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Item 7. Management’s Discussion and Analysis

2023-03-24 compared with 2022-03-24 · 117 added, 142 removed, 192 unchanged (57% of the section changed)

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Our primary area of operation is Pennsylvania.

Our assets are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs.

Substantially all of the production from our Pennsylvania acreage (4,597 net) is dedicated to the Auburn Gas Gathering System, or the Auburn GGS, located in Susquehanna County, Pennsylvania for a 15-year term expiring in 2026 under an operating agreement whereby the Auburn GGS owners receive a fixed percentage rate of return on the total capital invested in the construction of the system.

Epsilon owns a 35% interest in the system which is operated by a subsidiary of Williams Partners, LP.

In 2021, we paid $1.6 million to the Auburn GGS to gather and treat our 9.8 Bcf of natural gas production in Pennsylvania ($1.8 million to the Auburn GGS to gather and treat our 11.0 Bcf in 2020).

At December 31, 2021 our total estimated net proved reserves were 110,969 million cubic feet (MMcf) of natural gas reserves, 819,726 barrels (Bbl) of NGL reserves, and 305,052 barrels (Bbl) of oil and other liquids, and we held leasehold rights to approximately 76,544 gross (13,176 net) acres.

At December 31, 2022 our total estimated net proved reserves were 90,040 MMcf of natural gas reserves, 491,226 Bbls of NGL reserves, and 211,059 Bbls of oil and other liquids, and we held leasehold rights to approximately 75,954 gross (13,625 net) acres.

We have natural gas production in Pennsylvania, and natural gas, oil and other liquid production from our operated and non-operated wells in Oklahoma.

Business Strategy

Our business strategy is to manage the cash flow generated from our producing leasehold and midstream assets in a manner where the risked capital allocation provides attractive rates of return.

Our remaining inventory of drillable locations within existing leasehold is sufficient to maintain this cash flow for several years at capital expenditure levels well within the yearly free cash flow generated from these assets.

In addition, we seek to identify attractive onshore natural gas and oil properties in the United States, to acquire leasehold interests and to develop our leasehold interests with the goal of deploying capital to earn attractive rates of return.

The core Marcellus Shale is one of the most attractive dry gas resources in the United States and has attracted significant development capital.

Well productivity has improved dramatically for many years due to improving techniques in drilling and completing wells, resulting in increasing initial production rates and gas recoveries.

The resulting supply of natural gas at times stresses the transportation infrastructure of the Northeast US and exacerbates the local price discount to Henry Hub.

In many other basins throughout the US, the increase in natural gas production had historically outpaced demand.

Over the past couple of years, this over supply condition has become more balanced and demand growth from increased LNG exports and pipeline exports to Mexico have provided attractive markets improving the prices for natural gas.

The operating environment remains challenging in Northeast Pennsylvania.

We implemented a number of initiatives to enhance the value of our core assets in the Marcellus including a comprehensive review of well spacing and completion productivity for both the Lower and Upper Marcellus, and we are working with our well operators to increase operating efficiency.

In addition, we continue to work closely with our gathering system partners in order to optimize the operating conditions, enhance operational safety, and to preserve and grow the long-term value of our gathering system assets.

The major producers in the Appalachian region are under pressure from capital markets to demonstrate capital discipline and control costs.

Several major producers have announced reduced capital programs to balance the supply-demand for the commodity.

Accordingly, we expect local production during 2022 to be flat compared to 2021.

Our target is to maintain our current production level or grow modestly, but only if natural gas price levels are sufficient and the capital deployed can achieve our internal hurdle rate of return.

In the longer term, we believe natural gas prices will remain constructive due to moderating supply from both dry gas regions and associated gas from oil prone basins, and incremental demand from LNG exports, exports to Mexico and further coal to gas switching for domestic electrical power generation.

Specifically, LNG export capacity is expected to grow from the current ~ 13 Bcf/d to 17 Bcf/d by 2024 based only on facilities currently commissioning or under construction.

In the Northwest STACK of Oklahoma, we continue to appraise recent and historical results of the Meramec formation from both our wells and analog wells within the focus area.

At December 31, 2021, our initial well continues to outperform the pre-completion type curve expectations in terms of both production-to-date and projections for ultimate recoveries.

The Company has drilled, but has not yet completed, additional Meramec appraisal wells within the focus area to prove a greater area for further exploitation on an opportunistically prudent timeline.

We realized net income of $11.6 million during 2021 as compared to net income of $0.9 million for 2020.

At December 31, 2021, our total estimated net proved reserves of natural gas were 110,969 MMcf, an increase of 22,311 MMcf from December 31, 2020.

We are committed to disciplined capital allocation which could include shareholder returns in the form of dividends and/or share buybacks.

We seek to maintain a strong balance sheet and liquidity to allow us to opportunistically invest in both our existing project areas and potential new projects.

To date, our investments have been focused on the Marcellus Shale unconventional reservoir in Pennsylvania (“PA”).

Our PA assets are supported by our 35% ownership in the Auburn GGS.

Over the last two years, we have also been active in our position in the NW Stack area of Oklahoma (“OK”).

We have a substantial remaining drillable location inventory within our existing leasehold in PA and OK.

The Company also seeks to identify new opportunities in onshore North American natural gas and oil basins.

In the second half of 2022, we evaluated several potential investments outside our existing projects, with a focus on the Northeastern United States.

We expect to expand our area of interest in 2023 to selectively consider potential investments in other North American gas and oil basins.

During 2022, we realized net income of $35.4 million as compared to net income of $11.6 million for 2021.

At December 31, 2022, our total estimated net proved developed reserves were 80,795 MMcfe, an increase of 10% from December 31, 2021.

The increase is mainly attributable to revisions to previous estimates and transfers from proved undeveloped.

At December 31, 2022, our total estimated net proved reserves were 94,254 MMcfe, a 20% decrease from December 31, 2021.

The decrease in our total proved reserves is due to a change in our previously adopted development plan, primarily attributable to estimated proved undeveloped reserves in PA and OK that shifted into the probable reserve category under SEC guidelines due to timing.

As a non-operating working interest owner, we often do not have direct control or visibility over the pace of investment in our assets by the operator.

We anticipate reevaluating these reserves once we have line of sight on development timing.

Our standardized measure of discounted future net cash flows as of December 31, 2022 and 2021 was $145.8 million and $77.7 million, respectively.

This measure of discounted future net cash flows does not include any estimate for future cash flows generated by Epsilon’s gathering system assets.

This measure of discounted future net cash flows does not include any estimate for future cash flows generated by our gathering system assets.

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.

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

During the year ended December 31, 2022, revenues increased $27.6 million, or 65%, to $70.0 million from $42.4 million during the year ended December 31, 2021 due primarily to increased prices.

Revenue and volume statistics for the years ended December 31, 2022 and 2021 were as follows:

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Price ($/Mcf)

PA Exit Rate (MMcfpd)

Oil and other liquids revenue

Price ($/Bbl)

Gathering system revenue

Total PA Revenues

Natural gas revenue

Volume (MMcf)

Price ($/Mcf)

Natural liquids revenue

Price ($/Bbl)

Oil and condensate revenue

Price ($/Bbl)

Total OK Revenues

Total Revenues

We earn gathering system revenue as a 35% owner of the Auburn Gas Gathering system.

This revenue consists of fees paid by Anchor Shippers and third-party customers of the system to transport gas from the wellhead to the compression facility, and then to the delivery meter at Tennessee Gas Pipeline.

For the year ended December 31, 2021, approximately 80% of the Auburn GGS revenues earned are gathering fees, while 20% are compression fees.

customers represent approximately 5% of gathering revenues and 4% of compression revenues.

For the year ended December 31, 2020, approximately 85% of the Auburn GGS revenues earned were gathering fees, while 15% were compression fees.

Third party customers represent approximately 4% of gathering revenues and 2% of compression revenues.

Revenues derived from transporting and compressing Epsilon’s production which have been eliminated from gathering system revenues amounted to $1.6 million and $1.8 million respectively for the years ended December 31, 2021 and 2020.

Upstream natural gas revenue for the year ended December 31, 2022 increased by $25.2 million, or 80%, over 2021.

This was primarily a result of higher natural gas prices partially offset by lower volumes being produced due to natural decline of the wells.

An increase of $27.5 million was due to higher natural gas prices partially offset by a reduction of $2.3 million due to lower volumes being produced due to natural decline of the wells.

Upstream natural gas liquids revenue for the year ended December 31, 2022 increased by $0.7 million, or 65% over 2021.

This was a result of increased production from new wells in addition to higher NGL prices.

Upstream oil and other liquids revenue for the year ended December 31, 2022 increased by $1.4 million, or 80% over 2021.

This was a result of increased production from new wells in addition to higher oil prices.

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

The Auburn GGS is subject to a cost of service model, whereby the Anchor Shippers dedicate acreage and reserves to the Auburn GGS.

In exchange for this dedication, the owners of the Auburn system agree to a fixed rate of return on capital invested which cannot be exceeded.

Therefore, rather than being subject to a fixed gathering rate, the Shippers are subject to a fluctuating gathering rate which is re determined annually in order to produce the contractual return on capital to the Auburn GGS owners.

The term of the model is fixed from 2012 to 2026.

Each year, actual throughput, revenue, operating expenses and capital are captured in the model, and the remaining years are forecasted.

The model then iterates for a gathering rate that yields the contractual rate of return.

All else being equal, to the extent that throughput is higher or capital is lower than the preceding year’s forecast, the gathering rate will decline.

Gathering system revenue for the year ended December 31, 2022 increased by $0.2 million, or 3% over 2021.

This was the result of increased throughput in the system.

Revenues derived from transporting and compressing our production, which have been eliminated from gathering system revenues amounted to $1.5 million and $1.6 million, respectively, for the years ended December 31, 2022 and 2021.,

Operating Costs

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Gathering system operating costs $/Mcf

Operating costs include the effects of elimination entries to remove the gathering fees paid to Epsilon’s ownership in the gathering system.

Prior to the year ended December 31, 2022, the gathering fees were netted from the gathering system operating costs.

For the year ended December 31, 2022, the Company determined that it would be more appropriate to net the $1.5 million fees from the upstream lease operating costs.

To be consistent with the current presentation, the prior year elimination of $1.6 million has been reclassed as well.

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

For the year ended December 31, 2021, upstream operating costs decreased by $0.2 million, or 2.1% from the same period in 2020.

The decrease in total cost was primarily due to the decrease in volumes produced primarily in Pennsylvania.

The $/Mcfe increased primarily due to increased cost of discretionary maintenance during the year.

Gathering system operating costs consist primarily of rental payments for the natural gas fueled compression units.

Other significant gathering system operating costs include chemicals (to prevent corrosion and to reduce water vapor in the gas stream), saltwater disposal, measurement equipment / calibration and general project management.

The gathering system operating total per unit operating costs reported include the effects of elimination entries to remove the gas gathering fees billed by the gas gathering system operator to Epsilon’s upstream operations, and the volume associated with those fees.

The elimination entries amounted to $1.6 million and $1.8 million for the years ended December 31, 2021 and 2020, respectively (see Note 12, “Operating Segments,” of the Notes to Consolidated Financial Statements).

Gathering system costs (net of intercompany elimination) for the year ended December 31, 2021 increased $0.3 million, or 69% from the same period in 2020.

Although the Company’s gross share of total gathering system costs

increased only $0.06 million, or 3%, for the year ended December 31, 2021 over 2020, the elimination entry decreased by $0.2, or 11% for the same period.

This was due to a decrease in throughput in the gathering system resulting in a higher cost per MCF.

For the year ended December 31, 2022, upstream operating costs increased by $0.8 million, or 13.1% from the same period in 2021.

The increase was due to extraordinary plugging and abandonment costs related to atypical wellbore conditions in two older vintage wells in Pennsylvania, which is not representative of the other wells.

Gathering system operating costs consist primarily of rental payments for the natural gas fueled compression units and overhead fees due to the system’s operator.

For the year ended December 31, 2022, gathering system operating costs decreased by $0.03 million, or 1.4% from the same period in 2021.

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

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Accretion expense is related to the asset retirement costs.

During the year ended December 31, 2021, DD&A expense decreased by $2.9 million, or 31%, compared to the same period in 2020.

This was primarily due to the increase in reserves reported and the decrease in production volumes.

The lower volumes spread over the increased reserves resulted in lower DD&A.

During the year ended December 31, 2022, DD&A expense was generally consistent compared to the same period in 2021, decreasing by $0.2 million, or 3%.

Year ended December 31,

Epsilon performs a quantitative impairment test quarterly or whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable, over proved properties using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods.

We perform a quantitative impairment test whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable, over proved properties using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods.

When indicators of impairment are present, GAAP requires that the Company first compare expected future undiscounted cash flows by asset group to their respective carrying values.

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Additionally, GAAP requires that if an exploratory well is determined not to have found proved reserves, the costs incurred, net of any salvage value, should be charged to expense.

During the three months ended March 31, 2020, the Company recognized certain indicators of impairments specific to our Oklahoma assets and determined that carrying value of those assets was not recoverable.

As a result of this assessment, a $1.76 million impairment was assessed on the Company’s Oklahoma assets at March 31, 2020.

No additional impairment was required as of December 31, 2020.

For the year ended December 31, 2022, no impairment was recorded.

For the year ended December 31, 2021, the Company recognized dry hole costs of $0.15 million.

Gain (Loss) on Sale of Properties

Year ended December 31,

Gain on sale of properties

Gain on sale of assets

For the year ended December 31, 2022, the Company recorded a gain for a well-bore only asset sale and conveyance and partial release of oil and gas leases in Oklahoma.

For the year ended December 31, 2021, the Company recorded a gain on the sale of the shallow rights leases and wells in Oklahoma.

We had no sales for the year ended December 31, 2020.

General and Administrative (“G&A”)

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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.

The G&A expenses increased by $1.2 million, or 22%, during the year ended December 31, 2021 from the same period in 2020.

This was mainly due to increased legal fees related to the complaint filed against Chesapeake, the addition of a salary and benefits for the CEO, and increased stock-based compensation associated with the 2020 stock grants.

G&A expenses increased by $0.5 million, or 8%, during the year ended December 31, 2022 from 2021.

Increased compensation costs of $1.3 million associated with the management transition was offset by a decrease in legal fees by $0.8 million.

Interest Expense

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

Interest expense decreased by $0.01 million, or 11%, during the year ended December 31, 2021 from the same period in 2020.

Interest expense decreased by $0.05 million, or 50%, during the year ended December 31, 2022 from 2021.

The decrease is due to the reduction in the borrowing base on our line of credit during this time.

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Year ended December 31,

(Loss) gain on derivative contracts

During the years ended December 31, 2021 and 2020, Epsilon entered into NYMEX Henry Hub Natural Gas Futures swap, Dominion basis swap, and two-way costless collar derivative contracts for the purpose of hedging its physical natural gas sales revenue.

The amounts recorded represent the fair value changes on our derivative instruments during the period.

Gain (loss) on derivative contracts

During the years ended December 31, 2022 and 2021, we entered into NYMEX Henry Hub (“HH”) Natural Gas Futures swaps, Dominion basis swaps, and two-way costless collar derivative contracts for the purpose of hedging our physical natural gas sales revenue.

The amounts recorded represent the fair value changes on our derivative instruments during the year.

For the year ended December 31, 2022, the Company paid net cash settlements of $1,225,837.

For the year ended December 31, 2020, the Company received $4,503,457 on the settlement of contracts.

For the year ended December 31, 2021, the Company paid net cash settlements of $4,243,085.

In April 2022, the Company added NYMEX HH collars totaling 1.2 Bcf and basis swaps totaling 1.2 Bcf.

NYMEX HH prices generally increased throughout the first three quarters of 2022 resulting in realized losses for the year ended December 31, 2022.

In February 2021, the Company added Henry Hub collars totaling 3.96 Bcf and basis swaps totaling 0.31 Bcf.

In August 2021, the Company added Henry Hub collars totaling 0.46 Bcf and basis swaps totaling 1.10 Bcf.

In August 2021, the Company added Henry Hub swaps totaling 0.46 Bcf and basis swaps totaling 1.10 Bcf.

NYMEX HH prices generally increased throughout 2021 resulting in large realized losses for the year ended December 31, 2021.

During 2020, the Company added 0.6 Bcf of Henry Hub swaps and 2.14 Bcf of basis swaps to its existing 2020 hedge portfolio.

Both Henry Hub prices and basis prices generally declined throughout 2020 resulting in large realized gains for the year ended December 31, 2020.

The Company did not add any 2021 hedges during 2020.

At December 31, 2022, the Company had outstanding NYMEX HH swaps totaling 1.07 Bcf with a trade price of $5.212 and Tennessee Z4 basis swaps totaling 1.07 Bcf with a trade price of ($1.25) to hedge a portion of expected volumes for the contract period of April 2023 to October 2023.

Other Income (Expense)

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Interest income and other income

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

During the year ended December 31, 2022, interest income increased by $0.4 million, or 877%, during the year ended December 31, 2022 from the same period in 2021.

This increase was primarily due to the utilization of additional financial instruments with higher prevailing interest rates in 2022.

Net Income Compared to Adjusted EBITDA

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Stock based compensation expense

Loss on derivative contracts net of cash received or paid on settlement

(Gain) loss on derivative contracts net of cash received or paid on settlement

Foreign currency translation loss

Adjusted EBITDA

Epsilon defines Adjusted EBITDA as earnings before (1) net interest expense, (2) taxes, (3) depreciation, depletion, amortization and accretion expense, (4) impairments of natural gas and oil properties, (5) non-cash stock compensation expense, (6) gain or loss on derivative contracts net of cash received or paid on settlement, and (7) other income.

We define Adjusted EBITDA as earnings before (1) net interest expense, (2) taxes, (3) depreciation, depletion, amortization and accretion expense, (4) impairments of natural gas and oil properties, (5) non-cash stock compensation expense, (6) gain or loss on derivative contracts net of cash received or paid on settlement, and (7) other income.

Adjusted EBITDA is not a measure of financial performance as determined under U.S.

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Additionally, Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

Epsilon has included Adjusted EBITDA as a supplemental disclosure because its management believes that EBITDA provides useful information regarding its ability to service debt and to fund capital expenditures.

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 the Company in relation to other natural gas and oil companies providing corresponding non-U.S.

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.

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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.

The table above sets forth a reconciliation of Adjusted EBITDA to net income, which is the most directly comparable measure of financial performance calculated under U.S.

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

The primary source of cash during the year ended December 31, 2021 was funds generated from operations.

For the year ended December 31, 2020, the primary source of funds was from operations in addition to cash received on the settlement of derivative contracts.

The primary source of cash during the years ended December 31, 2022 and 2021 was funds generated from operations.

For the years ended December 31, 2022 and 2021, cash was primarily used for operations, as well as the development of natural gas and oil properties, the buyback of common shares through our share repurchase program, and the pre-payment of income taxes.

In 2022, we began paying dividends quarterly, which totaled $5.9 million.

At December 31, 2022, we had a working capital surplus of $51.0 million, an increase of $26.9 million from the $24.1 million surplus at December 31, 2021.

The surplus increased from December 31, 2021 primarily due to the increase in realized prices during 2022.

The Company anticipates its current cash balance, cash flows from operations, and available sources of liquidity to be sufficient to meet its cash requirements.

We anticipate that our current cash balance, cash flows from operations, and available sources of liquidity to be sufficient to meet our cash requirements.

Year ended December 31, 2022 compared to 2021

During the year ended December 31, 2022, $38.0 million was provided by our operating activities, compared to $20.0 million in 2021, a $18.0 million, or 90%, increase.

The increase was mainly due to the increase in realized prices resulting in increased revenue offset by an increase in cash paid for settlements of derivative contracts.

We used $4.4 million for investing activities during the year ended December 31, 2021, compared to $6.5 million in 2020, a $2.1 million, or 32%, decrease.

This was spent primarily on development costs targeting increasing production in Pennsylvania and Oklahoma, partially offset by the proceeds from the sale of the shallow right leases and wells in Oklahoma.

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

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

The increase was mainly due to the increase in realized prices resulting in increased revenue.

We used $7.9 million for investing activities during the year ended December 31, 2022, compared to $4.4 million in 2021, a $3.4 million, or 77%, increase.

This was spent primarily on upstream development costs in Pennsylvania and Oklahoma.

During the year ended December 31, 2022, $12.0 million of cash used for financing activity was related to the repurchase of our common shares and the payment of quarterly dividends.

This was offset by $0.7 million of proceeds from the exercise of stock options.

During the year ended December 31, 2021, $2.3 million of cash was used for financing activity, which was primarily related to the repurchase of our common shares.

Credit Agreement

In addition, the Company has a senior secured credit facility which includes a total commitment of up to $100 million.

The current effective borrowing base is $14 million, which is subject to semi-annual redetermination.

The Company has a senior secured credit facility which includes a total commitment of up to $100 million.

The effective borrowing base is $30 million, which is subject to semi-annual redetermination.

There are currently no borrowings under the facility.

If Epsilon decided to access the facility, depending on the level of borrowing, the Company might need to increase its hedging activity.

If we decide to access the facility, depending on the level of borrowing, we might need to increase our hedging activity.

Borrowings from the Facility may be used for the acquisition and development of oil and gas properties, investments in cash flow generating assets complimentary to the production of oil and gas, and for letters of credit and other general corporate purposes.

Upon each advance, interest is charged at the highest of a) rate of LIBOR plus an applicable margin (2.75%-3.75% based on the percent of the line of credit utilized), b) the Prime Rate, or c) the sum of the Federal Funds Rate plus 0.5%.

Upon each advance, interest is charged at the highest of a) the Prime Rate, or b) the sum of the Federal Funds Rate plus 0.5%, plus an applicable margin (0.25%-1.25%, based on percentage utilization on the facility).

The facility matures on March 1, 2024.

Effective April 6, 2021, the agreement was amended to extend the maturity date to March 1, 2024.

In addition, the agreement was amended to include a Benchmark Replacement definition and transition plan to be used at such time when the LIBOR rate is discontinued.

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

On November 23, 2021, the borrowing base of $14 million was reaffirmed until May 1, 2022, the next periodic redetermination of the borrowing base .

On February 10, 2023, Epsilon Energy USA entered into the Ninth Amendment of the Credit Agreement.

The borrowing base was increased to $30 million.

LIBOR was removed as a reference option in the calculation of interest.

Hedging requirements were amended to be between 0%-62.5% of the 24-month projected production volumes, based on percentage utilization on the facility.

Also, cash distributions to the parent company (Epsilon Energy Ltd.) were allowed

if the facility is < 80% utilized and the leverage ratio (total debt / income adjusted for interest, taxes and non-cash amounts) is less than 2.

The bank has a first priority security interest in the tangible and intangible assets of Epsilon Energy USA, Inc.

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Under the terms of the agreement, the Company must maintain the following covenants:

● Interest coverage ratio greater than 3 based on income adjusted for interest, taxes and non-cash amounts.

● Current ratio, adjusted for line of credit amounts used and available and non-cash amounts, greater than 1.

● Leverage ratio less than 3.5 based on income adjusted for interest, taxes and non-cash amounts.

We were in compliance with the financial covenants of the agreement as of December 31, 2021 and expect to be in compliance for the next 12 months.

We expect to remain in compliance as we currently have no borrowings under the facility and have funded all operations for 2021 out of operating cash flow and cash on hand and expect to continue to do so through 2022.

Borrowing Base

December 31, 2021

Revolving line of credit

LIBOR + 3.25%

● I nterest coverage ratio greater than 3 (income adjusted for interest, taxes and non-cash amounts / cash interest expense)

● Current ratio greater than 1 (current assets / current liabilities)

● Leverage ratio less than 3.5 (total debt / income adjusted for interest, taxes and non-cash amounts)

We were in compliance with the financial covenants of the agreement as of December 31, 2022.

Repurchase Transactions

Commencing on January 1, 2021, Epsilon has conducted a normal course issuer bid (“NCIB”) to repurchase our issued and outstanding common shares, when doing so has been accretive to management's estimates of intrinsic value per share.

The NCIB ended on December 31, 2021.

Since the commencement of the NCIB, Epsilon has strengthened its financial position.

With sufficient cash flow from operations, it used discretionary cash to fund these repurchases.

During the year ended December 31, 2021, Epsilon has repurchased 534,015 common shares of the authorized 1,193,000 purchase amount and spent $2,423,007 under the NCIB.

Commencing on May 20, 2019, Epsilon conducted a normal course issuer bid (“NCIB”) to repurchase up to 1,367,762 issued and outstanding common shares.

The NCIB ended on May 19, 2020.

Additionally, on May 14, 2020, the Company’s Board of Directors announced its intention to commence a substantial issuer bid/issuer tender offer to purchase for cash up to an aggregate of approximately $6.2 million of its common shares.

The tender offer expired on June 30, 2020.

During the year ended December 31, 2020, the Company repurchased 2,994,348 common shares and spent $9,062,089, excluding fees and expenses The Company canceled all common shares taken up and paid for under the NCIB and tender offer.

The Company funded the repurchases with cash on hand.

Commencing on March 8, 2022, we implemented a plan to repurchase our issued and outstanding common shares and to return capital to our shareholders.

We used cash on hand to fund these repurchases.

During the year ended December 31, 2022, we repurchased 982,500 common shares of the maximum of 1,183,410 authorized for repurchase and spent $6,234,879 under the plan.

The repurchased stock had an average price of $6.32 per share (excluding commissions) and was subsequently retired during the year ended December 31, 2022.

In 2023, we repurchased 190,700 common shares at an average price of $5.82 per share (excluding commissions) before the plan terminated on March 7, 2023.

Commencing on January 1, 2021, we implemented a plan to repurchase our issued and outstanding common shares.

The plan terminated on December 31, 2021.

We used cash on hand to fund these repurchases.

During the year ended December 31, 2021, we repurchased 534,015 common shares of the maximum of 1,193,000 authorized for repurchase and spent $2,423,007 under the plan.

The repurchased stock had an average price of $4.51 per share (excluding commissions) and was subsequently retired during the year ended December 31, 2022.

On March 9, 2023, the Board of Directors authorized a new share repurchase program of up to 2,292,644 common shares, representing 10% of the outstanding common shares of Epsilon, for an aggregate purchase price of not more than US $15.0 million.

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, 2023 and end on March 26, 2024, unless the maximum amount of common shares is purchased before then or Epsilon provides earlier notice of termination.

Derivative Transactions

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At December 31, 2022, Epsilon’s outstanding natural gas commodity swap contracts consisted of the following:

Weighted Average Price ($/MMbtu)

Fair Value of Asset

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December 31, 2022

Two-way costless collar

NYMEX Henry Hub swap

Tennessee Z4 basis swap

Contractual Obligations

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As of December 31, 2022 and 2021, we had no off-balance sheet arrangements.

Summary of Critical Accounting Policies and Estimates

Summary of Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements and accompany notes, which have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP, and SEC rules which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes.

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We also describe the most significant estimates and assumptions we make in applying these policies.

Successful Efforts Accounting

We use the successful efforts method of accounting for natural gas and oil operations.

Under this method, the fair value of property acquired and all costs associated with successful exploratory wells and all development wells are capitalized.

The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found.

At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found.

If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense.

In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells.

Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made.

Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

We do not currently do any exploratory drilling so this does not currently come into use.

Gathering System

We hold an undivided interest in a gas gathering system asset that supports our Pennsylvania operations.

We account for the costs and revenue from this system using the proportionate consolidation method.

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

Proved Natural Gas and Oil Reserves

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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.

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.

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Depreciation, depletion and amortization rates are updated quarterly to reflect the addition of capital costs, reserve revisions (upwards or downwards) and additions, property acquisitions and/or property dispositions and impairments.

Depreciation and amortization of other property, plant and equipment is calculated on a straight-line basis over the estimated useful life of the asset.

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.

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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.

expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.

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.

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and Canada are subject to change and differing interpretations requiring judgment.

Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in future periods, which requires judgment.

Deferred tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax authorities in future periods, which requires judgment.

Income tax filings are subject to audits and re-assessments.

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.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis