Epsilon Energy Ltd. 10-K

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The following discussion is intended to assist in the understanding of trends and significant changes in or results of operations and the financial condition of Epsilon Energy Ltd. and its subsidiaries for the periods presented. This section should be read in conjunction with the audited consolidated financial statements as of December 31, 2020 and 2019 and for the years then ended together with accompanying notes. Overview 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. 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 (3,979 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 32 ​ ​ ​ of Williams Partners, LP. In 2020, we paid $1.8 million to the Auburn GGS to gather and treat our 11.0 Bcf of natural gas production in Pennsylvania ($1.2 million to the Auburn GGS to gather and treat our 7.6 Bcf in 2019). 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. 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 has outpaced demand. This market condition has resulted in historically weaker natural gas prices for the benchmark index Henry Hub. 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 2021 to be flat compared to 2020. 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. We realized net income of $0.9 million during 2020 as compared to net income of $8.7 million for 2019. 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. Our standardized measure of discounted future net cash flows as of December 31, 2020 and 2019 was $16.0 million and $49.6 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. 33 ​ ​ ​ 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. Revenues 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. Revenue and volume statistics for the years ended December 31, 2020 and 2019 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended ​ ​ December 31, ​ 2020 2019 Revenues ​ ​ ​ ​ ​ ​ Natural gas revenue ​ $ 15,207,227 ​ $ 16,945,302 Volume (MMcf) ​ 11,204 ​ 7,757 Avg. Price ($/Mcf) ​ $ 1.36 ​ $ 2.18 PA Exit Rate (MMcfpd) ​ 32.8 ​ 30.5 Oil and other liquids revenue ​ $ 338,325 ​ $ 424,661 Volume (MBO) ​ 14.9 ​ 14.5 Avg. Price ($/Bbl) ​ $ 22.66 ​ $ 29.24 Gathering system revenue ​ $ 8,879,728 ​ $ 9,320,373 Total Revenues ​ $ 24,425,280 ​ $ 26,690,336 ​ 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, 2020, approximately 85% of the Auburn GGS revenues earned are gathering fees, while 15% are compression fees. Third party customers represent approximately 4% of gathering revenues and 2% of compression revenues. For the year ended December 31, 2019, approximately 87% of the Auburn GGS revenues earned were gathering fees, while 13% were compression fees. Third party customers represent approximately 11% of gathering revenues and 4% 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. 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. 34 ​ ​ ​ 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, 2020 and 2019: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2020 2019 Lease operating costs ​ $ 8,052,471 ​ $ 6,571,394 Gathering system operating costs ​ ​ 429,749 ​ ​ 1,337,409 ​ ​ $ 8,482,220 ​ $ 7,908,803 ​ ​ ​ ​ ​ ​ ​ Upstream operating costs—Total $/Mcfe ​ ​ 0.72 ​ ​ 0.85 Gathering system operating costs $ / Mcf ​ ​ 0.04 ​ ​ 0.11 ​ 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. 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 elimination entries amounted to $1.8 million and $1.2 million for the years ended December 31, 2020 and 2019, 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. Depletion, Depreciation, Amortization and Accretion (DD&A) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2020 2019 Depletion, depreciation, amortization and accretion ​ $ 9,557,891 ​ $ 7,387,681 ​ 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. At this time, the Company has only minimal leasehold acquisition costs, and only in Pennsylvania. 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. 35 ​ ​ ​ Depreciation expense includes amounts pertaining to our office furniture and fixtures, leasehold improvements, computer hardware and software. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 7 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. Impairment ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2020 2019 Impairment ​ $ 1,760,000 ​ $ — ​ 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. 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. 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. Gain (Loss) on Sale of Properties ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2020 2019 Gain (loss) on sale of properties ​ $ — ​ $ 1,375,000 ​ 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. We had no sales for the year ended December 31, 2020. General and Administrative (“G&A”) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2020 2019 General and administrative ​ $ 5,589,963 ​ $ 4,500,000 ​ 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 $1.1 million, or 24.2%, during the year ended December 31, 2020 from the same period in 2019. This was mainly due to legal and administrative fees related to the tender offer in June 2020, which closed 36 ​ ​ ​ in July 2020, legal fees related to executive compensation, and increased stock-based compensation associated with the 2019 and 2020 stock grants. Interest Expense ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2020 2019 Interest expense ​ $ 114,515 ​ $ 115,356 ​ 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. Net gain (loss) on commodity contracts ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2020 2019 Gain on derivative contracts ​ $ 2,503,655 ​ $ 4,246,057 ​ During the years ended December 31, 2020 and 2019, we entered into fixed price swap and basis swap derivative contracts. 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. 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. Other Income (Expense) ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2020 2019 Interest income and other income (expense) ​ $ 39,155 ​ $ 159,683 ​ 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. 37 ​ ​ ​ Net Income Compared to Adjusted EBITDA ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ 2020 2019 Net income (loss) ​ $ 875,171 ​ $ 8,697,999 Add Back: ​ ​ ​ ​ ​ ​ Net interest (income) expense ​ ​ 70,975 ​ ​ (43,523) Income tax expense (benefit) ​ ​ 575,420 ​ ​ 3,777,489 Depreciation, depletion, amortization, and accretion ​ ​ 9,557,891 ​ ​ 7,387,681 Impairment expense ​ ​ 1,760,000 ​ ​ — Stock based compensation expense ​ ​ 849,631 ​ ​ 510,460 (Gain) loss on derivative contracts net of cash received or paid on settlement ​ ​ 1,999,802 ​ ​ (2,296,825) Foreign currency translation (gain) loss ​ ​ 2,065 ​ ​ (437) Adjusted EBITDA ​ $ 15,690,955 ​ $ 18,032,844 ​ 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. 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. 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. 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. 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 Adjusted EBITDA to net income, 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 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 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 38 ​ ​ ​ 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, 2020 compared to 2019 During the year ended December 31, 2020, $14.8 million was provided by our operating activities, compared to $13.0 million in 2019, a $1.8 million, or 14%, 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. 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 $23 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. 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%. Effective January 7, 2019 the agreement was amended to extend the maturity date to March 1, 2022 The bank has a first priority security interest in the tangible and intangible assets of Epsilon Energy USA, Inc. to secure any outstanding amounts under the agreement. 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, 2020 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 2020 out of operating cash flow and cash on hand and expect to continue to do so through 2021. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at ​ Balance at ​ ​ ​ ​ ​ ​ ​ December 31, ​ December 31, ​ Borrowing Base ​ Interest ​ 2020 2019 December 31, 2020 Rate Revolving line of credit ​ $ — ​ $ — ​ $ 23,000,000 3 mo. LIBOR + 2.75% 39 ​ ​ ​ ​ 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. 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. Derivative Transactions We have 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. Contractual Obligations The following table summarizes our contractual obligations at December 31, 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Payments Due by Period ​ ​ ​ ​ ​ Less than ​ 1 – 3 ​ Greater than ​ Total 1 Year Years 3 Years Asset retirement obligations, undiscounted ​ $ 8,772,066 ​ $ 124,161 ​ $ — ​ $ 8,647,905 Capital expenditure commitments ​ 2,268,296 ​ 295,920 ​ 1,972,376 ​ — Operating leases ​ 245,883 ​ 103,073 ​ 142,810 ​ — Total future commitments ​ $ 11,286,245 ​ $ 523,154 ​ $ 2,115,186 ​ $ 8,647,905 ​ 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. 40 ​ ​ ​ 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. Off-Balance Sheet Arrangements As of December 31, 2020 and 2019, we had no off-balance sheet arrangements. Summary of Critical Accounting Policies and 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. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Described below are the most significant accounting policies we apply in preparing our consolidated financial statements. We also describe the most significant estimates and assumptions we make in applying these policies. 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. 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. 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 41 ​ ​ ​ 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.” Unproved Natural gas and oil Properties Unproved properties generally consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as an impairment of natural gas and oil properties in the consolidated statements of operations and comprehensive income (loss). Unproved natural gas and oil property costs are transferred to proved natural gas and oil properties if the properties are subsequently determined to be productive or are assigned proved reserves. 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. Depreciation, Depletion and Amortization of Natural gas and oil Properties and Gathering Systems The quantities of estimated proved natural gas and oil reserves are a significant component of our calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease, respectively. Oil and natural gas 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. 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. 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 described in the Fair Value Measurement Topic of the ASC 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 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. 42 ​ ​ ​ Under ASC 360, 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. 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. 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. Derivative Financial Instruments Derivative financial instruments are used to hedge exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity price swap and collar contracts. The use of these instruments is subject to policies and procedures as approved by the Board. Derivative financial instruments are not traded for speculative purposes. No derivative contracts have been designated as cash flow hedges for accounting purposes. Derivative financial instruments are initially recognized at cost, if any, which approximates fair value. Subsequent to initial recognition, derivative financial instruments are recognized at fair value. The derivatives are valued on a mark-to-market valuation, and the gain or loss on re-measurement to fair value is recognized through the consolidated statements of operations and comprehensive income (loss). The estimated fair value of derivative instruments requires substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity, and credit risk. The values reported in Epsilon’s financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. The counterparties to our derivative instruments are not known to be in default on their derivative positions. However, we are exposed to credit risk to the extent of nonperformance by the counterparty in the derivative contracts. We believe credit risk is minimal and do not anticipate such nonperformance by such counterparties. Asset Retirement Obligations (“ARO”) We recognize asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. 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. 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. Changes in facts, circumstances, and interpretations of the standards may result in a material increase or decrease in our provision for income taxes. 43 ​ ​ ​ Recently Issued Accounting Standards See Note 3 Summary of Significant Accounting Policies in Notes to the Consolidated Financial Statements. ​