Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Mar. 18, 2020 | Jun. 30, 2019 | |
Document and Entity Information | |||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2019 | ||
Entity Registrant Name | EPSILON ENERGY LTD. | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Small Business | true | ||
Entity Emerging Growth Company | true | ||
Entity Ex Transition Period | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 43.7 | ||
Entity Common Stock, Shares Outstanding | 26,790,985 | ||
Entity Central Index Key | 0001726126 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Dec. 31, 2019 | Dec. 31, 2018 |
Current assets | ||
Cash and cash equivalents | $ 14,052,417 | $ 14,401,257 |
Accounts receivable | 4,296,917 | 5,042,134 |
Fair value of derivatives | 1,999,802 | |
Prepaid income taxes | 1,641,501 | 205,711 |
Other current assets | 433,687 | 244,233 |
Total current assets | 22,424,324 | 19,893,335 |
Property and equipment: | ||
Proved properties | 130,819,256 | 118,851,574 |
Unproved properties | 21,047,512 | 19,498,666 |
Accumulated depletion, depreciation, and amortization | (89,255,035) | (83,807,401) |
Total oil and gas properties, net | 62,611,733 | 54,542,839 |
Gathering system | 41,445,225 | 41,040,847 |
Accumulated depletion, depreciation, and amortization | (29,961,690) | (28,137,573) |
Total gathering system, net | 11,483,535 | 12,903,274 |
Land | 375,314 | |
Buildings and other property and equipment, net | 211,879 | |
Total property and equipment, net | 74,682,461 | 67,446,113 |
Other assets: | ||
Restricted cash | 561,294 | 558,261 |
Prepaid drilling costs | 1,124 | |
Total non-current assets | 75,244,879 | 68,004,374 |
Total assets | 97,669,203 | 87,897,709 |
Current liabilities | ||
Accounts payable trade | 2,828,495 | 1,762,586 |
Royalties payable | 1,306,922 | 1,300,539 |
Accrued capital expenditures | 627,356 | 522,437 |
Accrued gathering fees | 373,929 | 300,301 |
Other accrued liabilities | 858,188 | 2,156,304 |
Fair value of derivatives | 297,023 | |
Asset retirement obligation | 1,503,978 | |
Total current liabilities | 7,498,868 | 6,339,190 |
Non-current liabilities | ||
Asset retirement obligation | 1,405,877 | 1,625,154 |
Deferred income taxes | 12,401,464 | 9,989,278 |
Total non-current liabilities | 13,807,341 | 11,614,432 |
Total liabilities | 21,306,209 | 17,953,622 |
Commitments and contingencies (Note 10) | ||
Shareholders' equity | ||
Common shares, no par value, unlimited shares authorized and 26,790,985 issued and outstanding at December 31, 2019 and 27,385,133 shares issued and 27,358,180 shares outstanding at December 31, 2018. | 140,808,923 | 143,705,441 |
Treasury shares, 26,953 shares issued, at December 31, 2018 | (94,418) | |
Additional paid-in capital | 7,029,488 | 6,519,028 |
Accumulated deficit | (81,285,895) | (89,983,894) |
Accumulated other comprehensive income | 9,810,478 | 9,797,930 |
Total shareholders' equity | 76,362,994 | 69,944,087 |
Total liabilities and shareholders' equity | $ 97,669,203 | $ 87,897,709 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2019 | Dec. 31, 2018 |
Consolidated Balance Sheets | ||
Par value | $ 0 | $ 0 |
Common shares issued | 26,790,985 | 27,385,133 |
Common shares outstanding | 26,790,985 | 27,358,180 |
Treasury shares | 26,953 |
Consolidated Statements of Oper
Consolidated Statements of Operations and Comprehensive Income - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Revenues from contracts with customers: | ||
Total revenue | $ 26,690,336 | $ 29,684,205 |
Operating costs and expenses: | ||
Lease operating expenses | 6,571,394 | 6,665,856 |
Gathering system operating expenses | 1,337,409 | 1,279,821 |
Development geological and geophysical expenses | 83,748 | |
Depletion, depreciation, amortization, and accretion | 7,387,681 | 7,181,753 |
(Gain) loss on sale/disposal of property | (1,375,000) | 189,142 |
General and administrative expenses: | ||
Stock based compensation expense | 510,460 | 330,232 |
Other general and administrative expenses | 3,989,540 | 4,605,506 |
Total operating costs and expenses | 18,505,232 | 20,252,310 |
Operating income | 8,185,104 | 9,431,895 |
Other income (expense): | ||
Interest income | 158,879 | 12,087 |
Interest expense | (115,356) | (140,615) |
Gain (loss) on derivative contracts | 4,246,057 | (1,938,465) |
Other income (expense) | 804 | 39,583 |
Other income (expense), net | 4,290,384 | (2,027,410) |
Income before income tax expense | 12,475,488 | 7,404,485 |
Income tax expense | 3,777,489 | 742,425 |
NET INCOME | 8,697,999 | 6,662,060 |
Currency translation adjustments | 12,548 | (115,306) |
NET COMPREHENSIVE INCOME | $ 8,710,547 | $ 6,546,754 |
Net income per share, basic | $ 0.32 | $ 0.24 |
Net income per share, diluted | $ 0.32 | $ 0.24 |
Weighted average number of shares outstanding, basic | 27,129,430 | 27,462,788 |
Weighted average number of shares outstanding, diluted | 27,129,430 | 27,474,125 |
Gas, oil, NGLs and condensate | ||
Revenues from contracts with customers: | ||
Total revenue | $ 17,369,963 | $ 19,702,643 |
Gas gathering and compression | ||
Revenues from contracts with customers: | ||
Total revenue | $ 9,320,373 | $ 9,981,562 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Shareholders' Equity - USD ($) | Common stock | Treasury Shares | Additional paid-in Capital | Accumulated Other Comprehensive Income | Accumulated Deficit | Total |
Balance at Dec. 31, 2017 | $ 144,292,238 | $ 6,171,525 | $ 9,913,236 | $ (96,645,954) | $ 63,731,045 | |
Balance (in shares) at Dec. 31, 2017 | 27,522,852 | |||||
Increase (Decrease) in Stockholders' Equity | ||||||
Net income | 6,662,060 | 6,662,060 | ||||
Stock-based compensation expenses | 330,232 | 330,232 | ||||
Buyback and retirement of common shares | $ (586,797) | 17,271 | (569,526) | |||
Buyback and retirement of common shares (Shares) | (137,719) | |||||
Buyback of common shares not yet retired | $ (94,418) | (94,418) | ||||
Buyback of common shares not yet retired (in shares) | 26,953 | |||||
Other comprehensive income | (115,306) | (115,306) | ||||
Balance at Dec. 31, 2018 | $ 143,705,441 | $ (94,418) | 6,519,028 | 9,797,930 | (89,983,894) | 69,944,087 |
Balance (in shares) at Dec. 31, 2018 | 27,385,133 | 26,953 | ||||
Increase (Decrease) in Stockholders' Equity | ||||||
Net income | 8,697,999 | 8,697,999 | ||||
Stock-based compensation expenses | 510,460 | 510,460 | ||||
Retirement of common shares | $ (94,418) | $ 94,418 | ||||
Retirement of common shares (in shares) | (26,953) | (26,953) | ||||
Exercise of stock options | $ 54,250 | 54,250 | ||||
Exercise of stock options (in shares) | 25,000 | |||||
Buyback and retirement of common shares | $ (2,856,350) | (2,856,350) | ||||
Buyback and retirement of common shares (Shares) | (753,196) | |||||
Restricted stock shares vested (in shares) | 161,001 | |||||
Other comprehensive income | 12,548 | 12,548 | ||||
Balance at Dec. 31, 2019 | $ 140,808,923 | $ 7,029,488 | $ 9,810,478 | $ (81,285,895) | $ 76,362,994 | |
Balance (in shares) at Dec. 31, 2019 | 26,790,985 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Cash flows from operating activities: | ||
Net income | $ 8,697,999 | $ 6,662,060 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depletion, depreciation, amortization, and accretion | 7,387,681 | 7,181,753 |
(Gain) loss on sale of properties | (1,375,000) | 189,142 |
(Gain) loss on derivative contracts | (4,246,057) | 1,938,465 |
Cash received from (paid for) settlements of derivative contracts | 1,949,232 | (1,381,898) |
Stock-based compensation expense | 510,460 | 330,232 |
Deferred income tax expense (benefit) | 2,412,186 | (572,405) |
Changes in assets and liabilities: | ||
Accounts receivable | 745,217 | (1,707,239) |
Prepaid income taxes and other current assets | (1,625,244) | (173,513) |
Accounts payable, royalties payable and other accrued liabilities | (1,471,460) | (545,286) |
Other long-term liabilities | (1,615,313) | |
Net cash provided by operating activities | 12,985,014 | 10,305,998 |
Cash flows from investing activities: | ||
Acquisition of unproved oil and gas properties | (596,500) | (260,000) |
Acquisition of proved oil and gas properties | (4,992) | |
Additions to unproved oil and gas properties | (952,345) | (1,787,114) |
(Additions to) refunds of proved oil and gas properties | (9,411,916) | (22,481) |
Additions to gathering system properties | (366,059) | (148,360) |
Additions to land, buildings and other fixed assets | (588,325) | |
Prepaid drilling costs | (1,124) | |
Proceeds from sale of properties | 1,375,000 | |
Net cash used in investing activities | (10,541,269) | (2,222,947) |
Cash flows from financing activities: | ||
Buyback of common shares | (2,856,350) | (663,944) |
Exercise of stock options | 54,250 | |
Repayment of revolving line of credit | (2,900,000) | |
Net cash used in financing activities | (2,802,100) | (3,563,944) |
Effect of currency rates on cash, cash equivalents and restricted cash | 12,548 | (115,306) |
Increase (decrease) in cash, cash equivalents and restricted cash | (345,807) | 4,403,801 |
Cash, cash equivalents and restricted cash, beginning of year | 14,959,518 | 10,555,717 |
Cash, cash equivalents and restricted cash, end of year | 14,613,711 | 14,959,518 |
Supplemental cash flow disclosures: | ||
Income taxes paid | 2,794,422 | 4,130,493 |
Interest paid | 119,138 | 136,833 |
Non-cash investing activities: | ||
Change in proved properties accrued in accounts payable and accrued liabilities | 1,464,965 | (587,472) |
Change in gathering system accrued in accounts payable and accrued liabilities | (40,782) | (48,961) |
Asset retirement obligation asset additions and adjustments | $ 1,169,903 | $ (135,900) |
Description of Business
Description of Business | 12 Months Ended |
Dec. 31, 2019 | |
Description of Business | |
Description of Business | 1. Description of Business Epsilon Energy Ltd. (the “Company” or “Epsilon” or “we”) was incorporated under the laws of the Province of Alberta, Canada on March 14, 2005. On October 24, 2007, the Company became a publicly traded entity trading on the Toronto Stock Exchange (“TSX”) in Canada. On February 14, 2019, Epsilon’s registration statement on Form 10 was declared effective by the United States Securities and Exchange Commission and on February 19, 2019, we began trading in the United States on the NASDAQ Global Market under the trading symbol “EPSN.” Effective as of the close of trading on March 15, 2019, Epsilon voluntarily delisted its common shares from the TSX. The Company is engaged in the acquisition, development, gathering and production of primarily natural gas reserves in the United States. |
Basis of Preparation
Basis of Preparation | 12 Months Ended |
Dec. 31, 2019 | |
Basis of Preparation | |
Basis of Preparation | 2. Basis of Preparation The accounts are maintained and the consolidated financial statements have been prepared using the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). All amounts presented are in US$ unless otherwise indicated. Principles of Consolidation 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. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2019 | |
Summary of Significant Accounting Policies | |
Summary of Significant Accounting Policies | 3. Summary of Significant Accounting Policies 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 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. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2019 | |
Property and Equipment | |
Property and Equipment | 4. Property and Equipment The following table summarizes the Company’s property and equipment at December 31, 2019 and 2018: December 31, December 31, 2019 2018 Property and equipment: Oil and gas properties, successful efforts method Proved properties $ 130,819,256 $ 118,851,574 Unproved properties 21,047,512 19,498,666 Accumulated depletion, depreciation, and amortization (89,255,035) (83,807,401) Total oil and gas properties, net 62,611,733 54,542,839 Gathering system 41,445,225 41,040,847 Accumulated depletion, depreciation, and amortization (29,961,690) (28,137,573) Total gathering system, net 11,483,535 12,903,274 Land 375,314 — Buildings and other property and equipment, net 211,879 — Total property and equipment, net $ 74,682,461 $ 67,446,113 Property Acquisitions During the years ended December 31, 2019 and 2018 the Company acquired additional acreage in the Anadarko Basin for $596,500 and $260,000, respectively. Included in additions to proved natural gas and oil properties for the year ended December 31, 2018 was an approximate $0.5 million cash call refund for wells previously drilled. Property Sale In June 2019, the Company completed the first part of a sale of undeveloped, stranded leases in Pennsylvania. At that time, the Company received $1.0 million. The sale was completed in July 2019 with a final payment of $0.4 million for a total of $1.4 million received for the stranded leases. Property Impairment At December 31, 2019 and 2018, the Company evaluated its proved and unproved natural gas and oil properties, and its gathering system assets for indicators of any potential impairment. As a result of these assessments, no impairment was required for the years ended December 31, 2019 and 2018. |
Revolving Line of Credit
Revolving Line of Credit | 12 Months Ended |
Dec. 31, 2019 | |
Revolving Line of Credit | |
Revolving Line of Credit | 5. Revolving Line of Credit Effective July 30, 2013, Epsilon Energy USA Inc., a wholly owned subsidiary of the Company, executed a three-year senior secured revolving credit facility with a bank (‘‘Credit Facility’’) for a total commitment of up to $100 million. Upon each advance, interest is charged at the rate of LIBOR plus an ‘‘applicable margin’’. The applicable margin ranges from 2.75 - 3.75% and is based on the percent of the line of credit utilized. The terms “Borrowing Base” and “Mortgaged Properties” include the Company’s gathering system assets in addition to the natural gas and oil properties. The “Required Reserve Value” is the lesser of 90% of the recognized value of all proved natural gas and oil properties or 150% of the then current borrowing base. On January 7, 2019, the maturity date of the Credit Facility was extended to March 1, 2022 and the borrowing base was increased from $13.5 million to $23 million. The borrowing base is subject to redetermination by the lenders based on, among other things, their evaluation of the Company’s natural gas reserves. Additionally, the Company is required to maintain acceptable commodity hedging agreements covering at least 25% of projected production of natural gas for the succeeding calendar year, along with the 50% for the current calendar year. On August 14, 2019 the borrowing base was reaffirmed at $23 million. Additionally, the commodity hedging requirements were updated. Currently, when the Company’s utilization exceeds 25%, the Company must have in place acceptable commodity hedging agreements covering at least 75% of projected production for the first full twelve months after such occurrence and 50% of projected production of natural gas for the succeeding six months. On February 11, 2020 the borrowing base was reaffirmed at $23 million and hedging requirements remained unchanged. The lender under the Credit Facility has a first priority security interest in the tangible and intangible assets, including the gathering system, 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. The Company was in compliance with the financial covenants of the Credit Facility as of December 31, 2019 and 2018 and we expect to be in compliance with the financial covenants for the next 12 months. A commitment fee of 0.50% is assessed quarterly on the daily average unused borrowing base on the Credit Facility Balance at Balance at December 31, December 31, Current Interest Rate 2019 2018 Borrowing Base 3 mo. Revolving line of credit $ — $ — $ 23,000,000 LIBOR + 2.75% (1) (1) At December 31, 2019, the interest rate was 4.65%. |
Shareholders Equity
Shareholders Equity | 12 Months Ended |
Dec. 31, 2019 | |
Shareholders' Equity | |
Shareholders' Equity | 6. Shareholders’ Equity (a) Authorized shares The Company is authorized to issue an unlimited number of Common Shares with no par value and an unlimited number of Preferred Shares with no par value. (b) Purchases of Equity Shares Prior to moving the Company listing from the TSX to the NASDAQ, and prior to the purchase of the equity shares on the NASDAQ shown below, the Company purchased shares through a normal-course issuer bid (“NCIB”) program with the TSX, which expired February 28, 2019. On the TSX, the Company repurchased and retired 57,100 shares of common stock through the year ended December 31, 2019. The repurchased stock had an average price of $4.26 per share. The average share price (converted to US$ using a rate of Cdn$1.33 to US$1) on the TSX from January 1, 2019 through the last day of trading on the TSX, March 15, 2019, was $4.22 (for the year ended December 31, 2018, $3.98). 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 following table contains information about our repurchase of equity securities during the year ended December 31, 2019: Total number Maximum number of shares of shares that purchased as may yet be Total number Average price part of publicly purchased under of shares paid per announced plans the plans or purchased share or programs programs Beginning balance at May 20, 2019 — 1,367,762 May 2019 16,148 $ 4.17 June 2019 221,041 $ 4.12 July 2019 55,112 $ 3.90 August 2019 56,432 $ 3.66 September 2019 14,797 $ 3.79 October 2019 42,307 $ 3.38 November 2019 290,259 $ 3.41 Total for the year ended December 31, 2019 696,096 $ 3.72 696,096 671,666 (c) Stock Options The Company maintains a stock option plan for directors, officers, employees and consultants of the Company and its subsidiaries. Through December 31, 2019, the Company had issued stock options covering 245,000 Common Shares at an overall average price of $5.27 per Common Share to directors, officers and employees of the Company and its subsidiaries. A maximum amount of 755,000 Common Shares are available for future option issuances. The following table summarizes stock option activity for the years ended December 31, 2019 and 2018: Year ended Year ended December 31, 2019 December 31, 2018 Weighted Weighted Number of Average Number of Average Options Exercise Options Exercise Exercise price in US$ Outstanding Price (1) Outstanding Price (1) Balance at beginning of period 290,750 $ 5.02 330,750 $ 5.14 Exercised (25,000) 2.17 — — Expired/Forfeited (20,750) 5.37 (40,000) 6.00 Balance at period-end 245,000 $ 5.27 290,750 $ 5.02 Exercisable at period-end 206,670 $ 5.32 210,249 $ 5.02 At December 31, 2019, the Company had unrecognized stock based compensation related to these options of $1,867 to be recognized over a weighted average period of 0.08 years (for the year ended December 31, 2018: $27,877 over 1.1 years). The aggregate intrinsic value at December 31, 2019 was nil (at December 31, 2018: $58,664). During the year ended December 31, 2019, the Company awarded no stock options (During the year ended December 31, 2018: no stock options). The following table summarizes information for stock options outstanding at December 31, 2019: Weighted Option Average Number of Number of Pricing Remaining Options Options Model Contractual Life Exercise Price Outstanding Exercisable Valuations (in years) As of December 31, 2019 $5.02 115,000 76,670 $ 201,630 4.08 $5.50 130,000 130,000 276,299 2.43 Total 245,000 206,670 $ 477,929 3.04 The value of the options was recorded as stock based compensation expense, with an offsetting amount to additional paid‑in capital based on the vesting terms. Stock based compensation for the options, for the years ended December 31, 2019 and 2018, was $25,203 and $83,328, respectively. (d) Share Compensation Plan A Share Compensation Plan (the “Plan”) was adopted by the Board on April 13, 2017 and approved by the shareholders at the Annual General Meeting in April 2017. The Plan provides that designated participants may, as determined by the Board, be issued Common Shares in an amount up to 100% of the participant’s compensation paid by the Company in consideration of the participant’s service for the current year divided by the market price of the Common Shares on the NASDAQ at the date of issuance of the Common Shares in the current year. In December 2019, 184,500 common shares of Restricted Stock were awarded to the Company’s officers, employees, and board of directors (in December 2018, 174,500 shares). These shares vest over a three year period, with one-third of the shares being issued per period on the anniversary of the award resolution. The vesting of the shares is contingent on the individuals continued employment or service. The vesting of the shares is contingent on the individuals continued employment or service. The Company determined the fair value of the granted Restricted Stock based on the market price of the common shares of the Company on the date of grant. Stock compensation expense for the granted Restricted Stock is recognized over the vesting period. Stock compensation expense recognized during the years ended December 31, 2019 and 2018 was $485,257 and $246,904, respectively. At December 31, 2019, the Company had unrecognized stock based compensation related to these shares of $1,641,295 to be recognized over a weighted average period of 1.12 years (for the year ended December 31, 2018: $1,767,975 over 1.42 years). The following table summarizes Restricted Stock activity for the years ended December 31, 2019 and 2018: Year ended Year ended December 31, 2019 December 31, 2018 Weighted Weighted Number of Average Number of Average Shares Remaining Life Shares Remaining Life Outstanding (years) Outstanding (years) Balance non-vested Restricted Stock at beginning of period 282,833 2.56 162,500 1.87 Granted 184,500 3.00 174,500 3.00 Vested (106,834) — (54,167) — Forfeited (14,000) 2.64 — — Balance non-vested Restricted Stock at end of period 346,499 1.67 282,833 2.56 |
Revenue Recognition
Revenue Recognition | 12 Months Ended |
Dec. 31, 2019 | |
Revenue Recognition | |
Revenue Recognition | 7. Revenue Recognition Revenues are comprised primarily of sales of natural gas along with the revenue generated from the Company’s ownership interest in the gas gathering system in the Auburn field in Northeastern Pennsylvania. Also included to a much lesser degree is natural gas, crude oil and NGLs from Oklahoma. Upon adoption, we did not make any changes to our revenue reporting based on ASC 606 (Note 3). The following table details revenue for the years ended December 31, 2019 and 2018: Year Ended December 31, 2019 2018 Operating revenue Natural gas $ 16,945,302 $ 19,031,422 Natural gas liquids 110,394 295,142 Oil and condensate 314,267 376,079 Gathering and compression fees 9,320,373 9,981,562 Total operating revenue $ 26,690,336 $ 29,684,205 Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers, and the related cash consideration are received within 30 days for natural gas, NGLs, oil, or condensate sold, and 60 days for gas gathering revenues. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the natural gas, NGLs, oil, or condensate. Estimated revenue due to the Company is recorded within the receivables line item on the accompanying consolidated balance sheets until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of December 31, 2019 and 2018 were $2.4 million and $3.0 million, respectively. The settlement statement from the operator of the Auburn GGS is received two months after transmission and compression has occurred. As a result, the Company must estimate the amount of production that was transmitted and compressed within the system. The accounts receivable balances from the operator of the Auburn GGS within the accompanying balance sheets as of December 31, 2019 and 2018 were $1.9 million and nil, respectively. The receivable balance was nil at December 31, 2018 as the Company had previously been overpaid by the operator. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income | 12 Months Ended |
Dec. 31, 2019 | |
Accumulated Other Comprehensive Income | |
Accumulated Other Comprehensive Income | 8. Accumulated Other Comprehensive Income Accumulated other comprehensive income includes certain transactions that have generally been reported in the consolidated statements of changes in shareholders’ equity. The activity in of Accumulated Other Comprehensive Income during the years ended December 31, 2019 and 2018 consisted of the following: Year Ended December 31, 2019 2018 Balance at beginning of period $ 9,797,930 $ 9,913,236 Translation gain (loss) other 12,548 (115,306) Balance at end of period $ 9,810,478 $ 9,797,930 Substantially all of the accumulated other comprehensive income is related to the translation adjustment for the Canadian convertible debentures settled in 2017. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2019 | |
Income Taxes | |
Income Taxes | 9. Income Taxes Income (loss) before income taxes is as follows for the periods indicated: Year ended December 31, 2019 2018 Foreign (307,286) $ (665,924) U.S. 12,782,774 8,070,409 $ 12,475,488 $ 7,404,485 We file a federal income tax return in the United States, Canada, and various state and local jurisdictions. We believe that we have appropriate support for the income tax positions taken and to be taken on the Company’s tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s tax returns are open to audit under the statute of limitations for the years ended December 31, 2016 through December 31, 2019. The following tables present the Company’s current and deferred tax expense (benefit) for the periods indicated: Year ended December 31, 2019 2018 Current: Federal $ 1,010,181 $ 1,742,898 State 355,122 (428,068) Total current income tax expense 1,365,303 1,314,830 Deferred: Federal 1,527,937 (392,574) State 884,249 (179,831) Total deferred tax expense (benefit) 2,412,186 (572,405) Income tax expense $ 3,777,489 $ 742,425 The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate to the income tax provision in our financial statements. Our effective tax rate for 2019 differs from the statutory rate primarily due to state taxes. In addition to state taxes, our effective tax rate for 2018 differs from the statutory rate primarily due to lapsed uncertain tax positions. Year Ended Year Ended December 31, Effective December 31, Effective 2019 Tax Rate 2018 Tax Rate Income tax provision computed at the statutory federal tax rate $ 2,619,853 21.00 % $ 1,554,942 21.00 % Difference in Canadian and U.S. tax rate (16,901) (0.14) % (30,633) (0.41) % Valuation allowance on Canadian loss 81,431 0.65 % 170,477 2.30 % Return to provision adjustment 16,503 0.13 % (179,120) (2.42) % State taxes 979,102 7.85 % 349,643 4.72 % Miscellaneous other items 97,501 0.80 % 28,860 0.39 % Change in uncertain tax position — — % (1,151,744) (15.55) % Income tax expense $ 3,777,489 30.29 % $ 742,425 10.03 % Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. As of December 31, 2019, we have no U.S. federal net operating loss carry-forwards and approximately $8.5 million of state net operating loss carry-forwards, which begin to expire after 2025. These loss carryforwards may reduce future taxable income, however, the extent of which may be limited due to any IRC Section 382 limitation. Net deferred tax liabilities consisted of the following at December 31, 2019 and 2018: As at December 31, 2019 2018 Deferred tax assets: State net operating loss carryforwards $ 492,672 $ 465,496 Canadian net operating loss carryforwards 12,195,114 12,113,684 ARO 833,562 — Unrealized Hedge/Other 71,524 91,646 Gross deferred tax assets 13,592,872 12,670,826 Valuation allowance (12,195,114) (12,113,684) Total deferred tax assets 1,397,758 557,142 Deferred tax liabilities: Oil and gas property (10,210,078) (7,407,828) Partnership (3,016,277) (3,138,592) Unrealized Hedge/Other (572,867) — Total deferred tax liabilities (13,799,222) (10,546,420) Net deferred tax liability $ (12,401,464) $ (9,989,278) We have recorded a valuation allowance against the Canadian net operating losses as we do feel that it is more likely than not that they will not be utilized as the Company does not have any revenue producing activities in Canada. We are subject to taxation in the United States and various state jurisdictions. As of December 31, 2019 and 2018, the Company had no gross liability for income taxes associated with uncertain tax positions. The Company recognizes interest expense and penalties related to the uncertain tax position in the income tax expense line in the accompanying consolidated statements of operations and comprehensive loss. Accrued interest and penalties are included in other non-current liabilities in the consolidated balance sheets and were $0 as of December 31, 2019 and 2018. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies | |
Commitments and Contingencies | 10 . Commitments and Contingencies The Company’s future minimum lease commitments as of December 31, 2019 are summarized in the following table: Year ended December 31, Payments 2020 90,553 2021 103,693 2022 107,419 2023 18,007 $ 319,672 The Company enters into commitments for capital expenditures in advance of the expenditures being made. As of December 31, 2019, we had commitments of $2.0 million for capital expenditures. Litigation The Company is not currently involved in any litigation. Management is of the opinion that the potential for litigation is remote. |
Net Income Per Share
Net Income Per Share | 12 Months Ended |
Dec. 31, 2019 | |
Net Income Per Share | |
Net Income Per Share | 11. Net Income Per Share Basic net income per share is computed on the basis of the weighted‑average number of common shares outstanding during the period. Diluted net income per share is computed based upon the weighted‑average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities. The net income used in the calculation of basic and diluted net income per share are as follows: Year ended December 31, 2019 2018 Net income available to shareholders $ 8,697,999 $ 6,662,060 In calculating the net income per share, basic and diluted, the following weighted‑average shares were used: Year ended December 31, 2019 2018 Basic weighted-average number of shares outstanding 27,129,430 27,462,788 Dilutive stock options — 11,337 Diluted weighted average shares outstanding 27,129,430 27,474,125 We excluded the following shares from the diluted EPS because their inclusion would have been anti‑dilutive. Year ended December 31, 2019 2018 Anti-dilutive options 206,670 279,413 Anti-dilutive unvested restricted shares 346,499 282,833 Total Anti-dilutive shares 553,169 562,246 |
Operating Segments
Operating Segments | 12 Months Ended |
Dec. 31, 2019 | |
Operating Segments. | |
Operating Segments | 12. Operating Segments Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision‑maker. The chief operating decision‑maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as executive management. Segment performance is evaluated based on operating profit or loss as shown in the table below. Interest expense, interest income and income taxes are managed separately on a group basis. The Company’s reportable segments are as follows: a. The Upstream segment activities include acquisition, development and production of primarily natural gas reserves on properties within the United States; b. The Gas Gathering segment partners with two other companies to operate a natural gas gathering system; and c. The Corporate segment activities include corporate listing and governance functions of the Company. Segment activity as at, and for the years ended December 31, 2019 and 2018 is as follows: Upstream Gas Gathering Corporate Elimination Consolidated As at and for the year ended December 31, 2019 Operating revenue Natural gas $ 16,945,302 $ — $ — $ — $ 16,945,302 Natural gas liquids 110,394 — — — 110,394 Oil and condensate 314,267 — — — 314,267 Gathering and compression fees — 10,517,439 — (1,197,066) 9,320,373 Total operating revenue $ 17,369,963 (1) $ 10,517,439 $ — $ (1,197,066) 26,690,336 Net earnings for the period $ 5,151,434 $ 6,158,670 $ (2,612,105) (3) — $ 8,697,999 Operating costs 6,571,394 2,534,475 — (1,197,066) 7,908,803 Development geological and geophysical expenses 83,748 — — — 83,748 Depletion, deprec., amortization and accretion 5,563,387 1,824,294 — — 7,387,681 Segment assets $ 83,056,034 $ 14,430,680 $ 182,489 — $ 97,669,203 Capital expenditures (2) 13,014,051 325,277 — — 13,339,328 Proved properties 41,564,221 — — — 41,564,221 Unproved properties 21,047,512 — — — 21,047,512 Gathering system — 11,483,535 — — 11,483,535 Other property and equipment 587,193 — — — 587,193 As at and for the year ended December 31, 2018 Operating revenue Natural gas $ 19,031,422 $ — $ — $ — $ 19,031,422 Natural gas liquids 295,142 — — — 295,142 Oil and condensate 376,079 — — — 376,079 Gathering and compression fees — 11,087,507 — (1,105,945) 9,981,562 Total operating revenue $ 19,702,643 (1) $ 11,087,507 $ — $ (1,105,945) 29,684,205 Net earnings for the period $ 7,742,587 $ 6,814,188 $ (7,894,715) (3) $ — $ 6,662,060 Operating costs 6,665,856 2,385,766 — (1,105,945) 7,945,677 Depletion, deprec., amortization and accretion 5,294,200 1,887,553 — — 7,181,753 Segment assets $ 71,350,546 $ 15,440,047 $ 1,107,116 $ — $ 87,897,709 Capital expenditures (2) 2,472,919 197,321 — — 2,670,240 Proved properties 35,044,173 — — — 35,044,173 Unproved properties 19,498,666 — — — 19,498,666 Gathering system — 12,903,274 — — 12,903,274 (1) Segment operating revenue represents revenues generated from the operations of the segment. Inter‑segment sales during the years ended December 31, 2019 and 2018 have been eliminated upon consolidation. For the year ended December 31, 2019, Epsilon sold natural gas to 29 unique customers. The two customers over 10% comprised 47% and 27% of total revenue. For the year ended December 31, 2018, Epsilon sold natural gas to 28 unique customers. The two customers over 10% comprised 46% and 21% of total revenue. (2) Capital expenditures for Upstream consist primarily of the drilling and completing of wells while Gas Gathering consists of expenditures relating to the installation of additional gathering facilities. (3) Segment reporting for net earnings for the period does not include non‑monetary compensation, general and administrative expense, interest income, interest expense or income tax amounts as they are managed on a group basis and are instead included in the corporate column for reconciliation purposes. Additionally, gains & (losses) from commodity hedging contracts are also included in the corporate column for reconciliation purposes. |
Commodity Risk Management Activ
Commodity Risk Management Activities | 12 Months Ended |
Dec. 31, 2019 | |
Commodity Risk Management Activities | |
Commodity Risk Management Activities | 13. Commodity Risk Management Activities Commodity Price Risks Epsilon engages in price risk management activities from time to time. These activities are intended to manage Epsilon’s exposure to fluctuations in commodity prices for natural gas by securing fixed price contracts for a portion of expected sales volumes. Inherent in the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not currently require collateral from any of its counterparties nor does its counterparties require collateral from the Company. The Company enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future natural gas production and related cash flows. The natural gas revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future natural gas sales from the risk of significant declines in commodity prices, which helps ensure the Company’s ability to fund the capital budget. Epsilon has historically elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for these financial commodity derivative contracts using the mark‑to‑market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as g ain (loss) on derivative contracts on the consolidated statements of operations and comprehensive income. The related cash flow impact is reflected in cash flows from operating activities. During 2019, Epsilon recognized gains on financial commodity derivative contracts of $4,246,057. This amount included cash received on settlements of these contracts of $1,949,232. For 2018, Epsilon recognized losses on financial commodity derivative contracts of $1,938,465. This amount included cash paid on settlements of these contracts of $1,381,898. Commodity Derivative Contracts Epsilon’s outstanding natural gas price swap contracts as of December 31, 2019 consisted of: Weighted Average Price ($/MMbtu) Fair Value Volume Basis December 31, Derivative Type (Mmbtu) Swaps Differential 2019 2020 Fixed price swap 4,637,500 $ 2.71 $ — 2,001,496 Basis swap 4,637,500 $ — $ (0.43) (1,694) $ 1,999,802 As of December 31, 2019 and 2018, all of the Company’s economic derivative hedge positions were with large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non‑performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non‑performance by such counterparties. None of the Company’s derivative instruments contains credit‑risk related contingent features. Derivatives are net on the balance sheet as they are subject to the right to offset the liabilities with the assets. Fair Value of Derivative December 31, December 31, 2019 2018 Current Basis swap $ 162,844 $ 76,075 Fixed price swap 2,001,496 125,790 $ 2,164,340 $ 201,865 Fair Value of Derivative December 31, December 31, 2019 2018 Current Basis swap $ (164,538) $ (337,438) Fixed price swap — (161,450) $ (164,538) $ (498,888) Net Fair Value of Derivatives $ 1,999,802 $ (297,023) The following table presents the changes in the fair value of Epsilon’s commodity derivatives for the periods indicated: Year ended December 31, 2019 2018 Fair value of asset (liability), beginning of year $ (297,023) $ 259,544 Gains (losses) on derivative contracts included in earnings 4,246,057 (1,938,465) Settlement of commodity derivative contracts (1,949,232) 1,381,898 Fair value of asset (liability), end of year $ 1,999,802 $ (297,023) |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2019 | |
Asset Retirement Obligations | |
Asset Retirement Obligations | 14. Asset Retirement Obligations Asset retirement obligations were estimated by management based on Epsilon’s net ownership interest in all wells and the gathering system, estimated costs to reclaim and abandon such assets and the estimated timing of the costs to be incurred in future periods, and the forecast risk free cost of capital. Epsilon has estimated the net present value of its total asset retirement obligations to be $2.9 million as at December 31, 2019 ($1.6 million at December 31, 2018) based on a total net future undiscounted liability of approximately $8.9 million ($21.5 million at December 31, 2018). Each year we review, and to the extent necessary, revise our asset retirement obligation estimates. During 2019 and 2018, we reviewed the actual abandonment costs with previous estimates. As a result, estimates of abandonment costs remained constant in 2019, but were updated at the end of 2018. Our overall liability increased due to the addition of new wells in both Pennsylvania and Oklahoma. From 2018 to 2019 our undiscounted liability decreased due to a decrease in the economic life of several of the wells in Pennsylvania. The life of the wells decreased due to the decrease in natural gas prices which caused the wells to be economically profitable for a shorter period of time. Due to the decrease in the life of the wells, there were fewer years of inflation affecting the plug and abandonment costs thereby lowering the estimate from December 31, 2018 to December 31, 2019.This was offset by the drilling of new wells which added to the liability. Even though the undiscounted liability decreased, the discounted liability shown below increased due to the effect of the discounting over time. The liability is spread over a shorter period so the ARO balance has increased at December 31, 2019 over the balance at December 31, 2018. The following table presents the activity in Epsilon’s asset retirement obligations for the periods indicated: Year Ended Year ended December 31, December 31, 2019 2018 Balance beginning of period $ 1,625,154 $ 1,646,601 Liabilities from drilling of new wells 16,163 1,590 Change in estimates 1,153,740 (137,490) Accretion 114,798 114,453 Balance end of period $ 2,909,855 $ 1,625,154 |
Consolidation of Common Shares
Consolidation of Common Shares | 12 Months Ended |
Dec. 31, 2019 | |
Consolidation of Common Shares | |
Consolidation of Common Shares | 15. Consolidation of Common Shares To meet NASDAQ listing standards, the shareholders of the Company on December 19, 2018 approved a Consolidation 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. |
Summary Of Significant Accoun_2
Summary Of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Summary of Significant Accounting Policies | |
Principles of Consolidation | Principles of Consolidation 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 | 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 | 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, 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 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 | 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 | 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 | 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 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 | 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 | 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 | 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 | 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 | 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 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 | 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 | 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 | 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 | 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. |
Summary Of Significant Accoun_3
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Summary of Significant Accounting Policies | |
Schedule of reconciliation of cash, cash equivalents and restricted cash | 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 |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Property and Equipment | |
Schedule of property and equipment | December 31, December 31, 2019 2018 Property and equipment: Oil and gas properties, successful efforts method Proved properties $ 130,819,256 $ 118,851,574 Unproved properties 21,047,512 19,498,666 Accumulated depletion, depreciation, and amortization (89,255,035) (83,807,401) Total oil and gas properties, net 62,611,733 54,542,839 Gathering system 41,445,225 41,040,847 Accumulated depletion, depreciation, and amortization (29,961,690) (28,137,573) Total gathering system, net 11,483,535 12,903,274 Land 375,314 — Buildings and other property and equipment, net 211,879 — Total property and equipment, net $ 74,682,461 $ 67,446,113 |
Revolving Line of Credit (Table
Revolving Line of Credit (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Revolving Line of Credit | |
Schedule of revolving line of credit | Balance at Balance at December 31, December 31, Current Interest Rate 2019 2018 Borrowing Base 3 mo. Revolving line of credit $ — $ — $ 23,000,000 LIBOR + 2.75% (1) (1) At December 31, 2019, the interest rate was 4.65%. |
Shareholders Equity (Tables)
Shareholders Equity (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Shareholders' Equity | |
Schedule of purchases of equity Shares | The following table contains information about our repurchase of equity securities during the year ended December 31, 2019: Total number Maximum number of shares of shares that purchased as may yet be Total number Average price part of publicly purchased under of shares paid per announced plans the plans or purchased share or programs programs Beginning balance at May 20, 2019 — 1,367,762 May 2019 16,148 $ 4.17 June 2019 221,041 $ 4.12 July 2019 55,112 $ 3.90 August 2019 56,432 $ 3.66 September 2019 14,797 $ 3.79 October 2019 42,307 $ 3.38 November 2019 290,259 $ 3.41 Total for the year ended December 31, 2019 696,096 $ 3.72 696,096 671,666 |
Summary of stock option activity | Year ended Year ended December 31, 2019 December 31, 2018 Weighted Weighted Number of Average Number of Average Options Exercise Options Exercise Exercise price in US$ Outstanding Price (1) Outstanding Price (1) Balance at beginning of period 290,750 $ 5.02 330,750 $ 5.14 Exercised (25,000) 2.17 — — Expired/Forfeited (20,750) 5.37 (40,000) 6.00 Balance at period-end 245,000 $ 5.27 290,750 $ 5.02 Exercisable at period-end 206,670 $ 5.32 210,249 $ 5.02 |
Summary of stock options outstanding | Weighted Option Average Number of Number of Pricing Remaining Options Options Model Contractual Life Exercise Price Outstanding Exercisable Valuations (in years) As of December 31, 2019 $5.02 115,000 76,670 $ 201,630 4.08 $5.50 130,000 130,000 276,299 2.43 Total 245,000 206,670 $ 477,929 3.04 |
Schedule of restricted stock activity | Year ended Year ended December 31, 2019 December 31, 2018 Weighted Weighted Number of Average Number of Average Shares Remaining Life Shares Remaining Life Outstanding (years) Outstanding (years) Balance non-vested Restricted Stock at beginning of period 282,833 2.56 162,500 1.87 Granted 184,500 3.00 174,500 3.00 Vested (106,834) — (54,167) — Forfeited (14,000) 2.64 — — Balance non-vested Restricted Stock at end of period 346,499 1.67 282,833 2.56 |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Revenue Recognition | |
Summary of revenue | Year Ended December 31, 2019 2018 Operating revenue Natural gas $ 16,945,302 $ 19,031,422 Natural gas liquids 110,394 295,142 Oil and condensate 314,267 376,079 Gathering and compression fees 9,320,373 9,981,562 Total operating revenue $ 26,690,336 $ 29,684,205 |
Accumulated Other Comprehensi_2
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Accumulated Other Comprehensive Income | |
Schedule of Accumulated Other Comprehensive Income | Year Ended December 31, 2019 2018 Balance at beginning of period $ 9,797,930 $ 9,913,236 Translation gain (loss) other 12,548 (115,306) Balance at end of period $ 9,810,478 $ 9,797,930 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Taxes | |
Schedule of income (loss) before income taxes | Year ended December 31, 2019 2018 Foreign (307,286) $ (665,924) U.S. 12,782,774 8,070,409 $ 12,475,488 $ 7,404,485 |
Schedule of current and deferred tax expense (benefit) | Year ended December 31, 2019 2018 Current: Federal $ 1,010,181 $ 1,742,898 State 355,122 (428,068) Total current income tax expense 1,365,303 1,314,830 Deferred: Federal 1,527,937 (392,574) State 884,249 (179,831) Total deferred tax expense (benefit) 2,412,186 (572,405) Income tax expense $ 3,777,489 $ 742,425 |
Schedule of reconciliation between statutory rate and effective income tax rate | Year Ended Year Ended December 31, Effective December 31, Effective 2019 Tax Rate 2018 Tax Rate Income tax provision computed at the statutory federal tax rate $ 2,619,853 21.00 % $ 1,554,942 21.00 % Difference in Canadian and U.S. tax rate (16,901) (0.14) % (30,633) (0.41) % Valuation allowance on Canadian loss 81,431 0.65 % 170,477 2.30 % Return to provision adjustment 16,503 0.13 % (179,120) (2.42) % State taxes 979,102 7.85 % 349,643 4.72 % Miscellaneous other items 97,501 0.80 % 28,860 0.39 % Change in uncertain tax position — — % (1,151,744) (15.55) % Income tax expense $ 3,777,489 30.29 % $ 742,425 10.03 % |
Schedule of net deferred tax liabilities | As at December 31, 2019 2018 Deferred tax assets: State net operating loss carryforwards $ 492,672 $ 465,496 Canadian net operating loss carryforwards 12,195,114 12,113,684 ARO 833,562 — Unrealized Hedge/Other 71,524 91,646 Gross deferred tax assets 13,592,872 12,670,826 Valuation allowance (12,195,114) (12,113,684) Total deferred tax assets 1,397,758 557,142 Deferred tax liabilities: Oil and gas property (10,210,078) (7,407,828) Partnership (3,016,277) (3,138,592) Unrealized Hedge/Other (572,867) — Total deferred tax liabilities (13,799,222) (10,546,420) Net deferred tax liability $ (12,401,464) $ (9,989,278) |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies | |
Schedule of future minimum lease commitments | Year ended December 31, Payments 2020 90,553 2021 103,693 2022 107,419 2023 18,007 $ 319,672 |
Net Income Per Share (Tables)
Net Income Per Share (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Net Income Per Share | |
Schedule of net income used in the calculation of basic and diluted net income per share | Year ended December 31, 2019 2018 Net income available to shareholders $ 8,697,999 $ 6,662,060 |
Schedule of weighted-average shares used in calculation of net income per share | Year ended December 31, 2019 2018 Basic weighted-average number of shares outstanding 27,129,430 27,462,788 Dilutive stock options — 11,337 Diluted weighted average shares outstanding 27,129,430 27,474,125 |
Schedule of anti-dilutive shares | Year ended December 31, 2019 2018 Anti-dilutive options 206,670 279,413 Anti-dilutive unvested restricted shares 346,499 282,833 Total Anti-dilutive shares 553,169 562,246 |
Operating Segments (Tables)
Operating Segments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Operating Segments. | |
Schedule of segment financial information | Upstream Gas Gathering Corporate Elimination Consolidated As at and for the year ended December 31, 2019 Operating revenue Natural gas $ 16,945,302 $ — $ — $ — $ 16,945,302 Natural gas liquids 110,394 — — — 110,394 Oil and condensate 314,267 — — — 314,267 Gathering and compression fees — 10,517,439 — (1,197,066) 9,320,373 Total operating revenue $ 17,369,963 (1) $ 10,517,439 $ — $ (1,197,066) 26,690,336 Net earnings for the period $ 5,151,434 $ 6,158,670 $ (2,612,105) (3) — $ 8,697,999 Operating costs 6,571,394 2,534,475 — (1,197,066) 7,908,803 Development geological and geophysical expenses 83,748 — — — 83,748 Depletion, deprec., amortization and accretion 5,563,387 1,824,294 — — 7,387,681 Segment assets $ 83,056,034 $ 14,430,680 $ 182,489 — $ 97,669,203 Capital expenditures (2) 13,014,051 325,277 — — 13,339,328 Proved properties 41,564,221 — — — 41,564,221 Unproved properties 21,047,512 — — — 21,047,512 Gathering system — 11,483,535 — — 11,483,535 Other property and equipment 587,193 — — — 587,193 As at and for the year ended December 31, 2018 Operating revenue Natural gas $ 19,031,422 $ — $ — $ — $ 19,031,422 Natural gas liquids 295,142 — — — 295,142 Oil and condensate 376,079 — — — 376,079 Gathering and compression fees — 11,087,507 — (1,105,945) 9,981,562 Total operating revenue $ 19,702,643 (1) $ 11,087,507 $ — $ (1,105,945) 29,684,205 Net earnings for the period $ 7,742,587 $ 6,814,188 $ (7,894,715) (3) $ — $ 6,662,060 Operating costs 6,665,856 2,385,766 — (1,105,945) 7,945,677 Depletion, deprec., amortization and accretion 5,294,200 1,887,553 — — 7,181,753 Segment assets $ 71,350,546 $ 15,440,047 $ 1,107,116 $ — $ 87,897,709 Capital expenditures (2) 2,472,919 197,321 — — 2,670,240 Proved properties 35,044,173 — — — 35,044,173 Unproved properties 19,498,666 — — — 19,498,666 Gathering system — 12,903,274 — — 12,903,274 (1) Segment operating revenue represents revenues generated from the operations of the segment. Inter‑segment sales during the years ended December 31, 2019 and 2018 have been eliminated upon consolidation. For the year ended December 31, 2019, Epsilon sold natural gas to 29 unique customers. The two customers over 10% comprised 47% and 27% of total revenue. For the year ended December 31, 2018, Epsilon sold natural gas to 28 unique customers. The two customers over 10% comprised 46% and 21% of total revenue. (2) Capital expenditures for Upstream consist primarily of the drilling and completing of wells while Gas Gathering consists of expenditures relating to the installation of additional gathering facilities. (3) Segment reporting for net earnings for the period does not include non‑monetary compensation, general and administrative expense, interest income, interest expense or income tax amounts as they are managed on a group basis and are instead included in the corporate column for reconciliation purposes. Additionally, gains & (losses) from commodity hedging contracts are also included in the corporate column for reconciliation purposes. |
Commodity Risk Management Act_2
Commodity Risk Management Activities (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commodity Risk Management Activities | |
Schedule of natural gas price and basis swap contracts | Weighted Average Price ($/MMbtu) Fair Value Volume Basis December 31, Derivative Type (Mmbtu) Swaps Differential 2019 2020 Fixed price swap 4,637,500 $ 2.71 $ — 2,001,496 Basis swap 4,637,500 $ — $ (0.43) (1,694) $ 1,999,802 |
Schedule of fair value of derivatives | Fair Value of Derivative December 31, December 31, 2019 2018 Current Basis swap $ 162,844 $ 76,075 Fixed price swap 2,001,496 125,790 $ 2,164,340 $ 201,865 Fair Value of Derivative December 31, December 31, 2019 2018 Current Basis swap $ (164,538) $ (337,438) Fixed price swap — (161,450) $ (164,538) $ (498,888) Net Fair Value of Derivatives $ 1,999,802 $ (297,023) |
Schedule of fair value of derivatives rollforward | Year ended December 31, 2019 2018 Fair value of asset (liability), beginning of year $ (297,023) $ 259,544 Gains (losses) on derivative contracts included in earnings 4,246,057 (1,938,465) Settlement of commodity derivative contracts (1,949,232) 1,381,898 Fair value of asset (liability), end of year $ 1,999,802 $ (297,023) |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Asset Retirement Obligations | |
Schedule of activity in asset retirement obligations | Year Ended Year ended December 31, December 31, 2019 2018 Balance beginning of period $ 1,625,154 $ 1,646,601 Liabilities from drilling of new wells 16,163 1,590 Change in estimates 1,153,740 (137,490) Accretion 114,798 114,453 Balance end of period $ 2,909,855 $ 1,625,154 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Reconciliation of Cash, Cash Equivalents and Restricted Cash (Details) - USD ($) | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Summary of Significant Accounting Policies | |||
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 | $ 10,555,717 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Additional Information (Details) | 12 Months Ended | |
Dec. 31, 2019USD ($)Institution | Dec. 31, 2018USD ($)Institution | |
Property, Plant and Equipment [Line Items] | ||
Allowance for doubtful accounts | $ | $ 0 | $ 0 |
Bad debt expense recognized | $ | $ 0 | $ 0 |
Asset development costs capitalization, Percentage | 35.00% | |
Number of financial institutions | 2 | 2 |
Auburn Gas Gathering System | ||
Property, Plant and Equipment [Line Items] | ||
Ownership interest | 35.00% | |
CANADA | ||
Property, Plant and Equipment [Line Items] | ||
Number of financial institutions | 1 | 1 |
U.S. | ||
Property, Plant and Equipment [Line Items] | ||
Number of financial institutions | 1 | 1 |
Restricted stock awards | ||
Property, Plant and Equipment [Line Items] | ||
Vesting period | 3 years | |
Buildings | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful lives of the property and equipment | 30 years | |
Other property and equipment | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful lives of the property and equipment | 3 years | |
Other property and equipment | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful lives of the property and equipment | 7 years | |
Gas, oil, NGLs and condensate | ||
Property, Plant and Equipment [Line Items] | ||
Receivable collection period | 30 days | |
Gas gathering and compression | ||
Property, Plant and Equipment [Line Items] | ||
Receivable collection period | 60 days |
Property and Equipment (Details
Property and Equipment (Details) - USD ($) | 1 Months Ended | 12 Months Ended | ||
Jul. 31, 2019 | Jun. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Property and equipment: | ||||
Proved properties | $ 130,819,256 | $ 118,851,574 | ||
Unproved properties | 21,047,512 | 19,498,666 | ||
Accumulated depletion, depreciation, and amortization | (89,255,035) | (83,807,401) | ||
Total oil and gas properties, net | 62,611,733 | 54,542,839 | ||
Gathering system | 41,445,225 | 41,040,847 | ||
Accumulated depletion, depreciation, and amortization | (29,961,690) | (28,137,573) | ||
Total gathering system, net | 11,483,535 | 12,903,274 | ||
Land | 375,314 | |||
Buildings and other property and equipment, net | 211,879 | |||
Total property and equipment, net | 74,682,461 | 67,446,113 | ||
Payment for land acquired | 596,500 | 260,000 | ||
Cash call refund | 500,000 | |||
Proceeds from sale of leases | $ 400,000 | $ 1,000,000 | 1,400,000 | |
Impairment of oil and gas properties | $ 0 | $ 0 |
Revolving Line of Credit (Detai
Revolving Line of Credit (Details) - Revolving Credit Facility - USD ($) | Aug. 14, 2019 | Jan. 07, 2019 | Jul. 30, 2013 | Dec. 31, 2019 | Feb. 11, 2020 | Jan. 06, 2019 |
Revolving Credit Facility | ||||||
Debt term | 3 years | |||||
Total commitments | $ 100,000,000 | |||||
Current borrowing base | $ 23,000,000 | $ 23,000,000 | $ 23,000,000 | $ 23,000,000 | $ 13,500,000 | |
Minimum utilization percentage | 25.00% | |||||
Hedging percentage on production for succeeding six months | 50.00% | |||||
Percentage of commodity hedge of natural gas | 50.00% | |||||
Reserve percentage on proved oil and gas properties | 90.00% | |||||
Minimum | ||||||
Revolving Credit Facility | ||||||
Percentage of commodity hedge of natural gas for the succeeding calendar year | 25.00% | |||||
Hedging percentage on production for first twelve months | 75.00% | |||||
Maximum | ||||||
Revolving Credit Facility | ||||||
Reserve percentage on borrowing base | 150.00% | |||||
LIBOR | ||||||
Revolving Credit Facility | ||||||
Margin added to variable interest rate | 2.75% | |||||
LIBOR | Minimum | ||||||
Revolving Credit Facility | ||||||
Margin added to variable interest rate | 2.75% | |||||
LIBOR | Maximum | ||||||
Revolving Credit Facility | ||||||
Margin added to variable interest rate | 3.75% |
Revolving Line of Credit - Rati
Revolving Line of Credit - Ratios (Details) - Revolving Credit Facility | 12 Months Ended | ||||
Dec. 31, 2019USD ($) | Feb. 11, 2020USD ($) | Aug. 14, 2019USD ($) | Jan. 07, 2019USD ($) | Jan. 06, 2019USD ($) | |
Revolving Credit Facility | |||||
Interest coverage ratio | 3 | ||||
Current ratio | 1 | ||||
Leverage ratio | 3.5 | ||||
Commitment fee assessed quarterly on the daily average unused commitments | 0.50% | ||||
Current borrowing base | $ 23,000,000 | $ 23,000,000 | $ 23,000,000 | $ 23,000,000 | $ 13,500,000 |
Weighted average interest rate (as a percent) | 4.65% | ||||
LIBOR | |||||
Revolving Credit Facility | |||||
Margin added to variable interest rate | 2.75% |
Shareholders Equity - Share Cap
Shareholders Equity - Share Capital (Details) | 12 Months Ended | |
Dec. 31, 2019$ / sharesshares | Dec. 31, 2018$ / shares | |
Components of share capital: | ||
Common Stock, No Par Value | $ 0 | $ 0 |
Preferred Stock, No Par Value | $ 0 | |
NCIB Program | ||
Components of share capital: | ||
Buyback and retirement of common shares | shares | 57,100 | |
Shares repurchased average price (in dollars per share) | $ 4.26 | |
Average share price, converted to US$ using rate | 1.33 | |
Average share price on the TSX | $ 4.22 | $ 3.98 |
Shareholders Equity - Purchases
Shareholders Equity - Purchases of Equity Shares (Details) - USD ($) $ / shares in Units, $ in Millions | May 20, 2019 | Nov. 30, 2019 | Oct. 31, 2019 | Sep. 30, 2019 | Aug. 31, 2019 | Jul. 31, 2019 | Jun. 30, 2019 | May 31, 2019 | Dec. 31, 2019 |
Shareholders' Equity | |||||||||
Stock Repurchase Program, Number of Shares Authorized to be Repurchased | 1,367,762 | ||||||||
Shares Repurchased As A Percentage Of Outstanding Common Shares | 5.00% | ||||||||
Stock Repurchase Program, Authorized Amount | $ 2.5 | ||||||||
Total number of shares purchased | 290,259 | 42,307 | 14,797 | 56,432 | 55,112 | 221,041 | 16,148 | 696,096 | |
Average price paid per share | $ 3.41 | $ 3.38 | $ 3.79 | $ 3.66 | $ 3.90 | $ 4.12 | $ 4.17 | $ 3.72 | |
Maximum number of shares that may yet be purchased under the plans or programs | 1,367,762 | 671,666 |
Shareholders Equity - Stock Opt
Shareholders Equity - Stock Option Activity (Details) - Stock options - $ / shares | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Share Compensation Plan | ||
Common Shares available for future option issuances | 755,000 | |
Number of Options Outstanding | ||
Balance at beginning of period (in shares) | 290,750 | 330,750 |
Exercised (in shares) | (25,000) | |
Expired/Forfeited (in shares) | (20,750) | (40,000) |
Options outstanding, end of period (in shares) | 245,000 | 290,750 |
Exercisable at period-end (in shares) | 206,670 | 210,249 |
Weighted average exercise price | ||
Balance at beginning of period (in dollars per share) | $ 5.02 | $ 5.14 |
Exercised (in dollars per share) | 2.17 | |
Expired/Forfeited (in dollars per share) | 5.37 | 6 |
Balance at period-end (in dollars per share) | 5.27 | 5.02 |
Exercisable at period-end (in dollars per share) | $ 5.32 | $ 5.02 |
Shareholders Equity - Stock O_2
Shareholders Equity - Stock Option Activity, Narrative (Details) - Stock options - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Share Compensation Plan | ||
Unrecognized stock based compensation to be recognized over a period | $ 1,867 | $ 27,877 |
Weighted average period for recognition | 29 days | 1 year 1 month 6 days |
Aggregate intrinsic value of options outstanding | $ 0 | $ 58,664 |
Granted (in shares) | 0 | 0 |
Shareholders Equity - Stock O_3
Shareholders Equity - Stock Options Outstanding (Details) - Stock options - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Share-based Payment Arrangement, Option, Exercise Price Range [Line Items] | ||
Number of Options Outstanding | 245,000 | |
Number of Options Exercisable | 206,670 | |
Option Pricing Model Valuations | $ 477,929 | |
Weighted Average Remaining Contractual Life (in years) | 3 years 15 days | |
Stock based compensation expense | $ 25,203 | $ 83,328 |
$5.02 | ||
Share-based Payment Arrangement, Option, Exercise Price Range [Line Items] | ||
Exercise Price | $ 5.02 | |
Number of Options Outstanding | 115,000 | |
Number of Options Exercisable | 76,670 | |
Option Pricing Model Valuations | $ 201,630 | |
Weighted Average Remaining Contractual Life (in years) | 4 years 29 days | |
$5.50 | ||
Share-based Payment Arrangement, Option, Exercise Price Range [Line Items] | ||
Exercise Price | $ 5.50 | |
Number of Options Outstanding | 130,000 | |
Number of Options Exercisable | 130,000 | |
Option Pricing Model Valuations | $ 276,299 | |
Weighted Average Remaining Contractual Life (in years) | 2 years 5 months 5 days |
Shareholders Equity - Share Com
Shareholders Equity - Share Compensation Plan (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Plan | |||
Share Compensation Plan | |||
Maximum participant's compensation percentage | 100.00% | ||
Restricted stock awards | |||
Share Compensation Plan | |||
Vesting period | 3 years | ||
Vesting percentage | 33.00% | ||
Stock based compensation expense | $ 485,257 | $ 246,904 | |
Unrecognized stock based compensation to be recognized over a period | $ 1,641,295 | $ 1,767,975 | |
Weighted average period for recognition | 1 year 1 month 13 days | 1 year 5 months 1 day | |
Number outstanding | |||
Balance non-vested Restricted Stock at beginning of period (in shares) | 282,833 | 162,500 | |
Granted (in shares) | 184,500 | 174,500 | |
Vested (in shares) | (106,834) | (54,167) | |
Forfeited (in shares) | (14,000) | ||
Balance non-vested Restricted Stock at end of period (in shares) | 346,499 | 282,833 | 162,500 |
Weighted Average Remaining Life | |||
Granted (in years) | 3 years | 3 years | |
Forfeited (in years) | 2 years 7 months 21 days | ||
Balance non-vested Restricted Stock at end of period (in years) | 1 year 8 months 1 day | 2 years 6 months 22 days | 1 year 10 months 13 days |
Revenue Recognition - Summary o
Revenue Recognition - Summary of revenue (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Revenue recognition | ||
Total operating revenue | $ 26,690,336 | $ 29,684,205 |
Natural gas | ||
Revenue recognition | ||
Total operating revenue | 16,945,302 | 19,031,422 |
Natural gas liquids | ||
Revenue recognition | ||
Total operating revenue | 110,394 | 295,142 |
Oil and condensate | ||
Revenue recognition | ||
Total operating revenue | 314,267 | 376,079 |
Gas gathering and compression | ||
Revenue recognition | ||
Total operating revenue | $ 9,320,373 | $ 9,981,562 |
Revenue Recognition - Additiona
Revenue Recognition - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Revenue recognition | ||
Accounts receivable balances | $ 2.4 | $ 3 |
Auburn Gas Gathering System | ||
Revenue recognition | ||
Accounts receivable balances | $ 1.9 | $ 0 |
Gas, oil, NGLs and condensate | ||
Revenue recognition | ||
Receivable collection period | 30 days | |
Gas gathering and compression | ||
Revenue recognition | ||
Receivable collection period | 60 days |
Accumulated Other Comprehensi_3
Accumulated Other Comprehensive Income (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Accumulated Other Comprehensive Income (Loss) | ||
Balance | $ 69,944,087 | $ 63,731,045 |
Translation gain (loss) other | 12,548 | (115,306) |
Balance | 76,362,994 | 69,944,087 |
Foreign Currency Translation Adjustment | ||
Accumulated Other Comprehensive Income (Loss) | ||
Balance | 9,797,930 | 9,913,236 |
Translation gain (loss) other | 12,548 | (115,306) |
Balance | $ 9,810,478 | $ 9,797,930 |
Income Taxes - Income before in
Income Taxes - Income before income taxes (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Income (loss) before income taxes | ||
Foreign | $ (307,286) | $ (665,924) |
U.S. | 12,782,774 | 8,070,409 |
Income (loss) before income taxes | $ 12,475,488 | $ 7,404,485 |
Income Taxes - Current and Defe
Income Taxes - Current and Deferred Tax Expense (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Current: | ||
Federal | $ 1,010,181 | $ 1,742,898 |
State | 355,122 | (428,068) |
Total current income tax expense | 1,365,303 | 1,314,830 |
Deferred: | ||
Federal | 1,527,937 | (392,574) |
State | 884,249 | (179,831) |
Total deferred tax expense (benefit) | 2,412,186 | (572,405) |
Income tax expense | $ 3,777,489 | $ 742,425 |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of Income taxes (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Reconciliation of income tax expense (benefit) between statutory tax rate and effective tax rate | ||
Income tax provision computed at the statutory federal tax rate | $ 2,619,853 | $ 1,554,942 |
Difference in Canadian and U.S. tax rate | (16,901) | (30,633) |
Valuation allowance on Canadian loss | 81,431 | 170,477 |
Return to provision adjustment | 16,503 | (179,120) |
State taxes | 979,102 | 349,643 |
Miscellaneous other items | 97,501 | 28,860 |
Change in uncertain tax position | (1,151,744) | |
Income tax expense | $ 3,777,489 | $ 742,425 |
Reconciliation of statutory tax rate and effective tax rate | ||
Income tax provision computed at the statutory federal tax rate (as a percent) | 21.00% | 21.00% |
Difference in Canadian and U.S. tax rate (as a percent) | (0.14%) | (0.41%) |
Valuation allowance on Canadian loss (as a percent) | 0.65% | 2.30% |
Return to provision adjustment (as a percent) | 0.13% | (2.42%) |
State taxes (as a percent) | 7.85% | 4.72% |
Miscellaneous other items (as a percent) | 0.80% | 0.39% |
Change in uncertain tax position (as a percent) | (15.55%) | |
Effective Tax Rate (as a percent) | 30.29% | 10.03% |
Income Taxes - Net Deferred Tax
Income Taxes - Net Deferred Tax Liabilities (Details) - USD ($) | Dec. 31, 2019 | Dec. 31, 2018 |
Deferred tax assets: | ||
State net operating loss carryforwards | $ 492,672 | $ 465,496 |
Canadian net operating loss carryforwards | 12,195,114 | 12,113,684 |
ARO | 833,562 | |
Unrealized Hedge/Other | 71,524 | 91,646 |
Gross deferred tax assets | 13,592,872 | 12,670,826 |
Valuation allowance | (12,195,114) | (12,113,684) |
Total deferred tax assets | 1,397,758 | 557,142 |
Deferred tax liabilities: | ||
Oil and gas property | (10,210,078) | (7,407,828) |
Partnership | (3,016,277) | (3,138,592) |
Unrealized Hedge/Other | (572,867) | |
Total deferred tax liabilities | (13,799,222) | (10,546,420) |
Net deferred tax liability | (12,401,464) | (9,989,278) |
Uncertain tax benefit liability | 0 | 0 |
Accrued interest and penalties | 0 | $ 0 |
U.S. federal | ||
Operating Loss Carryforwards [Line Items] | ||
Net operating loss carry-forwards | 0 | |
State | ||
Operating Loss Carryforwards [Line Items] | ||
Net operating loss carry-forwards | $ 8,500,000 |
Commitments and Contingencies_2
Commitments and Contingencies (Details) | Dec. 31, 2019USD ($) |
Future minimum lease commitments | |
2020 | $ 90,553 |
2021 | 103,693 |
2022 | 107,419 |
2023 | 18,007 |
Total future minimum lease commitments | 319,672 |
Commitments for capital expenditures | $ 2,000,000 |
Net Income Per Share (Details)
Net Income Per Share (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Net income available to shareholders | $ 8,697,999 | $ 6,662,060 |
Weighted average number of shares - basic and diluted | ||
Basic weighted-average number of shares outstanding | 27,129,430 | 27,462,788 |
Diluted weighted average shares outstanding | 27,129,430 | 27,474,125 |
Total Anti-dilutive shares | 553,169 | 562,246 |
Stock options | ||
Weighted average number of shares - basic and diluted | ||
Incremental common shares | 11,337 | |
Total Anti-dilutive shares | 206,670 | 279,413 |
Restricted stock awards | ||
Weighted average number of shares - basic and diluted | ||
Total Anti-dilutive shares | 346,499 | 282,833 |
Operating Segments - Segments (
Operating Segments - Segments (Details) | 12 Months Ended | |
Dec. 31, 2019USD ($)segment | Dec. 31, 2018USD ($) | |
Segment information | ||
Total operating revenue | $ 26,690,336 | $ 29,684,205 |
Net earnings for the period | 8,697,999 | 6,662,060 |
Operating costs | 7,908,803 | 7,945,677 |
Development geological and geophysical expenses | 83,748 | |
Depletion, deprec., amortization and accretion | 7,387,681 | 7,181,753 |
Segment assets | 97,669,203 | 87,897,709 |
Capital expenditures | 13,339,328 | 2,670,240 |
Proved properties | 41,564,221 | 35,044,173 |
Unproved properties | 21,047,512 | 19,498,666 |
Gathering system | 11,483,535 | 12,903,274 |
Other property and equipment | 587,193 | |
Corporate | ||
Segment information | ||
Net earnings for the period | (2,612,105) | (7,894,715) |
Segment assets | 182,489 | 1,107,116 |
Elimination | ||
Segment information | ||
Total operating revenue | (1,197,066) | (1,105,945) |
Operating costs | (1,197,066) | (1,105,945) |
Natural gas | ||
Segment information | ||
Total operating revenue | 16,945,302 | 19,031,422 |
Natural gas liquids | ||
Segment information | ||
Total operating revenue | 110,394 | 295,142 |
Oil and condensate | ||
Segment information | ||
Total operating revenue | 314,267 | 376,079 |
Gas gathering and compression | ||
Segment information | ||
Total operating revenue | 9,320,373 | 9,981,562 |
Gas gathering and compression | Elimination | ||
Segment information | ||
Total operating revenue | (1,197,066) | (1,105,945) |
Upstream | Operating Segments | ||
Segment information | ||
Total operating revenue | 17,369,963 | 19,702,643 |
Net earnings for the period | 5,151,434 | 7,742,587 |
Operating costs | 6,571,394 | 6,665,856 |
Development geological and geophysical expenses | 83,748 | |
Depletion, deprec., amortization and accretion | 5,563,387 | 5,294,200 |
Segment assets | 83,056,034 | 71,350,546 |
Capital expenditures | 13,014,051 | 2,472,919 |
Proved properties | 41,564,221 | 35,044,173 |
Unproved properties | 21,047,512 | 19,498,666 |
Other property and equipment | 587,193 | |
Upstream | Natural gas | Operating Segments | ||
Segment information | ||
Total operating revenue | 16,945,302 | 19,031,422 |
Upstream | Natural gas liquids | Operating Segments | ||
Segment information | ||
Total operating revenue | 110,394 | 295,142 |
Upstream | Oil and condensate | Operating Segments | ||
Segment information | ||
Total operating revenue | $ 314,267 | 376,079 |
Gas Gathering | Operating Segments | ||
Operating Segments | ||
Number of companies partnered to operate natural gas gathering system | segment | 2 | |
Segment information | ||
Total operating revenue | $ 10,517,439 | 11,087,507 |
Net earnings for the period | 6,158,670 | 6,814,188 |
Operating costs | 2,534,475 | 2,385,766 |
Depletion, deprec., amortization and accretion | 1,824,294 | 1,887,553 |
Segment assets | 14,430,680 | 15,440,047 |
Capital expenditures | 325,277 | 197,321 |
Gathering system | 11,483,535 | 12,903,274 |
Gas Gathering | Gas gathering and compression | Operating Segments | ||
Segment information | ||
Total operating revenue | $ 10,517,439 | $ 11,087,507 |
Operating Segments - Customers
Operating Segments - Customers (Details) - Sale of Natural Gas - customer | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Concentration risk | ||
Number of customers | 29 | 28 |
Customer Concentration risk | ||
Concentration risk | ||
Number of customers | 2 | 2 |
Threshold concentration risk for reporting (as a percent) | 10.00% | 10.00% |
Customer Concentration risk | Customer One | ||
Concentration risk | ||
Concentration risk (as a percent) | 47.00% | 46.00% |
Customer Concentration risk | Customer Two | ||
Concentration risk | ||
Concentration risk (as a percent) | 27.00% | 21.00% |
Commodity Risk Management Act_3
Commodity Risk Management Activities - Commodity Price Risks (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Commodity Risk Management Activities | ||
Unrealized gains (losses) on derivatives included in earnings | $ 4,246,057 | $ (1,938,465) |
Cash received from (paid for) settlements of derivative contracts | $ 1,949,232 | $ (1,381,898) |
Commodity Risk Management Act_4
Commodity Risk Management Activities - Commodity Derivative Contracts (Details) | 12 Months Ended | |
Dec. 31, 2019USD ($)MMBTU$ / MMBTU | Dec. 31, 2018USD ($) | |
Risk Management Activities | ||
Fair Value | $ 1,999,802 | $ (297,023) |
Fixed price swap | ||
Risk Management Activities | ||
Volume (Mmbtu) | MMBTU | 4,637,500 | |
Swaps | $ / MMBTU | 2.71 | |
Fair Value | $ 2,001,496 | |
Basis swap | ||
Risk Management Activities | ||
Volume (Mmbtu) | MMBTU | 4,637,500 | |
Basis Differential | $ / MMBTU | (0.43) | |
Fair Value | $ (1,694) |
Commodity Risk Management Act_5
Commodity Risk Management Activities - Fair Value of Derivative Instruments (Details) | Dec. 31, 2019USD ($)DerivativeInstrument | Dec. 31, 2018USD ($) |
Risk Management Activities | ||
Number of credit risk derivatives held | DerivativeInstrument | 0 | |
Fair value of derivative assets, current | $ 1,999,802 | |
Fair value of derivative liabilities, current | $ (297,023) | |
Fair Value of Derivative Assets | 2,164,340 | 201,865 |
Fair Value of Derivative Liabilities | (164,538) | (498,888) |
Net Fair Value of Derivatives | 1,999,802 | (297,023) |
Basis swap | ||
Risk Management Activities | ||
Fair Value of Derivative Assets | 162,844 | 76,075 |
Fair Value of Derivative Liabilities | (164,538) | (337,438) |
Net Fair Value of Derivatives | (1,694) | |
Fixed price swap | ||
Risk Management Activities | ||
Fair Value of Derivative Assets | 2,001,496 | 125,790 |
Fair Value of Derivative Liabilities | $ (161,450) | |
Net Fair Value of Derivatives | $ 2,001,496 |
Commodity Risk Management Act_6
Commodity Risk Management Activities - Fair value of asset (liability) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Commodity Risk Management Activities | ||
Fair value of asset (liability), beginning of year | $ (297,023) | $ 259,544 |
Gains (losses) on derivatives included in earnings | 4,246,057 | (1,938,465) |
Settlement of commodity derivative contracts | (1,949,232) | 1,381,898 |
Fair value of asset (liability), end of year | $ 1,999,802 | $ (297,023) |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Asset Retirement Obligations | ||
Net present value of asset retirement obligation | $ 2,900,000 | $ 1,600,000 |
Total net future undiscounted liability | 8,900,000 | 21,500,000 |
Reconciliation of provision for asset retirement obligations | ||
Balance beginning of period | 1,625,154 | 1,646,601 |
Liabilities from drilling of new wells | 16,163 | 1,590 |
Change in estimates | 1,153,740 | (137,490) |
Accretion | 114,798 | 114,453 |
Balance end of period | $ 2,909,855 | $ 1,625,154 |
Consolidation of Common Shares
Consolidation of Common Shares (Details) | Dec. 19, 2018 |
Consolidation of Common Shares | |
Basis for consolidation of the issued and outstanding common shares | 0.5 |