MMcfe, an increase of 10% from December 31, 2021. The increase is mainly attributable to revisions to previous estimates and transfers from proved undeveloped.
At December 31, 2023, our total estimated net proved developed reserves were 50,681 MMcfe, a decrease of 37% from December 31, 2022. The decrease is mainly attributable to revisions to previous estimates related to commodity pricing. At December 31, 2023, our total estimated net proved reserves were 70,262 MMcfe, a 25% decrease from December 31, 2022.
We anticipate that our current cash balance, cash flows from operations, and available sources of liquidity to be sufficient to meet our cash requirements. Year ended December 31, 2022 compared to 2021 During the year ended December 31, 2022, $38.0 million was provided by our operating activities, compared to $20.0 million in 2021, a $18.0 million, or 90%, increase.
Year ended December 31, 2023 compared to 2022 During the year ended December 31, 2023, $17.5 million was provided by our operating activities, compared to $38.0 million in 2022, a $20.5 million, or 54%, decrease. The decrease was mainly due to the decrease in realized prices resulting in decreased revenue.
During the year ended December 31, 2021, $2.3 million of cash was used for financing activity, which was primarily related to the repurchase of our common shares. Credit Agreement The Company has a senior secured credit facility which includes a total commitment of up to $100 million. The effective borrowing base is $30 million, which is subject to semi-annual redetermination.
During the year ended December 31, 2023, $11.7 million of cash used for financing activity was primarily related to the repurchase of our common shares and the payment of quarterly dividends.
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.
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. 32 ​ ​ Revenues During the year ended December 31, 2023, revenues decreased $39.3 million, or 56%, to $30.7 million from $70.0 million during the year ended December 31, 2022 primarily due to lower realized natural gas prices in PA (down 71%), partially offset by new oil revenues from the Permian Basin.
The increase was mainly due to the increase in realized prices resulting in increased revenue. We used $7.9 million for investing activities during the year ended December 31, 2022, compared to $4.4 million in 2021, a $3.4 million, or 77%, increase. This was spent primarily on upstream development costs in Pennsylvania and Oklahoma.
The company used $37.7 million for investing activities during the year ended December 31, 2023, compared to $7.9 million in 2022, a $29.8 million, or 379%, increase. The Company made a $17.9 million investment in U.S. Treasury bills and $19.8 million in capital investment in the upstream properties.
Removed
Over the last two years, we have also been active in our position in the NW Stack area of Oklahoma (“OK”). We have a substantial remaining drillable location inventory within our existing leasehold in PA and OK. The Company also seeks to identify new opportunities in onshore North American natural gas and oil basins.
Added
We have a substantial remaining drillable location inventory within our existing leasehold. ​ On May 9, 2023, Epsilon acquired a 10% interest in two wellbores located in Eddy County, New Mexico from a private operator. The wells are currently in production.
Removed
In the second half of 2022, we evaluated several potential investments outside our existing projects, with a focus on the Northeastern United States. We expect to expand our area of interest in 2023 to selectively consider potential investments in other North American gas and oil basins.
Added
Total capital expenditure (net to Epsilon) was $2.2 million. ​ On May 16, 2023, Epsilon acquired a 25% working interest in 1,297 gross acres on the Central Basin Platform in Ector County, Texas from a private operator. The Company participated in the drilling and completion of 2 gross (0.5 net) wells which were put on production in October 2023.
Removed
At December 31, 2022, our total estimated net proved reserves were 94,254 MMcfe, a 20% decrease from December 31, 2021.
Added
Total capital expenditures (net to Epsilon) to date are $9.3 million, including leasehold and drilling and completion costs. ​ On June 20, 2023, Epsilon acquired a 25% working interest in 11,067 gross acres on the Central Basin Platform in Ector County, Texas from a private operator.
Removed
The decrease in our total proved reserves is due to a change in our previously adopted development plan, primarily attributable to estimated proved undeveloped reserves in PA and OK that shifted into the probable reserve category under SEC guidelines due to timing.
Added
Total leasehold capital expenditures (net to Epsilon) to date are $6.2 million. ​ We continue to evaluate new opportunities in numerous onshore North American natural gas and oil basins. ​ During 2023, we realized net income of $7.9 million as compared to net income of $35.4 million for 2022.
Removed
Gathering system revenue for the year ended December 31, 2022 increased by $0.2 million, or 3% over 2021. This was the result of increased throughput in the system.
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We must have confirmation from the operator on near-term development to designate an undeveloped well location as proved. Our standardized measure of discounted future net cash flows as of December 31, 2023 and 2022 was $33.0 million and $145.8 million, respectively.
Removed
Prior to the year ended December 31, 2022, the gathering fees were netted from the gathering system operating costs. For the year ended December 31, 2022, the Company determined that it would be more appropriate to net the $1.5 million fees from the upstream lease operating costs.
Added
Price ($/Mcf) ​ $ 1.47 ​ $ — Natural gas liquids revenue ​ $ 353,612 ​ $ — Volume (MBOE) ​ 17.9 ​ — Avg. Price ($/Bbl) ​ $ 19.78 ​ $ — Oil and condensate revenue ​ $ 3,501,098 ​ $ — Volume (MBbl) ​ 44.5 ​ — Avg.
Removed
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.
Added
Price ($/Bbl) ​ $ 78.71 ​ $ — Total Permian Basin Revenues ​ $ 3,971,822 ​ $ — Oklahoma ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 1,014,050 ​ $ 3,189,380 Volume (MMcf) ​ 354 ​ 477 Avg.
Removed
Impairment ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2022 2021 Impairment ​ $ — ​ $ 153,058 ​ We perform a quantitative impairment test 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.
Added
A decrease of $35.1 million was due to lower realized natural gas prices and a reduction of $7.0 million was due to lower produced volumes due to natural decline of the wells. Upstream natural gas liquids revenue for the year ended December 31, 2023 decreased by $0.7 million, or 43% from 2022.
Removed
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.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeGathering 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.
Biggest changeGathering System Revenue Risk The Auburn Gas Gathering System lies within the Marcellus Shale 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.
Removed
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.
Removed
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.
Removed
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, 2022 and 2021, the outstanding principal balance under the credit agreement was nil.

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