Epsilon Energy Ltd. (EPSN) FY 2023 MD&A

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.

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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.

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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.

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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.

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We continue to evaluate new opportunities in numerous onshore North American natural gas and oil basins.

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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:

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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:

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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)

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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

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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”)

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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

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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

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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

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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.

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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.

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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.

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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.

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Income Tax Expense

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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.

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Net Income Compared to Adjusted EBITDA

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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:

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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:

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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

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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.

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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

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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.

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