What changed in this filing

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Item 7. Management’s Discussion and Analysis

2022-03-24 compared with 2021-03-25 · 95 added, 109 removed, 239 unchanged (46% of the section changed)

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This section should be read in conjunction with the audited consolidated financial statements as of December 31, 2021 and 2020 and for the years then ended together with accompanying notes.

We are 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.

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 primary area of operation is Pennsylvania.

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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.

We own a 35% interest in the system which is operated by a subsidiary

of Williams Partners, LP.

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, 2020 our total estimated net proved reserves were 88,658 million cubic feet (MMcf) of natural gas reserves and 371,343 barrels (Bbl) of oil and other liquids, and we held leasehold rights to approximately 78,298 gross (13,285 net) acres.

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

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.

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

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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 has outpaced demand.

This market condition has resulted in historically weaker natural gas prices for the benchmark index 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.

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

We cannot, however, predict the beginning of and duration of a global recession and its impact on oil and gas demand and commodity prices.

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 become more 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 more than double from the current ~ 10.5 Bcf/d to 17 Bcf/d by 2024 based only on facilities currently commissioning or under construction.

In the Northwest STACK, the Company is evaluating options for deploying capital due to the increase in prices for oil, natural gas liquids and natural gas.

The leases are held by production which provides a long-term right to develop these assets when prospective rates of return are attractive.

In the interim, Company continues to monitor the development activities from offset operators in our area in an effort to further appraise our leasehold.

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, 2020, our total estimated net proved reserves of natural gas were 88,658 MMcf, a decrease of 35,503 MMcf from December 31, 2019.

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.

Our standardized measure of discounted future net cash flows as of December 31, 2021 and 2020 was $77.7 million and $16.0 million, respectively.

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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, 2020, revenues decreased $2.3 million, or 8.5%, to $24.4 million from $26.7 million during the same period in 2019.

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.

Revenue and volume statistics for the years ended December 31, 2021 and 2020 were as follows:

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

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

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 $1.8 million and $1.2 million respectively for the year ended December 31, 2020 and 2019.

Upstream revenue consists substantially all of revenues from Pennsylvania, but immaterial Oklahoma revenues are also included.

For the year ended December 31, 2020 upstream revenue decreased by $1.8 million, or 10.5%, over 2019, primarily as a result of lower natural gas prices, but offset by higher volumes.

Volumes were higher during 2020, despite lower prices, primarily due to the reduction of the line pressure of the gathering system, and the addition of four new wells that went online in October 2019 in addition to the four new wells that went online in May of 2020.

The end of the year daily production rate for gas in Pennsylvania was 32.8 MMcf.

Gathering system revenue decreased $0.4 million, or 4.7%, during the year ended December 31, 2020, due to an approximately $1.0 million decline in revenue from volumes of imported gas from other inter-connected systems (crossflow) in 2020.

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, 2021 increased by $16.5 million, or 109%, over 2020.

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

Upstream oil and other liquids revenue for the year ended December 31, 2021 increased by $2.5 million, or 736% over 2020.

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.

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Gathering system operating costs $ / Mcf

Upstream operating costs include costs primarily from Pennsylvania.

Oklahoma costs have also been included in the total;

however the costs are not significant.

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 costs and the associated $/Mcf 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 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).

For the year ended December 31, 2020, upstream operating costs increased by $1.5 million, or 22.5% from the same period in 2019.

The increase in total cost was primarily due to the increase in volumes produced and the cost of operating four new wells that went online in October of 2019, in addition to four new wells that went online in May of 2020.

The $/Mcfe decreased, primarily due to a decrease in discretionary maintenance spending during the year.

Gathering system costs (net of intercompany elimination) for the year ended December 31, 2020 decreased $0.9 million, or 67.9% from the same period in 2019.

The Company’s share of total gathering system costs decreased only $0.3 million for the year ended December 31, 2020 over 2019;

however, due to increased production from Epsilon and the resulting increase in the elimination of entry costs subtracted from the consolidated operating statements resulted in the large decrease in gathering system operating costs reported and a lower cost per Mcf.

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.

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

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For leasehold acquisition costs and the cost to acquire proved and unproved properties, the reserve base used to calculate depreciation and depletion is total proved reserves.

At this time, the Company has only minimal leasehold acquisition costs, and only in Pennsylvania.

At this time, the Company has only minimal leasehold acquisition costs.

For natural gas and oil development and gathering system costs, the reserve base used to calculate depletion and depreciation is proved developed reserves.

A reserve report is prepared as of December 31, each year.

The depletion for the first three quarters of the next year is normally based on the reserve report prepared at the end of the previous year, taking into consideration the limited development of the reserves over these time periods.

The fourth quarter depletion is calculated using the reserve volumes from the reserve report prepared as of December 31 of the current year.

However, for the three months ended March 31, 2020 and the three months ended June 30, 2020, due to the historically low commodity prices, the December 31, 2019 reserves report volumes were updated based on relevant prices and the depletion and depreciation were calculated using the lower volumes that resulted from the economics of the properties due to the lower prices because of the COVID-19 pandemic.

Depreciation expense includes amounts pertaining to our office furniture and fixtures, leasehold improvements, computer hardware and software.

Depreciation expense includes amounts pertaining to our office furniture and fixtures, leasehold improvements, computer hardware.

Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 7 years.

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, 2020, DD&A expense increased by $2.2 million, or 29.4%, compared to the same period in 2019.

This was due to the increase in production volumes mainly due to the reduction of the line pressure of the gathering system, and the addition of four new wells that went online in October 2019, and four new wells that went online in May 2020 which also resulted in increased production volumes.

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.

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.

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

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

If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required.

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 based on the current indicators.

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.

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

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Year ended December 31,

Gain (loss) on sale of properties

For the year ended December 31, 2019 gain (loss) on sale of properties consisted of a gain on the sale of a few stranded, non-producing leases in Pennsylvania.

Gain on sale of properties

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.

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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 legal and administrative fees related to the tender offer in June 2020, which closed

in July 2020, legal fees related to executive compensation, and increased stock-based compensation associated with the 2019 and 2020 stock grants.

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.

Interest Expense

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

Interest expense for the periods consists primarily of commitment fees as Epsilon did not access our line of credit during this time.

Interest expense remained consistent during the year ended December 31, 2020 as compared to 2019 due to having no borrowings on our 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.

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

Net gain (loss) on commodity contracts

Year ended December 31,

Gain on derivative contracts

During the years ended December 31, 2020 and 2019, we entered into fixed price swap and basis swap derivative contracts.

(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.

During the periods, the Company received $4,503,457 and $1,949,232, respectively, on the settlement of contracts due to the change in commodity prices.

In January, March and October of 2019, the Company added Henry Hub and basis swaps totaling 2.22 Bcf with expirations during the year ended December 31, 2019.

In January, February, March, April and October of 2019, the Company added Henry Hub and basis swaps totaling 4.64 Bcf with expirations during the year ended December 31, 2020.

NYMEX HH prices generally declined throughout 2019 resulting in both realized gains on the Henry Hub swaps that expired in 2019 as well as unrealized gains on the Henry Hub swaps with expirations in 2020.

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

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

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.

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.

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Year ended December 31,

Interest income and other income (expense)

For the years ended December 31, 2020 and 2019 other income (expense) consisted primarily of interest income.

Interest income decreased for the year ended December 31, 2020 due to having less cash in our money market account.

We had less money in the account because of the money spent on share repurchase programs.

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.

Net Income Compared to Adjusted EBITDA

Year ended December 31,

Net income (loss)

Net interest (income) expense

Income tax expense (benefit)

Net interest expense

Income tax expense

Depreciation, depletion, amortization, and accretion

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Stock based compensation expense

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

Foreign currency translation (gain) loss

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

Foreign currency translation loss

Adjusted EBITDA

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Capital Resources and Liquidity

Our primary source of cash during the years ended December 31, 2020 and 2019 was funds generated from operations and cash received on the settlement of derivative contracts.

In addition, in 2019, cash was received from the sale of leases in Pennsylvania.

For the years ended December 31, 2020 and 2019, cash was primarily used for operations, as well as for acquisition and development of natural gas and oil properties, the buyback of approximately $2 million of common shares through our share repurchase program, and the pre-payment of income taxes.

Additionally, in 2020, cash was used for our substantial issuer bid/issuer tender dated May 19, 2020, as amended.

Under the substantial issuer bid/tender offer, Epsilon utilized cash on hand to pay for the 2,337,034 properly tendered and not withdrawn common shares at a cost of approximately $7.15 million, excluding fees and expenses.

At December 31, 2020, we had a working capital surplus of $13.3 million, a decrease of $1.6 million from the $14.9 million surplus at December 31, 2019.

The surplus decreased from December 31, 2019 primarily due to the $9.1 million of cash spent on the repurchase of common shares.

This decrease in cash was offset by the cash generated by operations and cash received from the settlement of derivative contracts.

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.

For the years ended December 31, 2021 and 2020, 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.

At December 31, 2021, we had a working capital surplus of $24.1 million, an increase of $10.8 million from the $13.3 million surplus at December 31, 2020.

The surplus increased from December 31, 2020 primarily due to the increase in realized prices during 2021.

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

However, as the impact of recent declines in worldwide crude oil and natural gas prices and the impact of COVID-19 on the economy

evolves, Epsilon will continue to assess its liquidity needs.

In the event of a sustained market deterioration, the Company may need additional liquidity, which would require it to evaluate available alternatives and take appropriate actions.

Year ended December 31, 2021 compared to 2020

During the year ended December 31, 2021, $20.0 million was provided by our operating activities, compared to $14.8 million in 2020, a $5.2 million, or 35%, increase.

The increase was mainly due to the increase in cash received on the settlement of derivative contracts.

We used $6.5 million for investing activities during the year ended December 31, 2020.

This was spent primarily on leasehold and development costs targeting increasing production in Pennsylvania.

During the same period of 2019, we used $10.5 million.

This was spent primarily on leasehold and development costs targeting increasing production in Pennsylvania and Oklahoma, and the acquisition of unproved properties in Oklahoma, all offset by the $1.4 million received on the sale of leases in Pennsylvania.

The $9.1 million and $2.8 million for the years ended December 31, 2020 and 2019, respectively, 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 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.

Credit Agreement

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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%.

Effective January 7, 2019 the agreement was amended to extend the maturity date to March 1, 2022

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 .

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

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LIBOR + 3.25%

Available borrowing capacity under the credit agreement is $23 million was reaffirmed on February 11, 2020.

Repurchase Transactions

Since May 20, 2019, 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 May 19, 2020.

Since the commencement of the NCIB on May 20, 2019, Epsilon has strengthened its financial position.

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.

Since May 20, 2019, Epsilon has repurchased 1,353,410 common shares of the authorized 1,367,762 purchase amount.

During the year ended December 31, 2020, the Company spent $1,910,765, excluding fees and expenses, under the NCIB.

For the year ended December 31, 2019, Epsilon spent $1,456,417, excluding fees and expenses, to repurchase common shares.

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.

In May 2020, upon the terms and subject to the conditions described in the Offer to Purchase dated May 19, 2020, as amended, the Company offered to repurchase up to 2,000,000 of its common shares for $3.06 per share, excluding taxes and interest, for a total cost of approximately $6.1 million, excluding expenses of the tender offer.

As permitted under Rule 13e-4(f) and Rule 14e-1(b) of the Exchange Act and as stated in its Offer to Purchase, Epsilon was permitted to take up and pay for 2,000,000 common shares plus 2% of its issued and outstanding common shares, or an aggregate total of up to 2,522,673 common shares.

The tender offer expired on June 30, 2020, and on July 6, 2020 the Company announced that it accepted 2,337,034 shares for repurchase under the terms of the Offer to Purchase for an aggregate consideration of $7,151,324, or $3.06 per share, excluding fees and expenses.

The Company canceled all common shares taken up and paid for under the tender offer.

The Company funded the repurchases under the tender offer with cash on hand.

Accordingly, during the year ended December 31, 2020, the Company spent $9,062,089, excluding fees and expenses, to repurchase common shares.

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.

Derivative Transactions

We have entered into hedging arrangements to reduce the impact of natural gas price volatility on operations.

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, 2020, we had no outstanding contracts.

At December 31, 2021, Epsilon’s outstanding natural gas commodity swap contracts consisted of the following:

Fair Value of Asset

Derivative Type

December 31, 2021

Two-way costless collar

Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2020:

Payments Due by Period

Asset retirement obligations, undiscounted

Capital expenditure commitments

Operating leases

Total future commitments

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 budget by means of giving the necessary authorizations to the asset operator to incur the expenditures in a future period.

Current commitments have been included in the contractual obligations table above.

Current commitments amounted to approximately $3.8 million, all of which we expect to incur in 2022.

Based on current natural gas prices and anticipated levels of production, we believe that the estimated net cash generated from operations, together with cash on hand and amounts available under our credit agreement, will be adequate to meet liquidity needs for the next 12 months and beyond, including satisfying our financial obligations and funding our operating and development activities.

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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

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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 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.

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.

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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 described in the Fair Value Measurement Topic of the ASC based on estimated discounted net cash flows.

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.

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(iii) future commodity prices and (iv) a market-based weighted average cost of capital rate.

Under ASC 360, we evaluate impairment of proved and unproved natural gas and oil properties on an area basis.

We evaluate impairment of proved and unproved 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.

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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.

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 described in the Fair Value Measurement Topic of the ASC, which considers estimated discounted future cash flows.

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.

Derivative Financial Instruments

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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