MEXCO ENERGY CORP 10-K

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 activities through cash flows from operating activities, borrowings under our credit facility, sales of non-core properties, and issuances of common stock. Our primary source of long-term value is our oil and gas reserve base. Our producing oil and gas properties are pledged as collateral under our credit facility. We do not have any contractual commitments to deliver fixed quantities of our oil and gas under existing agreements. Our long-term strategy is to increase profit margins by focusing on acquiring and developing oil and gas properties with low-cost operations and the potential for long-lived production. We focus our efforts on the acquisition of royalties and non-operated working interests in areas with significant development potential. 21 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, 2026 2025 Change Net cash provided by operating activities $ 3,779,152 $ 4,269,621 $ (490,469 ) Net cash used in investing activities $ (2,540,161 ) $ (4,154,575 ) $ 1,614,414 Net cash used in financing activities $ (216,970 ) $ (834,575 ) $ 617,605 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, 2026 was $3,779,152 in comparison to $4,269,621 for the year ended March 31, 2025. This decrease of $490,469 in our cash flow from operating activities consisted of an increase in our non-cash expenses of $245,850; a decrease in income tax payable of $179,147; an increase in our accounts receivable of $47,152; a decrease of $102,146 of our accounts payable and accrued expenses, and a decrease in our net income for the current year of $406,646. Variations in cash flow from operating activities may affect 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 include employee compensation, accounting, insurance, and other general and administrative expenses incurred to support the 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, 2026, net cash used for additions to oil and gas properties, net of drilling refunds and proceeds from property sales, was $2,109,157 compared to $3,154,575 in fiscal 2025. Cash used for an investment in a limited liability company was $427,429, compared to $1,000,000 in fiscal 2025. Cash Flow Used in Financing Activities. Cash flow from financing activities is derived from changes in long-term debt and in equity account balances. Net cash flow used in our financing activities was $216,970 for the year ended March 31, 2026, compared to $834,575 for the year ended March 31, 2025. During the year ended March 31, 2026, we expended $204,600 to pay the annual dividend and $12,370 to amend our credit facility. During the year ended March 31, 2025, we expended $209,000 to pay the annual dividend and $703,216 to purchase 57,766 shares of our stock for the treasury account, and received proceeds of $77,641 from the exercise of employee stock options. Accordingly, net cash increased $1,022,021, leaving cash and cash equivalents on hand of $2,775,976 as of March 31, 2026. We had working capital of $3,995,456 as of March 31, 2026, compared to $2,469,664 as of March 31, 2025, an increase of $1,525,792 for the reasons set forth below. Oil and Natural Gas Property Development New Participations in Fiscal 2026. The Company participated in the development of 57 horizontal wells and one vertical well at a cost of approximately $1,250,000 for the year ending March 31, 2026. Twenty of these wells have not been completed. Fifty-one of these wells are in the Delaware Basin located in the western portion of the Permian Basin in Lea and Eddy Counties, New Mexico. The remaining wells are in Glasscock, Midland, and Ward Counties, Texas. In addition to the above working interests, there were 177 gross wells (.07 net wells) drilled by other operators on Mexco’s royalty interests and 261 gross wells (.12 net wells) obtained through acquisitions. 22 Mexco expended approximately $230,000 to participate in the drilling and completion of five horizontal wells in the Bone Spring formation of the Delaware Basin in Eddy County, New Mexico. In November 2025, two of these wells were completed with initial average production rates of 1,194 barrels of oil, 2,924 barrels of water, and 1,819,000 cubic feet of gas per day, or 1,497 BOE per day. In February 2026, the remaining three wells were completed with initial average production rates of 974 barrels of oil, 2,971 barrels of water, and 1,417,000 cubic feet of gas per day, or 1,210 BOE per day. Mexco’s working interest in these wells is .5%. Mexco expended approximately $79,000 to drill and complete two horizontal wells in the Bone Spring formation of the Delaware Basin in Lea County, New Mexico. In August 2025, these wells were completed with initial average production rates of 741 barrels of oil, 3,276 barrels of water, and 1,110,000 cubic feet of gas per day, or 926 BOE per day. Mexco’s working interest in these wells is .3%. Mexco expended approximately $155,000 to participate in the drilling and completion of three horizontal wells in the Wolfcamp Sand Formation of the Delaware Basin in Lea County, New Mexico. In December 2025, these wells were completed with initial average production rates of 827 barrels of oil, 3,483 barrels of water, and 2,354,000 cubic feet of gas per day, or 1,219 BOE per day. Mexco’s working interest in these wells is .52%. Mexco expended approximately $65,000 to participate in an exploratory vertical well in the Ellenburger formation of Ward County, Texas. In November 2025, this well was determined to be noncommercial. In December 2025, Mexco expended approximately $406,000 to participate in the drilling and completion of two horizontal development wells in the Wolfcamp XY formation of the Delaware Basin in Eddy County, New Mexico. Mexco’s working interest in these wells is 2.1%. In December 2025, Mexco expended approximately $46,000 to participate in the drilling and completion of six horizontal wells in the Bone Spring formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .04%. In March 2026, Mexco expended approximately $200,000 to participate in the drilling and completion of five horizontal wells in the Wolfcamp B formation in the Spraberry trend area of the Midland Basin in Midland and Glasscock Counties, Texas. Mexco’s working interest in these wells is 1.9%. Subsequently, in May 2026, the Company expended an additional approximately $35,000 for these wells. Subsequently, in May 2026, Mexco expended approximately $460,000 to participate in the drilling and completion of six horizontal wells in the Wolfcamp A formation of the Delaware Basin in Reeves County, Texas. Mexco’s working interest in these wells is .8%. Completion of Wells Drilled in Fiscal 2025. The Company expended approximately $150,000 to complete seventeen horizontal wells in which the Company participated during fiscal 2025. These wells, located in the Delaware Basin of Lea County, New Mexico, have been completed and turned to production. Investments. In October 2022, the Company made an approximately 2% equity investment commitment in a limited liability company amounting to $2,000,000, which was fully funded as of July 2025. The limited liability company is capitalized at approximately $100 million to acquire mineral interests in the Utica and Marcellus formations in the state of Ohio. In October 2025, the Company expended $200,000 to exercise its option to participate in a voluntary optional cash call to increase its capitalized investment. In December 2025, the Company expended an additional $27,429 to exercise its option to acquire its share of the non-consenting interests from the October cash call. As of March 31, 2026, this LLC has returned $558,216, or 25% of the total investment. Acquisitions. In May 2025, the Company acquired royalty (mineral) interests in 2 wells operated by Chevron Corporation in Pecos County, Texas for a purchase price of $40,000. This acquisition was effective April 1, 2025 and includes acreage for future development. In August 2025, the Company acquired royalty interests in 12 producing wells operated by Diamondback Energy, Inc. in Martin County, Texas for a purchase price of $60,300 and royalty interests in 25 wells operated by Chevron Corporation in Weld County, Colorado for a purchase price of $26,300. These acquisitions were effective September 1, 2025. 23 In October 2025, the Company acquired royalty interests in 3 producing wells operated by Expand Energy Corporation in Caddo Parish, Louisiana for a purchase price of $31,300; royalty interests in 14 producing wells operated by Diamondback Energy, Inc. in Martin County, Texas for a purchase price of $44,300; royalty interests in 3 producing wells operated by Permian Resources Corporation in Eddy County, New Mexico for a purchase price of $6,800; and overriding royalty interests in 4 producing wells operated by Tap Rock Resources in Eddy County, New Mexico for a purchase price of $240,300. These acquisitions were effective November 1, 2025. In December 2025, the Company acquired royalty interests in 14 producing wells operated by Occidental Petroleum Corporation in Weld County, Colorado for a purchase price of $35,300; royalty interests in approximately 4 producing wells operated by SM Energy Company in Howard County, Texas for a purchase price of $100,600; and royalty interests in 11 producing wells operated by Ovintiv Inc. in Martin County, Texas for a purchase price of $18,300. These acquisitions were effective December 1, 2025. Also in December 2025, the Company acquired additional royalty interests in the 3 producing wells operated by Expand Energy Corporation in Caddo Parish, Louisiana for a purchase price of $22,300 and effective January 1, 2026. In January 2026, the Company acquired royalty interests in 3 producing wells operated by ConocoPhillips in Karnes County, Texas for a purchase price of $27,800. This acquisition is effective January 1, 2026. In February 2026, the Company acquired royalty interests in 41 producing wells operated by Occidental Petroleum Corporation and 15 producing wells operated by Bison IV Operating LLC in Weld County, Colorado, for an aggregate purchase price of $69,600; royalty interests in 29 producing wells operated by Brammer Petroleum, Sheridan Production and TGNR East Texas in Harrison and Panola Counties, Texas as well as additional interest in 19 producing wells in which we already held an interest for a purchase price of $43,100; royalty interests in 6 producing wells and additional interest in 5 producing wells operated by Aethon Energy Operating in Bienville Parish, Louisiana for a purchase price of $4,300; royalty interest in 1 producing well operated by San Juan Resources, Inc. for a purchase price of $3,800; royalty interests in 81 producing wells and additional interest in 10 producing wells in multiple counties in Louisiana and Texas for a purchase price of $41,800; and a leasehold in 40 undeveloped net acres in Eddy County, New Mexico for a purchase price of $1,500. All of these acquisitions were effective March 1, 2026. Other Projects. 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. Pricing. Crude oil and natural gas prices remained volatile over 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 $51.25 per bbl in December 2025 to a high of $98.86 per bbl in March 2025. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $2.65 per MMBtu in June and October 2025 to a high of $30.72 per MMBtu in January 2026, reflecting a temporary price spike during a period of severe weather and significant market volatility. On March 31, 2026, the WTI posted price for crude oil was $97.36 per bbl and the Henry Hub spot price for natural gas was $2.88 per MMBtu. See Results of Operations below for realized prices. Pipeline capacity constraints and maintenance in the Permian Basin area have contributed to a wider difference between the Waha Hub and the Henry Hub, and at times realized prices were negative. 24 Results of Operations Fiscal 2026 Compared to Fiscal 2025 We had net income of $1,305,722 for the year ended March 31, 2026, compared to $1,712,368 for the year ended March 31, 2025, a 24% decrease, primarily as a result of a decrease in operating revenues partially offset by a decrease in operating expenses as further explained below. Oil and natural gas sales. Revenue from oil and natural gas sales was $6,548,048 for the year ended March 31, 2026, an 8% decrease from $7,116,485 for the year ended March 31, 2025. This resulted from an increase in natural gas production volumes and natural gas prices, partially offset by a decrease in oil production volumes and 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: 2026 2025 % Difference Oil: Revenue $ 5,276,981 $ 6,145,674 (14.1 )% Volume (bbls) 82,133 83,564 (1.7 )% Average Price (per bbl) $ 64.25 $ 73.54 (12.6 )% Gas: Revenue $ 1,271,067 $ 970,811 30.9 % Volume (mcf) 681,794 570,012 19.6 % Average Price (per mcf) $ 1.86 $ 1.70 9.7 % Income from investments in LLCs . Income from investments in LLCs increased 51% to $329,102 in fiscal 2026 from $217,627 in fiscal 2025. This increase resulted primarily from higher earnings from one of the Company’s limited liability companies. Interest income. Interest income on corporate funds increased 23% to $89,341 in fiscal 2026 from $72,629 in fiscal 2025. This increase resulted from an increase in our investment fund balances. Production and exploration. Production costs were $1,428,353 in fiscal 2026, an 11% decrease from $1,605,096 in fiscal 2025. This is the result of a decrease in lease operating expenses on wells in which we own a working interest and a decrease in production taxes due to the decrease in oil and gas revenues. Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $2,523,827 in fiscal 2026, a 3% increase from $2,452,694 in fiscal 2025. This was primarily due to an increase in gas production, partially offset by an increase in gas reserves and a decrease in the full cost amortization base. General and administrative expenses. General and administrative expenses were $1,306,275 for the year ended March 31, 2026, a 1% decrease from $1,320,074 for the year ended March 31, 2025. This was primarily due to an increase in accounting and engineering services, partially offset by a decrease in contract services and employee stock option compensation. Income taxes. Income tax for fiscal 2026 was $379,043 compared to $304,330 for fiscal 2025. The combined federal and state effective tax rate for fiscal 2026 and fiscal 2025 was 22.5% and 15.1%, respectively. See Note 5 – Income Taxes to the Notes to Consolidated Financial Statements for additional information. 25 Contractual Obligations We have no off-balance sheet debt or unrecorded obligations, and we 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, 2026: Payments due in: Total less than 1 year 1 - 3 years over 3 years Contractual obligations: Leases (1) $ 80,427 $ 60,320 20,107 $ - (1) The lease amount represents the monthly rent amount for our principal office space in Midland, Texas under a 36-month lease agreement expiring July 31, 2027. Of this total obligation for the remainder of the lease, our majority shareholder will pay $10,175 within 1 year and $3,392 in years 1-3 for his portion of the shared office space. Alternative Capital Resources Although we have primarily used cash from operating activities, the sale 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. The following policies are those that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe inherently uncertain matters. 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 exclude 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. Sales of oil and natural gas properties, whether or not currently being amortized, are accounted for as adjustments to capitalized costs. 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. This includes any sales of properties such as Term Assignments and Assignments, Bills of Sale and Conveyances. 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, lease, or field basis rather than 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 those of companies that apply the successful efforts method, since we will generally reflect a higher level of capitalized costs and 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 periods of commodity price volatility 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 the impact from the full cost method of accounting. 26 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 of our oil and gas properties does not affect 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 if higher crude oil and natural gas prices 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 demonstrate, 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 actual future 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. 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 (“GAAP”), 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 consolidated financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining 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 the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization 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. Revenues from our royalty and non-operated working interest properties are recorded in accordance with ASC 606, Revenue from Contracts with Customers. Revenue is reported net of post-production costs when such costs are contractually deducted by the operator prior to distribution. Since the revenue checks are generally received two to three 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 the Company’s revenue estimates and actual revenue received historically have not been significant. 27 Asset Retirement Obligations . The Company records a liability for asset retirement obligations (“ARO”) associated with the plugging, abandonment, and remediation of oil and natural gas wells and related facilities in the period the obligation is incurred. The liability is recorded at estimated fair value, with a corresponding increase to the carrying amount of the related oil and natural gas property. The capitalized asset retirement cost is depleted using the unit-of-production method over the life of the related proved reserves. The ARO liability is measured using the present value of estimated future cash flows. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Estimating ARO requires management to make significant assumptions and judgments regarding the timing and amount of future abandonment and remediation costs, inflation rates, discount rates, and other factors. Revisions to these estimates are recorded as adjustments to both the ARO liability and the carrying amount of the related asset. Stock-based Compensation . The Company uses the Binomial option pricing model to estimate the grant-date fair value of stock-based awards. Compensation expense is recognized within general and administrative expense in the Consolidated Statements of Operations using the graded-vesting method over the applicable vesting period. Accounts Receivable. 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 is generally uncollateralized. The collectibility of receivables is assessed and an allowance is made for any credit losses. The allowance for credit losses is determined based on a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. 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 utilizes the measurement alternative to account for investments when it does not possess the ability to exercise significant influence or control and the investment does not have a readily determinable fair value. Under this method, investments are initially recognized at cost and subsequently measured at cost, adjusted for any observable changes in the fair value of the investment. In addition, the Company reviews the carrying value of investments measured under the measurement alternative for impairment on a regular basis. If there is an indication of impairment, the Company assesses whether the carrying value of the investment exceeds its recoverable amount. Any impairment losses are recognized in the consolidated statements of operations. Income from these investments is recognized as Income from investments in LLCs in the consolidated statements of operations. Reclassifications. Certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with the current period’s presentation. These reclassifications had no effect on previously reported results of operations, retained earnings, or net cash flows. Segments. The Company’s chief operating decision maker (“CODM”), comprised of the Chairman of the Board and the President, evaluates operating results and allocates capital resources on a consolidated basis. Accordingly, the Company has one reportable segment: crude oil and natural gas development, exploration, and production. 28 Leases. The Company determines that an arrangement is a lease at inception. Operating leases are recorded as an operating lease right-of-use asset, an operating lease liability, current, and an 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 the commencement date in determining the present value of lease payments. The incremental borrowing rate used at adoption was 9%. Significant judgment is required when determining the incremental borrowing rate. Rent expense for lease payments is recognized on a straight-line basis over the lease term. New Accounting Pronouncements Not Yet Adopted. In November 2024, the FASB issued ASU 2024-03, Topic 220 Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures: Disaggregation of the Income Statement Expenses. The amendments in this update require disclosure in the Company’s annual and interim consolidated financial statements of specified information about certain costs and expenses, including depletion, depreciation and amortization recognized as part of crude oil and natural gas producing activities, and employee compensation. This ASU is effective for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. While the adoption of this ASU will modify the Company’s disclosures, it will not have an impact on the Company’s financial position, results of operations, or liquidity.