PEDEVCO CORP 10-K

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “ forward-looking statements ” that reflect our future plans, estimates, beliefs and expected performance. We caution you that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “ Risk Factors ” and “ Forward-Looking Statements . ” The discussion in this section has been impacted by the restatement described in the Explanatory Note at the beginning of this Annual Report on Form 10-K and in Note 4 of the consolidated financial statements. Certain of the financial and other information provided in this Management’s Discussion and Analysis of our financial condition and results of operations has been updated to reflect the restatement adjustments. Summary of The Information Contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations Our Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is provided in addition to the accompanying consolidated financial statements and notes to assist readers in understanding our results of operations, financial condition, and cash flows. Our MD&A is organized as follows: · Overview . Discussion of our business and overall analysis of financial and other highlights affecting us, to provide context for the remainder of our MD&A. · Results of Operations . An analysis of our financial results comparing the years ended December 31, 2024 and 2023. · Liquidity and Capital Resources . An analysis of changes in our consolidated balance sheets and cash flows and discussion of our financial condition. · Critical Accounting Estimates . Accounting estimates that we believe are important to understanding the assumptions and judgments incorporated in our reported financial results and forecasts. Overview We are an oil and gas company focused on the acquisition and development of oil and natural gas assets where the latest in modern drilling and completion techniques and technologies have yet to be applied. In particular, we focus on legacy proven properties where there is a long production history, well defined geology and existing infrastructure that can be leveraged when applying modern field management technologies. Our current properties are located in the San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico and in the Denver-Julesberg Basin in Colorado and Wyoming. As of December 31, 2024, we held approximately 14,105 net Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned subsidiary, PEDCO, and which are operated by our wholly-owned operating subsidiary, RAZO, which asset we refer to as our “ Permian Basin Asset .” Also as of December 31, 2024, we held approximately 14,809 net D-J Basin acres located in Weld and Morgan Counties, Colorado, and 3,860 net D-J Basin acres located in Laramie County, Wyoming, through our wholly-owned subsidiary, PRH, and which are operated by our wholly-owned operating subsidiary, Red Hawk, which asset we refer to as our “ D-J Basin Asset .” As of December 31, 2024, we held interests in 35 gross (33.5 net) wells in our Permian Basin Asset, of which 28 gross (26.5 net) wells are active producers, five gross (five net) wells are inactive, and two gross (two net) wells are active salt water disposal wells (“ SWD’ s”), all of which are held by PEDCO and operated by RAZO, and interests in 82 gross (21.9 net) wells in our D-J Basin Asset held by PRH, all of which 17 gross (15.4 net) wells are operated by Red Hawk and currently producing, 48 gross (6.5 net) wells are non-operated, and 17 wells have an after-payout interest. Detailed information about our business plans and operations, including our core D-J Basin and Permian Basin Assets, is contained under “ Part 1 ” — “ Item 1. Business ” above. 76 Table of Contents How We Conduct Our Business and Evaluate Our Operations Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe have significant appreciation potential. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives. We will use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: · production volumes; · realized prices on the sale of oil and natural gas; · oil and natural gas production and operating expenses; · capital expenditures; · general and administrative expenses; · net cash provided by operating activities; and · net income. Reserves Our estimated net proved crude oil and natural gas reserves at December 31, 2024 and 2023 were approximately 18.1 million barrels of oil equivalent (“ MMBoe ”) and 17.0 MMBoe, respectively. The 1.1 MMBoe increase was primarily due to the addition of proved undeveloped reserves in our D-J Basin Asset as a result of increased activity around our acreage and favorable pricing. Using the average monthly crude oil price of $75.48 per barrel (“ Bbl ”) and natural gas price of $2.13 per thousand cubic feet (“ Mcf ”) for the twelve months ended December 31, 2024, our estimated discounted future net cash flow (“ PV-10 ”) for our proved reserves was approximately $178.9 million, of which approximately $104.3 million are proved undeveloped reserves. Total reserve value at December 31, 2024, represents a decrease of approximately $52.8 million or 23% from approximately $231.7 million a year earlier using the same SEC pricing and reserves methodology. The decrease is primarily attributable to commodity pricing, as the average SEC pricing for 2024, noted above, was lower than the 2023 average pricing of $78.22 per Bbl for crude oil and $2.64 per Mcf for natural gas. The reserves as of December 31, 2024 were determined in accordance with standard industry practices and SEC regulations by the licensed independent petroleum engineering firm of Cawley, Gillespie & Associates, Inc. A large portion of the proved undeveloped crude oil reserves are associated with our D-J Basin Asset. Although these hydrocarbon quantities have been determined in accordance with industry standards, they are prepared using the subjective judgments of the independent engineers and may actually be more or less. Oil and Natural Gas Sales Volumes During the year ended December 31, 2024, our net crude oil, natural gas, and NGLs sales volumes increased to 671,796 Bbls, or 1,835 barrels of oil per day (“ Bopd ”), from 520,886 Bbls, or 1,427 Bopd, a 29% increase over the previous fiscal year. The increase in production volume is related to our participation in 24 new non-operated wells (11 of which occurred in the latter four months of 2024) in the D-J Basin and the drilling and completion of three operated wells with a third-party in the Permian Basin in the latter part of Q1 2024 (see additional detail below). Significant Capital Expenditures The table below sets out the significant components of capital expenditures for the year ended December 31, 2024 (in thousands): Capital Expenditures Leasehold Acquisitions $ 862 Mineral Acquisitions 725 Drilling and Facilities 20,522 Total* $ 22,109 *see “ Item 8. Financial Statements and Supplementary Data ” - “ Note 7 - Oil and Gas Properties ”. 77 Table of Contents Market Conditions and Commodity Prices Our financial results depend on many factors, particularly the price of crude oil and natural gas and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our production volumes or revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. We expect prices to remain volatile for the remainder of the year. For information about the impact of realized commodity prices on our crude oil and natural gas and condensate revenues, refer to “ Results of Operations ” below. Results of Operations The following discussion and analysis of the results of operations for each of the two fiscal years in the years ended December 31, 2024 and 2023 should be read in conjunction with the consolidated financial statements of PEDEVCO Corp. and notes thereto included herein (see “ Item 8. Financial Statements and Supplementary Data ”). Net Income We reported net income for the year ended December 31, 2024 of $17.8 million, or $0.20 per share, compared to net income for the year ended December 31, 2023 of $1.7 million or $0.02 per share. The increase in net income of $16.1 million was primarily due to a recognition of an income tax benefit of $12.8 million (see “ Item 8. Financial Statements and Supplementary Data ” - “ Note 14 – Income Taxes ”) coupled with $8.8 million increase in revenue in the current period and a $4.3 million loss on the Milnesand Sale in the prior period, offset by a $9.5 million increase in total operating expenses in the current period, offset further by a $0.2 million decrease in other income and a $0.1 million loss on sale of oil and gas properties in the current period (all of which are discussed in more detail below). Net Revenues The following table sets forth the revenue and production data for the years ended December 31, 2024 and 2023: 2024 2023 Increase (Decrease) Increase (Decrease) Sale Volumes: Crude Oil (Bbls) 492,396 382,794 109,602 29% Natural Gas (Mcf) 608,382 479,533 128,849 27% NGL (Bbls) 78,003 58,170 19,833 34% Total (Boe) (1) 671,796 520,886 150,910 29% Crude Oil (Bbls per day) 1,345 1,049 296 28% Natural Gas (Mcf per day) 1,662 1,314 348 26% NGL (Bbls per day) 213 159 54 34% Total (Boe per day) (1) 1,835 1,427 408 29% Average Sale Price: Crude Oil ($/Bbl) $ 73.50 $ 72.95 $ 0.55 1% Natural Gas($/Mcf) 2.00 3.00 (1.00 ) (33%) NGL ($/Bbl) 27.48 24.43 3.05 13% Net Operating Revenues (In thousands): Crude Oil $ 36,193 $ 27,925 $ 8,268 30% Natural Gas 1,216 1,438 (222 ) (15%) NGL 2,144 1,421 723 51% Total Revenues $ 39,553 $ 30,784 $ 8,769 28% (1) Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil. Total crude oil, natural gas and NGL revenues for the year ended December 31, 2024, increased $8.8 million, or 28%, to $39.6 million, compared to $30.8 million for the same period a year ago, due to a favorable volume variance of $8.8 million. There was a negligible price variance over the periods. The increase in production volume is related to our participation in 24 new non-operated wells in the D-J Basin and the drilling and completion of three operated wells in the Permian Basin. 78 Table of Contents Net Operating and Other (Income) Expenses The following table sets forth operating and other expenses for the years ended December 31, 2024 and 2023 (in thousands): 2024 2023 Increase (Decrease) % Increase (Decrease) (As Restated) Direct Lease Operating Expense $ 6,961 $ 4,679 $ 2,282 49% Workovers 839 1,460 (621 ) (43%) Other* 4,649 3,571 1,078 30% Loss on settlement of ARO - 121 (121 ) (100%) Lease Operating Expenses $ 12,449 $ 9,831 $ 2,618 27% Depreciation, Depletion, Amortization and Accretion 15,920 9,440 6,480 69% General and Administrative (Cash) $ 4,532 $ 3,965 $ 567 14% Share-Based Compensation (Non-Cash) 1,859 2,043 (184 ) (9%) Total General and Administrative Expense $ 6,391 $ 6,008 $ 383 6% Loss on Sale of Oil and Gas Properties 76 4,268 (4,192 ) (98%) Interest Income $ 351 $ 422 $ (71 ) (17%) Other Income (Expense) $ (42 ) $ 40 $ (82 ) (205%) Gain on Sale of Fixed Asset $ 12 $ - $ 12 100% *Includes severance, ad valorem taxes, workover adjustments and assessment and marketing costs. Lease Operating Expenses. The increase of $2.6 million was primarily due to higher direct and variable lease operating expenses associated with the higher oil volume resulting from the increased number of wells and increased oil and gas production during the current year’s period, compared to the prior year’s period. Depreciation, Depletion, Amortization and Accretion. The $5.9 million increase was primarily the result of an increase in production (noted above) in the current period when compared to the prior period. Additionally, the Company continued to adhere to its plugging and abandonment program in the Permian Basin Asset (in accordance with the terms of an existing compliance order) to plug additional wells over the next several years, which increased accretion expense in Q4 2024 by approximately $0.4 million. 79 Table of Contents General and Administrative Expenses (excluding share-based compensation). The increase of $0.6 million in general and administrative expenses (excluding share-based compensation) was primarily due to increased contract and full time staff related to increased activity, an increase in accrued bonuses, which were subsequently paid in January 2025, software licensing fees and general increases in accounting and professional services when comparing the prior period to the current period. Share-Based Compensation. Share-based compensation, which is included in general and administrative expenses in the Statements of Operations, decreased nominally due to the forfeiture of certain employee stock-based options due to certain voluntary employee terminations. Share-based compensation is utilized for the purpose of conserving cash resources for use in field development activities and operations. Loss on Sale of Oil and Gas Properties, net . The Company completed three oil and gas property sales transactions during the year ended December 31, 2024, for a total net loss on the sale of oil and gas properties of $76,000, as follows: (i) the Company sold 30 gross (5.1 net) non-operated legacy well-bores in its D-J Basin Asset for net cash proceeds of $90,000 during 2024, resulting in the Company recognizing a loss on sale of oil and gas properties of $865,000 for these non-core assets, while noting. the Company still retained the corresponding acreage related to the sale for any potential future development; (ii) the Company sold a legacy well-bore assignment for net cash proceeds of $25,000 and recognized a gain on sale of oil and gas properties of $29,000; and (iii) the Company sold leasehold rights to 320 net acres located in the D-J Basin for net cash proceeds of $750,000 and recognized a corresponding gain on sale of oil and gas properties of $735,000, as the leasehold costs had been fully depleted. In the prior period, the Company sold its then-wholly-owned subsidiary EOR Operating Company and related assets in the November 2023 Milnesand Sale and recognized the corresponding loss of $4.3 million. (see “ Item 8. Financial Statements and Supplementary Data ” - “ Note 7 - Oil and Gas Properties ”). Interest Income and Other (Expense) Income. Includes interest earned from our interest-bearing cash accounts, for which interest rates have remained relatively flat in the current period, compared to the prior period, and interest on our note receivable. Other expense in the current period primarily relates to the subsequent disposition of a cash escrow bank balance related to the Milnesand Sale. Other income in the prior period is primarily related to the sale of used pipe. Gain on Sale of Fixed Asset. Relates to the sale of a vehicle and the subsequent purchase of another vehicle in the current period. Liquidity and Capital Resources The primary sources of cash for the Company during the year ended December 31, 2024 were from $39.6 million in sales of crude oil and natural gas. The primary uses of cash were funds used for drilling, completion, acquisition and operating costs. Working Capital At December 31, 2024, the Company’s total current assets of $13.2 million exceeded its total current liabilities of $6.9 million, resulting in a working capital surplus of $6.3 million, while at December 31, 2023, the Company’s total current assets of $24.6 million exceeded its total current liabilities of $18.9 million, resulting in a working capital surplus of $5.7 million. Although current assets and current liabilities both decreased when comparing periods, the $0.6 million net increase in our working capital surplus is primarily related to a larger reduction in accounts payable and accrued expenditures compared to the corresponding smaller reduction in current assets when comparing the current period to the prior period due to the timing of cash payments related to our drilling, as operator, and our participation in the drilling and completion of wells by a third-party operator. (see “ Item 8. Financial Statements and Supplementary Data ” - “ Note 7 - Oil and Gas Properties ”). Financing The Company has an ongoing $8.0 million offering of securities in an “at the market offering”, pursuant to which the Company may sell securities from time to time (the “ ATM Offering ”). The ATM Offering was made pursuant to the terms of a December 20, 2024, Sales Agreement (the “ Sales Agreement ”) with Roth Capital Partners, LLC and A.G.P./Alliance Global Partners. The Company will pay the Lead Agent a commission of 3.0% of the gross sales price of any shares sold under the Sales Agreement. The Company also agreed to reimburse the Agents for their reasonable and documented out-of-pocket expenses in an amount not to exceed $75,000, in connection with entering into the Sales Agreement and for the Agents’ reasonable and documented out-of-pocket expenses related to quarterly maintenance of the Sales Agreement on a quarterly basis in an amount not to exceed $5,000. The Company has not sold any securities under the ATM Offering as of the date of this report. 80 Table of Contents Our net capital expenditures for 2025 are estimated at the time of this Annual Report to range between $27 million to $33 million, including $24.5 million to $30.5 million for drilling and completion costs on our Permian Basin and D-J Basin Assets and approximately $2.5 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses. We anticipate that approximately 70% to 75% of our expected capital expenditures for 2025 will be allocated to development in the D-J Basin under our February 2025 joint development agreement entered into with a large private equity-backed D-J Basin operator and our Participation Agreement and Area of Mutual Interest (AMI) entered into in August 2024 with a private operator. This estimate does not include expenditures for acquisitions or other projects that may arise but are not currently anticipated. We periodically review our capital expenditures and adjust our capital forecasts and allocations based on liquidity, drilling results, leasehold acquisition opportunities, partner non-consents, proposals from third party operators, and commodity prices, while prioritizing our financial strength and liquidity (see “ Part I ” – “ Item 1A. Risk Factors ”). We plan to continue to evaluate D-J Basin well proposals as received from third party operators and participate in those we deem most economic and prospective. If new proposals are received that meet our economic thresholds and require material capital expenditures, we have flexibility to move capital from our Permian Asset to our D-J Basin Asset, or vice versa, as our Permian Asset is 100% operated and nearly 100% held by production (“ HBP ”), allowing for flexibility of timing on development. Our 2025 development program is based upon our current outlook for the year and is subject to revision, if and as necessary, to react to market conditions, product pricing, contractor availability, requisite permitting, capital availability, partner non-consents, capital allocation changes between assets, acquisitions, divestitures and other adjustments determined by the Company in the best interest of its shareholders while prioritizing our financial strength and liquidity. We expect that we will have sufficient cash available to meet our needs over the next 12 months after the filing of this report and in the foreseeable future, including to fund our 2025 development program, discussed above, which cash we anticipate being available from (i) projected cash flow from our operations, (ii) existing cash on hand, (iii) borrowing under our reserve-based lending facility (“ RBL ”) with Citibank, N.A., as administrative agent, which provides for an initial borrowing base of $20 million and an aggregate maximum revolving credit amount of $250 million (of which none has been drawn down by the Company to date), (iv) equity infusions or loans (which may be convertible) made available from Dr. Simon G. Kukes, our former CEO and newly appointed Executive Chairman of the Company's Board of Directors, which funding Dr. Kukes is under no obligation to provide, (v) public or private debt or equity financings, including up to $8.0 million in securities which we may sell in the future in “at the market offerings”, pursuant to a Sales Agreement entered into on December 20, 2024, with Roth Capital Partners, LLC (the “ Lead Agent ”), and A.G.P./Alliance Global Partners (“ AGP ” and, together with the Lead Agent, the “ Agents ”)(discussed in greater detail below under “ Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financing ” (under which we have sold no shares to date), and (vi) funding through other credit or loan facilities. In addition, we may seek additional funding through asset sales, farm-out arrangements, and partnerships to fund potential acquisitions during the remainder of 2025. Cash Flows (in thousands) Year Ended December 31, 2024 2023 Cash flows provided by operating activities $ 12,766 $ 23,481 Cash flows used in investing activities (26,874 ) (35,743 ) Cash flows provided by financing activities - - Net decrease in cash and restricted cash $ (14,108 ) $ (12,262 ) Cash provided by operating activities. Net cash provided by operating activities decreased by $10.7 million for the current year’s period, when compared to the prior year’s period, primarily due to our net income for the current period increasing by $5.6 million and from a $4.2 million increase in depreciation, depletion, amortization and accretion (primarily due to increased sales production, noted above), offset by a $4.2 million net loss on sale of oil and gas properties (primarily from a $4.3 million loss on the sale of our EOR Operating Company subsidiary and its corresponding assets in the prior period) and by a $16.3 million net decrease to our other components of working capital in the current period (due to increased cash payments and decreased payables and expenses outstanding from our drilling and completion activity) when comparing periods. 81 Table of Contents Cash used in investing activities. Net cash used in investing activities decreased by $8.9 million for the current year’s period, when compared to the prior year’s period, primarily due to decreased cash outlays from our capital spending relating to our drilling and completion activities. Cash financing activities. There were no cash flow financing activities in the current or prior period. Non-GAAP Financial Measures We have included EBITDA and Adjusted EBITDA in this Report as supplements to generally accepted accounting principles in the United States of America (“ GAAP ”) measures of performance to provide investors with an additional financial analytical framework which management uses, in addition to historical operating results, as the basis for financial, operational and planning decisions and present measurements that third parties have indicated are useful in assessing the Company and its results of operations. “EBITDA” represents net income before interest, taxes, depreciation and amortization. “Adjusted EBITDA” represents EBITDA, less share-based compensation, loss on sale of oil and gas properties, net, and gain on sale of fixed assets. Adjusted EBITDA excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. EBITDA and Adjusted EBITDA are presented because we believe they provide additional useful information to investors due to the various noncash items during the period. EBITDA and Adjusted EBITDA are also frequently used by analysts, investors and other interested parties to evaluate companies in our industry. EBITDA and Adjusted EBITDA have limitations as analytical tools, and you should not consider them in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are: EBITDA and Adjusted EBITDA do not reflect cash expenditures, future requirements for capital expenditures, or contractual commitments; EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, working capital needs; and EBITDA and Adjusted EBITDA do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt or cash income tax payments. For example, although depreciation and amortization are noncash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Additionally, other companies in our industry may calculate EBITDA and Adjusted EBITDA differently than PEDEVCO Corp. does, limiting its usefulness as a comparative measure. You should not consider EBITDA and Adjusted EBITDA in isolation, or as substitutes for analysis of the Company’s results as reported under GAAP. The Company’s presentation of these measures should not be construed as an inference that future results will be unaffected by unusual or nonrecurring items. We compensate for these limitations by providing a reconciliation of each of these non-GAAP measures to the most comparable GAAP measure. We encourage investors and others to review our business, results of operations, and financial information in their entirety, not to rely on any single financial measure, and to view these non-GAAP measures in conjunction with the most directly comparable GAAP financial measure. The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDA (in thousands): Years Ended December 31, 2023 2024 (As Restated) Net income $ 17,789 $ 1,699 Add (deduct) Income tax benefit (12,751 ) - Depreciation, depletion, amortization and accretion 15,920 9,440 EBITDA 20,958 11,139 Add (deduct) Share-based compensation 1,859 2,043 Loss on sale of oil and gas properties, net 76 4,268 Gain on sale of fixed assets (12 ) - Adjusted EBITDA $ 22,881 $ 17,450 82 Table of Contents Critical Accounting Estimates Our discussion and analysis of our financial condition and results of operations is based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our most significant judgments and estimates used in preparation of our financial statements. Oil and Gas Properties, Successful Efforts Method. The successful efforts method of accounting is used for oil and gas exploration and production activities. Under this method, all costs for development wells, support equipment and facilities, and proved mineral interests in oil and gas properties are capitalized. Geological and geophysical costs are expensed when incurred. Costs of exploratory wells are capitalized as exploration and evaluation assets pending determination of whether the wells find proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Exploratory wells in areas not requiring major capital expenditures are evaluated for economic viability within one year of completion of drilling. The related well costs are expensed as dry holes if it is determined that such economic viability is not attained. Otherwise, the related well costs are reclassified to oil and gas properties and subject to impairment review. For exploratory wells that are found to have economically viable reserves in areas where major capital expenditure will be required before production can commence, the related well costs remain capitalized only if additional drilling is under way or firmly planned. Otherwise, the related well costs are expensed as dry holes. Exploration and evaluation expenditures incurred subsequent to the acquisition of an exploration asset in a business combination are accounted for in accordance with the policy outlined above. Depreciation, depletion and amortization of capitalized oil and gas properties is calculated on a field-by-field basis using the unit of production method. Lease acquisition costs are amortized over the total estimated proved developed and undeveloped reserves and all other capitalized costs are amortized over proved developed reserves. Costs specific to developmental wells for which drilling is in progress or uncompleted are capitalized as wells in progress and not subject to amortization until completion and production commences, at which time amortization on the basis of production will begin. Asset Retirement Obligations. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Asset retirement costs for oil and gas properties are depreciated using the unit-of-production method, while asset retirement costs for other assets are depreciated using the straight-line method over estimated useful lives. Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included in DD&A expense in the Consolidated Statement of Operations. Revenue Recognition. The Company’s revenue is comprised entirely of revenue from exploration and production activities. The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery. Contracts with customers have varying terms, including month-to-month contracts, and contracts with a finite term. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs. Revenues are recognized for the sale of the Company’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues. 83 Table of Contents Stock-Based Compensation. Pursuant to the provisions of Financial Accounting Standards Board (“ FASB ”) Accounting Standards Codification (“ ASC ”) 718, Compensation – Stock Compensation, which establishes accounting for equity instruments exchanged for employee service, we utilize the Black-Scholes option pricing model to estimate the fair value of employee stock option awards at the date of grant, which requires the input of highly subjective assumptions, including expected volatility and expected life. Changes in these inputs and assumptions can materially affect the measure of estimated fair value of our share-based compensation. These assumptions are subjective and generally require significant analysis and judgment to develop. When estimating fair value, some of the assumptions will be based on, or determined from, external data and other assumptions may be derived from our historical experience with stock-based payment arrangements. The appropriate weight to place on historical experience is a matter of judgment, based on relevant facts and circumstances. We estimate volatility by considering historical stock volatility. We have opted to use the simplified method for estimating expected term, which is equal to the midpoint between the vesting period and the contractual term. Recently Adopted Accounting Pronouncements. In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280). The amendments in this update expand segment disclosure requirements, including new segment disclosure requirements for entities with a single reportable segment among other disclosure requirements. This update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Adoption of this standard is on a modified retrospective basis and had no impact on the Company’s financial position, results of operations, cash flows or net income per share. Recently Issued Accounting Pronouncements . In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires disaggregated information about a reporting entity's effective tax rate reconciliation, as well as information related to income taxes paid to enhance the transparency and decision usefulness of income tax disclosures. This ASU will be effective for the annual period ending December 31, 2025. The Company is currently evaluating the timing and impacts of adoption of this ASU. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK. Not required under Regulation S-K for “ smaller reporting companies .”