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Item 5. Market for Registrant’s Common Equity

2021-03-25 compared with 2020-03-18 · 33 added, 342 removed, 33 unchanged (92% of the section changed)

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

The information required by Item 201 of Regulation S-K is contained in ‘‘

Business .’’

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

The information required by Item 201 of Regulation S-K is contained in ‘‘ Item 1.

On December 31, 2020, our Board made a grant to our directors, executive officers and employees, entitling them to receive an aggregate of 200,900 Common Shares which shares will not be issued to the award recipients unless certain time or performance based vesting criteria, as applicable, are met, in which case the vesting will occur in equal parts over a three-year period.

The awards were made under the Share Compensation Plan in accordance with Rule 701 promulgated under the Securities Act.

On September 1, 2020 our Board made a grant to our CEO, entitling him to receive an aggregate of 125,000 Common Shares which shares will not be issued to the award recipient unless certain performance based vesting criteria are met, in which case the vesting will occur over a three-year period.

The awards were made under the 2020 Equity Incentive Plan in accordance with Rule 701 promulgated under the Securities Act.

Commencing on May 20, 2019, the Company entered into a share repurchase program on the NASDAQ conducted in accordance with Rule 10b-18 promulgated under the Securities Exchange Act of 1934.

The Company is authorized to repurchase up to 1,367,762 of its outstanding common shares, representing 5% of the outstanding common shares of Epsilon as of May 20, 2019, for an aggregate purchase price of not more than $2.5 million.

The program will end on May 19, 2020 unless the maximum amount of common shares is purchased before then or Epsilon provides earlier notice of termination.

Repurchases may be made at management’s discretion from time to time through the facilities of the NASDAQ Global Market.

The price paid for the common shares will be, subject to applicable securities laws, the prevailing market price of such common shares on the NASDAQ Global Market at the time of such purchase.

The Company intends to fund the purchase out of available cash and does not expect to incur debt to fund the share repurchase program.

The Company was authorized to repurchase up to 1,367,762 of its outstanding common shares, representing 5% of the outstanding common shares of Epsilon as of May 20, 2019, for an aggregate purchase price of not more than $5.0 million.

The program ended on May 19, 2020, but Epsilon’s final repurchase under this program occurred on May 8, 2020.

Repurchases were made at management’s discretion from time to time through the facilities of the NASDAQ Global Market.

The price paid for the common shares was, subject to applicable securities laws, the prevailing market price of such common shares on the NASDAQ Global Market at the time of such purchase.

The Company funded the purchases out of available cash and did not incur debt to fund the share repurchase program.

Substantial Issuer Bid/Issuer Tender Offer

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 Securities Exchange Act of 1934, as amended (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.

The following table contains information about our repurchase of equity securities during the year ended December 31, 2020:

5 unchanged sentences

announced plans

Beginning balance at May 20, 2019

September 2019

November 2019

Total for the year ended December 31, 2019

or programs (4)

Beginning of normal-course issuer bid, May 20, 2019

Shares purchased through December 31, 2019 (1) (2)

January 2020 (2)

February 2020 (2)

March 2020 (2)

April 2020 (2)

July 2020 (3)

Total as of December 31, 2020

(1) Shares purchased through December 31, 2019 were cancelled prior to the year ended December 31, 2019.

(2) Epsilon repurchased these shares under its share repurchase program that commenced on May 20, 2019, as described above.

(3) Epsilon repurchased these shares under its substantial issuer bid/issuer tender offer dated May 19, 2020, as described above.

(4) The Company announced its intention to commence a substantial issuer bid/issuer tender offer on May 14, 2020, and the substantial issuer bid/issuer tender offer commenced May 19, 2020, as described above.

(5) The normal-course issuer bid expired on May 19, 2020, and the substantial issuer bid/issuer tender offer expired on June 30, 2020.

SELECTED FINANCIAL DATA.

1 unchanged sentence

The selected historical consolidated financial data as of and for the years ended December 31, 2020 and 2019 have been derived from our audited consolidated financial statements, which have been audited by BDO USA, LLP, an independent registered public accounting firm.

The selected historical consolidated financial data set forth below should be read in conjunction with the section titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations”

for such periods and our consolidated financial statements and related notes.

Our consolidated financial

statements included in this report have been prepared in accordance with United States generally accepted accounting principles, or GAAP.

To meet NASDAQ listing standards, the shareholders of the Company, on December 19, 2018, approved a Consolidation (reverse stock split) of the issued and outstanding common shares on the basis of one (1) new common share for up to every existing two (2) common shares issued and outstanding immediately prior to the Consolidation.

The common shares commenced trading on a post-Consolidation basis on the TSX on December 24, 2018.

All share amounts and per share data are presented in these statements on a post-Consolidation basis.

Year ended December 31,

5 unchanged sentences

General and administrative expense

Income from operations

Other income (expense)

Income (loss) from operations

Income tax expense

9 unchanged sentences

Total long-term liabilities

Total shareholders’

Total shareholders’ equity (1)

(1) No cash dividends were declared or paid during the periods presented.

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 at December 31, 2019 and 2018 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.

Our primary areas of operation are Pennsylvania and Oklahoma.

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 (4,130 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.

In 2019, we paid $1.2 million to the Auburn GGS to gather and treat our 7.6 Bcf of natural gas production in Pennsylvania ($1.1 million to the Auburn GGS to gather and treat our 7.3 Bcf in 2018).

At December 31, 2019 our total estimated net proved reserves were 124,161 million cubic feet (MMcf) of natural gas reserves and 116,053 barrels (Bbl) of oil and other liquids, and we held leasehold rights to approximately 78,101 gross (13,100 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 a leasehold interest and to develop the leasehold interest with the goal of deploying capital at attractive rates.

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

Well productivity has improved dramatically for many years resulting in increasing initial production rates and gas recoveries.

The resulting supply of natural gas has at times stressed the transportation infrastructure of the Northeast US and exacerbated 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.

In the Marcellus, 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 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 tremendous 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 to decline modestly throughout the second half of 2020.

We cannot, however, predict the 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 prices improve 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 a moderating of supply 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 ~ 8.5 Bcf/d to 17 Bcf/d by 2024 based only on facilities currently commissioning or under construction.

In the Northwest STACK, the Company chooses to not deploy capital due to depressed natural gas liquids and natural gas pricing.

However, the leases are held by production which provides a long-term right to develop additional sales when commodity prices appear attractive.

In the interim, we intend to monitor development activities from offset operators in our area very closely in an effort to further appraise our leasehold interest without risking capital.

We realized net income of $8.5 million during 2019 as compared to net income of $6.7 million for 2018.

At December 31, 2019, our total estimated net proved reserves of natural gas were 124,161 MMcf, an increase of 5,045 MMcf from December 31, 2018.

Our standardized measure of discounted future net cash flows as of December 31, 2019 and

2018 was $49.6 million and $59.1 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.

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, 2019, revenues decreased $3.0 million, or 10.9%, to $26.7 million from $29.7 million during the same period in 2018.

Revenue and volume statistics for the years ended December 31, 2019 and 2018 were as follows:

Natural gas revenue

Volume (MMcf)

Price ($/Mcf)

PA Exit Rate (MMcfpd)

Oil and other liquids revenue

Price ($/Bbl)

Gathering system revenue

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, 2019, approximately 87% of the Auburn GGS revenues earned are gathering fees, while 13% are compression fees.

Third party customers represent approximately 11% of gathering revenues and 4% of compression revenues.

For the year ended December 31, 2018, approximately 86% of the Auburn GGS revenues earned were gathering fees, while 14% were compression fees.

Third party customers represent approximately 11% of gathering revenues and 5% of compression revenues.

Revenues derived from transporting and compressing Epsilon’s production which have been eliminated from gathering system revenues amounted to $1.2 million and $1.1 million respectively for the year ended December 31, 2019 and 2018.

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

For the year ended December 31, 2019 upstream revenue decreased by $2.3 million, or 11.8%, over 2018, primarily as a result of lower natural gas prices, offset slightly by higher volumes.

Volumes were higher during 2019, despite of lower prices, because of the completion of 4 wells drilled during 2018 that went online in February 2019, and the drilling and completion of 4 additional wells that went online in October 2019.

The end of the year daily production rate for gas in Pennsylvania was 30.5 MMcf.

Gathering system revenue decreased $0.7 million, or 6.6%, during the year ended December 31, 2019, due to a 12.3% decrease in the volumes flowing through the system.

This was partially offset by a higher gathering rate and lower volumes of imported gas from other inter-connected systems (crossflow).

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.

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, 2019 and 2018:

Year ended December 31,

Lease operating costs

Gathering system operating costs

Upstream operating costs—Total $/Mcfe

Gathering system operating costs $ / Mcf

Upstream operating costs include costs primarily from Pennsylvania, but insignificant 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 $1.2 million and $1.1 million for the years ended December 31, 2019 and 2018, respectively (see Note 12, “Operating Segments,”

of the Notes to Consolidated Financial Statements).

For the year ended December 31, 2019, upstream operating costs decreased by $0.09 million, or 1.4% from the same period in 2018.

The decrease in total cost was mainly due to the decrease in volumes produced for the first 10 months of the year.

The $/Mcfe also decreased, primarily due to a decrease in costs related to remediation costs related to a saltwater spill on one of our pads.

Production increased when 4 wells went online in October, but operating costs did not increase significantly.

Gathering system costs for the year ended December 31, 2019 increased $0.06 million, or 4.5% over the same period in 2018 despite lower throughput volumes due to increased chemical expenses and timing of maintenance expenses.

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

Year ended December 31,

Depletion, depreciation, amortization and accretion

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.

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

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 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.

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.

As discussed above, DD&A expense for the first three quarters is calculated based on the reserve report from the prior year.

During the year ended December 31, 2019, DD&A expense increased by $0.2 million, or 2.9%, compared to the same period in 2018 mainly due to the addition of eight new wells.

Four wells for the full year and four wells for the last three months of the year.

Even with the substantially increased production in the fourth quarter, DD&A only increased slightly as a result of a lower fourth quarter DD&A rate related primarily to the reserves added with the new wells.

Gain (Loss) on Sale of Properties

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.

For the year ended December 31, 2018 gain (loss) on sale of properties consisted of a loss taken for the writing off of six wells that do not belong to Epsilon.

General and Administrative (“G&A”)

Year ended December 31,

General and administrative

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 decreased by $0.4 million, or 8.4%, during the year ended December 31, 2019 from the same period in 2018, mainly due to decreased consulting and legal costs required for the effort to obtain a listing on a major U.S.

stock exchange spent in 2018.

We expect expenses to continue to decrease in 2020 as our efforts to be listed on a major U.S.

stock exchange were successful.

Interest Expense

Year ended December 31,

Interest expense

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

Interest expense decreased during the year ended December 31, 2019 from $0.14 million for the year ended December 31, 2018 to $0.12 million, or 18.0%.

This was due to the paying off of the revolving line of credit in December 2018.

Interest expense for 2019 consists primarily of commitment fees as we did not access our line of credit during 2019.

Net gain (loss) on commodity contracts

Year ended December 31,

Gain (loss) on derivative contracts

During the years ended December 31, 2019 and 2018, 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 $1,949,232 and paid $1,381,898, respectively, on the settlement of contracts due to the change in commodity prices.

The realized losses during 2018 were almost entirely due to NYMEX Henry Hub (“NYMEX HH”) swaps that settled out-of-the-money as Henry Hub prices moved higher throughout the year.

At December 31, 2018, however, the unrealized losses in the derivative contracts were almost entirely attributable to out-of-the-money basis swaps.

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.

NYMEX HH prices generally declined throughout the year resulting in large realized gains on both the Henry Hub swaps that were held at December 31, 2018 and also the HH swaps that were added during 2019.

Furthermore, by December 31, 2019, substantially all of the gains in the unsettled contracts held was due to in-the-money NYMEX HH swaps.

These NYMEX HH swaps totaling 5.26 Bcf were added to the hedge portfolio throughout 2019.

Other Income (Expense)

Year ended December 31,

Other income (expense)

For the year ended December 31, 2019 other income consisted primarily of net foreign currency gains.

For the year ended December 31, 2018 other expense consisted primarily of income from state income tax refunds received.

Net Income Compared to Adjusted EBITDA

Year ended December 31,

Net interest (income) expense

Income tax expense

Depreciation, depletion, amortization, and accretion

Stock based compensation expense

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

Foreign currency translation (gain) 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.

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.

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

Our primary source of cash during the years ended December 31, 2019 and 2018 was funds generated from operations.

In addition to operations, cash was received from the sale of leases in Pennsylvania and used for acquisition and development of natural gas and oil properties, and the buyback of common shares through our share repurchase program as discussed in Note 6 of our financial statements.

During the year ended December 31, 2018, funds were mainly used for operations, income tax prepayments, development expenditures, and the repayment of the revolving line of credit.

At December 31, 2019, we had a working capital surplus of $16.3 million, an increase of $2.7 million over the $13.6 million surplus at December 31, 2018.

The surplus increased over the last year because of the cash that is continually being generated by operations, cash received from the settlement of derivative contracts and the previously discussed sale of leases in Pennsylvania.

Year ended December 31, 2019 compared to 2018

During the year ended December 31, 2019, $13.0 million was provided by our operating activities, compared to $10.1million in 2018, a $2.9 million, or 28%, increase.

The increase was mainly due to the increase in net income combined with the collection of receivables outstanding at December 31, 2018 and cash received on the settlement of derivative contracts.

We used $10.5 million for investing activities during the year ended December 31, 2019.

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.

During the same period of 2018, we used $2.0 million, primarily for leasehold costs in anticipation of new lease purchases and a drilling program.

We used $2.8 million in financing activities during the year ended December 31, 2019 for the buyback and cancelation of shares of Epsilon stock.

The $3.6 million of cash used for financing activity during the year ended December 31, 2018 was used for the payoff of our revolving line of credit and the buyback and cancelation of shares of Epsilon stock.

Credit Agreement

In addition, we have 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.

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 to secure any outstanding amounts under the agreement.

Under the terms of the agreement, we 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, 2019 and December 31, 2018 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 2019 out of operating cash flow and cash on hand and expect to continue to do so through 2020.

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, 2019, our outstanding natural gas commodity swap contracts consisted of the following:

Weighted Average Price ($/MMbtu)

Fair Value of Asset

Derivative Type

December 31, 2019

Fixed price swap

Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2019:

Payments Due by Period

Derivative liabilities (1)

Asset retirement obligation, undiscounted

Capital expenditure commitments

Operating leases

Total future commitments

The liability balance shown represents the gross liability balance of derivative contracts before being offset by contracts in an asset position.

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.

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, 2019 and 2018, 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 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.

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 unamortized capitalized cost 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 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 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.

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 Obligation (“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.

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.

Recently Issued Accounting Standards

See note 3 of the financial statements.

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 5. Market for Registrant’s Common Equity