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 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 facility. 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. 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, 2025 2024 Change Net cash provided by operating activities $ 4,269,621 $ 4,433,935 $ (164,314 ) Net cash used in investing activities $ (4,154,575 ) $ (3,416,499 ) $ 738,076 Net cash used in financing activities $ (834,575 ) $ (779,723 ) $ 54,852 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, 2025 was $4,269,621 in comparison to $4,433,935 for the year ended March 31, 2024. This decrease of $164,314 in our cash flow operating activities consisted of increase in our non-cash expenses of $156,176; an increase in our accounts receivable of $533,564; an increase of $52,861 of our accounts payable and accrued expenses; and, an increase in our net income for the current year of $367,416. 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, 2025, we had net cash of $3,154,575 used for additions to oil and gas properties and a $1,000,000 investment in two limited liability companies compared to $3,016,499 and $400,000, respectively, for the year ended March 31, 2024. Cash Flow Used in Financing Activities. Cash flow from financing activities is derived from our changes in long-term debt and in equity account balances. Net cash flow used in our financing activities was $834,575 for the year ended March 31, 2025 compared to net cash flow used in our financing activities of $779,723 for the year ended March 31, 2024. During the year ended March 31, 2025, we expended $209,000 to pay the annual dividend, expended $703,216 to purchase 57,766 shares of our stock for the treasury account, and received proceeds of $77,641 for the exercise of employee stock options. During the year ended March 31, 2024, we expended $213,600 to pay the annual dividend, expended $585,035 to purchase 50,101 shares of our stock for the treasury account, and received proceeds of $19,662 for the exercise of employee and director stock options. 23 Accordingly, net cash decreased $719,529, leaving cash and cash equivalents on hand of $1,753,955 as of March 31, 2025. We had working capital of $2,469,664 as of March 31, 2025 compared to working capital of $3,259,200 as of March 31, 2024, a decrease of $789,536 for the reasons set forth below. Oil and Natural Gas Property Development. New Participations in Fiscal 2025. The Company participated in the development of 35 horizontal wells at a cost of approximately $1,100,000 for the year ending March 31, 2025. Seventeen of these wells have not been completed. Twenty-nine of these wells are in the Delaware Basin located in the western portion of the Permian Basin in Lea and Eddy Counties, New Mexico; three wells are in the Midland Basin located in the eastern portion of the Permian Basin in Reagan County, Texas; and, the remaining three horizontal wells are in Grady County, Oklahoma. In addition to the above working interests, there were 120 gross wells (.09 net wells) drilled by other operators on Mexco’s royalty interests and 840 gross wells (2.31 net wells) obtained through acquisitions. Mexco expended approximately $207,000 to participate in the drilling of five horizontal wells in the Bone Spring formation of the Delaware Basin in Lea County, New Mexico. In November 2024, these wells were completed with initial average production rates of 1,106 barrels of oil, 2,583 barrels of water and 1,165,000 cubic feet of gas per day, or 1,300 BOE per day. Mexco expended approximately $293,000 to drill and complete four horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico. In November 2024, these wells were completed with initial average production rates of 1,089 barrels of oil, 4,716 barrels of water and 3,601,000 cubic feet of gas per day, or 1,689 BOE per day. Mexco expended approximately $117,000 for the drilling and completion of two horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .5%. In March 2025, these wells were completed with initial average production rates of 1,734 barrels of oil, 3,171 barrels of water and 3,229,000 cubic feet of gas per day, or 2,272 BOE per day. Mexco expended approximately $176,000 for the drilling and completion of two horizontal wells in the Penn Shale formation of the Delaware Basin in Lea County, New Mexico. Mexco’s average working interest in these wells is .5%. Subsequently, in June 2025, one of these wells were completed with initial average production rates of 676 barrels of oil, 1,899 barrels of water and 729,000 cubic feet of gas per day, or 798 BOE per day Mexco expended approximately $46,000 for the drilling of two horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .28%. Mexco expended approximately $70,000 to participate in the drilling of six horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .16%. Subsequently, in May 2025, Mexco expended approximately $85,000 to complete these wells. Mexco expended approximately $70,000 to participate in the development of three horizontal wells in the Spraberry trend of the Midland Basin in Reagan County, Texas. Mexco’s working interest in these wells is approximately .26%. Mexco expended approximately $32,000 to participate in an exploratory well in the Fusselman Formation of Irion County, Texas. This well was determined to be noncommercial and was plugged and abandoned. In October 2022, the Company made an approximately 2% equity investment commitment in a limited liability company amounting to $2,000,000 of which $1,800,000 has been funded as of March 31, 2025. The limited liability company is capitalized at approximately $100 million to purchase mineral interests in the Utica and Marcellus areas in the state of Ohio. This LLC has returned $252,394 or 14% of the total investment. 24 Completion of Wells Drilled in Fiscal 2024. The Company expended approximately $300,000 for the completion of 19 horizontal wells in which the Company participated during fiscal 2024. The Company expended approximately $107,000 for the completion costs of two horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico that the Company participated in drilling during fiscal 2024. Mexco’s working interest in these wells is .53%. In July 2024, these wells were completed with initial average production rates of 1,402 barrels of oil, 2,009 barrels of water and 2,168,000 cubic feet of gas per day, or 1,763 BOE per day. Five horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico in which the Company participated during fiscal 2024 were completed in April 2024 with initial average production rates of 732 barrels of oil, 1,481 barrels of water and 657,000 cubic feet of gas per day, or 842 of oil equivalent per day. Mexco’s working interest in these wells is approximately 1.16%. A horizontal well in the Penn Shale formation of the Delaware Basin in Lea County, New Mexico was completed in May 2024 with the initial production rate of 964 barrels of oil, 2,441 barrels of water and 626,000 cubic feet of gas per day, or 1,068 of oil equivalent per day. Mexco’s working interest in this well is .165%. The Company expended approximately $207,000 for the completion costs of four horizontial wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico that the Company participated in drilling during fiscal 2024. Mexco’s working interest in these wells is .45%. In October 2024, these wells were completed with initial average production rates of 893 barrels of oil, 2,990 barrels of water and 1,161,000 cubic feet of gas per day, or 1,087 BOE per day. Acquisitions. In April 2024, the Company acquired royalty interests in 21 producing wells operated by Anadarko Petroleum Corporation and Cimarex Energy Company and located in Reeves County, Texas, for a purchase price of $158,000. In August 2024, the Company acquired royalty interests in 6 producing wells operated by Marathon Oil and located in Karnes County, Texas, for a purchase price of $50,000. This acquisition was effective August 1, 2024. In August 2024, the Company acquired royalty interests in 10 producing wells operated by Anadarko Petroleum Corporation and located in Weld County, Colorado, for a purchase price of $118,000 and royalty interests in approximately 250 producing wells operated by Samson Exploration, EOG Resources, and others in Laramie County, Wyoming and Adams and Weld Counties, Colorado, for a purchase price of $483,000. All of these acquisitions were effective September 1, 2024. In September 2024, the Company acquired royalty interests in 21 producing wells operated by Marathon Oil and Murphy Exploration and located in Karnes County, Texas, for a purchase price of $90,000, effective August 1, 2024. In October 2024, the Company acquired a .3% royalty interest in 15 producing wells operated by Civitas Resources, Inc. and located in Broomfield and Adams Counties, Colorado, for a purchase price of $450,000. This acquisition was effective November 1, 2024. In October 2024, the Company acquired a .5% royalty interest in 3 producing wells operated by Mewbourne Oil Company and located in Eddy County, New Mexico, for a purchase price of $260,000. This acquisition was effective November 1, 2024 and includes acreage for further development. In October 2024, the Company acquired royalty interests in 8 producing wells operated by Marathon Oil and located in Live Oak County, Texas, for a purchase price of $20,000; royalty interests in 6 producing wells operated by SWN Production Company, LLC and located in DeSoto Parish, Louisiana, for a purchase price of $25,000; royalty interests in 10 producing wells operated by Ovintiv, Inc. and located in Upton County, Texas, for a purchase price of $65,000; and, royalty interests in 12 producing wells operated by Pioneer Natural Resources and located in Reagan and Upton Counties, Texas, for a purchase price of $65,000. All of these acquisitions were effective November 1, 2024. 25 Also, in October 2024 and effective November 1, 2024, the Company acquired various small royalty interests in over 400 producing wells operated by Petro-Hunt Corporation, Hess Bakken Investments II, LLC, Marathon Oil, WPX Energy, and others in multiple counties throughout the states of Nebraska, North Dakota, South Dakota, and Montana for a purchase price of $188,000. Sale of Properties. In November 2024, the Company conveyed its working and royalty interests in 13.5 net acres in Ward County, Texas. The Company received $15,000 per acre in the total amount of $202,500. The Company retained an overriding royalty interest equal to the positive difference between 25% and any existing burdens of record as of the effective date. The divestiture of this non-core oil and gas asset did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as sales proceeds, a reduction of its full cost pool, with no gain or loss recognized on the sale. 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 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 $61.73 per bbl in September 2024 to a high of $82.89 per bbl in April 2024. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $1.21 per MMBtu in November 2024 to a high of $9.86 per MMBtu in January 2025. On March 31, 2025 the WTI posted price for crude oil was $67.46 per bbl and the Henry Hub spot price for natural gas was $4.11 per MMBtu. See Results of Operations below for realized prices. Pipeline capacity constraints and maintenance in the Permian Basin area has contributed to a wider difference between the WaHa Hub and the Henry Hub and at times realized prices were negative. Results of Operations Fiscal 2025 Compared to Fiscal 2024 We had net income of $1,712,368 for the year ended March 31, 2025 compared to $1,344,952 for the year ended March 31, 2024, a 27% increase primarily as a result of an increase in operating revenues partially offset by an increase in operating expenses that is further explained below. Oil and natural gas sales. Revenue from oil and natural gas sales was $7,116,485 for the year ended March 31, 2025, a 10% increase from $6,462,647 for the year ended March 31, 2024. This resulted from an increase in oil and natural gas production volumes partially offset by a decrease in oil and natural gas 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: 2025 2024 % Difference Oil: Revenue $ 6,145,674 $ 5,348,257 14.9 % Volume (bbls) 83,564 69,999 19.4 % Average Price (per bbl) $ 73.54 $ 76.40 (3.7 )% Gas: Revenue $ 970,811 $ 1,114,390 (12.9 )% Volume (mcf) 570,012 502,879 13.3 % Average Price (per mcf) $ 1.70 $ 2.22 (23.3 )% Other operating revenues. Other revenues increased 70% to $241,581 in fiscal 2025 from $142,237 in fiscal 2024. This resulted from an increase in income from one of our limited liability company investments. 26 Interest income. Interest income on corporate funds decreased 46% to $72,629 in fiscal 2025 from $135,476 in fiscal 2024. This decrease resulted from using the corporate funds for property acquisitions and purchase of treasury stock. Production and exploration. Production costs were $1,605,096 in fiscal 2025, a 5% increase from $1,526,472 in fiscal 2024. This is the result of an increase in production taxes due to an increase in oil and gas revenues and an increase in lease operating expenses on new wells in which we own an interest. Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $2,452,694 in fiscal 2025, a 25% increase from $1,969,742 in fiscal 2024. This was primarily due to an increase in oil and natural gas production and a decrease in oil and natural gas reserves. General and administrative expenses. General and administrative expenses were $1,320,074 for the year ended March 31, 2025, a 6% increase from $1,243,548 for the year ended March 31, 2024. This was primarily due to an increase in salaries and contract services, office expense, engineering services and legal expenses partially offset by a decrease in employee stock option compensation. Income taxes. Income tax for fiscal 2025 was $304,330 compared to $620,544 for fiscal 2024. This was primarily due to a decrease in state income taxes and the reconciliation to the federal tax return. The effective tax rate for state and federal taxes combined for fiscal 2025 and fiscal 2024 was 15% and 32%, respectively. The decrease in the effective tax rate is primarily the result of state income taxes, primarily in New Mexico, the impact of permanent differences between book and taxable income, and the reconciliation to the federal tax return. 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, 2025: Payments due in: Total less than 1 year 1 - 3 years over 3 years Contractual obligations: Leases (1) $ 140,747 $ 60,320 80,427 $ - (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 less than 1 year and $13,567 1-3 years 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. 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. 27 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. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of 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, Bill of Sales 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 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 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 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. 28 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. 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 its revenue estimates and actual revenue received historically have not been significant. 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. 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. 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. 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. 29 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 3% of any limited liability companies at cost. The Company has no control of the limited liability companies. 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. The Company evaluates investments for an impairment whenever events or changes in circumstances indicate that the carrying amount of an investment may not be recoverable. Indicators of impairment may include, but are not limited to, sustained declines in market value, investee financial condition and operating performance, industry or economic trends, and other relevant factors. 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. Based on the Company’s organizational structure, the Company has one operating segment, which is crude oil and natural gas development, exploration and production. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise. 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 9%. Significant judgement is required when determining the incremental borrowing rate. Rent expense for lease payments is recognized on a straight-line basis over the lease term. Recently Adopted Accounting Pronouncements. In December 2023, the FASB issued ASU 2023-09, Topic 740 Income Taxes: Improvements to Income Tax Disclosures, which is intended to enhance the transparency and decision usefulness of income tax disclosures. The amendments in this standard provide for enhanced income tax information primarily through changs to the rate reconciliation and income taxes paid. This ASU is effective for fiscal years beginning after December 15, 2024. 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. 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.