Summary Of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

Summary of Significant Accounting Policies

The Company’s consolidated financial statements include the accounts of the Company and its wholly owned subsidiary, Epsilon Energy USA, Inc. and its wholly owned subsidiaries, Epsilon Midstream, LLC, Dewey Energy GP, LLC, and Dewey Energy Holdings, LLC. With regard to the gathering system, in which Epsilon owns an undivided interest in the asset, proportionate consolidation accounting is used. All inter-company transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas reserves and related cash flow estimates used in impairment tests of oil and natural gas and gathering system properties, asset retirement obligations, accrued natural gas and oil revenues and operating expenses, accrued gathering system revenues and operating expenses, as well as the valuation of commodity derivative instruments. Actual results could differ from those estimates.

Reclassifications

Certain amounts reported in prior year’s consolidated financial statements have been reclassified to conform to the current presentation with no effect on shareholders’ equity or net income.

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents include cash on hand and short‑term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.

Restricted cash consists of amounts deposited to back bonds or letters of credit for potential well liabilities. The Company presents restricted cash with cash and cash equivalents in the Consolidated Statements of Cash Flows. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported in the Consolidated Balance Sheets to the total of the amounts in the Consolidated Statements of Cash Flows as of December 31, 2019 and December 31, 2018:


	Year ended December 31,
	2019		2018
Cash and cash equivalents	$	14,052,417	$	14,401,257
Restricted cash included in other assets		561,294		558,261
Cash, cash equivalents and restricted cash in the statement of cash flows	$	14,613,711	$	14,959,518

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are primarily from purchasers of oil and natural gas, counterparties to our financial instruments, and revenues earned for compression and gathering services. Both oil and natural gas receivables are generally collected within 30 days after the end of the month. Compression and gathering receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. Our allowance for doubtful accounts was nil as of December 31, 2019 and 2018. There was no bad debt expense recognized for the years ended December 31, 2019 and 2018.

Oil and Natural Gas Properties

Epsilon accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting.

Oil and natural gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and natural gas properties. Lease delay rentals are expensed as incurred.

Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether Epsilon has discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. 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 (see Note 4).

Depreciation, depletion and amortization of the cost of proved oil and natural gas properties is calculated using the unit‑of‑production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.

When circumstances indicate that proved oil and natural gas properties may be impaired, Epsilon compares 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 Epsilon’s estimate of future crude oil and natural gas prices, operating costs, 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 ASC 820, which considers estimated discounted future cash flows.

Gas Gathering System Properties

Epsilon accounts for its gas gathering system asset using the proportionate consolidation method of accounting.

Epsilon’s 35% portion of asset development costs are capitalized when incurred. All other costs are expensed.

Depreciation, depletion and amortization of the cost of gathering system properties is calculated using the unit‑of‑ production method. The reserve base used to calculate depreciation, depletion and amortization for the gathering system includes only proved Pennsylvania, natural gas developed reserves.

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 Fair Value Measurement Topic ASC 820, which considers estimated discounted future cash flows.

Revenue Recognition

Revenues are comprised primarily of sales of natural gas and to a much lesser degree crude oil and NGLs, along with the revenue generated from the Company’s ownership interest in the gas gathering system in the Auburn field in Northeastern Pennsylvania.

We adopted Accounting Standards Codification (“ASC”) topic 606 on January 1, 2019. The standard requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU replaced most existing revenue recognition guidance in GAAP when it became effective and was incorporated into GAAP as Accounting Standards Codification (“ASC”) Topic 606. Revenue recognition is evaluated through the following five steps: (i) identification of the contract, or contracts, with a customer; (ii) identification of the performance obligations in the contract; (iii) determination of the transaction price; (iv) allocation of the transaction price to the performance obligations in the contract; and (v) recognition of revenue when or as a performance obligation is satisfied. The Company applied the guidance to the contracts in effect at January 1, 2019 and used the modified retrospective transition method. There was no material impact to our net income related to the adoption of this standard. Based on ASC 606, the Company adheres to the following revenue recognition policies and procedures.

Accounting Policies

Revenue is recognized when performance obligations under the terms of a contract with a customer are satisfied. The Company recognizes upstream revenue at the point in time when control has been transferred to the customer, generally at the time natural gas reaches an agreed-upon delivery point and collectability is reasonably assured. Upstream revenue is generally based upon a fixed price, based on a market index, and is measured as the amount of consideration the Company expects to receive in exchange for the transferring of the natural gas. The services provided by the gas gathering system take place continuously and as a practical expedient, the revenues are recognized monthly for the volumes that are processed and transported for the upstream producers during that period of time. Revenue for the services performed are based on the rates outlined in the cost of service agreement that governs all volumes gathered and processed by the system. The gathering rates are adjusted, and fixed annually. Typically, the Company sells its natural gas directly to customers, under agreements with payment terms less than 30 days after delivery and 60 days on the revenue generated by the gas gathering system.

Natural Gas Revenues

The Company’s natural gas purchase contracts are generally structured such that Epsilon commits and dedicates for sale its proportionate share of natural gas production per day to a purchaser. Natural gas is sold at a percentage of index prices of each component, less any stated deductions. Control transfers at the delivery point specified in the contract, which typically is stated as the inlet of the 3rd party sales transportation pipeline. The Company recognizes revenue proportionate to its entitled share of volumes sold. Currently, almost all of Epsilon’s natural gas production comes from the Marcellus Field in Northeastern Pennsylvania.

Epsilon uses a third-party service for its natural gas marketing. In this capacity, the third-party is responsible for carrying out marketing activities such as submission of nominations, receipt of payments, submission of invoices and negotiation of contracts. Commissions payable to the third-party broker for these services are treated as lease operating expenses in the financial statements.

Gas Gathering System Revenue

The Company has a 35% ownership interest in the Auburn Gas Gathering System (“Auburn GGS”). This system aggregates the natural gas from the various pads in the field and transports the natural gas to the inlet of the Auburn compression facility where it is dehydrated, compressed and injected into Tennessee Gas Pipeline. The gathering and compression services operate under fee-based contracts. The producers in the area served by the gathering system pay fees to the system owners based on the services provided to them in getting their share of the gas production to the 3rd party sales transmission point. Revenue is recognized over time as the services are provided.

Accounts Receivable and Other

Accounts receivable – Oil, natural gas liquid and natural gas receivables consist of amounts due from purchasers for commodity sales primarily from our revenue interest in the leases in Northwestern Pennsylvania. Payments from purchasers are typically due by the last day of the month following the month of delivery. Gathering fee revenue consists of fees due from the operator of the Auburn GGS, as an agent for the Company fulfilling the operations of the gathering system. Payments from the operator are typically due 60 days from the last day of the month of transmission. The Company’s operations do not result in any contract assets or liabilities on the accompanying consolidated balance sheets.

Buildings and Other Property and Equipment

Buildings are depreciated on a straight-line basis over the estimated useful life of the property, 30 years.

Other property and equipment consists of computer hardware and software, and furniture and fixtures. Other property and equipment is generally depreciated on a straight‑line basis over the estimated useful lives of the property and equipment, which range from 3 years to 7 years.

Financial Instruments and Fair Value

Epsilon’s financial instruments consist of cash, cash equivalents, restricted cash, commodity derivative contracts, accounts receivable, accounts payable, accrued liabilities, and long‑term debt.

Our financial instruments that are accounted for at fair value measurement consist of commodity derivatives.

The Company classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instrument.

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

Level 3—Valuations in this level are those with inputs for the asset or liability that are not based on observable market data. The Company makes its own assumptions about how market participants would price the assets and liabilities.

Cash, cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities are carried at cost, which approximates their fair value because of the short‑term maturity of these instruments. The Company’s revolving line of credit has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates and the applicable margins represent market rates.

Commodity derivative instruments consist of fixed‑price swaps, and basis swap contracts for natural gas. The Company’s derivative contracts are valued based on an income approach. The model considers various assumptions, such as quoted forward prices for commodities, time value and volatility factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.

Derivative Instruments

The Company enters into derivative contracts to hedge price risk associated with a portion of natural gas production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated, which has, and could, result in over‑hedged volumes. Natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the NYMEX or the published natural gas index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. Our derivative transactions have included the following:

Fixed‑price swaps—where a fixed‑price is received for production and a variable market price is paid to the contract counterparty.

Basis swap contracts—which guarantee a specified price differential between the price at Henry Hub and our physical pricing points. If the settled price differential is greater than the swapped basis, then we receive a payment from the counterparty in the amount of the difference between the two. If the settled price differential is less than the swapped basis, then we make a payment to the counterparty for the difference between the two.

Derivative assets and liabilities are initially measured at fair value and then re‑valued at each reporting period. Using this method, derivative instruments are recorded on the consolidated balance sheets at fair value as either current or non‑current assets or liabilities based on their anticipated settlement date. Gains or losses on derivative contracts are recorded as gain (loss) on commodity contracts in the consolidated statements of operations and comprehensive income. Hedge accounting is not used for our derivative assets and liabilities.

Asset Retirement Obligations

The Company records a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long‑lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method of the asset’s useful life. Recognized asset retirement obligation relates to the plugging and abandonment of oil and natural gas wells and decommissioning of the gas gathering system. Management reviews the estimates of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate. These adjustments are recorded to the asset retirement obligation with an offsetting change to oil and gas properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the forecast inflation due to the passage of time, which is recorded in depreciation, depletion, amortization, and accretion expense in the consolidated statements of operations and comprehensive income.

Concentrations of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. Exposure to credit risk associated with these instruments is controlled by (i) placing assets and other financial interests with credit‑worthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring paying history, although the Company does not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties with a legal right of offset. At December 31, 2019 and 2018, the cash and cash equivalents were primarily concentrated in two financial institutions, one in Canada and one in the US. The Company periodically assesses the financial condition of these institutions and believe that any possible credit risk is minimal.

Geographic Locations of Operations

Through December 31, 2019, our primary source of revenue originated from natural gas production and gathering system revenues in the state of Pennsylvania. Our asset in Pennsylvania has not yet reached the mature stage, but at some point we may need to acquire and develop other producing assets to maintain our current level or to grow. To this end, we have begun to acquire leases in the Anadarko basin and to expand our holdings in Pennsylvania.

Income Taxes

Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. Epsilon assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate (see Note 9).

Foreign Currency Transactions

The United States dollar is the functional currency for all of Epsilon’s consolidated subsidiaries. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. Gains and losses on translation of balances denominated in Canadian dollars are included in accumulated other comprehensive income.

Stock Based Compensation

Stock‑Based Compensation

The Company mainly estimates the fair value of all stock options awarded to employees and directors using the Black‑Scholes option pricing model. Other models are used for options with more complex vesting criteria. Compensation expense and a corresponding increase to additional paid‑in capital are recorded over the vesting period based on the fair value of the options granted using a graded vesting approach. When stock options are exercised for common shares, consideration paid by the stock option holders and additional paid‑in capital associated with the stock options are recorded. The Company estimates a forfeiture rate and adjusts the corresponding expense each period based on an updated forfeiture estimate (see Note 6).

The Company has issued restricted stock to employees and directors of the Company. The fair value of the restricted stock is determined using the fair value of the Company’s common stock on the date of grant. These awards vest ratably over a three-year period. Compensation expense and a corresponding increase to additional paid in capital are recorded over the vesting period.

Leases

Agreements under which the Company makes payments to owners in return for the right to use an asset for a period are accounted for as leases. Leases that transfer substantially all the risks and rewards of ownership to third parties are recorded at inception as finance leases within property and equipment and debt. Assets acquired under capital leases are amortized over the estimated useful lives of the underlying assets. All other leases are accounted for as operating leases and the related lease payments are charged to expense as incurred.

Joint Interests

The majority of the Company’s oil and natural gas exploration, development and production activities, and the gathering system, are conducted jointly with others and, accordingly, these financial statements reflect only the Company’s proportionate interest in such jointly controlled assets.

Recently Issued Accounting Standards

The Company, an emerging growth company (“EGC”), has elected to take advantage of the benefits of the extended transition period provided for in Section 7(a)(2)(B) of the Securities Act, for complying with new or revised accounting standards which allows the Company to defer adoption of certain accounting standards until those standards would otherwise apply to private companies.

In December 2019, the Financial Accounting Standards Board ( FASB ) issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” which simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740, Income Taxes. The guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Early adoption is permitted.

In June 2016 the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which removes the thresholds that companies apply to measure credit losses on financial instruments measured at amortized cost, such as loans, receivables, and held-to-maturity debt securities. Under current U.S. GAAP, companies generally recognize credit losses when it is probable that the loss has been incurred. The revised guidance will remove all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. ASU 2016-13 is effective for fiscal years beginning after December 15, 2022, and interim periods within those fiscal years, and must be applied retrospectively. Early adoption is permitted. Epsilon is evaluating the impact of the adoption of ASU 2016-13 on January 1, 2023.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)” (ASU 2016-02), which significantly changes accounting for leases by requiring that lessees recognize a right of use asset and a related lease liability representing the obligation to make lease payments, for all lease transactions with terms greater than one year. Additional disclosures about an entity’s lease transactions will also be required. ASU 2016-02 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant, or equipment (an identified asset) for a period of time in exchange for consideration.” ASU 2016-02 is effective for the Company for fiscal years beginning after December 15, 2020, and interim periods within fiscal years beginning after December 15, 2021. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. Epsilon is reviewing the provisions of ASU 2016-02 to determine the impact on its consolidated financial statements and related disclosures. Epsilon is evaluating the impact of the adoption of ASU 2016-02 on the financial statements.