UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number
(Exact name of registrant as specified in its charter)
(State or Other Jurisdiction of Incorporation or Organization) | (I.R.S. Employer Identification No.) |
(
(Address of principal executive offices including zip code and
telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol | Name of each exchange on which registered |
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ☐ |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes ☐ |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
No ☐ |
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
No ☐ |
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☐ | Accelerated filer ☐ | Smaller reporting company | Emerging growth company |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to § 240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).
Yes | No ☒ |
Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $
PART I
FORWARD LOOKING STATEMENTS.
Certain statements contained in this report constitute forward-looking statements. The use of any of the words ‘‘anticipate,’’ ‘‘continue,’’ ‘‘estimate,’’ ‘‘expect,’’ ‘‘may,’’ ‘‘will,’’ ‘‘project,’’ ‘‘should,’’ ‘‘believe,’’ and similar expressions and statements relating to matters that are not historical facts constitute ‘‘forward looking statements’’ within the meaning of applicable securities laws. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated. Such forward-looking statements are based on reasonable assumptions, but no assurance can be given that these expectations will prove to be correct and the forward-looking statements included in this report should not be unduly relied upon. These statements are made only as of the date of this report. All statements that address operating performance, events or developments that we expect or anticipate will occur in the future — including statements relating to oil and natural gas production rates, commodity prices for crude oil or natural gas, supply and demand for oil and natural gas; the estimated quantity of oil and natural gas reserves, including reserve life; future development and production costs, and statements expressing general views about future operating results — are forward-looking statements. Management believes that these forward-looking statements are reasonable as and when made. However, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date when made. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. In addition, forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from our present expectations or projections. These risks and uncertainties include, but are not limited to, those described in this Annual Report on Form 10-K, and those described from time to time in our future reports filed with the Securities and Exchange Commission.
DEFINED TERMS
We have included below the definitions for certain terms used in this document:
‘‘3-D seismic’’ Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
‘‘ABCA’’ Business Corporations Act (Alberta).
‘‘Anchor shippers’’ Parties listed in the Anchor Shipper Gas Gathering Agreement for Northern Pennsylvania, including Epsilon Energy USA, Inc., Equinor USA Onshore Properties, Inc., and Chesapeake Energy Corporation. for the Auburn Gas Gathering System.
‘‘ASC’’ Accounting Standards Codification.
‘‘Bbl’’ One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil, NGLs and other liquid hydrocarbons.
‘‘Bcf’’ One billion cubic feet, used in reference to natural gas.
‘‘BOE’’ One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals one Bbl of natural gas liquids.
‘‘Completion’’ The process of preparing a natural gas and oil wellbore for production through the installation of permanent production equipment, as well as perforation and fracture stimulation to optimize production.
‘‘Delay rental’’ Consideration paid to the lessor by a lessee to extend the terms of an oil and natural gas lease in the absence of drilling operations and/or production that is contractually required to hold the lease. This consideration is generally required to be paid on or before the anniversary date of the natural gas and oil lease during its primary term, and typically extends the lease for an additional year.
‘‘Development well’’ A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
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‘‘Differential’’ The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot price, and the wellhead price received.
‘‘Dry hole’’ A well found to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well.
‘‘Exit rate’’ Upstream term referring to the rate of production of oil and/or gas as of a specified date.
‘‘Exploratory well’’ A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
‘‘FASB’’ Financial Accounting Standards Board.
‘‘Field’’ An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms ‘‘structural feature’’ and ‘‘stratigraphic condition’’ are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.
‘‘Free cash flow’’ A measure of a company’s financial performance, calculated as operating cash flow minus capital expenditures. Free cash flow represents the cash that a company is able to generate after spending the money required to maintain or expand its asset base.
‘‘GAAP’’ Generally accepted accounting principles in the United States of America.
‘‘Gross acres’’ or ‘‘gross wells’’ The total acres or wells, as the case may be, in which a working interest is owned.
“Henry Hub” A natural gas pipeline located in Erath, Louisiana, that serves as the official delivery location for futures contracts on the NYMEX. The hub is owned by Sabine Pipe Line LLC and has access to many of the major gas markets in the United States.
‘‘ISDA’’ International Swaps and Derivatives Association, Inc.
‘‘Lease operating expense’’ or ‘‘LOE’’ The expenses of lifting oil or gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.
‘‘LIBOR’’ London interbank offered rate.
‘‘MBbl’’ One thousand barrels of oil, NGLs or other liquid hydrocarbons.
‘‘MBbl/d’’ One MBbl per day.
‘‘MBOE’’ One thousand BOE.
‘‘MBOE/d’’ One MBOE per day.
‘‘Mcf’’ One thousand cubic feet, used in reference to natural gas.
‘‘MMBbl’’ One million Bbl.
‘‘MMBOE’’ One million BOE.
‘‘MMBtu’’ One million British Thermal Units, used in reference to natural gas.
‘‘MMcf’’ One million cubic feet, used in reference to natural gas.
‘‘MMcf/d’’ One MMcf per day.
‘‘Net acres’’ or ‘‘net wells’’ The sum of the fractional working interests owned in gross acres or wells, as the case may be.
‘‘Net production’’ The total production attributable to the fractional working interest owned.
‘‘NGL’’ Natural gas liquid.
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‘‘NYMEX’’ The New York Mercantile Exchange.
‘‘PDNP’’ Proved developed nonproducing reserves.
‘‘PDP’’ Proved developed producing reserves.
‘‘Plugging and abandonment’’ Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of most states legally require plugging of abandoned wells.
‘‘Prospect’’ A property on which indications of oil or gas have been identified based on available seismic and geological information.
‘‘Proved developed reserves’’ Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
‘‘Proved reserves’’ Those reserves that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.
The area of the reservoir considered as proved includes all of the following:
| a. | The area identified by drilling and limited by fluid contacts, if any, and |
| b. | Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:
| a. | Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and |
| b. | The project has been approved for development by all necessary parties and entities, including governmental entities. |
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
‘‘Proved undeveloped reserves’’ or ‘‘PUDs’’ Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
‘‘PV-10’’ The present value, discounted at 10% per annum, of future net revenues (estimated future gross revenues less estimated future costs of production, development, and asset retirement costs) associated with reserves and is not necessarily the same as market value. PV-10 does not include estimated future income taxes. Unless otherwise noted, PV-10 is calculated using the pricing scheme as required by the Securities and Exchange Commission (‘‘SEC’’). PV-10
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of proved reserves is calculated the same as the standardized measure of discounted future net cash flows, except that the standardized measure of discounted future net cash flows includes future estimated income taxes discounted at 10% per annum. See the definition of standardized measure of discounted future net cash flows.
‘‘Reasonable certainty’’ If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.
‘‘Reserves’’ Estimated remaining quantities of natural gas and oil and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering natural gas and oil or related substances to market, and all permits and financing required to implement the project.
‘‘Reservoir’’ A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
‘‘Royalty’’ The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil or natural gas produced and sold, unencumbered by expenses relating to the drilling, completing or operating of the affected well.
‘‘Royalty interest’’ An interest in an oil or natural gas property entitling the owner to shares of the crude oil or natural gas production free of costs of exploration, development and production operations.
‘‘Section’’ An area of one square mile of land, 640 acres, with 36 sections making up one survey township on a rectangular grid.
‘‘Standardized Measure’’ or ‘‘SMOG’’ The standardized measure of discounted future net cash flows (the ‘‘Standardized Measure’’) is an estimate of future net cash flows associated with proved reserves, discounted at 10% per annum. Future net cash flows is calculated by reducing future net revenues by estimated future income tax expenses and discounting at 10% per annum. The Standardized Measure and the PV-10 of proved reserves is calculated in the same exact fashion, except that the Standardized Measure includes future estimated income taxes discounted at 10% per annum. The Standardized Measure is in accordance with U.S. GAAP.
‘‘Working interest’’ The interest in a crude oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.
‘‘Workover’’ Operations on a producing well to restore or increase production.
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ITEM 1. BUSINESS.
Summary
Epsilon Energy Ltd. (the “Company” or “Epsilon” or “we”) was incorporated under the laws of the Province of Alberta, Canada on March 14, 2005, pursuant to the ABCA. The Company is extra-provincially registered in Ontario pursuant to the Business Corporations Act (Ontario). Epsilon is a North American on-shore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves. On February 14, 2019, Epsilon’s registration statement on Form 10 was declared effective by the United States Securities and Exchange Commission and on February 19, 2019, we began trading in the United States on the NASDAQ Global Market under the trading symbol “EPSN.”
At December 31, 2023, Epsilon’s total estimated net proved reserves were 65,916 million cubic feet of natural gas reserves, 383,174 barrels of NGL reserves, and 341,286 barrels of oil and other liquids. Epsilon holds leasehold rights to approximately 84,684 gross (15,463 net) acres, excluding the Texas acreage acquired in February 2024. The Company has natural gas production in the Marcellus Shale in Pennsylvania and oil, natural gas liquids and natural gas production in the Permian Basin in Texas and New Mexico and in the Anadarko Basin in Oklahoma.
We conduct operations in the United States through our wholly owned subsidiaries Epsilon Energy USA Inc., an Ohio corporation, or Epsilon Energy USA; Epsilon Midstream, LLC, a Pennsylvania limited liability company, or Epsilon Midstream; Epsilon Operating, LLC, a Delaware limited liability company; Dewey Energy GP LLC, a Delaware limited liability company; Dewey Energy Holdings LLC, a Delaware limited liability company; and Altolisa Holdings, LLC, a Delaware limited liability company.
Substantially all the production from our Pennsylvania acreage (4,807 net) is dedicated to the Auburn Gas Gathering System, or the Auburn GGS, located in Susquehanna County, Pennsylvania for a 15-year term expiring in 2026 under an operating agreement whereby the Auburn GGS owners receive a fixed percentage rate of return on the total capital invested in the construction and maintenance of the system. We own a 35% interest in the Auburn GGS which is operated by a subsidiary of Williams Partners, LP. In 2023, we paid $2.5 million (after elimination) to the Auburn GGS to gather and treat our 7.9 Bcf of natural gas production in Pennsylvania ($2.8 million after elimination was paid to the Auburn GGS to gather and treat our 9.0 Bcf in 2022), including the fees paid to our subsidiary, Epsilon Midstream.
Our principal executive office is located at 500 Dallas Street, Suite 1250, Houston, Texas 77002, and our telephone number at that address is (281) 670-0002. Our registered office in Alberta, Canada is located at 14505 Bannister Road SE, Suite 300, Calgary, AB, Canada T2X 3J3.
Business highlights of 2023
Operational Highlights
Marcellus Shale—Pennsylvania
| ● | During the year ended December 31, 2023, Epsilon’s realized natural gas price was $1.74 per Mcf, excluding the impact of hedges, a 71% decrease from $5.96 for the year ended December 31, 2022. |
| ● | Total year ended December 31, 2023, natural gas sales were 7.9 Bcf, as compared to 9.0 Bcf during 2022. |
| ● | Gathered and delivered 66.2 Bcf gross (23.2 Bcf net to Epsilon’s interest) during the year, or 181 MMcf/d through the Auburn GGS. |
| ● | We participated in the drilling of 7 gross (0.74 net) and completion of 2 gross (0.02 net) Marcellus wells in 2023. The completed wells went into production in January 2023. |
| ● | At year end, the Company had 1 gross (0.01 net) well being drilled and 6 gross (0.73 net) wells waiting on completion. |
Permian Basin—New Mexico and Texas
| ● | During the year ended December 31, 2023, Epsilon’s realized price for all Permian Basin production was |
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| $52.49 per BOE, excluding the impact of hedges. |
| ● | Total sales for 2023 including oil, natural gas, and other liquids was 75.7 MBOE. |
| ● | In 2023, the Company acquired 12,373 gross (3,093 net) of undeveloped leasehold acres in Ector County, Texas. |
| ● | In 2023, the Company participated in the drilling and completion of 4 gross (0.7 net) wells. These wells went into production in April 2023 (1 – New Mexico), May 2023 (1 – New Mexico) and October 2023 (2 – Texas). |
Anadarko, NW STACK Trend—Oklahoma
| ● | During the year ended December 31, 2023, Epsilon’s realized price for all Oklahoma production was $5.35 per Mcfe, excluding the impact of hedges, a 38% decrease from $8.68 for the year ended December 31, 2022. |
| ● | Total sales for 2023 including natural gas, oil, and other liquids was 0.60 Bcfe, as compared to 0.93 Bcfe during 2022. |
| ● | In 2023, the Company participated in the completion of 1 gross (0.11 net) well. The well went into production in May 2023. |
Properties
Wells
As of December 31, 2023, Epsilon’s 84,684 gross (15,463 net) acres are all located in the United States and include 362 gross (37.47 net) wells.
| Gross(1) |
| Net(2) | |
Producing Wells |
|
|
|
|
Gas |
| 289 |
| 31.42 |
Oil |
| 29 |
| 2.68 |
Total Producing Wells | 318 | 34.10 | ||
Non-Producing Wells | 44 | 3.37 | ||
Total Wells | 362 | 37.47 |
Acreage
As of December 31, 2023, our leasehold inventory consisted of the following acreage amounts, rounded to the nearest acre:
| Gross(1) |
| Net(2) (3) | |
Developed Acres |
|
|
|
|
Pennsylvania |
| 11,270 |
| 4,807 |
Texas |
| 800 |
| 200 |
Oklahoma |
| 5,113 |
| 991 |
| 17,183 |
| 5,998 | |
Undeveloped Acres |
|
|
|
|
Pennsylvania |
| 335 |
| 335 |
Texas |
| 11,573 |
| 2,893 |
Oklahoma |
| 55,593 |
| 6,237 |
| 67,501 |
| 9,465 | |
Total Acres |
|
|
|
|
Pennsylvania |
| 11,605 |
| 5,142 |
Texas |
| 12,373 |
| 3,093 |
Oklahoma |
| 60,706 |
| 7,228 |
Total acres |
| 84,684 |
| 15,463 |
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| (1) | “Gross” means one-hundred percent of the working interest ownership in each leasehold tract of land. |
| (2) | “Net” means the Company’s fractional working interest share in each leasehold tract of land on which productive wells have been drilled. |
| (3) | “Net Undeveloped” means the Company’s fractional working interest share in each leasehold tract of land where productive wells have yet to be drilled. All of Epsilon’s Oklahoma undeveloped properties are deep rights acreage which is held by production of developed properties. |
Business Segments
Our operations are conducted by three operating segments for which information is provided in our consolidated financial statements for the years ended December 31, 2023 and 2022.
The three segments are as follows:
Upstream: Activities include acquisition, exploration, development and production of oil and natural gas reserves on properties within the United States.
Gathering System: We partner with two other companies to operate a natural gas gathering system.
Corporate: Activities include our corporate and governance functions.
For information about our segment’s revenues, profits and losses, total assets, and total liabilities, see Note 14 “Operating Segments” in the Notes to Consolidated Financial Statements.
Oil and Natural Gas Production and Revenues and Gathering System Revenues
A summary of our net oil and natural gas production, average oil and natural gas prices and related revenues and our gathering system revenues for the years ended December 31, 2023 and 2022, respectively, follows:
Year ended | ||||||
December 31, | ||||||
| 2023 |
| 2022 | |||
Production Volumes | ||||||
Pennsylvania | ||||||
Natural gas (MMcf) | 7,906 | 9,026 | ||||
Total (Mmcfe) | 7,906 | 9,026 | ||||
Permian Basin | ||||||
Natural gas (MMcf) | 80 | - | ||||
Natural gas liquids (MBOE) | 18 | - | ||||
Oil & other liquids (MBbl) | 44 | - | ||||
Total (Mmcfe) | 454 | - | ||||
Oklahoma | ||||||
Natural gas (MMcf) | 354 | 477 | ||||
Natural gas liquids (MBOE) | 21 | 44 | ||||
Oil & other liquids (MBbl) | 21 | 32 | ||||
Total (Mmcfe) | 605 | 933 | ||||
Company Total | ||||||
Natural gas (MMcf) | 8,340 | 9,503 | ||||
Natural gas liquids (MBOE) | 39 | 44 | ||||
Oil & other liquids (MBbl) | 65 | 32 | ||||
Total (Mmcfe) | 8,965 | 9,959 | ||||
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Year ended | ||||||
December 31, | ||||||
| 2023 |
| 2022 | |||
Revenues | ||||||
Pennsylvania | ||||||
Natural gas revenue | $ | 13,733,052 | $ | 53,759,354 | ||
Avg. Price ($/Mcf) | $ | 1.74 | $ | 5.96 | ||
Gathering system revenue (net of elimination) | $ | 9,790,531 | $ | 8,085,512 | ||
Total PA Revenues | $ | 23,523,583 | $ | 61,844,866 | ||
Permian Basin | ||||||
Natural gas revenue | $ | 117,112 | $ | — | ||
Avg. Price ($/Mcf) | $ | 1.47 | $ | — | ||
Natural gas liquids revenue | $ | 353,612 | $ | — | ||
Avg. Price ($/Bbl) | $ | 19.78 | $ | — | ||
Oil and condensate revenue | $ | 3,501,098 | $ | — | ||
Avg. Price ($/Bbl) | $ | 78.71 | $ | — | ||
Total Permian Basin Revenues | $ | 3,971,822 | $ | — | ||
Oklahoma | ||||||
Natural gas revenue | $ | 1,014,050 | $ | 3,189,380 | ||
Avg. Price ($/Mcf) | $ | 2.87 | $ | 6.68 | ||
Natural gas liquids revenue | $ | 630,806 | $ | 1,733,129 | ||
Avg. Price ($/Bbl) | $ | 29.96 | $ | 39.31 | ||
Oil and condensate revenue | $ | 1,589,491 | $ | 3,195,334 | ||
Avg. Price ($/Bbl) | $ | 76.37 | $ | 99.24 | ||
Total OK Revenues | $ | 3,234,347 | $ | 8,117,843 | ||
Total Company Revenues | $ | 30,729,752 | $ | 69,962,709 | ||
Gathering System Operations
Epsilon Energy USA is the 100% owner of Epsilon Midstream, which owns a 35% undivided interest in the Auburn GGS, located in Susquehanna County, Pennsylvania, with partners Appalachia Midstream Services, LLC (43.875%) and Equinor Pipelines, LLC (21.125%). The Anchor Shippers, consisting of Epsilon Energy USA, Equinor USA Onshore Properties, Inc., and Chesapeake Energy Corporation, dedicated approximately 18,000 mineral acres to the Auburn GGS for an initial term of 15 years under an operating agreement whereby the Auburn GGS owners receive a fixed percentage rate of return on the total capital invested in the construction of the system.
During 2023, the gathering rate of the Auburn GGS was determined by a cost of service model whereby the Anchor Shippers dedicate acreage and reserves to the gas gathering system in exchange for the Auburn GGS owners agreeing to an 18% contractual rate of return on invested capital. The term of this arrangement is 15 years commencing January 1, 2012 and expiring December 31, 2026. Each year, the Auburn GGS historical and forecast throughput, revenue, operating expenses and capital expenditures are entered into the cost of service model. The model then computes the new gathering rate that will yield the contractual rate of return to the Auburn GGS owners. In January 2027, the Auburn GGS will transition to a fixed gathering rate.
Revenues from the Auburn GGS are earned primarily from the Anchor Shippers. Revenues are also earned from third-party customers of the system to transport gas from the wellhead to the compression facility, and then to the delivery meter at Tennessee Gas Pipeline. The relative mix of Anchor Shipper gas and third-party gas is critical to the revenue and earnings of the Auburn GGS because the third-party gathering rate is only 25% of the Anchor Shipper rate. Third-party shippers must pay the gathering rate of the originating gathering system plus 25% of the Auburn GGS gathering rate. The purpose of the reduced rate is to attract additional volumes that require delivery to Tennessee Gas Pipeline when there is spare capacity at the Auburn compression facility, or the “Auburn CF”. Throughput at the Auburn CF has declined from 100.1 Bcf in 2018 to 66.2 Bcf in 2023, a decrease of 34%. However, Anchor Shipper gas as a percentage of total throughput has increased from 57% in 2018 to 74% in 2023. As a result of this shift toward a higher percentage of Anchor Shipper gas, as well as higher gathering rates charged, revenues for the gathering system have only declined 2% from 2018 to 2023.
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The Auburn GGS consists of approximately 44 miles of gathering pipelines, a small auxiliary compression facility and a main compression facility with three dehydration units and three Caterpillar 3612 compression units. At inception, the capacity of the Auburn CF was approximately 330,000 Mcf per day at a design suction pressure of 800 psig. The design suction pressure was subsequently reduced to 550 psig in June 2020 at the request of the Anchor Shippers. This request served to minimize throughput decline during a period of low pricing in which the drilling of new wells was undesirable. Operating at the lower design suction pressure also has the benefit of reducing hydrate occurrences in the system which can pose an operational hazard. The current system capacity of the Auburn CF at this lower design pressure is approximately 220,000 Mcf per day. The facility capacity could be increased again, if required, by either adding compression units or increasing the design suction pressure.
The Auburn CF delivers processed natural gas into the Tennessee Gas Pipeline at the Shoemaker Dehy receipt meter. The Auburn GGS is connected with the adjacent Rome GGS, which allows for the receipt of additional natural gas to maximize utilization of the Auburn CF and Tennessee Gas Pipeline meter capacity.
During the years ended December 31, 2023 and 2022, the Auburn GGS delivered 66.2 Bcf and 66.3 Bcf respectively, of natural gas, or 181 and 182 MMcf per day.
Gathering system revenues derived from Epsilon’s production, which have been eliminated from total gathering system revenues (“elimination entry”), amounted to $1.4 million and $1.5 million, respectively, for the years ended December 31, 2023 and 2022.
Proved Reserves
Per our reserve report prepared by independent petroleum consultants, DeGolyer and MacNaughton, our estimated proved reserves as of December 31, 2023, are summarized in the table below. See Risk Factors for information relating to the uncertainties surrounding these reserve categories.
Natural Gas | Natural Gas | Oil and Other | Total | |||||
| MMcf |
| Liquids MBbl |
| Liquids MBbl |
| MMcfe | |
Proved developed reserves | 47,555 | 249 | 272 |
| 50,681 | |||
Proved undeveloped reserves | 18,361 | 134 | 69 |
| 19,581 | |||
Total Proved Reserves at December 31, 2023 | 65,916 | 383 | 341 |
| 70,262 | |||
| ||||||||
Changes in Total Proved Undeveloped Reserves |
|
|
|
|
|
|
|
|
Proved undeveloped reserves at December 31, 2022 | 11,074 | 293 | 104 |
| 13,459 | |||
Revisions of previous estimates | 7,549 | (132) | (25) | 6,602 | ||||
Transfers to proved developed | (262) | (27) | (10) |
| (480) | |||
Proved undeveloped reserves at December 31, 2023 |
| 18,361 |
| 134 |
| 69 |
| 19,581 |
Revisions to previous estimates for total proved undeveloped reserves for 2023 include additions of 14,867 MMcfe related to changes to the previously adopted development plan and reductions of 8,265 MMcfe related to commodity pricing. Transfers to proved developed relates to the development of one well in Oklahoma.
We did not engage in any exploration capital spending in 2023 or 2022. Our development capital spending to convert proved undeveloped reserves to proved developed reserves for the periods indicated is as follows:
| ● | In 2023 in Pennsylvania, we drilled 7 gross (0.74 net) wells and completed 2 gross (0.02 net) wells. (Net development capital $2.5 million). The two wells turned online in January 2023. |
| ● | In 2022 in Pennsylvania, we drilled 5 gross (0.05 net) wells and completed 4 gross (0.21 net) wells. (Net development capital $2.5 million). Reserves of 5.4 Bcf for the 1 well with proved undeveloped reserves were reclassified as proved developed producing as this well was turned online in August 2022. Additionally, 2 gross (0.02 net) wells were drilled in 2022, but not completed (development capital $0.1 million). They were completed and turned online in January 2023. |
| ● | In 2023 in Oklahoma, we completed 1 gross (0.11 net) well. (Net development capital $0.7 million). The |
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| well turned online in May 2023. |
| ● | In 2022 in Oklahoma, we drilled 2 gross (0.26 net) wells and completed 3 gross (0.7 net) wells. (Net development capital $5.4 million). Reserves of 2.9 Bcfe for the 3 wells were reclassified as proved developed producing as these wells were turned online at various times beginning in March 2022 and going through October 2022. One gross (0.11 net) well was drilled in 2022, but not completed. It was completed in May 2023. |
Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company’s Overall Reserve Estimation Process
Our policies regarding internal controls over reserve estimates require reserves to be prepared by an independent engineering firm under the supervision of our Chief Operating Officer, and to be in compliance with generally accepted geologic, petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The corporate staff interacts with our internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data for the reserves estimation process. We provide our engineering firm with property interests, production, capital budgets, current operating costs, current production prices and other information. This information is reviewed by our Chief Operating Officer to ensure accuracy and completeness of the data prior to submission to our independent engineering firm. Reserves are reviewed and approved internally by our Chief Operating Officer on a semi-annual basis. Our Chief Operating Officer holds a Bachelor of Science degree in Petroleum Engineering and received a Master’s Degree of Business Administration. He has over 30 years of experience in upstream exploration and production, and has managed all phases of drilling, completions, production and field operations.
The reserve information in this report is based on estimates prepared by DeGolyer and MacNaughton, our independent petroleum consultants. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.
For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas).
The person responsible for preparing the reserve report, Dilhan Ilk, is a Registered Professional Engineer (No.139334) in the State of Texas and a Senior Vice President of the firm. Mr. Ilk graduated from Texas A&M University with a Doctor in Philosophy degree in Petroleum Engineering, is a member of the Society of Petroleum Engineers, and has in excess of 13 years of experience in oil and gas reservoir studies and reserves evaluations.
Marketing and Major Customers
Natural gas marketing is competitive in northeast Pennsylvania because of the limited interstate transportation capacity and ample natural gas supply. We do not currently own any firm transportation on interstate pipelines that would enable us to diversify our natural gas sales to downstream locations. As a result, all of our Pennsylvania gas sales occur in Zone 4 of the Tennessee Gas Pipeline at the Shoemaker Dehy meter, which is the receipt point from the Auburn CF.
Epsilon uses a third-party service, ARM Energy Management LLC (“ARM”) for its natural gas marketing. In this capacity, ARM is responsible for carrying out marketing activities such as submission of nominations, receipt of payments, and submission of invoices.
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For the year ended December 31, 2023, we sold natural gas through ARM to 33 unique customers. Direct Energy Business Marketing, LLC and EQT Energy, LLC each accounted for 10% or more of our total revenue. For the year ended December 31, 2022, we sold natural gas through ARM to 26 unique customers. Direct Energy Business Marketing, LLC and SWN Energy Services Company, LLC each accounted for 10% or more of our total revenue.
Geographic Locations of Operations
Approximately 77% and 88% of our revenue during fiscal years 2023 and 2022, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania. As a result of prolonged weak pricing in Zone 4 of the Tennessee Gas Pipeline and, therefore, a reduced pace of development, Epsilon’s management is striving to allocate capital to additional upstream opportunities outside of the Marcellus Shale. More specifically, the Company has allocated capital to the Permian Basin through its investments in New Mexico and Texas. Epsilon’s management expects to continue to seek opportunities outside of the Marcellus Shale in order to provide the Company the flexibility to respond to market conditions by allocating capital across multiple basins and commodities.
As a result of the geographic concentration, we may be disproportionately exposed to the effect of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of crude oil or natural gas.
Competition
It is not uncommon in the oil and natural gas industry to experience shortages of drilling and completion rigs, equipment, pipe, services, and personnel, which can cause both delays in development drilling activities and significant cost increases. We are exposed to the risk of industry competition for drilling rigs, completion rigs and availability of related equipment and services, among other goods and services required in our business.
Our Status as an Emerging Growth Company
We are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012, or the “JOBS Act”. Certain specified reduced reporting and other regulatory requirements are available to public companies that are emerging growth companies. These provisions include:
| ● | an exemption from the auditor attestation requirement in the assessment of our internal controls over financial reporting required by Section 404 of the Sarbanes—Oxley Act of 2002 (provided that this exemption will continue for such time as we are a “non-accelerated filer”); |
| ● | an exemption from the adoption of new or revised financial accounting standards until they would apply to private companies; |
| ● | an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board, or the PCAOB, requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about our audit and our financial statements; and |
| ● | reduced disclosure about our executive compensation arrangements. |
We have elected to take advantage of the exemption from the adoption of new or revised financial accounting standards until they would apply to private companies.
We will continue to be an emerging growth company not later than December 31, 2024.
Employees
As of December 31, 2023, we had ten full-time employees (including executive officers) in Houston, Texas. None
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of our employees are subject to a collective bargaining agreement or represented by a union.
The foundation of our Company is our employees and our success begins with a values-driven culture and commitment to developing a skilled, agile, diverse and engaged workforce where every employee understands that they can and do make a difference. Advancing a safe, ethical, inclusive and diverse culture creates an environment that attracts and retains the high-performing workforce needed to successfully execute our strategy.
We continue to foster a culture that embraces inclusion and diversity and encourages collaboration. Our core values include inclusion and diversity, and we believe in equity and the value and voice of every employee.
Legal Proceedings
On March 10, 2021, Epsilon filed a complaint against Chesapeake Appalachia, LLC (“Chesapeake”) in the United States District Court for the Middle District of Pennsylvania, Scranton, Pennsylvania (“Middle District”). Epsilon claimed that Chesapeake had breached a settlement agreement and several operating agreements (“JOAs”) to which Epsilon and Chesapeake are parties. Epsilon asserted that Chesapeake had failed to cooperate with Epsilon’s efforts to develop resources in the Auburn Development, located in North-Central Pennsylvania, as required under both the settlement agreement and JOAs.
Epsilon requested a preliminary injunction but was unsuccessful in obtaining that injunction. Epsilon filed a motion to amend its original Complaint. Chesapeake opposed. The Court ruled in Epsilon’s favor and allowed Epsilon’s amendment. Chesapeake moved to dismiss the amended Complaint. The Court granted the motion to dismiss on a narrow issue without prejudice to Epsilon’s right to file a new lawsuit based on new proposals made after the Court’s decision. Epsilon filed a motion for reconsideration of that decision, but the court denied the motion for reconsideration on January 18, 2022.
Epsilon filed a notice of appeal on February 15, 2022 challenging the District Court's rulings in the case. Following the Third Circuit's ruling to remand the case back to District court, Epsilon sought and was granted a dismissal of the case without prejudice in September 2023.
Regulation
Environmental Regulation
Epsilon is subject to various federal, state and local laws and regulations governing the handling, management, disposal and discharge of materials into the environment or otherwise relating to the protection of human health, safety and the environment. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or that may result in injunctive relief for failure to comply. These laws and regulations may:
| ● | require the acquisition of various permits before drilling commences; |
| ● | restrict the types, quantities and concentrations of various substances, including water and waste, that can be released into the environment; |
| ● | limit or prohibit activities on lands lying within wilderness, wetlands and other protected areas; and |
| ● | require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells. |
Compliance with environmental laws and regulations increases Epsilon’s overall cost of business, but has not had, to date, a material adverse effect on Epsilon’s operations, financial condition or results of operations. In addition, it is not anticipated, based on current laws and regulations, that Epsilon will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to its total exploration and
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development expenditure program in order to comply with such laws and regulations. However, given that such laws and regulations are subject to change, Epsilon is unable to predict the ultimate cost of compliance or the ultimate effect on Epsilon’s operations, financial condition and results of operations.
Climate Change
There is consensus in the international scientific community that increasing concentrations of greenhouse gas emissions (“GHG”) in the atmosphere will produce changes to global, as well as local, climate. Scientists project that increased concentrations of GHGs will cause more frequent, and more powerful storms, droughts, floods and other climatic events. If such effects were to occur, our development and production operations, as well as operations of our third party providers and customers, could be adversely affected. To date, we have not developed a comprehensive plan to address potential impacts of climate change on our operations and there can be no assurance that any such impacts would not have an adverse effect on our financial condition and results of operations.
Attempts to address GHGs, as well as climate change more generally, have taken the form of local, state, national and international proposals. Broadly speaking, examples include cap-and-trade programs, carbon tax proposals, GHG reporting and tracking programs, and regulations that directly limit GHGs from certain sources.
In the United States, federal proposals are rooted in the EPA’s “endangerment finding,” that was upheld by the Supreme Court. Simply, EPA has concluded that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment. For example, the EPA adopted regulations that require Prevention of Significant Deterioration (“PSD”) construction under Title V operating permit reviews for GHG emissions from certain large stationary sources that constitute major sources of emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards.
Rules requiring the monitoring and reporting of GHG emissions from designated sources in the United States on an annual basis, including, oil and natural gas production facilities and processing, transmission, storage and distribution facilities, which include certain of our operations, have been adopted. The EPA has expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities.
Federal agencies also have begun directly regulating emissions of methane from natural gas operations. In 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain facilities to reduce methane gas and volatile organic compound emissions. EPA published amendments to those regulations effective September 15, 2020. However, on January 20, 2021, President Biden issued an Executive Order directing EPA to consider suspending, revising or rescinding the September 15, 2020 amendments and also to consider proposing new regulations governing methane and volatile organic compound emissions from existing oil and gas sector operations.
In November 2016, the Bureau of Land Management (“BLM”) published a final rule to reduce methane emissions by regulating venting, flaring, and leaking from oil and natural gas operations on public lands. A federal district court vacated much of that rule in October 2020 and that decision is now subject to an appeal.
Internationally, in April 2016, the United States joined other countries in entering into a non-binding agreement in France for nations to limit their GHG emissions through country-determined reduction goals every five years beginning in 2020 (the “Paris Agreement”). Although the Trump Administration subsequently announced plans to withdraw from the Paris Agreement, on January 20, 2021, President Biden issued an Executive Order providing that he was accepting the Paris Agreement on behalf of the United States.
In addition, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations on certain sources of funding for the energy sector. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities.
Epsilon is unable to predict the timing, scope and effect of any currently proposed or future, laws, regulations or treaties regarding climate change and GHG emissions. Any limits on GHG emissions, however, could adversely affect demand for the oil and natural gas that production operators produce, some of whom are our customers, which could thereby reduce demand for our gas gathering services. We are currently unable to calculate or predict the direct and indirect costs of GHG or climate change related laws, regulations and treaties, and accordingly, we cannot assure you that any such
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efforts will not have a material impact on our operations, financial condition and results.
Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices and has finalized a study of the potential environmental impacts of hydraulic fracturing activities. In 2014, the EPA issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act of 1976 requesting comments related to disclosure for hydraulic fracturing chemicals. The Department of the Interior had released final regulations governing hydraulic fracturing on federal and Native American oil and natural gas leases which require lessees to file for approval of well stimulation work before commencement of operations and require well operators to disclose the trade names and purposes of additives used in the fracturing fluids. However, in December 2017, the Bureau of Land Management published a final rule rescinding the March 26, 2015 rule (“BLM 2015 Rule”), entitled “Natural gas and oil; Hydraulic Fracturing on Federal and Indian Lands.” The primary purposes of the BLM 2015 Rule were to ensure that wells were constructed so as to protect water supplies, to ensure environmentally responsible management of fluids displaced by fracturing, and to provide public disclosure of chemicals used in fracturing operations. The net effect of the December 2017 rule making is to return the affected sections of the Code of Federal Regulations to the language that existed before the BLM’s 2015 Rule. In addition, legislation has from time to time been introduced, but not adopted, in Congress to provide for additional federal regulation of hydraulic fracturing and to require additional disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances.
Epsilon is unable to predict the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing in the United States, but there can be no assurance that the direct and indirect costs of such laws and regulations (if enacted) would not materially and adversely affect Epsilon’s operations, financial condition and results of operations.
Gathering System Regulation
Regulation of gathering facilities may affect certain aspects of Epsilon’s business and the market for Epsilon’s services. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily the Federal Energy Regulatory Commission, or the FERC. The FERC regulates interstate natural gas transportation rates, terms and conditions of service, which affects the marketing of natural gas produced by Epsilon, as well as the revenues received for sales of Epsilon’s natural gas.
The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act, or the NGA, and by regulations and orders promulgated under the NGA by the FERC. In certain limited circumstances, intrastate transportation, gathering, and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the U.S. Congress and by FERC regulations.
Market for Our Common Equity and Related Stockholder Matters
Market Information. Commencing on February 19, 2019, the common shares of the Company trade on the NASDAQ Global Market with the ticker symbol ‘‘EPSN.’’ The last reported sales price of our common shares on the NASDAQ Global Market on March 19, 2024 was $5.01 per share.
Shareholders. We had approximately 975 shareholders of record as of March 1, 2024.
Dividends. Epsilon made aggregate quarterly distributions of $5.6 million ($0.25 per share) during the year ended December 31, 2023. The dividend is well supported and the Company intends to maintain it going forward.
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Securities Authorized for Issuance under Equity Incentive Plans.
The following tables set out the number of common shares available to be issued upon exercise of outstanding options issued and the changes to the options outstanding for the year pursuant to our equity compensation plans and the weighted average exercise price of outstanding options for the periods indicated:
Number of Shares to be | Weighted Average | ||||||
Issued Upon Exercise or | Exercise or Vesting Price | Number of Shares Remaining | |||||
Vesting of Outstanding | of Outstanding Options | Available for Future Issuance | |||||
Plan Category | Options or Shares | or Shares | Under Equity Compensation Plans | ||||
Equity share options under Amended and Restated 2017 Stock Option Plan |
| 57,500 |
| $ | 5.03 |
| — |
Common shares under 2020 Equity Incentive Plan |
| 491,536 | $ | 5.59 |
| 957,489 |
As of | As of | |||||||||
December 31, 2023 | December 31, 2022 | |||||||||
| Weighted |
|
| Weighted | ||||||
Number of | Average | Number of | Average | |||||||
Options | Exercise | Options | Exercise | |||||||
| Outstanding |
| Price |
| Outstanding |
| Price | |||
Balance at beginning of period |
| 70,000 | $ | 5.03 |
| 218,750 | $ | 5.28 | ||
Exercised |
| (12,500) | 5.03 |
| (138,750) |
| 5.38 | |||
Expired/Forfeited |
| — | — |
| (10,000) |
| 5.51 | |||
Balance at period-end |
| 57,500 | $ | 5.03 |
| 70,000 | $ | 5.03 | ||
Exercisable at period-end |
| 57,500 | $ | 5.03 |
| 70,000 | $ | 5.03 | ||
For the years ended December 31, 2023 and 2022, we had no warrants or other common share-related rights outstanding.
At December 31, 2023, under the 2020 Equity Incentive Plan (the “2020 Plan”) (See Note 7, “Shareholders’ Equity” of the Notes to the Consolidated Financial Statements), we are authorized to issue 2,000,000 common shares to employees and directors of the Company. As of that date, we had 1,042,511 common shares granted under the 2020 Plan. No more shares are authorized to be issued under our predecessor plan.
The following table sets out the number of time restricted common shares available to be issued upon vesting over the next three years and the changes during the year pursuant to our share compensation plans and the weighted average market price at date of issue for outstanding shares for the periods indicated:
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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.
ITEM 1A. RISK FACTORS.
You should carefully consider the risks and uncertainties described below, together with all of the other information and risks included in, or incorporated by reference into this report, including our consolidated financial statements and the related notes thereto, before making any financial decisions relating to Epsilon.
Risks Related to Oil and Natural Gas Reserves
Our business is dependent on oil and natural gas prices, and any fluctuations or decreases in such prices could adversely affect our results of operations and financial condition.
Revenues, profitability, liquidity, ability to access capital and future growth prospects are highly dependent on the prices received for oil and natural gas. The prices of these commodities are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile, and this volatility may continue in the future. The volatility of the energy markets generally makes it extremely difficult to predict future oil and natural gas price movements. 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. 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.
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,
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cash flows, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures, spending will be required to be reduced, assets could be sold or funds may be borrowed to fund any such shortfall.
Our long-term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves, the failure of which could result in under-use of capital and in losses.
Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Our long-term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, any existing reserves that we may have at any particular time and the production from those reserves will decline over time as those reserves are exploited. A future increase in our reserves will depend not only on our ability to explore and develop any properties we may have from time to time, but also on our ability to select and acquire suitable producing properties or prospects. We cannot assure you that we will be able to locate and continue to locate satisfactory properties for acquisition or participation. Moreover, if we do identify such acquisitions or participations, we may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. We cannot assure you that we will discover or acquire further commercial quantities of oil and natural gas.
Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not ensure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.
Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or in personal injury. In accordance with industry practice, we are not fully insured against all of these risks, nor are all such risks insurable. Although we maintain liability insurance in an amount that we consider consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect upon our financial condition. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations, and the loss of the ability to use hydraulic fracturing (see risk factor regarding government legislation). Losses resulting from the occurrence of any of these risks could have a material adverse effect on our future results of operations, liquidity and financial condition.
Our reserve estimates may be inaccurate, and future net cash flows as well as our ability to replace any reserves are uncertain.
There are numerous uncertainties inherent in estimating quantities of oil and natural gas reserves and cash flows to be derived therefrom, including many factors beyond our control. The reserve and associated cash flow information set forth herein represents estimates only. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows 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. 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. 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.
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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. Actual future net revenue will be affected by other factors such as actual commodity prices, production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs. Actual production and revenues derived 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. The oil and natural gas reserves and estimated cash flows to be derived therefrom contained in the DeGolyer Reserve Report will be reduced to the extent that such activities do not achieve the level of success assumed in the DeGolyer Reserve Report.
Our future oil and natural gas reserves, production, and derived cash flows are highly dependent on our successfully acquiring or discovering and developing new reserves. Without the continual addition of new reserves, any of our existing reserves and their production will decline as such reserves are exploited. A future increase in our reserves will depend not only on our ability to develop any properties we may have from time to time, but also on our ability to select and acquire suitable producing properties or prospects. There can be no assurance that our future exploration and development efforts will result in the discovery and development of additional commercial accumulations of oil and natural gas.
Risks Related to Stage of Development, 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. We may be unable to obtain additional capital required to implement our business plan, which could restrict our ability to grow.
Operations could also be adversely affected by general economic downturns or limitations on spending. An economic downturn and uncertainty may have a negative impact on our business. During 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.
Substantial capital, which may not be available to us in the future, is required to replace and grow reserves.
We anticipate making capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. If our revenues or reserves decline, we may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing or cash generated by operations will be available or sufficient to meet these requirements, or for other corporate purposes. If debt or equity financing is available, there is no assurance that it will be on terms acceptable to us. Moreover, future activities may require us to alter our capitalization significantly. Additional capital raised through the issuance of common shares or other securities convertible into common shares may result in a change of control of us and dilution to shareholders. Our inability to access sufficient capital for our operations could have a material adverse effect on our financial condition and results of operations.
Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times. From time to time, we may require additional financing in order to carry out our oil and natural gas acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause us to forfeit our interest in certain properties, miss certain acquisition opportunities, or reduce or terminate our operations. If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our production. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt, equity financing or the proceeds from the sale of a portion or all of our interest in one or more projects will be available to meet these requirements or available on terms acceptable to us.
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The borrowing base under our credit facility may be reduced in light of commodity price declines, which could limit us in the future.
Lower commodity volumes and prices may reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of our lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to twice yearly redeterminations, as well as special redeterminations described in the credit agreement. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under our credit agreement. In addition, we may be unable to access the equity or debt capital markets to meet our obligations, including any such debt repayment obligations.
The terms of our revolving credit facility may restrict our operations, particularly our ability to respond to changes or to take certain actions.
The contract that governs our revolving credit facility contains covenants that impose operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability, subject to satisfaction of certain conditions, to incur additional indebtedness, sell assets, enter into transactions with affiliates, and enter into or refrain from entering into hedging contracts.
In addition, the restrictive covenants in our revolving credit facility require us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we may be unable to meet them.
A breach of the covenants or restrictions under the contract that governs our revolving credit facility could result in an event of default under the applicable indebtedness. Such a default may allow the creditors to accelerate the related debt. In the event our lenders accelerate the repayment of our borrowings, we may not have sufficient assets to repay that indebtedness.
Depending on forces outside our control, we may need to allocate our available capital in ways that we did not anticipate.
Because of the volatile nature of the oil and natural gas industry, we regularly review our budgets in light of past results and future opportunities that may become available to us. In addition, our ability to carry out operations may depend upon the decisions of other working interest owners in our properties. Accordingly, while we anticipate that we will have the ability to spend the funds available to us, there may be circumstances where, for sound business reasons, a reallocation of funds may be prudent.
We may issue debt to acquire assets or for working capital.
From time to time, we may enter into transactions to acquire assets or shares of other companies. These transactions may be financed partially or wholly with debt, which may increase our debt levels. Depending on future exploration and development plans, we may require additional equity and/or debt financing that may not be available or, if available, may not be available on favorable terms. Neither our articles of incorporation nor our by-laws limit the amount of indebtedness that we may incur. The level of our indebtedness, from time to time, could impair our ability to obtain additional financing in the future on a timely basis to take advantage of business opportunities that may arise.
Our potential lenders will likely require security over substantially all of our assets. If we become unable to pay our debt service charges or otherwise commit an event of default, such as bankruptcy, these lenders may foreclose on or sell our properties. The proceeds of any such sale would be applied to satisfy amounts owed to our lenders and other creditors, and only the remainder, if any, would be available to us.
Future equity transactions could result in dilution to existing stockholders.
We may make future acquisitions or enter into financing or other transactions involving the issuance of securities, which may be dilutive to existing security holders.
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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.
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. Past industry conditions have led to periods of extreme shortages of drilling equipment in certain areas of the United States. On the oil and natural gas properties that we do not operate, we will be dependent on such operators for the timing of activities related to such properties and may be largely unable to direct or control the activities of the operators.
Results of our drilling are uncertain, and we may not be able to generate high returns.
Our operations involve utilizing the latest drilling and completion techniques in order to maximize cumulative recoveries and generate high returns. If drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, or if crude oil and natural gas prices decline, the return on our investment in these areas may not be as attractive as anticipated. Further, less than anticipated results in developments could incur material write-downs of our oil and natural gas properties and the value of undeveloped acreage could decline in the future.
Extensive government legislation and regulatory initiatives could increase costs and impose burdensome operating restrictions that may cause operational delays.
Hydraulic fracturing, which involves the injection of water, sand and chemicals under pressure into deep rock formations to stimulate oil or natural gas production, is often used in the completion of unconventional oil and natural gas wells. Currently, hydraulic fracturing is primarily regulated in the United States at the state level, which generally focuses on regulation of well design, pressure testing, and other operating practices.
However, some states and local jurisdictions across the United States, such as the State of New York, have begun adopting more restrictive regulation. Some members of the U.S. Congress and the EPA are studying environmental contamination related to hydraulic fracturing and the impact of fracturing on public health. In March 2015, the U.S. Congress introduced legislation to regulate hydraulic fracturing and require disclosure of the chemicals used in the hydraulic fracturing process, and may implement more stringent regulations in the future. Additionally, some states, such as the State of New York, have adopted, and others are considering, regulations that could restrict hydraulic fracturing. The ultimate status of such regulation is currently unknown. Any federal or state legislative or regulatory changes with respect to hydraulic fracturing could cause us to incur substantial compliance costs or result in operational delays, and the consequences of any failure to comply by us or our third-party operating partners could have a material adverse effect on our financial condition and results of operations.
Our corporate structure could result in incremental tax burden in certain circumstances.
Epsilon Energy Ltd. is an Alberta company. Epsilon Energy USA Inc. (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 Epsilon Energy USA Inc. were a USRPHC, then Epsilon Energy Ltd.’s investment in Epsilon Energy USA Inc. would be a United States Real Property Interest (USRPI) for US federal tax purposes. As a result, the Foreign Investment in Real Property Tax Act, or “FIRPTA,” would require Epsilon Energy Ltd. to pay U.S. federal income tax at the corporate income tax rates on capital gain distributions made by Epsilon Energy USA Inc. to Epsilon Energy Ltd. 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.
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Our operations are currently geographically concentrated and therefore subject to regional economic, regulatory and capacity risks.
Approximately 77% and 88% of our revenue during fiscal years 2023 and 2022, respectively, was derived from natural gas production and gathering system revenues in the state of Pennsylvania. As a result of prolonged weak pricing in Zone 4 of the Tennessee Gas Pipeline and, therefore, a reduced pace of development, Epsilon’s management is striving to allocate capital to additional upstream opportunities outside of the Marcellus Shale. More specifically, the Company has allocated capital to the Permian Basin through its investments in New Mexico and Texas. Epsilon’s management expects to continue to seek opportunities outside of the Marcellus Shale in order to provide the Company the flexibility to respond to market conditions by allocating capital across multiple basins and commodities.
As a result of 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.
Delays in business operations may reduce cash flows and subject us to credit risks.
In addition to the usual delays in payments by purchasers of oil and natural gas to us or to the operators, and the delays by operators in remitting payment to us, payments from these parties may be delayed by restrictions imposed by lenders, accounting delays, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, adjustment for prior periods, or recovery by the operator of expenses incurred in the operation of the properties. In addition, the transition of one operator to another as the result of an operator being bought or sold could cause additional operational delays beyond our control. Any of these delays could reduce the amount of cash flow available for our business in a given period and expose us to additional third-party credit risks.
We depend on the successful acquisition, exploration and development of oil and natural gas properties to develop any future reserves and grow production and revenue in the future, and assessments of our assets may be subject to uncertainty.
Acquisitions of oil and natural gas companies and oil and natural gas assets are typically based on engineering and economic assessments made by independent engineers and our own assessments. These assessments will include a series of assumptions regarding such factors as recoverability and marketability of oil and natural gas, future prices of oil and natural gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. In particular, the prices of, and markets for, oil and natural gas products may change from those anticipated at the time of making such assessment. In addition, all such assessments involve a measure of geologic and engineering uncertainty which could result in lower production and reserves than anticipated. Initial assessments of acquisitions may be based on analysis by our internal engineers or reports by a firm of independent engineers that are not the same as the firm that we use for our year-end reserve evaluations. Because each of these firms may have different evaluation methods and approaches, these initial assessments may differ significantly from the assessments of the firm that we use.
We depend on third-party operators and our key personnel, and competition for experienced technical personnel may negatively affect our operations.
Approximately 99% of our oil and natural gas properties are operated by third-party operators. As such, we will be dependent on such operators for the timing of activities related to such properties and will largely be unable to direct or control the activities of the operators. The objectives and strategy of those operators may not always be consistent with ours, and we have a limited ability to exercise influence over, and control the risks associated with, operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues from our assets or could increase costs or create liability for the operator’s failure to properly maintain the well and facilities and to adhere to applicable safety and environmental standards.
In addition to the operator, our success will depend in large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse effect on us. We do not have key-person insurance in effect
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for management. The contributions of these individuals to our immediate operations are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is intense, and there can be no assurance that we will be able to continue to attract and retain all personnel necessary for the development and operation of our business. Certain of our directors 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.
Our leasehold interests are subject to termination or expiration under certain conditions.
Our properties are held in the form of leases and working interests in leases, collectively referred to as “leasehold interests.” If we or our joint venture partner fails to meet the specific requirement(s) of a particular leasehold interest, the leasehold interest may terminate or expire. There can be no assurance that any of the obligations required to maintain each leasehold interest will be met. The termination or expiration of a particular leasehold interest may have a material adverse effect on our financial condition and results of operations.
We may incur losses as a result of title deficiencies.
Although title reviews will be done according to industry standards before the purchase of most oil and natural gas-producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat our claim, which could result in a reduction in our ownership interest or of the revenue that we receive.
We may be exposed to third-party credit risk, and defaults by third parties could adversely affect us.
We are or may be exposed to third-party credit risk through our contractual arrangements with current or future joint venture partners, marketers of our petroleum and natural gas production, derivative counterparties and other parties. In the event such entities fail to meet their contractual obligations to us, such failures could have a material adverse effect on us and our cash flow from operations.
We may not be insured against all of the operating risks to which we are exposed.
Our involvement in the exploration for and development of oil and natural gas properties may result in our becoming subject to liability for pollution, blow outs, property damage, personal injury or other hazards. Although before drilling we plan to obtain insurance in accordance with industry standards to address certain of these risks, such insurance may not be available, be price-prohibitive, or contain limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not in all circumstances be insurable, or, in certain circumstances, we may elect not to obtain insurance to deal with specific risks because of the high premiums associated with such insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to us. The occurrence of a significant event that we are not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on our financial position and our results of operations.
Risks Related to Commodity Prices, Hedging and Marketing
Natural gas and oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse 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. Our ability to borrow and to obtain additional capital on attractive terms is also substantially dependent upon oil and natural gas prices. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control. These factors include economic conditions in the United States, the Middle East and elsewhere in the world; the actions of OPEC; governmental regulation; political stability in the Middle East and elsewhere; the foreign supply of oil and natural gas; the price of foreign imports; and the availability of alternative fuel sources. Any substantial and extended decline in the price of oil and natural gas would have an adverse effect on the carrying value of our proved reserves, borrowing capacity, revenues, profitability and cash flows from operations. There can be no assurance that recent commodity prices can be sustained over the life of our operations. There
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is substantial risk that commodity prices may decline in the future, although it is not possible to predict the time or extent of such decline.
Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.
In addition, bank borrowings that may be available to us are in part determined by our borrowing base. A sustained material decline in prices from historical average prices could reduce our borrowing base, thereby reducing the bank credit available to us, which could require that a portion, or all, of our bank debt be repaid.
Hedging transactions may limit our potential gains or cause us to lose money.
From time to time, we may enter into agreements to receive fixed prices on our oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, we will not benefit from such increases.
We are exposed to risks of loss in the event of nonperformance by our counterparties to our hedging arrangements. Some of our counterparties may be highly leveraged and subject to their own operating and regulatory risks. Despite our analysis, we may experience financial losses in our dealings with these and other parties with whom we enter into transactions as a normal part of our business activities. Any nonpayment or nonperformance by our counterparties could have a material adverse effect on our business, financial condition and results of operations.
Additionally, we may, due to circumstances beyond our control, be put in a position of over-hedging. If this occurs, our revenue could be adversely affected due to the necessity of buying gas at the current market rate in order to fulfill hedging sales obligations.
Market conditions or operation impediments may hinder our access to natural gas and oil markets or delay our production.
The marketability and price of oil and natural gas that we may produce, acquire or discover will be affected by numerous factors beyond our control. Our ability to market our natural gas may depend upon our ability to acquire space on pipelines that deliver crude oil and natural gas to commercial markets. This risk is somewhat mitigated by our 35% ownership of a gathering system in the Marcellus Shale in Pennsylvania. We may also be affected by extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, and many other aspects of the oil and natural gas business.
Investor sentiment towards climate change, fossil fuels, and sustainability could adversely affect our business and our share price.
There have been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to promote the divestment of shares of energy companies, as well as to pressure lenders and other financial services companies to limit or curtail activities with energy companies. If these efforts are successful, our stock price and our ability to access capital markets may be negatively impacted.
Members of the investment community are also increasing their focus on sustainability practices, including practices related to GHGs and climate change, in the energy industry. As a result, we may face increasing pressure regarding our sustainability disclosures and practices. Additionally, members of the investment community may screen companies such as ours for sustainability performance before investing in our shares.
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We are subject to complex laws and regulations, including environmental regulations that can have a material adverse effect on the cost, manner and feasibility of doing business.
Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels of government that may be amended from time to time. Our operations may require licenses and permits from various governmental authorities. There can be no assurance that we will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development at our projects. It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and natural gas companies of similar size.
Environmental and health and safety risks may adversely affect our business.
All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills and releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. Although we believe that we are in material compliance with current applicable environmental regulations, we cannot assure you that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect our financial condition, results of operations or prospects.
We must also conduct our operations in accordance with various laws and regulations concerning occupational safety and health. Currently, we do not foresee expending material amounts to comply with these occupational safety and health laws and regulations. However, since such laws and regulations are frequently changed, we are unable to predict the future effect of these laws and regulations.
Risks Related to 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. 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. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
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. 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. 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
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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. 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. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.
Risks Related to Internal Controls
For as long as we are an “emerging growth company,” we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to some other public companies.
As an “emerging growth company” as defined in the 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.
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. |
In addition, the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period for complying with new or revised accounting standards. We have elected to take advantage of the extended transition period, which allows us to delay the adoption of new or revised accounting standards until those standards apply to private companies. As a result of this election, our financial statements may not be comparable to public companies that comply with new or revised accounting standards.
Because of these exemptions, some investors may find our common shares less attractive, which may result in a less active trading market for our common shares, and our shares price may be more volatile.
If we fail to establish and maintain proper disclosure or internal controls, our ability to produce accurate financial statements and supplemental information or comply with applicable regulations could be impaired.
As we grow, we may be subject to growth-related risks including capacity constraints and pressure on our internal systems and controls. Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to train and manage our employee base.
We must maintain effective disclosure controls and procedures. We must also maintain effective internal controls over financial reporting or, at the appropriate time, our independent auditors will be unwilling or unable to provide us with an unqualified report on the effectiveness of our internal controls over financial reporting as required by Section 404(b) of
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the Sarbanes-Oxley Act, once we become subject to those requirements. If we fail to maintain effective controls, investors may lose confidence in our operating results, the price of our common shares could decline and we may be subject to litigation or regulatory enforcement actions.
Risks Related to Gathering System
Because of the natural decline in production from existing wells, our success depends on the Anchor Shippers’ economically developing the remaining Marcellus Shale reserves.
Our natural gas gathering system is dependent upon the level of production from natural gas wells, from which production will naturally decline over time. In order to maintain or increase throughput levels on our gathering system and compression facility, we must continually develop reserves within the Auburn GGS boundary or obtain new supplies external to the Auburn GGS boundary. Developing reserves within the system boundary is the priority as external natural gas volumes have a contractual gathering rate that is 25% of the Anchor Shipper rate. The primary factors affecting our ability to obtain new supplies of natural gas is the level of successful drilling activity from the Anchor Shippers, of which Epsilon is one, as well as our ability to compete for volumes from successful new wells drilled by third parties proximate to our system. If we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, throughput on our pipelines and the utilization rates of our compression facility would decline, which could have an adverse effect on our business, results of operations, financial position and cash flows. 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.
The gathering rate charged by the Auburn GGS is determined by a cost-of-service model whereby the Anchor Shippers in the system, of which Epsilon is one, dedicate acreage and reserves to the gas gathering system in exchange for the Auburn GGS owners agreeing to a contractual rate of return on invested capital. The term of this arrangement is 15 years commencing in 2012 and expiring in 2026 with an 18% rate of return. Each year, the Auburn GGS historical and forecast throughput, revenue, operating expenses and capital expenditures are entered into the cost-of-service model. The model then computes the new gathering rate that will yield the contractual rate of return to the Auburn GGS owners. In January 2027, the Auburn GGS will transition to a fixed gathering rate.
Under the cost-of-service model, if total throughput on the system is lower than forecasted in the prior year, the gathering rate will increase. The 2022 model forecasts 276 Bcf throughput from 2022-2026 (approximately 69% of current capacity at the 550 psig design suction pressure) which resulted in a $0.40 gathering rate. If the gathering rate on the Auburn GGS increases, it could result in reduced or deferred development in the Auburn GGS. In one unlikely scenario, if no further development activity beyond work in progress occurs in the Auburn GGS, forecast throughput from 2022-2026 is expected to decline to 205 Bcf (approximately 52% of current capacity at the 550 psig design suction pressure) resulting in a still acceptable $0.62 gathering rate. 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.
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. Many factors influence the size and duration of differentials including local supply / demand imbalances, seasonal fluctuations in demand, transportation availability and cost, as well as the regulatory environment as it pertains to constructing new transportation pipelines. In Northeast Pennsylvania, negative differentials have persisted for many years due to rapid increases in supply as a result of advances in well completion techniques. Despite substantial increases in local demand for natural gas coupled with pipeline expansions, optimizations, and new pipelines that have been brought into service, the natural gas differential in Northeast Pennsylvania remains significant. There is no guarantee that future demand or pipeline transportation projects will eliminate this differential, and it will therefore remain a significant risk to demand for transportation service on the Auburn GGS, and therefore Epsilon’s revenues and cash flows.
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We compete with other operators in our gas gathering energy businesses.
Although the Anchor Shippers have dedicated their acreage and reserves to the Auburn GGS, the Auburn GGS may not be chosen by other producers in these areas to gather and compress the natural gas extracted. We compete with other companies, including co-owners of the Auburn GGS who operate other systems, for any such production from non-Anchor Shippers on the basis of many factors, including but not limited to geographic proximity to the production, costs of connection, available capacity, rates and access to markets. Competition in natural gas gathering is based in large part on existing assets, reputation, efficiency, system reliability, gathering system capacity and pricing arrangements. Our key competitors in the natural gas gathering business include independent gas gatherers and major integrated energy companies. Alternate gathering facilities are available to non-Anchor Shippers we serve, and those producers may also elect to construct proprietary gas gathering systems. A significant increase in competition in the gas gathering industry could have a material adverse effect on our financial position, results of operations and cash flows.
Several of our assets 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. The age and condition of our assets could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our gathering rate and competitive position.
We are exposed to the credit risk of our customers and counterparties, and our credit risk management will not be able to completely eliminate such risk.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy, or may be required to make prepayments or provide security to satisfy credit concerns. However, our credit procedures and policies cannot completely eliminate customer and counterparty credit risk. Our customers and counterparties include natural gas producers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. In a low commodity price environment certain of our customers could be negatively impacted, causing them significant economic stress including, in some cases, to file for bankruptcy protection or to renegotiate contracts. To the extent one or more of our key customers commences bankruptcy proceedings, our contracts with the customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code, or may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties or otherwise do not take or are unable to take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness, and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivable. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows, and financial condition.
Prices for natural gas in Northeast Pennsylvania are volatile and are subject to significant discounts from pricing at Henry Hub. This discount and volatility has and could continue to adversely affect our financial results, cash flows, access to capital and ability to maintain our existing businesses.
Our revenues, operating results, and future rate of growth depend primarily upon the price of natural gas in Northeast Pennsylvania which is currently volatile and significantly discounted to natural gas at Henry Hub due to insufficient interstate pipeline capacity out of the region. This volatility and discount has adversely impacted reserve development in the past, and could do so again in the future. A slowing pace of or complete halt to the development of Anchor Shipper reserves will impact our financial results, cash flows, and access to capital.
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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. Production from existing wells with access to our gathering systems will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of the 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. Alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy could reduce demand for natural gas in our markets and have an adverse effect on our business. A failure to obtain access to sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Our operations are subject to operational hazards and unforeseen interruptions.
There are operational risks associated with gathering and compression of natural gas, including:
| ● | Hurricanes, tornadoes, floods, extreme weather conditions and other natural disasters; |
| ● | Aging infrastructure and mechanical problems; |
| ● | Damages to pipelines and pipeline blockages or other pipeline interruptions; |
| ● | Uncontrolled releases of natural gas, brine, or industrial chemicals; |
| ● | Operator error; |
| ● | Damage caused by third-party activity, such as operation of construction equipment; |
| ● | Pollution and other environmental risks; |
| ● | Fires, explosions, craterings, and blowouts; and |
| ● | Terrorist attacks on our facilities or those of other energy companies. |
Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial financial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of our precautions, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
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ITEM 1C. CYBERSECURITY
Risk Management and Strategy
The Company considers cybersecurity risks as part of our overall risk management process. The management team works closely with our IT consultants and IT auditors to ensure potential risks are mitigated within our systems.
The Company engages a third-party IT consulting firm and conducts an annual IT audit to test our risk management processes.
The Company, together with our IT consultants and auditors, has processes that thoroughly vet third-party service providers, continuously monitoring to ensure compliance with our cybersecurity standards.
The Company has not encountered cybersecurity threats that have materially impacted our business or operations.
Governance
The Company’s Board of Directors is aware of the impact of potential cybersecurity threats and stays in close contact with management in case a threat is identified.
The Audit Committee of the Board of Directors is the primary governing body that is tasked with the evaluation and confirmation of the Company’s cybersecurity threat mitigation processes. More specifically, they review the Company’s annual IT audits and discuss any potential threats in quarterly meetings.
The Chief Financial Officer, Chief Operating Officer, Controller, and Director – Finance are all involved in communications with our IT consultants and auditors. The Chief Financial Officer notifies the Audit Committee and Chief Executive Officer of any cybersecurity threats.
ITEM 2. PROPERTIES.
The information required by Item 2 is contained in ‘‘Item 1. Business – Properties.’’
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 asserted that Chesapeake had failed to cooperate with Epsilon’s efforts to develop resources in the Auburn Development, located in North-Central Pennsylvania, as required under both the settlement agreement and JOAs.
Epsilon requested a preliminary injunction but was unsuccessful in obtaining that injunction. Epsilon filed a motion to amend its original Complaint. Chesapeake opposed. The Court ruled in Epsilon’s favor and allowed Epsilon’s amendment. Chesapeake moved to dismiss the amended Complaint. The Court granted the motion to dismiss on a narrow issue without prejudice to Epsilon’s right to file a new lawsuit based on new proposals made after the Court’s decision. Epsilon filed a motion for reconsideration of that decision, but the court denied the motion for reconsideration on January 18, 2022.
Epsilon filed a notice of appeal on February 15, 2022 challenging the District Court's rulings in the case. Following the Third Circuit's ruling to remand the case back to District court, Epsilon sought and was granted a dismissal of the case without prejudice in September 2023.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
The information required by Item 201 of Regulation S-K is contained in ‘‘Item 1. Business.’’
On 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. The awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act.
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. The awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act.
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. The awards were made under the 2020 Equity Incentive plan in accordance with Rule 701 promulgated under the Securities Act.
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. 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. The shares are accounted for as treasury shares until such a time as they are retired.
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 6. [RESERVED.]
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, 2023 and 2022 and for the years then ended together with accompanying notes.
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Overview
Epsilon Energy Ltd. (the “Company”) is a North American onshore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves. Our 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.
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. 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. 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 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. 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. 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. 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.
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. 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. 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. This measure of discounted future net cash flows does not include any estimate for future cash flows generated by our gathering system assets.
Results of Operations
The following review of operations for the periods presented below should be read in conjunction with our consolidated financial statements and the notes thereto.
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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.
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. 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. 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. 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. 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. 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. 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. 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. 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. This was the result of anchor shipper volumes, which pay the full gathering rate, increasing from 69% to 78% of total
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throughput in addition to a one-time compressor fee adjustment as a result of the operator’s internal audit of the gathering system. Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues, amounted to $1.4 million and $1.5 million, respectively, for the years ended December 31, 2023 and 2022.
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.
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. 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.
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.
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. 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.
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. 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. This increase was a result of the lower reserves causing an increased depletion rate in addition to four new producing wells in the Permian Basin.
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Loss (gain) on Sale of Assets
Year ended December 31, | ||||||
| 2023 |
| 2022 | |||
Loss (gain) on sale of assets | $ | 1,449,871 | $ | (221,642) | ||
For the year ended December 31, 2023, the Company had a loss on sale of assets of $1.4 million, compared to a gain of $0.2 million in 2022 due to the assets sold in 2023 having a larger net book value than the asset sold in 2022. Epsilon sold two Oklahoma assets in April 2023 and one Oklahoma asset in April 2022.
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.
G&A expenses were generally consistent compared to the same period in 2022, decreasing by $0.03 million, or 0%.
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. This increase was primarily due to the utilization of additional financial instruments with higher prevailing interest rates in 2023.
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. The increase is due to the front-end fees on our new credit facility put in place during 2023.
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. 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. For the year ended December 31, 2022, the Company paid net cash settlements of $1,225,837.
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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. The Company also added NYMEX HH swaps totaling 1.07 Bcf with a strike price of $3.1975 and Tennessee Z4 basis swaps totaling 1.07 Bcf with a strike price of ($1.145) to hedge a portion of the expected volumes for the contract period of April 2024 to October 2024.
In October 2023, the Company added NYMEX HH swaps totaling 0.38 Bcf with a strike price of $3.455 and Tennessee Z4 basis swaps totaling 0.38 Bcf with a strike price of ($0.81) to hedge a portion of the expected volumes for the contract period of November 2023 to March 2024. The Company also added NYMEX HH swaps totaling 0.535 Bcf with a strike price of $3.29 and Tennessee Z4 basis swaps totaling 0.535 Bcf with a strike price of ($1.20) to hedge a portion of the expected volumes for the contract period of April 2024 to October 2024.
At December 31, 2023, the Company had outstanding NYMEX HH swaps totaling 1.905 Bcf with a weighted average strike price of $3.25 and Tennessee Z4 basis swaps totaling 1.905 Bcf with a weighted average strike price of ($1.10) to hedge a portion of expected volumes for the contract period of January 2024 to October 2024.
Income Tax Expense
Year ended December 31, | ||||||
| 2023 |
| 2022 | |||
Income tax expense | $ | 3,200,447 | $ | 12,157,487 | ||
During the year ended December 31, 2023, income tax expense decreased by $9.0 million, or 74%, from the same period in 2022. 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. 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.
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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. It further provides investors a helpful measure for comparing operating performance on a "normalized" or recurring basis with the performance of other companies, without giving effect to certain non-cash expenses and other items. This provides management, investors and analysts with comparative information for evaluating us in relation to other natural gas and oil companies providing corresponding non-U.S. GAAP financial measures or that have different financing and capital structures or tax rates. These non-U.S. GAAP financial measures should be considered in addition to, but not as a substitute for, measures for financial performance prepared in accordance with U.S. GAAP. The table above sets forth a reconciliation of 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. For the year ended December 31, 2023 the primary uses of cash were the acquisition and development of upstream properties, investment in U.S. Treasury bills, the repurchase of shares of common stock, and the distribution of dividends. For the year ended December 31, 2022, cash was primarily used for the development of upstream properties, the repurchase of common stock, and the distribution of dividends.
At December 31, 2023, we had a working capital surplus of $33.2 million, a decrease of $16.0 million from the $49.2 million surplus at December 31, 2022. The surplus decreased from December 31, 2022 due to lower cash and short term investment balances. We anticipate that our current cash balance, short term investments, available borrowings, and cash flows from operations to be sufficient to meet our cash requirements for at least the next twelve months.
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.
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.
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. 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.
Credit Agreement
The Company closed a senior secured reserve based revolving credit facility on June 28, 2023 with Frost Bank as issuing bank and sole lender. The new facility replaced the Company’s previous facility. The initial commitment and borrowing base is $35 million (redetermined as of December 6, 2023), supported by the Company’s upstream assets in Pennsylvania and subject to semi-annual redeterminations with a maturity date of the earlier of June 28, 2027. Interest will be charged at the Daily Simple SOFR rate plus a margin of 3.25%. The facility is secured by the assets of the Company’s Epsilon Energy USA subsidiary (Borrower). There are currently no borrowings under the facility.
Under 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) |
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| ● | 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.
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. 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. 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. 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. 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.
On March 19, 2024, the Board of Directors authorized a new share repurchase program of up to 2,191,320 common shares, representing 10% of the current outstanding common shares of Epsilon, for an aggregate purchase price of not more than US $12.0 million. The program is pursuant to a normal course issuer bid and will be conducted in accordance with Rule 10b-18 under the Exchange Act. The program will commence on March 27, 2024 and end on March 26, 2025, unless the maximum amount of common shares is purchased before then or Epsilon provides earlier notice of termination.
Derivative Transactions
The Company has entered into hedging arrangements to reduce the impact of natural gas price volatility on operations. By removing the price volatility from a significant portion of natural gas production, the potential effects of changing prices on operating cash flows have been mitigated, but not eliminated. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we might otherwise receive from increases in commodity prices.
At December 31, 2023, Epsilon’s outstanding natural gas commodity swap contracts consisted of the following:
Weighted Average | ||||||||
Volume | Price ($/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. 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. 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. 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. 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.
Proved Natural Gas and Oil Reserves
Our engineers estimate proved natural gas and oil reserves in accordance with SEC regulations, which directly impact financial accounting estimates, including depreciation, depletion and amortization and impairments of proved properties and related assets. Proved reserves represent estimated quantities of crude oil and condensate, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved natural gas and oil reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Accordingly, there can be no assurance that ultimately, the reserves will be produced, nor can there be assurance that the proved undeveloped reserves will be developed within the period anticipated. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. We cannot predict the types of reserve revisions that will be required in future periods. For related discussion, see the sections titled “Risk Factors” and “Supplemental Information to Consolidated Financial Statements.”
Impairments
The carrying value of unproved and proved oil and natural gas properties and gathering system assets are reviewed for impairment whenever events indicate that the carrying amounts for those assets may not be recoverable. Such indicators include changes in our business plans, changes in commodity prices leading to unprofitable performance, and, for natural gas and oil properties, significant downward revisions of estimated proved reserve quantities or significant increases in the estimated development costs.
We compare expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the carrying value of the asset. If the expected undiscounted future cash flows, based on our estimates of (and assumptions regarding) future oil and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the carrying value of the asset, the carrying value is reduced to fair value. Fair value is generally calculated using the “Income Approach” based on estimated discounted net cash flows. Estimates of future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. In addition, such assumptions and estimates are reasonably likely to change in the future. Significant
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. 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. 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. 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. ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. For our upstream properties, these obligations consist of estimated future costs associated with the plugging and abandonment of natural gas and oil wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. For our gathering system, these obligations consist of estimated future costs associated with the removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the natural gas and oil or gathering system asset. The initial recognition of an ARO fair value requires that management make numerous assumptions regarding such factors as the amounts and timing of settlements; the credit-adjusted risk-free discount rate; and the inflation rate. In periods subsequent to the initial measurement of an ARO, period-to-period changes are recognized in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the natural gas and oil property or gathering system asset.
Income Taxes
Tax regulations and legislation in the U.S. and Canada are subject to change and differing interpretations requiring judgment. We compute income taxes using the asset-and-liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities, as well as loss and tax credit carryforwards. Changes in tax rates and laws are recognized in income in the period such changes are enacted.
We establish a valuation allowance if, based on available evidence, it is more likely than not that some or all of the deferred tax assets will not be realized. 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. 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
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Our earnings and cash flow are significantly affected by changes in the market price of commodities. The prices of oil and natural gas can fluctuate widely and are influenced by numerous factors such as demand, production levels, and world political and economic events and the strength of the U.S. dollar relative to other currencies. Should the price of oil or natural gas decline substantially, the value of our assets could fall dramatically, impacting our future options and exploration and development activities, along with our gas gathering system revenues. In addition, our operations are exposed to market risks in the ordinary course of our business, including interest rate and certain exposure as well as risks relating to changes in the general economic conditions in the United States.
Gathering System Revenue Risk
The Auburn Gas Gathering System lies within the Marcellus 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.
Derivative Contracts
The Company’s financial results and condition depend on the prices received for natural gas production. Natural gas prices have fluctuated widely and are determined by economic and political factors. Supply and demand factors, including weather, general economic conditions, the ability to transport the gas to other regions, as well as conditions in other natural gas regions, impact prices. Epsilon has established a hedging strategy and may manage the risk associated with changes in commodity prices by entering into various derivative financial instrument agreements and physical contracts. Although these commodity price risk management activities could expose the Company to losses or gains, entering into these contracts helps to stabilize cash flows and support the Company’s capital spending program.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Our consolidated balance sheets as of December 31, 2023 and 2022, and the consolidated statements of operations and comprehensive income, changes in shareholders’ equity and cash flows for years ended December 31, 2023 and 2022 included in this annual report have been prepared in accordance with U.S. GAAP.
41
Report of Independent Registered Public Accounting Firm
Shareholders and Board of Directors
Epsilon Energy Ltd.
Houston, Texas
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Epsilon Energy Ltd. (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations and comprehensive income, changes in shareholders’ equity, and cash flows for each of the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/
We have served as the Company’s auditor since 2017.
March 20, 2024
42
EPSILON ENERGY LTD.
Consolidated Balance Sheets
| December 31, |
| December 31, | |||
2023 | 2022 | |||||
ASSETS | ||||||
Current assets | ||||||
Cash and cash equivalents | $ | | $ | | ||
Accounts receivable | | | ||||
Short term investments | | | ||||
Fair value of derivatives | | | ||||
Prepaid income taxes | | | ||||
Other current assets | | | ||||
Operating lease right-of-use assets | | | ||||
Total current assets | | | ||||
Non-current assets | ||||||
Property and equipment: | ||||||
Oil and gas properties, successful efforts method | ||||||
Proved properties | | | ||||
Unproved properties | | | ||||
Accumulated depletion, depreciation, amortization and impairment | ( | ( | ||||
Total oil and gas properties, net | | | ||||
Gathering system | | | ||||
Accumulated depletion, depreciation, amortization and impairment | ( | ( | ||||
Total gathering system, net | | | ||||
Land | | | ||||
Buildings and other property and equipment, net | | | ||||
Total property and equipment, net | | | ||||
Other assets: | ||||||
Operating lease right-of-use assets, long term | | | ||||
Restricted cash | | | ||||
Prepaid drilling costs | | | ||||
Total non-current assets | | | ||||
Total assets | $ | | $ | | ||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||
Current liabilities | ||||||
Accounts payable trade | $ | | $ | | ||
Gathering fees payable | | | ||||
Royalties payable | | | ||||
Accrued capital expenditures | | | ||||
Accrued compensation | | | ||||
Other accrued liabilities | | | ||||
Fair value of derivatives | | | ||||
Operating lease liabilities | | | ||||
Total current liabilities | | | ||||
Non-current liabilities | ||||||
Asset retirement obligations | | | ||||
Deferred income taxes | | | ||||
Operating lease liabilities, long term | | | ||||
Total non-current liabilities | | | ||||
Total liabilities | | | ||||
Commitments and contingencies (Note 11) | ||||||
Shareholders' equity | ||||||
Preferred shares, | | | ||||
Common shares, | | | ||||
Treasury shares, at cost, | ( | | ||||
Additional paid-in capital | | | ||||
Accumulated deficit | ( | ( | ||||
Accumulated other comprehensive income | | | ||||
Total shareholders' equity | | | ||||
Total liabilities and shareholders' equity | $ | | $ | | ||
The accompanying notes are an integral part of these consolidated financial statements
43
EPSILON ENERGY LTD.
Consolidated Statements of Operations and Comprehensive Income
Year ended December 31, | ||||||
| 2023 |
| 2022 | |||
Revenues from contracts with customers: | ||||||
Gas, oil, NGL, and condensate revenue | $ | | $ | | ||
Gas gathering and compression revenue | | | ||||
Total revenue | | | ||||
Operating costs and expenses: | ||||||
Lease operating expenses | | | ||||
Gathering system operating expenses | | | ||||
Development geological and geophysical expenses | | | ||||
Depletion, depreciation, amortization, and accretion | | | ||||
Loss (gain) on sale of oil and gas properties | | ( | ||||
General and administrative expenses: | ||||||
Stock based compensation expense | | | ||||
Other general and administrative expenses | | | ||||
Total operating costs and expenses | | | ||||
Operating income | | | ||||
Other income (expense): | ||||||
Interest income | | | ||||
Interest expense | ( | ( | ||||
Gain on derivative contracts | | | ||||
Other income (expense), net | | ( | ||||
Other income, net | | | ||||
Net income before income tax expense | | | ||||
Income tax expense | | | ||||
NET INCOME | $ | | $ | | ||
Currency translation adjustments | ( | ( | ||||
Unrealized gain on securities | | | ||||
NET COMPREHENSIVE INCOME | $ | | $ | | ||
Net income per share, basic | $ | | $ | | ||
Net income per share, diluted | $ | | $ | | ||
Weighted average number of shares outstanding, basic | | | ||||
Weighted average number of shares outstanding, diluted | | | ||||
The accompanying notes are an integral part of these consolidated financial statements
44
EPSILON ENERGY LTD.
Consolidated Statements of Changes in Shareholders’ Equity
|
|
|
|
|
| Accumulated |
|
| ||||||||||||||
Other | Total | |||||||||||||||||||||
Common Shares Issued | Treasury Shares | Additional | Comprehensive | Accumulated | Shareholders' | |||||||||||||||||
Shares | Amount | Shares | Amount | paid-in Capital | Income | Deficit | Equity | |||||||||||||||
Balance at December 31, 2021 | | $ | | ( | $ | ( | $ | | $ | | $ | ( | $ | | ||||||||
Net income | — | — | — | — | — | — | | | ||||||||||||||
Dividends | — | — | — | — | — | — | ( | ( | ||||||||||||||
Stock-based compensation expense | — | — | — | — | | — | — | | ||||||||||||||
Buyback of common shares | — | — | ( | ( | — | — | — | ( | ||||||||||||||
Retirement of treasury shares | ( | ( | | | — | — | — | — | ||||||||||||||
Exercise of stock options | | | — | — | — | — | — | | ||||||||||||||
Vesting of shares of restricted stock | | — | — | — | — | — | — | — | ||||||||||||||
Other comprehensive loss | — | — | — | — | — | ( | — | ( | ||||||||||||||
Balance at December 31, 2022 | | $ | | — | $ | — | $ | | $ | | $ | ( | $ | | ||||||||
Net income | — | — | — | — | — | — | | | ||||||||||||||
Dividends | — | — | — | — | — | — | ( | ( | ||||||||||||||
Stock-based compensation expense | — | — | — | — | | — | — | | ||||||||||||||
Buyback of common shares | — | — | ( | ( | — | — | — | ( | ||||||||||||||
Retirement of treasury shares | ( | ( | | | — | — | — | — | ||||||||||||||
Exercise of stock options | | | — | — | — | — | — | | ||||||||||||||
Vesting of shares of restricted stock | | — | — | — | — | — | — | — | ||||||||||||||
Other comprehensive loss | — | — | — | — | — | ( | — | ( | ||||||||||||||
Balance at December 31, 2023 | | $ | | ( | $ | ( | $ | | $ | | $ | ( | $ | | ||||||||
The accompanying notes are an integral part of these consolidated financial statements
45
EPSILON ENERGY LTD.
Consolidated Statements of Cash Flows
Year ended December 31, | ||||||
| 2023 |
| 2022 | |||
Cash flows from operating activities: | ||||||
Net income | $ | | $ | | ||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||
Depletion, depreciation, amortization, and accretion | | | ||||
Accretion of discount on available for sale securities | ( | | ||||
Loss (gain) on sale of oil and gas properties | | ( | ||||
Gain on derivative contracts | ( | ( | ||||
Settlement received (paid) on derivative contracts | | ( | ||||
Settlement of asset retirement obligation | ( | ( | ||||
Stock-based compensation expense | | | ||||
Deferred income tax expense | | | ||||
Changes in assets and liabilities: | ||||||
Accounts receivable | | ( | ||||
Prepaid income taxes | | | ||||
Other assets and liabilities | | ( | ||||
Accounts payable, royalties payable and other accrued liabilities | ( | | ||||
Income taxes payable | | ( | ||||
Net cash provided by operating activities | | | ||||
Cash flows from investing activities: | ||||||
Additions to unproved oil and gas properties | ( | ( | ||||
Additions to proved oil and gas properties | ( | ( | ||||
Additions to gathering system properties | ( | ( | ||||
Additions to land, buildings and property and equipment | ( | ( | ||||
Purchases of short term investments - held to maturity | ( | | ||||
Purchases of short term investments - available for sale | ( | | ||||
Proceeds from sales and maturities of short term investments | | | ||||
Proceeds from sale of oil and gas properties | | | ||||
Prepaid drilling costs | ( | | ||||
Net cash used in investing activities | ( | ( | ||||
Cash flows from financing activities: | ||||||
Buyback of common shares | ( | ( | ||||
Exercise of stock options | | | ||||
Dividends paid | ( | ( | ||||
Debt issuance costs | ( | | ||||
Net cash used in financing activities | ( | ( | ||||
Effect of currency rates on cash, cash equivalents, and restricted cash | ( | ( | ||||
(Decrease) increase in cash, cash equivalents, and restricted cash | ( | | ||||
Cash, cash equivalents, and restricted cash, beginning of period | | | ||||
Cash, cash equivalents, and restricted cash, end of period | $ | | $ | | ||
Supplemental cash flow disclosures: | ||||||
Income taxes paid | $ | | $ | | ||
Interest paid | $ | | $ | | ||
Non-cash investing activities: | ||||||
Change in proved properties accrued in accounts payable and accrued liabilities | $ | | $ | ( | ||
Change in gathering system accrued in accounts payable and accrued liabilities | $ | | $ | ( | ||
Asset retirement obligation asset additions and adjustments | $ | | $ | | ||
The accompanying notes are an integral part of these consolidated financial statements
46
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022
1. Description of Business
Epsilon Energy Ltd. (the “Company” or “Epsilon” or “we”) was incorporated under the laws of the Province of Alberta, Canada on
2. Basis of Preparation
Principles of Consolidation
The Company’s consolidated financial statements include the accounts of the Company and its wholly owned subsidiary, Epsilon Energy USA, Inc. and its wholly owned subsidiaries, Epsilon Midstream, LLC, Epsilon Operating, LLC, Dewey Energy GP, LLC, Dewey Energy Holdings, LLC and Altolisa Holdings, LLC. With regard to the gathering system, in which Epsilon owns an undivided interest in the asset, proportionate consolidation accounting is used. All inter-company transactions have been eliminated.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas reserves and related cash flow estimates used in impairment tests of oil and natural gas and gathering system properties, asset retirement obligations, accrued natural gas and oil revenues and operating expenses, accrued gathering system revenues and operating expenses, as well as the valuation of commodity derivative instruments. Actual results could differ from those estimates.
3. Summary of Significant Accounting Policies
Cash, Cash Equivalents and Restricted Cash
Cash and cash equivalents include cash on hand and short-term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
Restricted cash consists of amounts deposited to back bonds or letters of credit for potential well liabilities. The Company presents restricted cash with cash and cash equivalents in the Consolidated Statements of Cash Flows.
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported in the Consolidated Balance Sheets to the total of the amounts in the Consolidated Statements of Cash Flows as of December 31, 2023 and 2022:
| December 31, |
| December 31, | |||
2023 | 2022 | |||||
Cash and cash equivalents | $ | | $ | | ||
Restricted cash included in other assets | | | ||||
Cash, cash equivalents, and restricted cash in the statement of cash flows | $ | | $ | | ||
47
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
Oil and Natural Gas Properties
Epsilon accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting.
Oil and natural gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and natural gas properties. Lease delay rentals are expensed as incurred.
Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether Epsilon has discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized (see Note 5).
Depreciation, depletion and amortization of the cost of proved oil and natural gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.
When circumstances indicate that proved (developed and undeveloped) oil and natural gas properties may be impaired, Epsilon compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the carrying value of the asset. If the expected undiscounted future cash flows, based on Epsilon’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the carrying value of the asset, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach which considers estimated discounted future cash flows.
Gas Gathering System Properties
Epsilon’s
Depreciation, depletion and amortization of the cost of gathering system properties is calculated using the unit-of- production method. The reserve base used to calculate depreciation, depletion and amortization for the gathering system includes only proved Pennsylvania natural gas developed reserves.
When circumstances indicate that the gathering system properties may be impaired, Epsilon compares expected undiscounted future cash flows related to the gathering system to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach, which considers estimated discounted future cash flows.
Revenue Recognition
Revenues are comprised primarily of sales of natural gas and to a much lesser degree crude oil and NGLs, along with the revenue generated from the Company’s ownership interest in the gas gathering system in the Auburn field in Northeastern Pennsylvania.
Revenue recognition is evaluated through the following five steps: (i) identification of the contract, or contracts, with a customer; (ii) identification of the performance obligations in the contract; (iii) determination of the transaction price; (iv) allocation of the transaction price to the performance obligations in the contract; and (v) recognition of revenue when or as a performance obligation is satisfied.
48
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
Accounting Policies
Revenue is recognized when performance obligations under the terms of a contract with a customer are satisfied. The Company recognizes upstream revenue at the point in time when control has been transferred to the customer, generally at the time natural gas reaches an agreed-upon delivery point and collectability is reasonably assured. Upstream revenue is generally based upon a fixed price, based on a market index, and is measured as the amount of consideration the Company expects to receive in exchange for the transferring of the natural gas. The services provided by the gas gathering system take place continuously and as a practical expedient, the revenues are recognized monthly for the volumes that are processed and transported for the upstream producers during that period of time. Revenue for the services performed are based on the rates outlined in the cost of service agreement that governs all volumes gathered and processed by the system. The gathering rates are adjusted, and fixed annually. Typically, the Company sells its natural gas directly to customers, under agreements with payment terms less than
Natural Gas Revenues
The Company’s natural gas purchase contracts are generally structured such that Epsilon commits and dedicates for sale its proportionate share of natural gas production per day to a purchaser. Natural gas is sold at a percentage of index prices of each component, less any stated deductions. Control transfers at the delivery point specified in the contract, which typically is stated as the inlet of the third-party sales transportation pipeline. The Company recognizes revenue proportionate to its entitled share of volumes sold. Currently, the vast majority of Epsilon’s natural gas production comes from the Marcellus Field in Northeastern Pennsylvania.
Epsilon uses a third-party service for its natural gas marketing. In this capacity, the third-party is responsible for carrying out marketing activities such as submission of nominations, receipt of payments, submission of invoices and negotiation of contracts. Commissions payable to the third-party broker for these services are treated as lease operating expenses in the financial statements.
Gas Gathering System Revenue
The Company has a
Oil and Other Liquids Revenue
The source of the Company’s oil and other liquids revenue is its ownership interest in wells in the Permian Basin and Oklahoma. The Company does not operate the wells and has elected not to receive its proportionate share of the production. As such, under the Joint Operating Agreement, the operators have control of the marketing of this production at current market prices and remits our net revenue interest less taxes and fees on a monthly basis. The Company recognizes revenue with a monthly accrual of its proportionate share of volumes produced at an estimated market price.
Accounts Receivable and Other
Oil, natural gas liquid and natural gas receivables consist of amounts due from purchasers for commodity sales from our revenue interest in the leases in Northeastern Pennsylvania, the Permian Basin, and Oklahoma. Payments from purchasers are typically due by the last day of the month following the month of delivery. Gathering fee revenue consists of fees due from the operator of the Auburn GGS, as an agent for the Company fulfilling the operations of the gathering system. Payments from the operator are typically due
49
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
Buildings and Other Property and Equipment
Buildings are depreciated on a straight-line basis over the estimated useful life of the property,
Other property and equipment consists of computer hardware and software, and furniture and fixtures. Other property and equipment is generally depreciated on a straight-line basis over the estimated useful lives of the property and equipment, which range from
Financial Instruments and Fair Value
Epsilon’s financial instruments consist of cash and cash equivalents, short term investments, restricted cash, commodity derivative contracts, accounts receivable, accounts payable, and long-term debt.
The Company classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instrument.
Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.
Level 3—Valuations in this level are those with inputs for the asset or liability that are not based on observable market data. The Company makes its own assumptions about how market participants would price the assets and liabilities.
Cash and cash equivalents, restricted cash, accounts receivable, and accounts payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The Company’s revolving line of credit has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates and the applicable margins represent market rates. The revolving line of credit is classified within Level 2 of the fair value hierarchy.
The Company has investments in U.S. Treasury Bills, which mature over a period between 3 and 12 months and are classified as short term investments. The U.S. Treasury Bills are carried at fair value. The U.S. Treasury Bills are classified within Level 1 of the fair value hierarchy.
Commodity derivative instruments consist of NYMEX HH swap and basis swap contracts for natural gas. The Company’s derivative contracts are valued based on a marked to market approach. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.
Derivative Instruments
The Company enters into derivative contracts to hedge price risk associated with a portion of natural gas production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated, which has, and could, result in over-hedged volumes. Natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the NYMEX or the published natural gas index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. Our derivative transactions have included the following:
| ● | Fixed-price swaps—where a fixed-price is received for production and a variable market price is paid to the contract counterparty. |
50
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
| ● | Basis swap contracts—which guarantee a specified price differential between the price at Henry Hub and our physical pricing points. If the settled price differential is greater than the swapped basis, then we receive a payment from the counterparty in the amount of the difference between the two. If the settled price differential is less than the swapped basis, then we make a payment to the counterparty for the difference between the two. |
| ● | Two-way collar contracts—which guarantee a specified price range for NYMEX by using the proceeds of selling a call option at a specified strike price (the “Ceiling”) to finance the purchase of a put option at a specified strike price (the “Floor”). |
Derivative instruments are recorded on the consolidated balance sheets at fair value as either current or non-current assets or liabilities based on their anticipated settlement date. Gains or losses on derivative contracts are recorded as gain (loss) on commodity contracts in the consolidated statements of operations and comprehensive income. Hedge accounting is not used for our derivative assets and liabilities.
Asset Retirement Obligations
The Company records a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method of the asset’s useful life. Recognized asset retirement obligations relate to the plugging and abandonment of oil and natural gas wells and decommissioning of the gas gathering system. Management reviews the estimates of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate. These adjustments are recorded to the asset retirement obligations with an offsetting change to oil and gas properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the forecast inflation due to the passage of time, which is recorded in depreciation, depletion, amortization, and accretion expense in the consolidated statements of operations and comprehensive income.
Concentrations of Credit Risk
Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents, short term investments, accounts receivable and derivative contracts. Exposure to credit risk associated with these instruments is controlled by (i) placing assets and other financial interests with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring paying history, although the Company does not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties with a legal right of offset.
At December 31, 2023 and 2022, the cash and cash equivalents and short term investments were primarily concentrated in
For the year ended December 31, 2023, the Company had
Geographic Locations of Operations
Approximately
51
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
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.
Income Taxes
Deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. Epsilon assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate (see Note 10).
Foreign Currency Transactions
Even though the Canadian dollar is the functional currency of Epsilon Energy Ltd. (the parent entity), the United States dollar is the reporting currency for all of Epsilon’s consolidated subsidiaries. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. Gains and losses on translation of balances denominated in Canadian dollars are included in accumulated other comprehensive income.
Stock-Based Compensation
The Company mainly estimates the fair value of all stock options awarded to employees and directors using the Black-Scholes option pricing model. Other models are used for options with more complex vesting criteria. Compensation expense and a corresponding increase to additional paid-in capital are recorded over the vesting period based on the fair value of the options granted using a graded vesting approach. When stock options are exercised for common shares, consideration paid by the stock option holders and additional paid-in capital associated with the stock options are recorded. The Company estimates a forfeiture rate and adjusts the corresponding expense each period based on an updated forfeiture estimate (see Note 7).
The Company has issued time-based restricted stock and performance share units (“PSU”) to employees and directors of the Company. The fair value of the time-based restricted stock is determined using the fair value of the Company’s common shares on the date of grant. The fair value of the PSUs is determined by the performance requirements. These awards vest ratably over a
Leases
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)”, which significantly changed accounting for leases by requiring that lessees recognize a right of use asset and a related lease liability representing the obligation to make lease payments, for all lease transactions with terms greater than one year. Additional disclosures about an entity’s lease transactions are also required. ASU 2016-02 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant, or equipment (an identified asset) for a period of time in exchange for consideration.” The Company adopted ASU 2016-02 as of January 1, 2022. We have chosen the transition using the comparative report at adoption method of applying the provisions of the new standard at the beginning of the period of adoption instead of the earliest comparative period presented in the consolidated financial statements. There was no material effect from the adoption.
The Company leases office space to be used for general, administrative, and executive offices with terms typically ranging from to
52
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
The Company determines whether a contract is, or contains, a lease at inception of the contract and whether that lease meets the classification criteria of a finance or operating lease. When available, the Company uses the rate implicit in the lease to discount lease payments to present value; however, most of the Company’s leases do not provide a readily determinable implicit rate. Therefore, the Company must discount lease payments based on an estimate of its incremental borrowing rate based on prevailing financial market conditions at the later of date of adoption or lease commencement, credit analysis of comparable companies and management judgments to determine the present values of its lease payments (see Note 12).
Joint Interests
The majority of the Company’s oil and natural gas exploration, development and production activities, and the gathering system, are conducted jointly with others and, accordingly, these financial statements reflect only the Company’s proportionate interest in such jointly controlled assets.
Recently Issued Accounting Standards
The Company, an emerging growth company (“EGC”), has elected to take advantage of the benefits of the extended transition period provided for in Section 7(a)(2)(B) of the Securities Act, for complying with new or revised accounting standards which allows the Company to defer adoption of certain accounting standards until those standards would otherwise apply to private companies.
In June 2016 the FASB issued Accounting Standards Update (“ASU”) 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which removes the thresholds that companies apply to measure credit losses on financial instruments measured at amortized cost, such as loans, receivables, and held-to-maturity debt securities. Under current U.S. GAAP, companies generally recognize credit losses when it is probable that the loss has been incurred. The revised guidance removes all recognition thresholds and requires companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the Company expects to collect over the instrument’s contractual life. Epsilon has adopted ASU 2016-13 as of January 1, 2023. There was no impact from the adoption of this ASU.
In 2020, the FASB issued ASU 2020-04, Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which, for a limited period of time, adds Accounting Standards Codification (“ASC”) 848 to provide entities with certain practical expedients and exceptions from applying modification accounting if certain criteria are met. The amendments are designed to reduce operational challenges that entities will face in applying modification accounting to all contracts that will be revised due to reference rate reform. The guidance in ASC 848 was triggered by the pending discontinuation of certain benchmark reference rates and, in some cases, their replacement by new rates that are more observable or transaction-based and, therefore, less susceptible to manipulation, than certain interest-rate benchmark reference rates commonly used today, including the London Interbank Offered Rate (“LIBOR”). This process of reference rate reform will require entities to modify certain contracts by removing the discontinued rates and including new rates. Epsilon has adopted ASU 2020-04 as of January 1, 2023. There was no impact from the adoption of this ASU.
In July 2023, the FASB issued ASU No. 2023-03 to amend various SEC paragraphs in the ASC to primarily reflect the issuance of SEC Staff Accounting Bulletin No. 120. ASU No. 2023-03, “Presentation of Financial Statements (Topic 205), Income Statement - Reporting Comprehensive Income (Topic 220), Distinguishing Liabilities from Equity (Topic 480), Equity (Topic 505), and Compensation - Stock Compensation (Topic 718): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 120 (“SAB 120”), SEC Staff Announcement at the March 24, 2022 Emerging Issues Task Force (“EITF”) Meeting, and Staff Accounting Bulletin Topic 6.B, Accounting Series Release 280 - General Revision of Regulation S-X: Income or Loss Applicable to Common Stock.” ASU 2023-03 amends the ASC for SEC updates pursuant to SEC Staff Accounting Bulletin No. 120; SEC Staff Announcement at the March 24, 2022 EITF Meeting; and Staff Accounting Bulletin Topic 6.B, Accounting Series Release 280 – General Revision of Regulation S-X; Income or Loss Applicable to Common Stock. SAB 120 provides guidance on the measurement and disclosure of share-based awards shortly before announcing material nonpublic information. These updates were immediately effective and did not have any impact on our consolidated financial statements.
53
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
In October 2023, the FASB issued ASU 2023-06, Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative, to amend certain disclosure and presentation requirements.
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. This ASU required disclosure of incremental segment information, primarily through enhanced disclosures about significant segment expenses and amounts for each reportable segment on an annual and interim basis. This guidance is effective for fiscal years beginning after December 15, 2023 and interim periods with fiscal years beginning after December 15, 2024. The Company is currently assessing the potential effects of the standard.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires public entities, on an annual basis, to disclose disaggregated information about a reporting entity’s effective tax rate reconciliation, using both percentages and reporting currency amounts for specific standardized categories, as well as disclosure of income taxes paid disaggregated by jurisdiction. ASU 2023-09 is effective for fiscal years beginning after December 15, 2024, with early adoption permitted. The Company is currently assessing the potential effects of this standard.
4. Short Term Investments
Short term investments are highly liquid investments with original maturities between three and twelve months. The Company’s short term investments consist of US Treasury bills. These investments were previously classified as held-to-maturity. In May 2023, as a result of a change in business investment strategy, the Company transferred all of its held-to-maturity short term investments to the available-for-sale category. The securities transferred had a total amortized cost of $
Available-for-sale short term investments are reported at fair value in the Consolidated Balance Sheets. Unrealized gains and losses are excluded from earnings and are reported in accumulated other comprehensive income in the consolidated statements of operations and comprehensive income.
The following table summarizes the available-for-sale short term investments as of December 31, 2023 and 2022.
| December 31, 2023 |
| December 31, 2022 | |||||||||||||||
Amortized | Unrealized | Fair | Amortized | Unrealized | Fair | |||||||||||||
| Cost |
| Gains |
| Value |
| Cost |
| Losses |
| Value | |||||||
U.S. Treasury Bills | $ | | $ | | $ | | $ | | $ | | $ | | ||||||
During the year ended December 31, 2023, the Company sold securities with a carrying amount of $
54
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
5. Property and Equipment
The following table summarizes the Company’s property and equipment at December 31, 2023 and 2022:
| December 31, |
| December 31, | |||
2023 | 2022 | |||||
Property and equipment: | ||||||
Oil and gas properties, successful efforts method | ||||||
Proved properties | $ | | $ | | ||
Unproved properties | | | ||||
Accumulated depletion, depreciation, amortization and impairment | ( | ( | ||||
Total oil and gas properties, net | | | ||||
Gathering system | | | ||||
Accumulated depletion, depreciation, amortization and impairment | ( | ( | ||||
Total gathering system, net | | | ||||
Land | | | ||||
Buildings and other property and equipment, net | | | ||||
Total property and equipment, net | $ | | $ | | ||
Asset Acquisitions
During the year ended December 31, 2023, Epsilon made the following
| ● | a |
| ● | a |
| ● | a |
Property Sale
During the year ended December 31, 2023, Epsilon sold
Property Impairment
Epsilon performs a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable. When indicators of impairment are present, the Company first compares 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 to the estimated fair values is required. This is determined based on discounted cash flow techniques using significant assumptions including production volumes, future commodity prices, and a market-specific weighted average cost of capital which are affected by expectations about future market and economic conditions. Additionally, U.S. GAAP requires that if an exploratory well is determined not to have found proved reserves, the costs incurred, net of any salvage value, are charged to expense. For unproved properties, such as leasehold costs, expected current and future market prices for similar assets are considered relative to carrying values in evaluating impairment.
55
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
6. Revolving Line of Credit
The Company closed a senior secured reserve based revolving credit facility on June 28, 2023 with Frost Bank as issuing bank and sole lender. The new facility replaced the Company’s previous facility. The initial commitment and borrowing base is $
Under the terms of the facility, the Company must adhere to the following financial covenants:
| ● | Current ratio of |
| ● | Leverage ratio of less than |
Additionally, if the leverage ratio is greater than
We were in compliance with the financial covenants of the agreement as of December 31, 2023
| Balance at |
| Balance at |
|
| |||||||
December 31, |
| December 31, | Current | |||||||||
| 2023 | 2022 |
| Borrowing Base |
| Interest Rate | ||||||
Revolving line of credit | $ | | $ | | $ | | SOFR + | |||||
7. Shareholders’ Equity
| (a) | Authorized shares |
The Company is authorized to issue an unlimited number of common shares with
| (b) | Purchases of Equity Securities |
On March 9, 2023, Epsilon’s Board of Directors (the “Board”) authorized a new share repurchase program of up to
The previous share repurchase program commenced on March 8, 2022. During the year ended December 31, 2022, we repurchased
56
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
was subsequently retired during the year ended December 31, 2022. In 2023, we repurchased and retired
In 2023, the Company repurchased
On March 19, 2024, the Board of Directors authorized a new share repurchase program of up to
| (c) | Equity Incentive Plan |
The Board adopted the 2020 Equity Incentive Plan (the “2020 Plan”) on July 22, 2020 subject to approval by Epsilon’s shareholders at Epsilon’s 2020 Annual General and Special Meeting of shareholders, which occurred on September 1, 2020 (the “Meeting”). Shareholders approved the 2020 Plan at the Meeting. Following Epsilon’s listing on the NASDAQ Global Market, the Board determined that it is in the best interest of the shareholders to approve a new incentive plan that is compliant with U.S. public company equity plan rules and practices that would replace Epsilon’s Amended and Restated 2017 Stock Option Plan (including its predecessors) and the Share Compensation Plan (collectively referred to as the “Predecessor Plans”). No further awards will be granted under the Predecessor Plans.
The 2020 Plan provides for incentive compensation in the form of stock options, stock appreciation rights, restricted stock and stock units, performance shares and units, other stock-based awards and cash-based awards. Under the 2020 Plan, Epsilon is authorized to issue up to
Restricted Stock Awards
For the year ended December 31, 2023,
The following table summarizes restricted stock for the years ended December 31, 2023 and 2022:
Year ended | Year ended | |||||||
December 31, 2023 | December 31, 2022 | |||||||
Number of | Weighted | Number of | Weighted | |||||
Restricted | Average | Restricted | Average | |||||
Shares | Remaining Life | Shares | Remaining Life | |||||
| Outstanding |
| (years) |
| Outstanding |
| (years) | |
Balance non-vested Restricted Stock at beginning of period | | | ||||||
Granted | | | ||||||
Vested | ( | — | ( | — | ||||
Balance non-vested Restricted Stock at end of period | | | ||||||
Stock compensation expense for the granted Restricted Stock is recognized over the vesting period. Stock compensation expense recognized during the year ended December 31, 2023 was $
57
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
At December 31, 2023, the Company had unrecognized stock-based compensation related to these shares of $
Performance Share Unit Awards (“PSU”)
The Company historically granted PSUs, which are paid in stock to certain key employees. The PSUs will vest on the last day of the performance period. The number of PSUs that will ultimately vest is based on
| ● | The targets for the PSUs are based on (i) the relative total stockholder return (“TSR”) percentile ranking and (ii) the relative cash flow per debt adjusted share – growth (“CFDAS Growth”) percentile ranking of the Company, each as compared to the Company’s peer group as specified in the award agreement during the applicable |
| ● | Cash Flow per Debt Adjusted Share (“CFDAS”) is defined as EBITDA (earnings before interest, taxes, depreciation and amortization) divided by the sum of the (i) the total debt plus the value of preferred stock minus cash and the amount of dividends paid for the year divided by the share price at the end of the year; and (ii) the actual share count at year end. |
| ● | The vesting of each PSU Award will be based |
| ● | The recipient of the award must be employed with the Company at the time of vesting. |
The number of shares ultimately issued under these awards can range from
The following table summarizes PSUs for the years ended December 31, 2023 and 2022:
Year ended | Year ended | |||||||
December 31, 2023 | December 31, 2022 | |||||||
Number of | Weighted | Number of | Weighted | |||||
Performance | Average | Performance | Average | |||||
Shares | Remaining Life | Shares | Remaining Life | |||||
| Outstanding |
| (years) |
| Outstanding |
| (years) | |
Balance non-vested PSUs at beginning of period | | | ||||||
Vested | ( | — | ( | — | ||||
Balance non-vested PSUs at end of period | — | | ||||||
Stock compensation expense for the granted PSUs is recognized over the vesting period. Stock compensation expense recognized during the year ended December 31, 2023 related to PSUs was $
At December 31, 2023, the Company had
Stock Options
As of December 31, 2023, the Company had outstanding stock options covering
The following table summarizes stock option activity for the years ended December 31, 2023 and 2022:
58
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
Year ended | Year ended | ||||||||||
December 31, 2023 | December 31, 2022 | ||||||||||
Weighted | Weighted | ||||||||||
Number of | Average | Number of | Average | ||||||||
Options | Exercise | Options | Exercise | ||||||||
Exercise price in US$ |
| Outstanding |
| Price |
| Outstanding |
| Price (1) | |||
Balance at beginning of period | | $ | | | $ | | |||||
Exercised | ( | $ | | ( | $ | | |||||
Expired/Forfeited | — | $ | — | ( | $ | | |||||
Balance at period-end | | $ | | | $ | | |||||
Exercisable at period-end | | $ | | | $ | | |||||
At December 31, 2023 and 2022, the Company had unrecognized stock-based compensation related to these options of
During the years ended December 31, 2023 and 2022, the Company awarded
The following table summarizes information for stock options outstanding at December 31, 2023:
| Weighted | |||||
Average | ||||||
Number of | Number of | Remaining | ||||
Options | Options | Contractual Life | ||||
Exercise Price |
| Outstanding |
| Exercisable |
| (in years) |
As of December 31, 2023 | ||||||
$ |
| |
| |
| |
Total |
| |
| |
|
The value of the options was recorded as stock-based compensation expense, with an offsetting amount to additional paid-in capital based on the vesting terms. Stock-based compensation expense for the options, for the years ended December 31, 2023 and 2022 was
8. Revenue Recognition
Revenues are comprised primarily of sales of natural gas, oil and NGLs, along with the revenue generated from the Company’s ownership interest in the gas gathering system in the Auburn field in Northeastern Pennsylvania.
Overall, product sales revenue generally is recorded in the month when contractual delivery obligations are satisfied, which occurs when control is transferred to the Company’s customers at delivery points based on contractual terms and conditions. In addition, gathering and compression revenue generally is recorded in the month when contractual service obligations are satisfied, which occurs as control of those services is transferred to the Company’s customers. Gathering System revenues derived from Epsilon’s production, which have been eliminated from total gathering system revenues (“elimination entry”), amounted to $
59
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
The following table details revenue for the years ended December 31, 2023 and 2022:
Year Ended December 31, | ||||||
| 2023 |
| 2022 | |||
Operating revenue | ||||||
Natural gas | $ | | $ | | ||
Natural gas liquids | | | ||||
Oil and condensate | | | ||||
Gathering and compression fees (1) | | | ||||
Total operating revenue | $ | | $ | | ||
| (1) | Net of the elimination entry |
Product Sales Revenue
The Company enters into contracts with third party purchasers to sell its natural gas, oil, NGLs and condensate production. Under these product sales arrangements, the sale of each unit of product represents a distinct performance obligation. Product sales revenue is recognized at the point in time that control of the product transfers to the purchaser based on contractual terms which reflect prevailing commodity market prices. To the extent that marketing costs are incurred by the Company prior to the transfer of control of the product, those costs are included in lease operating expenses on the Company’s consolidated statements of operations and comprehensive income.
Settlement statements for product sales, and the related cash consideration, are generally received from the purchaser within
Gas Gathering and Compression Revenue
The Company also provides natural gas gathering and compression services through its ownership interest in the gas gathering system in the Auburn field. For the provision of gas gathering and compression services, the Company collects its share of the gathering and compression fees per unit of gas serviced and recognizes gathering revenue over time using an output method based on units of gas gathered.
The settlement statement from the operator of the Auburn GGS is received
Allowance for Credit Losses
The Company records an allowance for credit losses on a case-by-case basis once there is evidence that collection is not probable. At December 31, 2023 and 2022, there were
The following table details accounts receivable as of December 31, 2023 and 2022:
| December 31, |
| December 31, |
| December 31, | ||||
2023 | 2022 | 2021 | |||||||
Accounts receivable | |||||||||
Natural gas and oil sales | $ | | $ | | $ | | |||
Joint interest billing | | | | ||||||
Gathering and compression fees | | | | ||||||
Commodity contract | | | | ||||||
Interest | | | | ||||||
Total accounts receivable | $ | | $ | | $ | | |||
60
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
9. Accumulated Other Comprehensive Income
Accumulated other comprehensive income includes certain transactions that have generally been reported in the consolidated statements of changes in shareholders’ equity. The activity in accumulated other comprehensive income during the years ended December 31, 2023 and 2022 consisted of the following:
Year Ended December 31, | |||||||
| 2023 |
| 2022 | ||||
Balance at beginning of period | $ | | $ | | |||
Translation loss | ( | ( | |||||
Unrealized gain on securities | | | |||||
Balance at end of period | $ | | $ | | |||
10. Income Taxes
Net income before income taxes is as follows for the periods indicated:
Year ended December 31, | ||||||
| 2023 |
| 2022 | |||
Foreign |
| $ | ( | $ | ( | |
U.S. |
| |
| | ||
$ | | $ | | |||
We file a federal income tax return in the United States, Canada, and various state and local jurisdictions.
We believe that we have appropriate support for the income tax positions taken and to be taken on the Company's tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company's tax returns are open to audit under the statute of limitations for the years ending December 31, 2020 through December 31, 2023.
The following tables present the Company’s current and deferred tax expense (benefit) for the periods indicated:
Year ended December 31, | ||||||
| 2023 |
| 2022 | |||
Current: | ||||||
Foreign | $ | | $ | | ||
Federal | | | ||||
State | | | ||||
Total current income tax expense | | | ||||
Deferred: | ||||||
Federal | | | ||||
State | ( | ( | ||||
Total deferred tax expense | | | ||||
Income tax expense | $ | | $ | | ||
The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate to the income tax provision in our financial statements. Our effective tax rate for 2023 differs from the statutory rate primarily due to states taxes, foreign withholding taxes, & the recognition of a valuation allowance on our Canadian and Oklahoma
61
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
state deferred tax assets. Our effective tax rate for 2022 differs from the statutory rate primarily due to states taxes & the recognition of a valuation allowance on our Canadian and Oklahoma state deferred tax assets.
Year Ended |
|
| Year Ended |
|
| ||||||
December 31, | Effective | December 31, | Effective | ||||||||
| 2023 |
| Tax Rate |
| 2022 |
| Tax Rate |
| |||
Income tax provision computed at the statutory federal tax rate | $ | |
| | % | $ | |
| | % | |
Difference in Canadian and U.S. tax rate |
| ( |
| ( | % |
| ( |
| ( | % | |
Adjustment of Canadian deferred tax balances | ( | ( | % | | | % | |||||
Valuation allowance on Canadian loss |
| |
| | % |
| |
| | % | |
Return to provision adjustment |
| |
| | % |
| ( |
| ( | % | |
State taxes |
| |
| | % |
| |
| | % | |
State valuation allowance | | | % | ( | ( | % | |||||
Foreign withholding on dividends | | | % | | | % | |||||
Miscellaneous other items |
| ( |
| ( | % |
| ( |
| ( | % | |
Income tax expense | $ | |
| | % | $ | |
| | % | |
Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.
Net deferred tax liabilities consisted of the following at December 31, 2023 and 2022:
As of December 31, | ||||||
| 2023 |
| 2022 | |||
Deferred tax assets: | ||||||
State net operating loss carryforwards | $ | | $ | | ||
Canadian net operating loss carryforwards |
| |
| | ||
ARO | | | ||||
Lease Liabilities | | | ||||
Unrealized derivatives/other |
| |
| | ||
Gross deferred tax assets |
| |
| | ||
Valuation allowance |
| ( |
| ( | ||
Total deferred tax assets |
| |
| | ||
Deferred tax liabilities: |
|
|
|
| ||
Oil and gas property |
| ( |
| ( | ||
Partnership |
| ( |
| ( | ||
ROU Assets | ( | | ||||
Unrealized derivatives/other | ( | ( | ||||
Gross deferred tax liabilities |
| ( |
| ( | ||
Net deferred tax liability | $ | ( | $ | ( | ||
As of December 31, 2023, we have
On August 16, 2022, legislation commonly known as the Inflation Reduction Act was signed into law. Among other things, the Inflation Reduction Act includes a 1% excise tax on corporate stock repurchases applicable to repurchases
62
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
after December 31, 2022, and also a new minimum tax based on book income. The Inflation Reduction Act did not have a material impact on our effective tax rate.
The Company does not have any material uncertain tax positions. The Company recognizes interest expense and penalties related to the uncertain tax position in the income tax expense line in the accompanying consolidated statements of operations and comprehensive income. Accrued interest and penalties are included in other non-current liabilities in the consolidated balance sheets and were $
11. Commitments and Contingencies
The Company also enters into commitments for capital expenditures in advance of the expenditures being made. As of December 31, 2023, our commitments for capital expenditures were
Litigation
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. Epsilon asserts that Chesapeake has failed to cooperate with Epsilon’s efforts to develop resources in the Auburn Development, located in North-Central Pennsylvania, as required under both the settlement agreement and JOAs.
Epsilon requested a preliminary injunction but was unsuccessful in obtaining that injunction. Epsilon filed a motion to amend its original Complaint. Chesapeake opposed. The Court ruled in Epsilon’s favor and allowed Epsilon’s amendment. Chesapeake moved to dismiss the amended Complaint. The Court granted the motion to dismiss on a narrow issue without prejudice to Epsilon’s right to file a new lawsuit based on new proposals made after the Court’s decision. Epsilon filed a motion for reconsideration of that decision, but the court denied the motion for reconsideration on January 18, 2022.
Epsilon filed a notice of appeal on February 15, 2022 challenging the District Court's rulings in the case. Following the Third Circuit's ruling to remand the case back to District court, Epsilon has sought and was granted a dismissal of the case without prejudice in September 2023.
63
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
12. Leases
Under ASC 842, Leases, the Company recognized an operating lease related to its corporate office as of December 31, 2023 summarized in the following table:
| December 31, |
| December 31, | |||
2023 | 2022 | |||||
Asset | ||||||
Operating lease right-of-use assets | $ | | $ | | ||
Operating lease right-of-use assets, long term | | | ||||
Total operating lease right-of-use assets | $ | | $ | | ||
Liabilities | ||||||
Operating lease liabilities | $ | | $ | | ||
Operating lease liabilities, long term | | | ||||
Total operating lease liabilities | $ | | $ | | ||
Operating lease costs | $ | | $ | | ||
Cash paid for amounts included in the measurement of lease liabilities | ||||||
Operating cash flows from operating leases | $ | | $ | | ||
Right-of-use assets obtained in exchange for new operating lease liabilities | $ | | $ | | ||
Weighted average remaining lease term (years) - operating lease | ||||||
Weighted average discount rate (annualized) - operating lease | ||||||
The Company had one office lease that expired in April 2023. On March 1, 2023, the Company commenced a new office lease with a
Future minimum lease payments as of December 31, 2023 are as follows:
Operating Leases | |||
2023 | $ | — | |
2024 | | ||
2025 | | ||
2026 | | ||
2027 | | ||
Thereafter | | ||
Total minimum lease payments | | ||
Less: imputed interest | ( | ||
Present value of future minimum lease payments | | ||
Less: current obligations under leases | ( | ||
Long-term lease obligations | $ | | |
13. Net Income Per Share
Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income per share is computed based upon the weighted-average number of
64
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities.
The net income used in the calculation of basic and diluted net income per share are as follows:
Year ended December 31, | ||||||
| 2023 |
| 2022 | |||
Net income | $ | | $ | | ||
In calculating the net income per share, basic and diluted, the following weighted-average shares were used:
Year ended December 31, | ||||
| 2023 |
| 2022 | |
Basic weighted-average number of shares outstanding | | | ||
Dilutive stock options | | | ||
Unvested performance-based restricted shares |
| |
| |
Diluted weighted-average shares outstanding |
| |
| |
We excluded the following shares from the diluted net income per share because their inclusion would have been anti-dilutive.
Year ended December 31, | ||||
| 2023 |
| 2022 | |
Anti-dilutive options | | | ||
Anti-dilutive unvested time-based restricted shares | | | ||
Anti-dilutive unvested performance-based restricted shares | | | ||
Total Anti-dilutive shares |
| |
| |
14. Operating Segments
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as executive management. Segment performance is evaluated based on operating income or loss as shown in the table below. Interest income and income taxes are managed separately on a group basis.
The Company’s reportable segments are as follows:
| a. | The Upstream segment activities include acquisition, development and production of natural gas and oil reserves on properties within the United States; |
| b. | The Gas Gathering segment partners with |
| c. | The Corporate segment activities include corporate listing and governance functions of the Company. |
65
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
Segment activity as of, and for the years ended December 31, 2023 and 2022 is as follows:
| Upstream |
| Gas Gathering |
| Corporate |
| Elimination |
| Consolidated | ||||||
As of and for the year ended December 31, 2023 | |||||||||||||||
Operating revenue | |||||||||||||||
Natural gas | $ | | $ | | $ | | $ | | $ | | |||||
Natural gas liquids | | | | | | ||||||||||
Oil and condensate | | | | | | ||||||||||
Gathering and compression fees | | | | ( | | ||||||||||
Total operating revenue (1) | | | | ( | | ||||||||||
Operating costs | |||||||||||||||
Operating costs (2) | | | | ( | | ||||||||||
Depletion, depreciation, amortization and accretion | | | | | | ||||||||||
Operating income (loss) | | | ( | | | ||||||||||
Other income (expense) | |||||||||||||||
Interest income | | | | | | ||||||||||
Interest expense | ( | | | | ( | ||||||||||
Gain on derivative contracts | | | | | | ||||||||||
Other income | | | | | | ||||||||||
Other income (expense), net | | | | | | ||||||||||
Net income (loss) before income tax expense | $ | | $ | | $ | ( | $ | | $ | | |||||
Segment assets | |||||||||||||||
Current assets, net | $ | | $ | | $ | | $ | | $ | | |||||
Proved properties | | | | | | ||||||||||
Unproved properties | | | | | | ||||||||||
Gathering system | | | | | | ||||||||||
Other property and equipment | | | | | | ||||||||||
Operating lease right-of-use asset | | | | | | ||||||||||
Total segment assets | $ | | $ | | $ | | $ | | $ | | |||||
Capital expenditures (3) | $ | | $ | | $ | | $ | | $ | | |||||
As of and for the year ended December 31, 2022 | |||||||||||||||
Operating revenue | |||||||||||||||
Natural gas | $ | | $ | | $ | | $ | | $ | | |||||
Natural gas liquids | | | | | | ||||||||||
Oil and condensate | | | | | | ||||||||||
Gathering and compression fees | | | | ( | | ||||||||||
Total operating revenue (1) | | | | ( | | ||||||||||
Operating costs | |||||||||||||||
Operating costs | | | | ( | | ||||||||||
Depletion, depreciation, amortization and accretion | | | | | | ||||||||||
Operating income (loss) | | | ( | | | ||||||||||
Other income (expense) | |||||||||||||||
Interest income | | | | | | ||||||||||
Interest expense | ( | | | | ( | ||||||||||
Loss on derivative contracts | | | | | | ||||||||||
Other (expense) income | ( | | | | ( | ||||||||||
Other income (expense), net | | | | | | ||||||||||
Net income (loss) before income tax expense | $ | | $ | | $ | ( | $ | | $ | | |||||
Segment assets | |||||||||||||||
Current assets, net | $ | | $ | | $ | | $ | | $ | | |||||
Proved properties | | | | | | ||||||||||
Unproved properties | | | | | | ||||||||||
Gathering system | | | | | | ||||||||||
Other property and equipment | | | | | | ||||||||||
Total segment assets | $ | | | | | | |||||||||
Capital expenditures (3) | $ | | | | | | |||||||||
66
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
| (1) | Segment operating revenue represents revenues generated from the operations of the segment. Inter-segment sales during the years ended December 31, 2023 and 2022 have been eliminated upon consolidation. For the year ended December 31, 2023, we sold natural gas to |
| (2) | Operating expenses for the year ended December 31, 2023 includes loss on the sale of Oklahoma assets of $ |
| (3) | Capital expenditures for the Upstream segment consist primarily of the acquisition of properties, and the drilling and completing of wells while Gas Gathering consists of expenditures relating to the expansion, completion, and maintenance of the gathering and compression facility. |
15. Commodity Risk Management Activities
Commodity Price Risks
Epsilon engages in price risk management activities from time to time. These activities are intended to manage Epsilon’s exposure to fluctuations in commodity prices for natural gas by securing fixed price contracts for a portion of expected sales volumes.
Inherent in the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not currently require collateral from any of its counterparties nor do its counterparties require collateral from the Company.
The Company enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future natural gas production and related cash flows. The natural gas revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future natural gas sales from the risk of significant declines in commodity prices, which helps ensure the Company’s ability to fund the capital budget.
Epsilon has historically elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for these financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as gain (loss) on derivative contracts on the consolidated statements of operations and comprehensive income. The related cash flow impact is reflected in cash flows from operating activities. During 2023, Epsilon recognized gains on financial commodity derivative contracts of $
Commodity Derivative Contracts
At December 31, 2023, the Company had outstanding NYMEX HH swaps totaling
67
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
Fair Value of Derivative | ||||||
| December 31, |
| December 31, | |||
2023 | 2022 | |||||
Current |
|
|
|
| ||
NYMEX Henry Hub swap |
| $ | | $ | | |
Tennessee Z4 basis swap |
| | | |||
| $ | | $ | | ||
Fair Value of Derivative | ||||||
| December 31, |
| December 31, | |||
2023 | 2022 | |||||
Current |
|
|
|
| ||
Tennessee Z4 basis swap |
| ( | ( | |||
| $ | ( | $ | ( | ||
Net Fair Value of Derivatives |
| $ | | $ | | |
The following table presents the changes in the fair value of Epsilon’s commodity derivatives for the periods indicated:
Year ended December 31, | ||||||
| 2023 |
| 2022 | |||
Fair value of asset (liability), beginning of the period | $ | | $ | ( | ||
| |
| | |||
Settlement of commodity derivative contracts |
| ( |
| | ||
Fair value of asset, end of the period | $ | | $ | | ||
The following table presents the fair value of derivatives, as presented in the Consolidated Balance Sheets, on a net basis as they are subject to master netting arrangements:
December 31, 2023 | December 31, 2022 | |||||||||||||||||
Gross Fair | Amounts | Net Fair | Gross Fair | Amounts | Net Fair | |||||||||||||
| Value |
| Netted |
| Value |
| Value |
| Netted |
| Value | |||||||
Derivative Assets | ||||||||||||||||||
Fair value of derivatives |
| $ | | $ | ( | $ | |
| $ | | $ | ( | $ | | ||||
Derivative Liabilities |
| |||||||||||||||||
Fair value of derivatives |
| $ | ( | $ | | $ | ( |
| $ | ( | $ | | $ | | ||||
16. Asset Retirement Obligations
Asset retirement obligations are estimated by management based on Epsilon’s net ownership interest in all wells and the gathering system, estimated costs to reclaim and abandon such assets and the estimated timing of the costs to be incurred in future periods, and the forecast risk free cost of capital. Epsilon has estimated the net present value of its total asset retirement obligations to be $
68
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
The following table presents the activity in Epsilon’s asset retirement obligations for the periods indicated:
Year Ended | Year ended | |||||
December 31, | December 31, | |||||
2023 |
| 2022 | ||||
Balance beginning of period | $ | | $ | | ||
Liabilities acquired | | | ||||
Liabilities disposed of | ( | ( | ||||
Wells plugged and abandoned | ( | ( | ||||
Change in estimates | | | ||||
Accretion | | | ||||
Balance end of period | $ | | $ | | ||
17. Fair Value Measurements
The methodologies used to determine the fair value of our financial assets and liabilities at December 31, 2023 were the same as those used at December 31, 2022.
Cash and cash equivalents, restricted cash, accounts receivable, and accounts payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The Company’s revolving line of credit has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates and the applicable margins represent market rates. The revolving line of credit is classified within Level 2 of the fair value hierarchy.
The Company has investments in U.S. Treasury bills, all of which mature over a period of 3 and 12 months and are classified as short term investments. The U.S. Treasury bills are carried at fair value. The U.S. Treasury bills are classified within Level 1 of the fair value hierarchy.
Commodity derivative instruments consist of NYMEX HH swap and basis swap contracts for natural gas. The Company’s derivative contracts are valued based on a marked to market approach. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.
| December 31, 2023 | ||||||||||||||
| Level 1 | Level 2 |
| Level 3 |
| Effect of Netting |
| Net Fair Value | |||||||
Assets |
|
|
|
|
| ||||||||||
Derivative contracts | $ | | $ | | $ | | $ | | $ | | |||||
Cash equivalents | $ | | $ | | $ | | $ | | $ | | |||||
Short term investments | $ | | $ | | $ | | $ | | $ | | |||||
Liabilities | |||||||||||||||
Derivative contracts | $ | | $ | | $ | | $ | ( | $ | ( | |||||
December 31, 2022 | |||||||||||||||
Level 1 | Level 2 |
| Level 3 |
| Effect of Netting |
| Net Fair Value | ||||||||
Assets |
|
|
|
|
| ||||||||||
Derivative contracts | $ | | $ | | $ | | $ | ( | $ | | |||||
Cash equivalents | $ | | $ | | $ | | $ | | $ | | |||||
Liabilities | |||||||||||||||
Derivative contracts | $ | | $ | ( | $ | | $ | | $ | | |||||
69
EPSILON ENERGY LTD.
Notes to the Consolidated Financial Statements (Continued)
For the years ended December 31, 2023 and 2022
18. Current Expected Credit Loss
Under ASU 326, Financial Instruments – Credit Losses, estimated losses on financial assets are provided through an allowance for credit losses. The majority of our financial assets are invested in U.S. Treasury bills. We also have accounts receivable which are primarily from purchasers of oil and natural gas, counterparties to our financial instruments, and revenues earned for compression and gathering services. Our oil, gas, and natural gas liquids accounts receivables are generally collected within 30 days after the end of the month. Compression and gathering receivables are generally collected within 60 days after the end of the month. We assess collectability through various procedures, including review of our trade receivable balances by counterparty, assessing economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount and age of past due accounts. As of December 31, 2023 and 2022, we determined that our allowance for credit loss was
19. Subsequent Events
On January 30, 2024, the Company repurchased
On February 27, 2024 the Company closed an acquisition in the Permian Basin in Ector County, Texas. The acquired assets are a
70
EPSILON ENERGY LTD.
Supplemental Information to Consolidated Financial Statements
(Unaudited)
SUPPLEMENTAL NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
Natural gas and oil Reserves
Users of this information should be aware that the process of estimating quantities of ‘‘proved,’’ ‘‘proved developed’’ and ‘‘proved undeveloped’’ crude oil, natural gas liquids (NGLs) and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity; evolving production history; crude oil and condensate, NGL and natural gas prices; and continual reassessment of the viability of production under varying economic conditions.
Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
Proved reserves represent estimated quantities of crude oil, NGLs and natural gas, which, by analysis of geoscience and engineering data, can be estimated, with reasonable certainty, to be economically producible from a given date forward from known reservoirs under then-existing economic conditions, operating methods and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved developed reserves are proved reserves expected to be recovered under operating methods being utilized at the time the estimates were made, through wells and equipment in place or if the cost of any required equipment is relatively minor compared to the cost of a new well.
Proved undeveloped reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. PUDs can be recorded in respect of a particular undrilled location only if the location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the date that the PUDs are to be recorded, unless specific factors (such as those described in interpretative guidance issued by the Staff of the SEC) justify a longer timeframe. Likewise, absent any such specific factors, PUDs associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond five years from the date that the PUDs were recorded. Epsilon has formulated development plans for all drilling locations associated with its PUDs at December 31, 2023. Under these plans, each PUD location will be drilled within five years from the date it was recorded.
Estimates for PUDs are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
The following tables set forth Epsilon’s net proved reserves at December 31, 2023 and 2022 and changes for each of the two years in the year ended December 31, 2023. Net proved reserves at December 31 are estimated by the Company’s independent petroleum engineers, DeGolyer and MacNaughton.
71
EPSILON ENERGY LTD.
Supplemental Information to Consolidated Financial Statements
(Unaudited)
NET PROVED RESERVE SUMMARY
All reserves located in United States | Permian | |||||||
Pennsylvania |
| Basin |
| Oklahoma |
| Total | ||
Natural Gas (MMcf) | ||||||||
Net proved reserves at December 31, 2021 |
| 101,424 | - | 9,545 | 110,969 | |||
Revisions of previous estimates | (7,901) | - | (3,525) | (11,426) | ||||
Production | (9,026) | - | (477) | (9,503) | ||||
Net proved reserves at December 31, 2022 |
| 84,497 | - | 5,543 | 90,040 | |||
Revisions of previous estimates |
| (14,831) | - | (1,515) | (16,346) | |||
Acquisitions | - | 481 | - | 481 | ||||
Production | (7,906) | - | (354) | (8,260) | ||||
Net proved reserves at December 31, 2023 | 61,760 | 481 | 3,674 | 65,915 | ||||
Natural Gas Liquids (MBbl) | ||||||||
Net proved reserves at December 31, 2021 | - | - | 820 | 820 | ||||
Revisions of previous estimates | - | - | (285) | (285) | ||||
Production | - | - | (44) | (44) | ||||
Net proved reserves at December 31, 2022 | - | - | 491 | 491 | ||||
Revisions of previous estimates | - | - | (203) | (203) | ||||
Acquisitions | - | 116 | - | 116 | ||||
Production | - | - | (21) | (21) | ||||
Net proved reserves at December 31, 2023 | - | 116 | 267 | 383 | ||||
Oil and Condensate (MBbl) | ||||||||
Net proved reserves at December 31, 2021 | - | - | 305 | 305 | ||||
Revisions of previous estimates | - |
| - |
| (62) |
| (62) | |
Production | - | - | (32) | (32) | ||||
Net proved reserves at December 31, 2022 | - |
| - |
| 211 |
| 211 | |
Revisions of previous estimates | - | - | (43) | (43) | ||||
Acquisitions | - | 194 | - | 194 | ||||
Production | - | - | (21) | (21) | ||||
Net proved reserves at December 31, 2023 | - | 194 | 147 | 341 | ||||
Total Company (MMcfe) | ||||||||
Net proved reserves at December 31, 2021 | 101,424 | - | 16,295 | 117,719 | ||||
Revisions of previous estimates (1)(2) | (7,901) |
| - |
| (5,604) |
| (13,505) | |
Production | (9,026) | - | (933) | (9,959) | ||||
Net proved reserves at December 31, 2022 | 84,497 |
| - |
| 9,758 |
| 94,255 | |
Revisions of previous estimates (3)(4) | (14,831) | - | (2,991) | (17,822) | ||||
Acquisitions | - | 2,341 | - | 2,341 | ||||
Production | (7,906) | - | (606) | (8,512) | ||||
Net proved reserves at December 31, 2023 | 61,760 | 2,341 | 6,161 | 70,262 |
72
EPSILON ENERGY LTD.
Supplemental Information to Consolidated Financial Statements
(Unaudited)
All reserves located in United States | Permian | |||||||
Pennsylvania |
| Basin |
| Oklahoma |
| Total | ||
Proved developed reserves: | ||||||||
Natural Gas (MMcf) | ||||||||
At December 31, 2021 | 70,102 | - | 2,124 | 72,226 | ||||
At December 31, 2022 | 76,302 | - | 2,664 | 78,966 | ||||
At December 31, 2023 | 45,135 | 481 | 1,939 | 47,555 | ||||
Natural Gas Liquids (MBbl) | ||||||||
At December 31, 2021 | - | - | 157 | 157 | ||||
At December 31, 2022 | - | - | 198 | 198 | ||||
At December 31, 2023 | - | 116 | 133 | 249 | ||||
Oil and condensate (MBbl) | ||||||||
At December 31, 2021 | - | - | 66 | 66 | ||||
At December 31, 2022 | - | - | 107 | 107 | ||||
At December 31, 2023 | - | 194 | 78 | 272 | ||||
Total proved developed reserves (MMcfe) | ||||||||
At December 31, 2021 | 70,102 | - | 3,462 | 73,564 | ||||
At December 31, 2022 | 76,302 | - | 4,494 | 80,796 | ||||
At December 31, 2023 | 45,135 | 2,341 | 3,205 | 50,681 | ||||
Proved undeveloped reserves: | ||||||||
Natural Gas (MMcf) | ||||||||
At December 31, 2021 | 31,322 | - | 7,421 | 38,743 | ||||
At December 31, 2022 | 8,195 | - | 2,879 | 11,074 | ||||
At December 31, 2023 | 16,625 | - | 1,736 | 18,361 | ||||
Natural Gas Liquids (MBbl) | ||||||||
At December 31, 2021 | - | - | 663 | 663 | ||||
At December 31, 2022 | - | - | 293 | 293 | ||||
At December 31, 2023 | - | - | 134 | 134 | ||||
Oil and condensate (MBbl) | ||||||||
At December 31, 2021 | - | - | 239 | 239 | ||||
At December 31, 2022 | - | - | 104 | 104 | ||||
At December 31, 2023 | - | - | 69 | 69 | ||||
Total proved undeveloped reserves (MMcfe) | ||||||||
At December 31, 2021 | 31,322 | - | 12,833 | 44,155 | ||||
At December 31, 2022 | 8,195 | - | 5,264 | 13,459 | ||||
At December 31, 2023 | 16,625 | - | 2,956 | 19,581 | ||||
Total proved reserves: | ||||||||
Natural Gas (MMcf) | ||||||||
At December 31, 2021 | 101,424 | - | 9,545 | 110,969 | ||||
At December 31, 2022 | 84,497 | - | 5,543 | 90,040 | ||||
At December 31, 2023 | 61,760 | 481 | 3,675 | 65,916 | ||||
Natural Gas Liquids (MBbl) | ||||||||
At December 31, 2021 | - | - | 820 | 820 | ||||
At December 31, 2022 | - | - | 491 | 491 | ||||
At December 31, 2023 | - | 116 | 267 | 383 | ||||
Oil and condensate (MBbl) | ||||||||
At December 31, 2021 | - | - | 305 | 305 | ||||
At December 31, 2022 | - | - | 211 | 211 | ||||
At December 31, 2023 | - | 194 | 147 | 341 | ||||
Total proved reserves (MMcfe) | ||||||||
At December 31, 2021 | 101,424 | - | 16,295 | 117,719 | ||||
At December 31, 2022 | 84,497 | - | 9,758 | 94,255 | ||||
At December 31, 2023 | 61,760 | 2,341 | 6,161 | 70,262 |
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EPSILON ENERGY LTD.
Supplemental Information to Consolidated Financial Statements
(Unaudited)
| (1) | Revisions of previous estimates for Pennsylvania for 2022 include additions of 6,238 MMcf related to well performance and 4,759 MMcf related to commodity pricing, and reductions of 18,898 MMcf related to changes to previously adopted development plans. |
| (2) | Revisions of previous estimates for Oklahoma for 2022 include additions of 310 MMcfe related to commodity pricing, reductions of 4,353 MMcfe related to changes to previously adopted development plans and reductions of 1,561 MMcfe related to well performance. |
| (3) | Revisions of previous estimates for Pennsylvania for 2023 include reductions of 9,626 MMcf related to well performance, reductions of 21,830 MMcf related to commodity pricing, and additions of 16,625 MMcf related to changes in previously adopted development plans. |
| (4) | Revisions of previous estimates for Oklahoma for 2023 include reductions of 454 MMcfe related to commodity pricing, 1,760 MMcfe related to changes in previously adopted development plans, and 777 MMcfe related to well performance. |
Capitalized Costs Relating to Natural gas and oil Producing Activities
The following table sets forth the capitalized costs relating to Epsilon’s crude oil and natural gas production and gathering activities at December 31, 2023 and 2022:
Year ended December 31, | ||||||
| 2023 |
| 2022 | |||
Proved properties |
| $ | 160,263,511 | $ | 148,326,265 | |
Unproved properties |
| 25,504,873 | 18,169,157 | |||
Gathering system properties | 42,738,273 | 42,639,001 | ||||
Total Oil & Gas Properties | 228,506,657 | 209,134,423 | ||||
Accumulated depreciation, depletion, amortization and impairment | (149,248,206) |
| (142,230,033) | |||
Net capitalized costs | $ | 79,258,451 | $ | 66,904,390 | ||
Costs incurred for oil and natural gas property acquisition, exploration and development activities
The following table summarizes costs incurred and capitalized in oil and natural gas properties related to acquisition, exploration and development activities. Property acquisition costs are those costs incurred to lease property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling, as well as the costs to develop the gathering system.
Year ended December 31, | ||||||
| 2023 |
| 2022 | |||
Oil and Natural Gas Activities: |
| |||||
Unproved acquisition costs | $ | 7,335,716 | $ | 310,211 | ||
Development costs | 11,994,374 | 6,426,037 | ||||
Total costs incurred for oil and natural gas activities | 19,330,090 | 6,736,248 | ||||
Gathering System development costs | 99,272 |
| 163,915 | |||
Total costs incurred | $ | 19,429,362 | $ | 6,900,163 | ||
Results of Operations for Natural Gas and Oil Producing Activities
The following table sets forth results of operations for natural gas and oil producing activities for the years ended December 31, 2023 and 2022:
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EPSILON ENERGY LTD.
Supplemental Information to Consolidated Financial Statements
(Unaudited)
Year ended December 31, | ||||||
| 2023 |
| 2022 | |||
Oil and gas producing activities: |
| |||||
Gas sales |
| $ | 14,864,214 | $ | 56,948,734 | |
Oil and other liquid sales | 6,075,007 | 4,928,463 | ||||
Total revenues | 20,939,221 | 61,877,197 | ||||
Lease operating costs | (6,405,281) | (7,128,631) | ||||
Depreciation, depletion, amortization, accretion and impairment | (6,638,882) | (5,375,225) | ||||
Income tax expense | (2,569,725) | (12,157,487) | ||||
Results of operations from oil and gas producing activities | $ | 5,325,333 | $ | 37,215,854 | ||
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural gas and oil Reserves
The following information has been developed utilizing procedures prescribed by the Extractive Activities—Natural Oil and Gas (Topic 932) of the ASC and based on natural gas reserves and production volumes estimated by our independent petroleum consultants, DeGolyer and MacNaughton. The commodity prices estimated below were based on a 12-month average of first-day-of-the-month commodity prices for the years 2023 and 2022. The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating Epsilon or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of Epsilon.
The future cash flows presented below are based on expense and cost rates in existence as of the date of the projections. It is expected that material revisions to some estimates of natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.
Estimated future income taxes are computed using current statutory income tax rates including consideration of the current tax basis of the properties and related carryforwards. The resulting tax-effected future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible reserves as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The following table sets forth the standardized measure of discounted future net cash flows from projected production of Epsilon’s gas reserves as of December 31, 2023 and 2022.
Year ended December 31, | ||||||
| 2023 |
| 2022 | |||
Future cash inflows |
| $ | 152,124,830 | $ | 529,886,325 | |
Future production costs |
| (73,813,321) | (119,404,233) | |||
Future development costs(1) | (15,815,930) | (21,171,395) | ||||
Future income taxes(2) | (11,581,004) | (97,165,344) | ||||
Future net cash flows (undiscounted) | 50,914,575 | 292,145,353 | ||||
10% annual discount for estimated timing of cash flows | (17,941,667) | (146,368,246) | ||||
Standardized measure of discounted future net cash flows | $ | 32,972,908 | $ | 145,777,107 | ||
| (1) | Costs associated with the abandonment of proved properties are included in future development costs. |
| (2) | Future income taxes for 2023 and 2022 were estimated using a combined federal and state statutory tax rate of approximately 26%. |
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EPSILON ENERGY LTD.
Supplemental Information to Consolidated Financial Statements
(Unaudited)
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth the changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2023 and 2022:
Year ended December 31, | ||||||
| 2023 |
| 2022 | |||
Beginning balance |
| $ | 145,777,107 | $ | 77,708,130 | |
Revenue less production and other costs | (13,158,195) | (53,224,969) | ||||
Changes in price, net of production costs | (156,373,808) | 147,777,736 | ||||
Development costs incurred | 10,011,508 | 10,396,380 | ||||
Net changes in future development costs | (5,088,346) | 5,054,884 | ||||
Revisions of previous quantity estimates | (531,514) | (31,515,746) | ||||
Accretion of discount |
| 14,271,185 | 9,790,852 | |||
Net change in income taxes | 39,799,369 | (17,827,596) | ||||
Timing differences and other technical revisions | (1,734,398) | (2,382,564) | ||||
Ending balance | $ | 32,972,908 | $ | 145,777,107 | ||
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and our principal financial officer, evaluated, as of the end of the period covered by this Annual Report on Form 10-K, the design and effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer have concluded that as of December 31, 2023, our disclosure controls and procedures were effective at the reasonable assurance level. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and our management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting for Epsilon as such term is defined in the Exchange Act. Our internal control structure is designed to provide reasonable assurance that assets are safeguarded and that transactions are properly executed and recorded. The internal control structure includes, among other things, established policies and procedures, the selection and training of qualified personnel as well as management oversight.
With the participation of our management, we performed an evaluation of the effectiveness of our internal control over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “2013 Framework)”. Based upon our evaluation under the 2013 Framework, we have concluded that as of December 31, 2023 our internal control over financial reporting was effective.
This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by Epsilon’s independent registered public accounting firm pursuant to rules of the SEC that permit Epsilon to provide only management's report in this Annual Report. We were not required to have, nor have we, engaged our independent registered public accounting firm to perform an audit of internal control over financial reporting pursuant to the rules of the Commission that permit us to provide only management’s report in this Annual Report.
Changes in Internal Control Over Financial Reporting
There have been no significant changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION.
During the quarter ended December 31, 2023,
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS.
None.
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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
The names, ages, business experience (for at least the past five years) and positions of our directors and executive officers as of December 31, 2023, are set out below. Our Board of Directors consisted of six members at such date. All directors serve until the next annual meeting of shareholders or until their successors are elected or appointed and qualified. The Board of Directors appoints the executive officers annually.
Directors and Executive Officers | Age | Position with us |
Jason Stabell | 49 | Chief Executive Officer and Director |
Henry N. Clanton | 61 | Chief Operating Officer |
Andrew Williamson | 35 | Chief Financial Officer |
John Lovoi | 63 | Chairman of the Board and Director |
Tracy Stephens | 63 | Director |
Jason Stankowski | 53 | Director |
David Winn | 61 | Director |
Nicola Maddox | 68 | Director |
Biographies of Corporate Directors and Executive Officers.
Jason Stabell. Mr. Stabell has served as chief executive officer and a director for Epsilon Energy Ltd. since July 2022. He has worked in the energy industry since 1998 with a focus on upstream E&P. Most recently he served as President and CEO of Merlon International, LLC, a privately held company with assets in the Western Desert of Egypt and US Gulf Coast which was sold in 2019 to a publicly listed UK company where he served as an advisor until 2021. Previously, he served as CFO and ultimately President of privately held Merlon Petroleum Company, which had assets in the US Gulf Coast and Egypt and was sold in 2006. He has a BA in Economics from Williams College. We believe that Mr. Stabell is qualified to serve as a member of our board of directors as a result of his experience in the natural gas and oil industry.
Henry N. Clanton. Mr. Clanton has served as our chief operating officer since January 2017. He has over 30 years of experience in the upstream E&P sector. His experience includes financial and technical management over all phases of drilling, completions, production, and field operations. Before joining us, he spent 14 years with a private E&P start-up, ARES Energy, Ltd, which he co-founded and served as a Managing Partner. Previous to that time Mr. Clanton worked with Schlumberger, ARCO Permian, and Coastal Management Company. He holds a MBA and a BS in Petroleum Engineering from Texas A&M University.
Andrew Williamson. Mr. Williamson has served as our chief financial officer since July 2022. He has spent his entire career in the energy business. From 2012 to early 2019, he served as Corporate Development Manager then Vice President Finance (CFO) of Merlon International, LLC. More recently, he served as the Corporate Strategy Manager for Petrosantander Inc. Mr. Williamson started his career in management consulting advising energy clients on transaction due diligence, growth strategy, and cost reduction. He has a BBA in Finance and a BA in Political Science from Southern Methodist University.
John Lovoi. Mr. Lovoi has been chairman of our board of directors since July 2013. Mr. Lovoi has been the managing partner of JVL Advisors, LLC, a private natural gas and oil investment advisor, since November 2002. He is a Director of Helix Energy Solutions Group, an operator of offshore natural gas and oil properties and production facilities, the Chairman of Dril-Quip, Inc., a provider of subsea, surface and offshore rig equipment. We believe that Mr. Lovoi is qualified to serve as a member of our board of directors as a result of his background in investment banking, equity research, and asset management, with an emphasis on the global natural gas and oil practice.
Tracy Stephens. Mr. Stephens has been a director since May 2018. He has also been a member of our Compensation, Nominating and Corporate Governance Committee, and Conflicts Committee since February 2019. He is the founder of Westminster Advisors, a CEO advisory services company, and served as its Chief Executive Officer from January 2018. He was previously employed by Resources Global Professionals, a large business consulting company, from July 2001 to December 2016, and was the Chief Operating Officer the last three years. We believe that Mr. Stephens is qualified to serve as a member of our board of directors as a result of his extensive experience with public companies.
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Jason Stankowski. Mr. Stankowski has been a director and member of the Audit Committee since January 2021. Mr. Stankowski is the founder and a partner and portfolio manager for Clayton Partners, LLC. He began his career at Prudential Securities in San Francisco and spent eight years in structured finance at CMA Capital Management, where he acted in a number of roles, including specializing in corporate retirement planning, structuring complex investment and financing structures for Fortune 1000 companies. He became designated as a Chartered Financial Analyst in 2003. We believe that Mr. Stankowski is qualified to serve as a member of our board of directors based on his corporate finance and experience in public equity markets.
David Winn. Mr. Winn has been a director and member of the Audit Committee since January 2021. Mr. Winn recently retired from a 36 year career in public accounting that involved extensive board interaction. From 2003 until July 2020, Mr. Winn was an Audit Partner for Grant Thornton LLP, which is an independent audit, tax, and advisory firm and the U.S. member firm of Grant Thornton International Ltd. During his tenure, Mr. Winn served as audit department head, industry program leader, an engagement partner, quality control reviewer, and was a relationship partner to large clients. Mr. Winn has extensive Securities and Exchange Commission reporting experience with registration statements and annual and quarterly filings. Previously Mr. Winn served as a Director for PricewaterhouseCoopers LLP and previously as a Partner with Arthur Andersen LLP. We believe that Mr. Winn is qualified to serve as a member of our board of directors because of his experience in public accounting and public company reporting.
Nicola Maddox. Ms. Maddox has over forty years’ experience in the oil and gas industry. After receiving her BA in Communications, she was employed by Exxon Minerals starting as an Associate Landman eventually ending in Executive Management positions starting in 1993. She was a co-founder of Centurion Exploration Company in 2004, initially serving as an EVP and then becoming its President, CEO and Chairman of the Board from 2007 to 2009. At Merlon International, LLC, Ms. Maddox was SVP in charge of its Texas subsidiary. She advanced to EVP and ultimately President after Merlon sold its Egyptian subsidiary in 2019. Since 2022, she has been a self-employed energy advisor specializing in contract analysis, strategic planning, and negotiation strategies. We believe that Ms. Maddox is qualified to serve as a member of our board of directors because of his significant industry experience in upstream oil and gas.
Corporate Governance Practices and Policies
Our corporate governance practices and policies are administered by the board of directors and by committees of the board appointed to oversee specific aspects of our management and operations, pursuant to written charters and policies adopted by the board and such committees.
The Board of Directors
The Board is committed to a high standard of corporate governance practices. The Board believes that this commitment is not only in the best interests of the shareholders but that it also promotes effective decision-making at the Board level. The Board is of the view that its approach to corporate governance is appropriate and complies with the objectives and guidelines relating to corporate governance set out in National Instrument 58-201 adopted by the Canadian securities administrators, or NI 58-201, as well as the governance requirements of the NASDAQ Global Market. In addition, the Board monitors and considers for implementation the corporate governance standards that are proposed by various Canadian regulatory authorities or that are published by various non-regulatory organizations in Canada. The Board has also established a Compensation, Nominating and Corporate Governance Committee and has adopted a Compensation, Nominating and Corporate Governance Charter to ensure the objectives of NI 58-201 and the NASDAQ Global Market are met.
Mr. Lovoi is the Managing Partner of JVL Advisors, LLC, beneficial owner of 3.46% of our common shares and Chairman of the Board.
The Board held eleven meetings during 2023 and thirteen meetings during 2022. All Board meetings were conducted with open and candid discussions. As such, directors did not hold any separate meetings, other than Audit and Compensation, Nominating and Corporate Governance Committee meetings. The members of the Board have the ability to meet on their own and are authorized to retain independent financial, legal and other experts as required whenever, in their opinion, matters come before the Board that require an independent analysis by the members of the Board. The Board intends to hold at least four regular meetings each year, as well as additional meetings as required. The Board has not established any required attendance levels for the Board and committee meetings. In setting the regular meeting schedule, care is taken to ensure that meeting dates are set to accommodate directors’ schedules so as to encourage full attendance.
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The Board has stewardship responsibilities, including responsibilities with respect to oversight of our investments, management of the Board, monitoring of our financial performance, financial reporting, financial risk management and oversight of policies and procedures, communications and reporting and compliance. In carrying out its mandate, the Board meets regularly and a broad range of matters are discussed and reviewed for approval. These matters include overall plans and strategies, budgets, internal controls and management information systems, risk management as well as interim and annual financial and operating results. The Board is also responsible for the approval of all major transactions, including property acquisitions, property divestitures, equity issuances and debt transactions, if any. The Board strives to ensure that our corporate actions correspond closely with the objectives of its shareholders. The Board will meet at least once annually to review in depth our strategic plan and review our available resources required to carry out our growth strategy and to achieve its objectives. The mandate of the Board is to be reviewed by the Board annually.
Position Descriptions. The Board has outlined the responsibilities in respect to our Chief Executive Officer, or CEO. The Board and CEO do not have a written position description for the CEO; however, the CEO’s principal duties and responsibilities are planning our strategic direction, providing leadership, acting as our spokesperson, reporting to shareholders, and overseeing our executive management with respect to operations and finance.
The charter for each of the Board committees outlines the duties and responsibilities of the members of each of the committees, including the chair of such committees. See ‘‘Board Committees’’ below.
Orientation and Continuing Education. We have not adopted a formalized process of orientation for new Board members. However, all directors have been provided with a base line of knowledge about us that serves as a basis for informed decision making. This includes a combination of written material, in person meetings with our senior management, site visits and other briefings and training, as appropriate.
Directors are kept informed as to matters affecting, or that may affect, our operations through reports and presentations at the quarterly Board meetings. Special presentations on specific business operations are also provided to the Board.
Ethical Business Conduct and Whistleblower Policy. Our Code of Ethics and Whistleblower Policy are available on our website at http://www.epsilonenergyltd.com/. Each director is expected to disclose all actual or potential conflicts of interest and refrain from voting on matters in which such director has a conflict of interest. In addition, a director must recuse himself from any discussion or decision on any matter of which the director is precluded from voting as a result of a conflict of interest. The Board has reviewed and approved a disclosure and insider trading policy for us, in order to promote consistent disclosure practices aimed at informative, timely and broadly disseminated disclosure of material information to the market in accordance with applicable securities legislation. The disclosure policy promotes, among other things, the disclosure and reporting of any serious weaknesses which may affect the financial stability and assets of us and our operating entities.
National Instrument 52-110 adopted by the Canadian securities administrators, the listing standards of the Toronto Stock Exchange and the listing standards of the NASDAQ Global Market require the Audit Committee to establish formal procedures for (a) the receipt, retention, and treatment of complaints received by us and our subsidiaries regarding accounting, internal accounting controls, or auditing matters and (b) the confidential, anonymous submission by our consultants or employees of concerns regarding questionable accounting or auditing matters. We are committed to achieving compliance with all applicable securities laws and regulations, accounting standards, accounting controls and audit practices. In addition, we post on our website all disclosures that are required by law or the listing standards of the NASDAQ Global Market concerning any amendments to, or waivers from, any provision of the code.
Assessments. The Board does not conduct regular assessments of the Board, its committees or individual directors, however, the Board does periodically review and satisfy itself at meetings that the Board, its committees and its individual directors are performing effectively.
Board Diversity. Our Compensation, Nominating and Corporate Governance Committee is responsible for reviewing with the board of directors, on an annual basis, the appropriate characteristics, skills and experience required for the board of directors as a whole and its individual members. In evaluating the suitability of individual candidates (both new candidates and current members), the nominating and corporate governance committee, in recommending candidates for election, and the board of directors, in approving (and, in the case of vacancies, appointing) such candidates, will take into account many factors, including the following:
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| ◾ | personal and professional integrity, ethics and values; |
| ◾ | experience in corporate management, such as serving as an officer or former officer of a publicly held company; |
| ◾ | experience as a board member or executive officer of another publicly held company; |
| ◾ | strong finance experience; |
| ◾ | diversity of expertise and experience in substantive matters pertaining to our business relative to other board members; |
| ◾ | diversity of background and perspective, including, but not limited to, with respect to age, gender, race, place of residence and specialized experience; |
| ◾ | experience relevant to our business industry and with relevant social policy concerns; and |
| ◾ | relevant academic expertise or other proficiency in an area of our business operations. |
Currently, our Board evaluates each individual in the context of the board of directors as a whole, with the objective of assembling a group that can best maximize the success of the business and represent stockholder interests through the exercise of sound judgment using its diversity of experience in these various areas.
Board Committees
The Board has two committees. The committees are the Audit Committee and the Compensation, Nominating and Corporate Governance Committee. Each committee has been constituted with independent directors.
Audit Committee. The Audit Committee currently consists of David Winn (Chairman), John Lovoi, and Jason Stankowski. All members of the Audit Committee are independent and financially literate under the applicable rules and regulations of the SEC and the NASDAQ Global Market.
The Audit Committee meets at least on a quarterly basis to review and approve our consolidated financial statements before the financial statements are publicly filed.
The Audit Committee reviews our interim unaudited condensed consolidated financial statements and annual audited consolidated financial statements and certain corporate disclosure documents including the Annual Information Form, Management’s Discussion and Analysis, and annual and interim earnings press releases before they are approved by the Board. The Audit Committee reviews and makes a recommendation to the Board in respect of the appointment and compensation of the external auditors and it monitors accounting, financial reporting, control and audit functions. The Audit Committee meets to discuss and review the audit plans of external auditors and is directly responsible for overseeing the work of the external auditors with respect to preparing or issuing the auditors’ report or the performance of other audit, review or attest services, including the resolution of disagreements between management and the external auditors regarding financial reporting. The Audit Committee questions the external auditors independently of management and reviews a written statement of its independence. The Audit Committee must be satisfied that adequate procedures are in place for the review of our public disclosure of financial information extracted or derived from our consolidated financial statements and it periodically assesses the adequacy of those procedures. The Audit Committee must approve or pre-approve, as applicable, any non-audit services to be provided to us by the external auditors. In addition, it reviews and reports to the Board on our risk management policies and procedures and reviews the internal control procedures to determine their effectiveness and to ensure compliance with our policies and avoidance of conflicts of interest. The Audit Committee has established procedures for dealing with complaints or confidential submissions which come to its attention with respect to accounting, internal accounting controls or auditing matters. To date, neither the Board nor the Audit Committee has formally assessed any individual director with respect to their effectiveness and contribution to us in their capacity as a director. Instead, members of the Board have relied on informal conversations among themselves to adequately cover such matters.
The Audit Committee operates under a written charter that satisfies the applicable standards of the SEC and The NASDAQ Global Market. A copy of the Audit Committee Charter can be found on our website at www.epsilonenergyltd.com.
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Compensation, Nominating and Corporate Governance Committee. The Compensation, Nominating and Corporate Governance Committee is currently comprised of Tracy Stephens (Chairman), John Lovoi, and Nicola Maddox. All members of this committee are independent directors.
The Compensation, Nominating and Corporate Governance Committee’s mandate is to:
| 1. | Assist and advise the Board regarding its responsibility for oversight of our compensation policy; provided that all determinations on officer compensation will be subject to review and approval by the Board; |
| 2. | Study and evaluate appropriate compensation mechanisms and criteria; |
| 3. | Develop and establish appropriate compensation policies and practices for the Board and our senior management, including our security-based compensation arrangements; |
| 4. | Evaluate senior management; |
| 5. | Serve in an advisory capacity on organizational and personnel matters to the Board; |
| 6. | Assist the Board by identifying individuals qualified to serve on the Board and its committees; |
| 7. | Recommend to the Board the director nominees for the next annual meeting; |
| 8. | Recommend to the Board members and chairpersons for each committee; |
| 9. | Develop and recommend to the Board and review from time to time, a set of corporate governance principles and monitor compliance with such principles; and |
| 10. | Serve in an advisory capacity on matters of governance structure and the conduct of the Board. |
These responsibilities include reporting and making recommendations to the Board for their consideration and approval. Corporate governance also relates to the activities of the Board, the members of which are elected by and are accountable to the shareholders, and takes into account the role of the individual members of management who are appointed by the Board and who are charged with the day-to-day management of us. The Board is committed to sound corporate governance practices, which are both in the interest of its shareholders and contribute to effective and efficient decision making.
The Compensation, Nominating and Corporate Governance Committee operates under a written charter that satisfies the applicable standards of the SEC and The NASDAQ Global Market. A copy of such charter can be found on our website at www.epsilonenergyltd.com.
Communications to the Board
Shareholders may communicate directly with our Board or any director by writing to the board or a director in care of the corporate secretary at Epsilon Energy Ltd., 500 Dallas Street, Suite 1250, Houston, Texas 77002, or by faxing their written communication to AeRayna Flores at (281) 668-0985. Shareholders may also communicate with the Board or any director by calling Ms. Flores at (281) 670-0002. Ms. Flores will review any communication before forwarding it to the Board or director, as the case may be.
Employment Agreements
All named executive officers have executed employment contracts with us. Mr. Jason Stabell’s employment agreement is effective from July 1, 2022 and filed in Form 8-K with the SEC on June 24, 2022. Mr. Henry Clanton’s employment agreement is effective from January 4, 2019 and filed in Form 10-12B with the SEC on December 21, 2018. Mr. Andrew Williamson’s employment agreement is effective from July 1, 2022 and filed in Form 8-K with the SEC on June 24, 2022.
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ITEM 11. EXECUTIVE COMPENSATION.
Summary Compensation Table
The Board adopted the 2020 Equity Incentive Plan (the “2020 Plan”) on July 22, 2020 subject to approval by Epsilon’s shareholders at Epsilon’s 2020 Annual General and Special Meeting of shareholders, which occurred on September 1, 2020 (the “Meeting”). Shareholders approved the 2020 Plan at the Meeting. Following Epsilon’s listing on the NASDAQ Global Market, the Board determined that it is in the best interest of the shareholders to approve a new incentive plan that is compliant with U.S. public company equity plan rules and practices that would replace Epsilon’s Amended and Restated 2017 Stock Option Plan (including its predecessors) and the Share Compensation Plan (collectively referred to as the “Predecessor Plans”). No further awards will be granted under the Predecessor Plans.
The following table sets out information concerning the compensation paid to our principal executive officer and our two most highly compensated executive officers other than our principal executive officer, or our named executive officers, for the two years ended December 31, 2023 and 2022. Compensation amounts in the following table are in U.S. dollars.
Non-equity incentive |
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plan compensation |
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Annual | Long-term |
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Name and principal |
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| Share-based |
| Incentive |
| Incentive |
| Other |
| Total | ||||||||||
position | Year | Salary | Bonuses | Awards | Plans | Plans | Compensation (4) | Compensation | |||||||||||||||
Jason Stabell, CEO (1) |
| 2023 | $ | 311,000 | $ | 184,000 | $ | 851,003 | $ | — | $ | — | $ | 7,350 | $ | 1,353,353 | |||||||
| 2022 | $ | 150,000 | $ | 100,000 | $ | 600,000 | $ | — | $ | — | $ | 4,346 | $ | 854,346 | ||||||||
Henry N. Clanton, COO (2) |
| 2023 | $ | 272,000 | $ | 92,000 | $ | 92,004 | $ | — | $ | — | $ | 15,752 | $ | 471,756 | |||||||
| 2022 | $ | 262,500 | $ | 117,000 | $ | 173,187 | $ | — | $ | — | $ | 15,250 | $ | 567,937 | ||||||||
| 2021 | $ | 250,000 | $ | 75,000 | $ | — | $ | — | $ | — | $ | 14,500 | $ | 339,500 | ||||||||
Andrew Williamson, CFO (3) |
| 2023 | $ | 239,000 | $ | 138,000 | $ | 355,006 | $ | — | $ | — | $ | 12,448 | $ | 744,454 | |||||||
| 2022 | $ | 115,000 | $ | 75,000 | $ | 250,000 | $ | — | $ | — | $ | 3,981 | $ | 443,981 | ||||||||
| (1) | Mr. Stabell was hired as our chief executive officer in July 2022. His current base salary is $311,000. |
2023—Share award of 108,465 common shares valued at $5.08 per share, market price on the grant date of December 31, 2023, which vests evenly over a three year period.
Share award of 56,180 common shares valued at $5.34 per share, market price on the grant date of July 1, 2023. This stub grant, although awarded in 2023, was based on 2022 performance. The grant vests evenly over a three year period.
2022—Share award of 97,560 common shares valued at $6.15 per share, market price on the grant date, July 1, 2022. This grant was awarded up-front on the employment effective date as part of the employment agreement. The grant vests over a four-year period with 25% vesting on the first anniversary and an additional 6.25% vesting on the first day of each subsequent quarter, with full vesting on July 1, 2026 so long as Mr. Stabell is still employed.
| (2) | Mr. Henry Clanton was hired as our chief operating officer in January 2018. His current base salary of $272,000. |
2023—Share award of 18,111 common shares valued at $5.08 per share, market price on the grant date of December 31, 2023, which vest evenly over a three year period.
2022— Share award of 12,825 common shares valued at $6.33 per share, market price on the grant date, April 6, 2022, and a share award of 13,877 common shares valued at $6.63 per share, market price on the grant date, December 31, 2022, both of which vest evenly over a three year period, so long as Mr. Clanton is still employed.
| (3) | Mr. Andrew Williamson was hired as our chief financial officer in July 2022. His current base salary is $239,000. |
2023—Share award of 45,276 valued at $5.08 per share, market price on the grant date of December 31, 2023, which grants vest evenly over a three year period.
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Share award of 23,409 common shares valued at $5.34 per share, market price on the grant date of July 1, 2023. This stub grant, although awarded in 2023, was based on 2022 performance. The grant vests evenly over a three year period.
2022— Share award of 40,650 common shares valued at $6.15 per share, market price on the grant date, July 1, 2022. This grant was awarded up-front on the employment effective date as part of the employment agreement. The grant vests over a four-year period with 25% vesting on the first anniversary and an additional 6.25% vesting on the first day of each subsequent quarter, with full vesting on July 1, 2026 so long as Mr. Williamson is still employed.
| (4) | As a Company policy, Epsilon matches on 401K contributions up to 5%. |
Description of the 2020 Equity Incentive Plan
The 2020 Plan was approved by the Board on July 22, 2020 and shareholders on September 1, 2020 as a replacement of our Amended and Restated 2017 Stock Option Plan and the Share Compensation Plan.
The 2020 Plan is administered by the Board, a committee of the Board or one or more officers delegated authority by the Board to administer the 2020 Plan. The Board has the authority in its discretion to interpret the 2020 Plan. The Board determines to whom stock options, stock appreciation rights, restricted stock and stock units, performance shares and units, other stock-based awards and cash-based awards are granted, subject to options and all other terms and conditions of the awards.
The maximum number common shares that may be issued under the 2020 Plan is 2,000,000. As of December 31, 2023, 234,834 performance stock units (“PSUs”), and 807,677 time-based restricted shares were outstanding, leaving 957,489 shares available to be granted under the 2020 Plan.
If the shares granted under the 2020 Plan expire or terminate for any reason without having been issued or are forfeited, they again become available for grant under the 2020 Plan. Shares granted under the 2020 Plan are not transferable or assignable other than by will or other testamentary instrument or the laws of succession.
In the event we undergo a change of control by a reorganization, acquisition, amalgamation or merger (or a plan or arrangement in connection with any of these) with respect to which all or substantially all of the persons who were the beneficial owners of the common shares immediately prior to such transaction do not, following such transaction, beneficially own, directly or indirectly more than 50% of the resulting voting power, a sale of all, or substantially all, of the Company’s assets, or the liquidation, dissolution or winding-up of the Company, outstanding awards shall be subject to the definitive agreement entered into by the Company in connection with the change of control.
At December 31, 2023, we were authorized to issue equity securities as follows:
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 |
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Incentive Plan Awards for Named Executive Officers
Outstanding Share-Based Awards and Option-Based Awards as of December 31, 2023 are as follows:
Option-based Awards | Share-based Awards | |||||||||||||||||
Market or | Market or | |||||||||||||||||
Number of | Number of | Payout Value | Payout Value of | |||||||||||||||
Securities | Value of | Shares or Units | of Share-Based | Vested Share- | ||||||||||||||
Underlying | Option | Option | Unexercised | of Shares that | Awards that | Based awards | ||||||||||||
Unexercised | Exercise | Expiration | In-the-Money | Have Not | Have Not | not Paid Out or | ||||||||||||
Name | Options | Price | Date | Options | Vested | Vested | Distributed | |||||||||||
Jason Stabell |
| — |
| $ |
|
| $ | — |
| 123,252 |
| $ | 626,120 |
| $ | — | ||
Henry N. Clanton |
| 30,000 | $ | 5.03 |
| 01/30/24 | $ | 1,500 |
| 13,526 | $ | 68,712 | $ | 74,849 | ||||
Andrew Williamson |
| — | $ |
| $ | — |
| 51,356 | $ | 260,888 | $ | — | ||||||
Incentive Plan Awards—Value Vested or Earned for Named Executive Officers
The values of incentive plan awards that were vested or earned during the year ended December 31, 2023 are as follows:
Non-Equity Incentive Plan | |||||||||
Option-Based Awards—Value | Share-based awards—Value | Compensation—Value Earned | |||||||
Name | Vested During the Year | Vested During the Year | During the Year | ||||||
Jason Stabell |
| $ | — |
| $ | 162,806 |
| $ | N/A |
Henry N. Clanton | $ | — |
| $ | 80,985 |
| $ | N/A | |
Andrew Williamson | $ | — |
| $ | 67,834 |
| $ | N/A |
We have adopted the 2020 Plan as an incentive-based share award plan applicable to all named executive officers and employees.
Change of control is defined as any event whereby any person acquires at least 50% of the Company’s stock or if a group of shareholders causes at least 50% of the board members to change.
DIRECTOR COMPENSATION
The following table contains compensation earned in the year ended December 31, 2023 by our independent directors who are not named executive officers:
Non-Equity | |||||||||||||||
Share-Based | Incentive Plan | All Other | |||||||||||||
Name |
| Fees Earned |
| Awards |
| Compensation |
| Compensation |
| Total | |||||
John Lovoi | $ | 95,000 | $ | 65,000 | $ | — | $ | — | $ | 160,000 | |||||
Tracy Stephens | $ | 65,000 | $ | 65,000 | $ | — | $ | — | $ | 130,000 | |||||
David Winn | $ | 70,000 | $ | 65,000 | $ | — | $ | — | $ | 135,000 | |||||
Jason Stankowski | $ | 55,000 | $ | 65,000 | $ | — | $ | — | $ | 120,000 | |||||
Nicola Maddox | $ | 34,507 | $ | 40,781 | $ | — | $ | — | $ | 75,288 | |||||
On a quarterly basis, we compensate each director for services rendered (unless a director elects not to receive payment) and reimburse reasonable out-of-pocket travel expenses when incurred.
As of January 1, 2023, board member compensation is fixed at an annual fee of $55,000 paid in cash quarterly and $65,000 as a share-based award valued at the prior year-end share price (vesting evenly over a three year period). The chairman of the board receives an additional $40,000 annual cash fee, the chairman of the audit committee receives an
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additional $15,000 annual cash fee, and the chairman of the compensation, nominating, and corporate governance committee receives an additional $10,000 annual cash fee.
Incentive Plan Awards—Value Vested or Earned During the Year for Directors (Other Than Named Executive Officers)
Outstanding Share-Based Awards and Option-Based Awards as of December 31, 2023 are as follows:
| Option-based Awards | Share-based Awards | ||||||||||||||||
Market or | Market or | |||||||||||||||||
Number of | Number of | Payout Value | Payout Value of | |||||||||||||||
Securities | Value of | Shares or Units | of Share-Based | Vested Share- | ||||||||||||||
Underlying | Option | Option | Unexercised | of Shares that | Awards that | Based awards | ||||||||||||
Unexercised | Exercise | Expiration | In-the-Money | Have Not | Have Not | not Paid Out or | ||||||||||||
Name | Options | Price | Date | Options | Vested | Vested | Distributed | |||||||||||
John Lovoi |
| — |
| $ | — |
|
| $ | — | 23,403 |
| $ | 118,887 |
| $ | 46,401 | ||
Tracy Stephens |
| — | $ | — |
|
| $ | — | 11,403 | $ | 57,927 | $ | 46,401 | |||||
David Winn |
| — | $ | — |
| $ | — | 11,403 | $ | 57,927 | $ | 27,777 | ||||||
Jason Stankowski | — | $ | — |
|
| $ | — | 11,403 | $ | 57,927 | $ | 27,777 | ||||||
Nicola Maddox | — | $ | — |
|
| $ | — | 4,101 | $ | 20,833 | $ | 10,414 | ||||||
The values of incentive plan awards that were vested or earned during the year ended December 31, 2023 are as follows:
Non-Equity Incentive Plan | |||||||||
Option-Based Awards—Value | Share-based awards—Value | Compensation—Value Earned | |||||||
Name | Vested During the Year | Vested During the Year | During the Year | ||||||
John Lovoi |
| $ | — |
| $ | 97,834 |
| $ | N/A |
Tracy Stephens | $ | — |
| $ | 60,509 |
| $ | N/A | |
David Winn | $ | — |
| $ | 41,886 |
| $ | N/A | |
Jason Stankowski | $ | — |
| $ | 41,886 |
| $ | N/A | |
Nicola Maddox | $ | — |
| $ | 10,414 |
| $ | N/A |
Directors and Officers Liability Insurance
We maintain directors’ and officers’ liability insurance for the protection of our directors and officers against liability incurred by them in their capacities as our directors and officers. The policy provides an aggregate limit of liability of $35,000,000 with a retention held by the Company of $1,500,000. The current annual premium for the Directors’ and Officers’ liability insurance is approximately $375,000 and is re-bid annually. The premium is not allocated between Directors and Officers as separate groups.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The table set forth below is information with respect to beneficial ownership of common shares as of March 20, 2024, by our named executive officers, by each of our directors, by all our current executive officers and directors as a group, and by each person known to us who beneficially own 5% or more of the outstanding common shares. To our knowledge, each person named in the table has sole voting and investment power with respect to the common shares identified as beneficially owned.
Unless otherwise indicated, the address of each of the individuals named below is c/o Epsilon Energy Ltd., 500 Dallas, Suite 1250, Houston, Texas 77002.
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| Number of |
| Percentage of | ||
Common | Common | ||||
Name of Beneficial Owner | Shares | Shares Owned | |||
5% Stockholders |
|
|
|
| |
Palo Duro Energy Fund, LP (1) |
| 1,461,558 |
| 6.67 | % |
Solas Capital Management LLC (2) |
| 3,768,467 |
| 17.20 | % |
Named Executive Officers and Directors |
|
|
|
| |
Jason Stabell (3) |
| 397,319 |
| * | |
Henry Clanton (4) |
| 95,674 |
| * | |
Andrew Williamson (5) |
| 15,244 |
| * | |
John Lovoi (6) |
| 266,579 |
| * | |
Tracy Stephens (7) |
| 49,401 |
| * | |
David Winn (8) |
| 20,501 |
| * | |
Jason Stankowski (9) |
| 347,727 |
| * | |
Nicola Maddox (10) |
| 2,050 |
| * | |
All executive officers and directors as a group (8 persons) (11) |
| 1,194,495 |
| 5.44 | % |
* | Indicates beneficial ownership of less than 5% of outstanding shares. |
| (1) | The address of Palo Duro Energy Fund, LP, or Palo Duro is 311 S. Wacker Drive, Suite 1250, Chicago, Illinois 60606. Matthew Dougherty is the managing partner of Palo Duro and exercises the voting and dispositive power with respect to the common shares held by Palo Duro. |
| (2) | The address of Solas Capital Management, LLC is 405 Park Avenue, New York, NY 10022. Pursuant to a Schedule 13G filed with the SEC on February 14, 2020, Solas Capital Management, LLC (“Solas”) and Frederick Tucker Golden share voting and dispositive power with respect to these common shares. All of the securities reported are owned by advisory clients of Solas, none of which is a beneficial owner of more than 5% as of July 14, 2020. |
| (3) | Mr. Stabell is our chief executive officer and a member of our board of directors. |
| (4) | Includes 30,000 shares issuable upon the exercise (at exercise price of $5.03) of options exercisable within 60 days of March 20, 2024. Mr. Clanton is our chief operating officer. |
| (5) | Mr. Williamson is our chief financial officer. |
| (6) | Includes the shares held by JVL. Mr. Lovoi is the chairman of our board of directors. |
| (7) | Mr. Stephens is a member of our board of directors. |
| (8) | Mr. Winn is a member of our board of directors. |
| (9) | Mr. Stankowski is a member of our board of directors and a partner and portfolio manager for Clayton Partners, LLC. |
| (10) | Ms. Maddox is a member of our board of directors. |
| (11) | Includes 30,000 shares issuable upon the exercise (at exercise price of $5.03) of options exercisable within 60 days of March 20, 2024. |
Changes in Control. We do not know of any arrangement, the operation of which may at a subsequent date result in a change in control of us.
Securities Authorized For Issuance under Equity Compensation Plans
The information required by Item 201 of Regulation S-K in “Item 1. Business – Market for Our Common Equity and Related Stockholder Matters.”
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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
Certain Relationships and Related Transactions
Since the beginning of fiscal 2023, there has not been, nor is there currently proposed, any transaction or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our voting securities, or any member of the immediate family of any of the foregoing persons, had or will have a direct or indirect material interest, except for the compensation and other arrangements described in “Executive Compensation” and “Director Compensation” elsewhere in this document and the transactions described below.
Independence of the Board of Directors
The Board is currently composed of five directors who provide us with a wide diversity of business experience.
Our Board has determined that John Lovoi, Tracy Stephens, Jason Stankowski, David Winn, and Nicola Maddox are independent in accordance with the listing requirements of the NASDAQ Global Market, representing over 50% of the Board. Our Board conducted its independence analysis for each of its current members, considering all relevant facts and circumstances, including the director’s other commercial, accounting, legal, banking, consulting, charitable and familial relationships. Pursuant to its review, the Board determined that with respect to each of its current members, there are no disqualifying factors with respect to director independence enumerated in the listing standards of NASDAQ or any relationships that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director, and that each such member is an “independent director” as defined in the listing standards of NASDAQ.
Indemnification of Officers and Directors
Under Section 124 of the Business Corporations Act (Alberta) (the "ABCA"), except in respect of an action by or on behalf of us or body corporate to procure a judgment in our favor, we may indemnify a current or former director or officer or a person who acts or acted at our request as a director or officer of a body corporate of which we are or were a shareholder or creditor and the heirs and legal representatives of any such persons (collectively, "Indemnified Persons") against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by any such Indemnified Person in respect of any civil, criminal or administrative actions or proceedings to which the director or officer is made a party by reason of being or having been our director or officer, if (i) the director or officer acted honestly and in good faith with a view to our best interests, and (ii) in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, the director or officer had reasonable grounds for believing that such director's or officer's conduct was lawful (collectively, the "Indemnification Conditions").
Notwithstanding the foregoing, the ABCA provides that an Indemnified Person is entitled to indemnity from us in respect of all costs, charges and expenses reasonably incurred by the person in connection with the defense of any civil, criminal or administrative action or proceeding to which the person is made a party by reason of being or having been our director or officer, if the person seeking indemnity (i) was substantially successful on the merits in the person's defense of the action or proceeding, (ii) fulfills the Indemnification Conditions, and (iii) is fairly and reasonably entitled to indemnity. We may advance funds to an Indemnified Person for the costs, charges and expenses of a proceeding; however, the Indemnified Person shall repay the moneys if such individual does not fulfill the Indemnification Conditions. The indemnification may be made in connection with a derivative action only with court approval and only if the Indemnification Conditions are met.
As contemplated by Section 124(4) of the ABCA and our by-laws, we have acquired and maintain liability insurance for our directors and officers with coverage and terms that are customary for a company of our size in our industry of operations. The ABCA provides that we may not purchase insurance for the benefit of an Indemnified Person against a liability that relates to the person's failure to act honestly and in good faith with a view to our best interests.
Our by-laws provide that, subject to the ABCA, the Indemnified Persons shall be indemnified against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by such person in respect of any civil, criminal or administrative action or proceeding to which such person is made a party by
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reason of being or having been a director or officer of the Company or such body corporate, if the Indemnification Conditions are satisfied. In addition, pursuant to our by-laws, we may indemnify such person in such other circumstances as the ABCA or law permits.
Our by-laws also provide that none of our directors or officers shall be liable for the acts, receipts, neglects or defaults of any other director, officer or employee, or for joining in any receipt or other act for conformity, or for any loss, damage or expense happening to us through the insufficiency or deficiency of title to any property acquired for or on behalf of us, or for the insufficiency or deficiency of any security in or upon which any of our moneys shall be invested, or for any loss or damage arising from the bankruptcy, insolvency or tortious acts of any person with whom any of our moneys, securities or effects shall be deposited, or for any loss occasioned by any error of judgment or oversight on his part, or for any other loss, damage or misfortune which shall happen in the execution of the duties of his or her office or in relation thereto; provided that nothing in our by-laws shall relieve any director or officer from the duty to act in accordance with the ABCA and the regulations thereunder. The foregoing is premised on the requirement under our by-laws that each of our directors and officers in exercising his or her powers and discharging duties shall act honestly and in good faith with a view to our best interests and exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances.
We have entered into indemnification agreements with our directors and officers which generally require that we indemnify and hold the indemnitees harmless to the greatest extent permitted by law for liabilities arising out of the indemnitees' service to us and our subsidiaries as directors and officers, if the indemnitees acted honestly and in good faith with a view to our best interests and, with respect to criminal or administrative actions or proceedings that are enforced by monetary penalty, if the indemnitee had no reasonable grounds to believe that his or her conduct was unlawful. The indemnification agreements also provide for the advancement of defense expenses to the indemnitees by us.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
The following table summarizes fees billed to us for fiscal 2023 and for fiscal 2022 by our principal auditors, BDO USA, P.C.:
| December 31, |
| December 31, | |||
2023 | 2022 | |||||
Audit Fees: | ||||||
Audit of financial statements | $ | 374,970 | $ | 395,634 | ||
Total Audit Fees | $ | 374,970 | $ | 395,634 | ||
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PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
(a)1. |
| |
Report of Independent Registered Public Accounting Firm (PCAOB ID | ||
Consolidated Balance Sheets as of December 31, 2023 and December 31, 2022. | ||
Consolidated Statements of Cash Flows for the years ended December 31, 2023 and December 31, 2022. | ||
(a)2. | Financial Statement Schedules: | |
None. | ||
(a)3. | Exhibits | |
3.1 | ||
3.2 | ||
3.3 | ||
4.1 | ||
10.1+ | ||
10.2 | ||
10.3+ | ||
10.4+ | ||
10.5 | ||
10.6+ | ||
10.7+ |
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10.8* | ||
21.1 | ||
23.1* | ||
23.2* | ||
31.1* | ||
31.2* | ||
32.1** | ||
32.2** | ||
97.1* | ||
99.1* | ||
101.INS* | Inline XBRL Instance Document. | |
101.SCH* | Inline XBRL Taxonomy Extension Schema Document. | |
101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | |
101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document. | |
101.LAB* | Inline XBRL Taxonomy Extension Label Linkbase Document. | |
101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | |
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
* | Filed herewith. |
** | Furnished herewith. |
+ | Denotes a management contract or compensatory plan or arrangement. |
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on March 20, 2024.
Epsilon Energy Ltd. | |
By: /s/ J. Andrew Williamson | |
J. Andrew Williamson | |
Chief Financial Officer | |
(duly authorized to sign on behalf of the registrant) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:
Signature | Title | Date | ||
/s/ Jason Stabell | Chief Executive Officer and Director | March 20, 2024 | ||
Jason Stabell | (Principal Executive Officer) | |||
/s/ J. Andrew Williamson | Chief Financial Officer | March 20, 2024 | ||
J. Andrew Williamson | (Principal Financial and Accounting Officer) | |||
/s/ John Lovoi |
| Chairman of the Board | March 20, 2024 | |
John Lovoi | ||||
/s/ Jason Stankowski | Director | March 20, 2024 | ||
Jason Stankowski | ||||
/s/ Tracy Stephens | Director | March 20, 2024 | ||
Tracy Stephens | ||||
/s/ David Winn | Director | March 20, 2024 | ||
David Winn | ||||
/s/Nicola Maddox | Director | March 20, 2024 | ||
Nicola Maddox | ||||
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