MEXCO ENERGY CORP 10-K

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Market Information In September 2003, our common stock began trading on the NYSE American, formerly the American Stock Exchange and more recently the NYSE MKT, under the symbol “MXC”. Prior to September 2003, the Company’s common stock was traded on the over-the-counter bulletin board market under the symbol “MEXC”. The registrar and transfer agent is Issuer Direct Corporation, 500 Perimeter Park Drive, Suite D, Morrisville, North Carolina, 27560 (Tel: 877-481-4014). The following table sets forth certain information as to the high and low sales price quoted for Mexco’s common stock on the NYSE American. High Low 2021: April - June 2020 $ 5.24 $ 2.00 July - September 2020 14.63 2.92 October - December 2020 8.79 4.60 January - March 2021 14.25 5.50 2020: April - June 2019 $ 6.10 $ 3.37 July - September 2019 5.70 3.70 October - December 2019 4.98 3.60 January - March 2020 4.25 1.75 On June 14, 2021, the closing sales price of our common stock on the NYSE American was $8.85 per share. Stockholders As of March 31, 2021, we had 2,143,666 shares issued and 856 shareholders of record which does not include shareholders for whom shares are held in a “nominee” or “street” name. 20 Dividends We have never declared or paid any cash dividends on our common stock. We currently intend to retain future earnings and other cash resources, if any, for the operation and development of our business and do not anticipate paying any cash dividends on our common stock in the foreseeable future. Payment of any future dividends will be at the discretion of our Board of Directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our current bank loan prohibits us from paying cash dividends on our common stock without written permission. Securities Authorized for Issuance Under Compensation Plans The following table includes certain information about our Employee Incentive Stock Plan as of March 31, 2021, which has been approved by our stockholders. Number of Shares Authorized for Issuance under Plan Number of Shares to be Issued upon Exercise of Outstanding Options Weighted Average Exercise Price of Outstanding Options Number of Shares Remaining Available for Future Issuance under Plan 2009 Plan 200,000 115,000 $ 5.38 - 2019 Plan 200,000 41,000 3.34 159,000 Total 400,000 156,000 $ 5.28 159,000 Issuer Repurchases In September 2020, the Board of Directors authorized the use of up to $250,000 to repurchase shares of our common stock for the treasury account. This program does not have an expiration date. Under the repurchase program, shares of common stock may be purchased from time to time through open market purchases or other transactions. The amount and timing of repurchases will be subject to the availability of stock, prevailing market conditions, the trading price of the stock, our financial performance and other conditions. Repurchases may also be made from time-to-time in connection with the settlement of our share-based compensation awards. Repurchases will be funded from cash flow from operations. There were no shares of our common stock repurchased for the treasury account during the fiscal years ended March 31, 2021 and 2020. ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA Not applicable. ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-K. Liquidity and Capital Resources and Commitments Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our primary financial resource is our base of oil and gas reserves. We have pledged our producing oil and gas properties to secure our credit facilty. We do not have any delivery commitments to provide a fixed and determinable quantity of our oil and gas under any existing contract or agreement. 21 Due to the current commodity price environment, we are applying financial discipline to all aspects of our business. In order to meet obligations and to optimize allocation of resources, we may continue to sell non-core assets. Our long-term strategy is on increasing profit margins while concentrating on obtaining reserves with low-cost operations by acquiring and developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and working interests and non-operated properties in areas with significant development potential. Cash Flows Changes in the net funds provided by or (used in) each of our operating, investing and financing activities are set forth in the table below: For the Years Ended March 31, 2021 2020 % Difference Net cash provided by operating activities 710,047 864,960 (18 )% Net cash used in investing activities (1,387,624 ) (1,741,565 ) (20 )% Net cash provided by financing activities 701,009 782,734 (10 )% Cash Flow Provided by Operating Activities. Cash flow from operating activities is primarily derived from the production of our crude oil and natural gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances. Cash flow provided by our operating activities for the year ended March 31, 2021 was $710,047 in comparison to $864,960 for the year ended March 31, 2020. Changes in our cash flow operating activities for the year ended March 31, 2021 in comparison to the year ended March 31, 2020 were ($154,913) and consisted of an increase in our non-cash expenses of $4,979; an increase in our accounts receivable of $431,992; an increase of $48,052 in our accounts payable and accrued expenses; a decrease in other assets of $30.421; and, an increase in our net income for the current year compared to a net loss the prior year of $255,410. Variations in cash flow from operating activities may impact our level of exploration and development expenditures. Our expenditures in operating activities consist primarily of drilling expenses, production expenses and engineering services. Our expenses also consist of employee compensation, accounting, insurance and other general and administrative expenses that we have incurred in order to address normal and necessary business activities of a public company in the crude oil and natural gas production industry. Cash Flow Used in Investing Activities. Cash flow from investing activities is derived from changes in oil and gas property balances. For the year ended March 31, 2021, we had net cash of $1,337,624 used for additions to oil and gas properties and a $50,000 investment in a limited liability company compared to $1,591,565 and $150,000, respectively, for the year ended March 31, 2020. Cash Flow Provided by Financing Activities. Cash flow from financing activities is derived from our changes in long-term debt and in equity account balances. Cash flow provided by our financing activities was $701,009 for the year ended March 31, 2021 compared to $782,734 for the year ended March 31, 2020. During the years ended March 31, 2021 and 2020, we received advances of $935,000 and $1,285,000, respectively, from our credit facility. For the year ended March 31, 2021 and March 31, 2020, we made payments of $550,000 and $490,000, respectively, on the credit facility. For the year ended March 31, 2021, we received proceeds of $247,435 for the exercise of employee and director stock options and $68,574 under the paycheck protection program (PPP). Accordingly, net cash increased $23,432, leaving cash and cash equivalents on hand of $57,813 as of March 31, 2021. We had working capital of $618,960 as of March 31, 2021 compared to working capital of $186,785 as of March 31, 2020, an increase of $409,849 for the reasons set forth below. 22 Oil and Natural Gas Property Development The Company participated in the drilling and completion of 22 horizontal wells at a cost of approximately $1,030,000 for the fiscal year ending March 31, 2021, of which 12 have not been completed. All of these horizontal wells are in the Delaware Basin located in the western portion of the Permian Basin in Lea and Eddy Counties, New Mexico. In addition to the above working interests, there were 57 gross wells (.13 net wells) drilled by other operators on Mexco’s royalty interests, Participations in Fiscal 2021. Mexco participated in the drilling and completion of two horizontal wells in the Wolfcamp formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico with aggregate costs of approximately $233,000. These wells were completed in September 2020 with initial average production rates of 1,224 barrels of oil, 4,881 barrels of water and 3,422,000 cubic feet of gas per day, or 1,794 barrels of oil equivalent per day. Mexco’s working interest in these wells is 1.2%. Mexco participated in the drilling and completion of four horizontal wells in the Wolfcamp formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico with aggregate costs of approximately $370,000. Mexco’s working interest in these wells is 1.2%. These wells were completed in March and April 2021 with initial average production rates of 1,044 barrels of oil, 4,686 barrels of water and 2,898,000 cubic feet of gas per day, or 1,527 barrels of oil equivalent per day. Mexco expended $271,000 to participate in the drilling and completion of five horizontal wells in the Upper Avalon formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .5%. These wells were completed in February 2021 with initial average production rates of 1,126 barrels of oil, 2,036 barrels of water and 2,108,000 cubic feet of gas per day, or 1,477 barrels of oil equivalent per day. Mexco participated in the drilling of two horizontal wells in the Wolfcamp formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico with aggregate costs of approximately $74,000. Mexco’s working interest in these wells is 1.2%. Subsequently, in April 2021, Mexco expended another $108,000 to complete these wells. The Company expended $28,500 for its share to participate in the drilling and completion of two horizontal wells in the 3rd Bone Spring Sand formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .1%. Subsequently, these wells were completed in April 2021 with initial average production rates of 1,225 barrels of oil, 3,891 barrels of water and 2,905,000 cubic feet of gas per day, or 1,709 barrels of oil equivalent per day. Also in April 2021, the Company expended $11,400 to participate in the drilling of two additional wells on this acreage. Mexco invested approximately $49,000 in the drilling of four horizontal wells in the Upper and Middle Wolfcamp formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .36%. These wells are planned to be drilled during fiscal 2022. Mexco participated in the drilling of four horizontal wells in the Wolfcamp formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico with aggregate costs of approximately $67,000. Mexco’s working interest in these wells is .56%. Subsequently, in May 2021, Mexco expended approximately $109,000 to complete these wells. The Company also participated in the drilling and completion of three vertical wells in Winkler County, Texas at an aggregate cost of $12,400. Mexco’s working interest in these wells is .41%. These wells, operated by Blackbeard Operating, LLC are currently producing. Completion of Wells Drilled in Fiscal 2020. The Company expended approximately $270,000 which was the balance of the completion costs of 22 horizontal wells located in Lea and Eddy Counties, New Mexico which were drilled during fiscal 2020. As of January 2021, all of these wells have been completed and are currently producing. 23 Sales of Properties. Effective July 1, 2020, the Company sold its interest in the deep rights of a property in Martin County, Texas for a cash payment of $100,000. Participations Subsequent to Fiscal 2021. In May 2021, Mexco expended approximately $28,000 to participate in the drilling of two horizontal wells in the Wolfcamp Sand formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .37%. In May 2021, Mexco expended approximately $70,000 to participate in the drilling of four horizontal wells in the Lower Wolfcamp Shale of the Delaware Basin in Eddy County, New Mexico. Mexco’s working interest in these wells is .44%. We are participating in other projects and are reviewing projects in which we may participate. The cost of such projects would be funded, to the extent possible, from existing cash balances and cash flow from operations. The remainder may be funded through borrowings on the credit facility and, if appropriate, sales of non-core properties. Markets. Crude oil and natural gas prices generally remained volatile during the last year. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, in the last twelve months, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of negative $41.25 per bbl in April 2020 to a high of $62.07 per bbl in March 2021. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. On March 31, 2021 the WTI posted price for crude oil was $55.14 per bbl and the Henry Hub spot price for natural gas was $2.52 per MMBtu. See Results of Operations below for realized prices. Results of Operations Fiscal 2021 Compared to Fiscal 2020 We had net income of $155,932 for the year ended March 31, 2021 compared to a net loss of $99,478 for the year ended March 31, 2020. This is primarily the result of an increase in natural gas sales and a decrease in operating expenses partially offset by a decrease in oil sales as further explained below. Oil and natural gas sales. Revenue from oil and natural gas sales was $2,773,779 for the year ended March 31, 2021, a 2% increase from $2,720,353 for the year ended March 31, 2020. This resulted from an increase in oil and natural gas production and an increase in natural gas prices partially due to improved availability of pipeline capacities of natural gas. This increase was partially offset by a decrease in oil prices. The following table sets forth our oil and natural gas revenues, production quantities and average prices received during the fiscal years ended March 31: 2021 2020 % Difference Oil: Revenue $ 2,028,792 $ 2,310,127 (12.1 )% Volume (bbls) 50,327 44,301 13.6 % Average Price (per bbl) $ 40.31 $ 52.15 (22.7 )% Gas: Revenue $ 744,987 $ 410,226 81.6 % Volume (mcf) 324,205 294,007 10.3 % Average Price (per mcf) $ 2.30 $ 1.40 64.3 % Production and exploration. Production costs were $871,963 in fiscal 2021, a 5% decrease from $914,649 in fiscal 2020. This was primarily the result of a decrease in lease operating expenses due to numerous wells being shut-in during the month of May 2020 as well as cost cutting measures being implemented by the operators because of the depressed oil prices. 24 Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $906,361 in fiscal 2021, a 6% increase from $853,801 in fiscal 2020. This was primarily due to an increase in oil and gas production and a decrease in oil and gas reserves partially offset by a decrease in the full cost pool amortization base. General and administrative expenses. General and administrative expenses were $833,431 for the year ended March 31, 2021, a 17% decrease from $1,006,531 for the year ended March 31, 2020. This was primarily due to a decrease in salaries, contract services, engineering fees and accounting fees. Interest expense. Interest expense was $53,232 in fiscal 2021, a 41% increase from $37,656 in fiscal 2020, due to an increase in borrowings partially offset by a decrease in interest rate. PPP loan forgiveness . PPP loan forgiveness in the amount of $68,957 for the fiscal year ended March 31, 2021 was for the forgiveness of our PPP loan in the amount of $68,574 and $383 in accrued interest expense. The Company received the proceeds for this loan in May 2020 and applied for and received loan forgiveness in November 2020. Income taxes. There was no federal income tax for fiscal 2021 or fiscal 2020. The effective tax rate for fiscal 2021 and fiscal 2020 was 0%. We are in a net deferred tax asset position and believe it is more likely than not that these deferred tax assets will not be realized. Contractual Obligations We have no off-balance sheet debt or unrecorded obligations and have not guaranteed the debt of any other party. The following table summarizes future payments we are obligated to make based on agreements in place as of March 31, 2021: Payments due in: Total less than 1 year 1 - 3 years over 3 years Contractual obligations: Secured bank credit facility (1) $ 1,180,000 $ - $ 1,180,000 $ - Leases (2) $ 21,965 $ 21,965 $ - $ - (1) These amounts represent the balances outstanding under the bank credit facility. This repayment assumes that interest will be paid on a monthly basis, no additional funds will be drawn and does not include estimated interest $44,250 less than 1 year, and $44,250 1-3 years. (2) The lease amount represents the monthly rent amount for our principal office space in Midland, Texas under one three-year lease agreement effective May 15, 2018. Of this total obligation for the remainder of the lease, our majority shareholder will pay $5,393 for his portion of the shared office space. Alternative Capital Resources Although we have primarily used cash from operating activities, the sales of assets and funding from the credit facility as our primary capital resources, we have in the past, and could in the future, use alternative capital resources. These could include joint ventures, carried working interests and issuances of our common stock through a private placement or public offering. Other Matters Critical Accounting Policies and Estimates In preparing financial statements, management makes informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to litigation, environmental liabilities, income taxes, fair value and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. 25 The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain. Full Cost Method of Accounting for Crude Oil and Natural Gas Activities . SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in crude oil and natural gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the sale would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of crude oil and natural gas properties are generally calculated on a well by well or lease or field basis versus the “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of crude oil and natural gas properties under the successful efforts method. As a result our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher DD&A rate on our crude oil and natural gas properties. At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. However, the full cost method makes us more susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. Our crude oil and natural gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from the full cost method of accounting. Ceiling Test . Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after-tax present value of the future net cash flows from proved crude oil and natural gas reserves plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce our stockholders’ equity and reported earnings. The risk that we will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or if purchasers cancel long-term contracts for natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the subsequent period. Estimates of our proved reserves are based on the quantities of oil and gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our reserve estimates and the projected cash flows are derived from these reserve estimates, in accordance with SEC guidelines by an independent engineering firm based in part on data provided by us. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgment of the persons preparing the estimate. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. 26 It should not be assumed that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, the cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future production using the average price over the prior 12-month period. The estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost projects. Use of Estimates . In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining year end proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of our oil and natural gas reserves, which is used to compute DD&A and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results. Excluded Costs . Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the DD&A pool). Impairments transferred to the DD&A pool increase the DD&A rate. Revenue Recognition - Revenue from Contracts with Customers. Revenues from our royalty and non-operated working interest properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to four months after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. The Company records transportation and processing costs that are incurred after control of its product has transferred to the customer as a reduction of “Natural gas sales” on the Consolidated Statement of Operations. Asset Retirement Obligations . The estimated costs of plugging, restoration and removal of facilities are accrued. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated by the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement in the full cost amortization base and amortize these costs as a component of our depletion expense. Gas Balancing . Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when our excess takes of natural gas volumes exceed our estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where Mexco has taken less than its ownership share of gas production (under produced). Stock-based Compensation . We use the Binomial option pricing model to estimate the fair value of stock-based compensation expenses at grant date. This expense is recognized as compensation expense in our financial statements over the vesting period. We recognize the fair value of stock-based compensation awards as wages in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting period. 27 Accounts Receivable. Our accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer’s financial condition and, generally, is uncollateralized. Accounts receivable under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is completed. The collectability of receivables is assessed and an allowance is made for any doubtful accounts. The allowance for doubtful accounts is determined based on our previous loss history. Income Taxes . The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded as interest expense and general and administrative expense, respectively. Other Property and Equipment . Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of three to ten years. Investments. The Company accounts for investments of less than 1% in limited liability companies using the cost method. The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from the investment is received, it is immediately recognized on the consolidated statements of operations. Leases. The Company determines an arrangement is a lease at inception. Operating leases are recorded in operating lease right-of-use asset, operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheets. Operating lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate, the Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The incremental borrowing rate used at adoption was 6.0%. Significant judgement is required when determining the incremental borrowing rate. The Company chose not to discount because the difference is not significant. Rent expense for lease payments is recognized on a straight-line basis over the lease term. Recent Accounting Pronouncements. In December 2019, the FASB issued ASU No. 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes” (“ASU 2019-12”), which simplifies various aspects of the income tax accounting guidance in ASC 740, including requirements related to the following: (i) hybrid tax regimes; (ii) the tax basis step-up in goodwill obtained in a transaction that is not a business combination; (iii) separate financial statements of entities not subject to tax; (iv) the intraperiod tax allocation exception to the incremental approach; (v) ownership changes in investments - changes from a subsidiary to an equity method investment (and vice versa); (vi) interim-period accounting for enacted changes in tax laws; and (vii) the year-to-date loss limitation in interim-period tax accounting. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years and early adoption is permitted. If an entity early adopts these amendments in an interim period, it should reflect any adjustments as of the beginning of the annual period that includes that interim period. In addition, an entity that elects to early adopt ASU 2019-12 is required to adopt all of the amendments in the same period. The Company adopted ASU 2019-12 on April 1, 2021 and it will not have a material impact on its financial position, results of operations and disclosures.