Royale Energy, Inc. 10-K

Item 5 Market for Common Equity and Related Stockholder Matters There is no established trading market for Royale’s Common Stock, which is quoted on the OTC QB Market under the symbol “ROYL.” As of December 31, 2024, 96,600,302 shares of Common Stock were held by approximately 3,052 stockholders. The following table reflects the high and low quarterly bid prices as reported on the OTC QB Market from January 2023 through December 2024: 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr High Low High Low High Low High Low 2023 $ 0.06 $ 0.04 $ 0.06 $ 0.04 $ 0.05 $ 0.03 $ 0.04 $ 0.02 2024 $ 0.07 $ 0.02 $ 0.07 $ 0.03 $ 0.08 $ 0.03 $ 0.07 $ 0.04 The OTC QB Market is not an exchange, and any over the counter quotations reflect inter-dealer prices, without retail markup, markdown or commission, and may not necessarily represent actual transactions. Transfer Agent The Company utilizes the independent transfer agent services of American Stock Transfer & Trust Company as its transfer agent. Dividends The Board of Directors did not declare cash dividends in either 2024 or 2023. The Board of Directors did declare dividends during 2024 and 2023 on the preferred stock to be Paid In Kind (“PIK”) of 65,372 and 84,470 shares with a respective par value of $653,730 and $844,700, as more fully set forth in Note 5 to our Financial Statements. Recent Sales of Unregistered Securities During the fiscal year ended December 31, 2024, Royale Energy, Inc. issued the following unregistered securities in transactions exempt from registration under the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) and/or Regulation D thereunder: Shares Issued for Compensation The Company issued 1,299,641 shares of common stock to its officers, directors, and consultants in lieu of cash compensation for services rendered. These shares were issued at prevailing market prices or pursuant to existing contractual arrangements, and no underwriters were involved. Shares Issued Upon Conversion of Preferred Stock On October 11, 2024, Royale completed a significant equity restructuring in which it issued 22,198,095 shares of common stock to former holders of Series B 3.5% Convertible Preferred Stock, representing approximately 90% of the total preferred stock retired. Additionally, 2,538,378 shares were issued for conversion of accrued preferred dividends, resulting in a total of 24,736,473 shares issued related to the preferred equity conversion. Shares Issued Upon Conversion of Debt As part of the same restructuring transaction, the Company also issued common stock to settle approximately $3 million in historical liabilities, including certain outstanding debt. The specific number of shares issued in connection with debt settlement was not separately disclosed but was included as part of the equity issued in the restructuring. All of the above issuances were conducted without general solicitation, and the recipients were either accredited investors or had access to such information as would be required to make an informed investment decision. No underwriters or placement agents were involved, and no commissions were paid. 12 Table of Contents Item 7 Management ’ s Discussion and Analysis of Financial Condition and Results of Operations Management’s Discussion and Analysis is the Company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the Company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company’s disclosures under the heading: “Cautionary Statement about Forward-Looking Statements” in this Annual Report. Overview Royale is an independent oil and natural gas producer. Royale’s principal lines of business are the production and sale of oil and natural gas, acquisition of oil and gas lease interests and proved reserves, drilling of both exploratory and development wells, and sales of fractional working interests in wells to be drilled by Royale. Since 1993, Royale has acquired and developed producing and non-producing natural gas properties in California. In December 2018, Royale became the operator of a newly acquired field in Texas. The most significant factors affecting the results of operations are (i) changes in oil and natural gas prices, production levels and reserves, (ii) turnkey drilling activities, and (iii) the increase in future cost associated with abandonment of wells. Critical Accounting Policies Revenue Recognition Royale’s primary business is oil and gas production. Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into metered transportation and customer pipelines. Monthly, price data and daily production are used to invoice customers for amounts due to Royale and other working interest owners. Royale operates most of its own wells and receives industry standard operator fees (“Supervisory Fees”). Supervisory Fees are recognized as a reduction to the Company’s General and Administrative Expenses. Royale generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. Revenues from the production of oil and natural gas properties in which the Royale has an interest with other producers are recognized on the basis of Royale’s net working interest. Differences between actual production and net working interest volumes are not significant. The Company’s Financial Statements include its pro rata ownership of wells. The Company usually sells to third-party participants a portion of the working interest in each well it drills or participates in, and retains a portion of the prospect for its own account. All results, successful or not, are included at its pro-rata ownership amounts: revenue, expenses, assets, and liabilities as defined in FASB ASC 932-323-25 and 932-360. Oil and Gas Property and Equipment Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets. Royale uses the “successful efforts” method to account for its exploration and production activities. Under this method, Royale accumulates its proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalizes expenditures for productive wells. Royale amortizes the costs of productive wells under the unit-of-production method. Royale carries, as an asset, exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where Royale is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. 13 Table of Contents Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain Royale’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. Proved oil and gas properties held and used by Royale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Royale estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated evaluation assumptions for crude oil commodity prices. Annual volumes are based on field production profiles, which are also updated annually. Prices for natural gas and other products are based on assumptions developed annually for evaluation purposes. Impairment analyses are generally based on proved reserves. An asset group would be impaired if the undiscounted cash flows were less than its’ carrying value. Impairments are measured by the amount the carrying value exceeds fair value. During 2024 and 2023, impairment losses of $400,719 and $1,599,001, respectively, were recorded on various capitalized lease and land costs where the carrying value exceeded the fair value or where the leases were no longer viable. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that Royale expects to hold the properties. The valuation allowances are reviewed at least annually. Upon the sale or retirement of a complete field of a proved property, Royale eliminates the cost from its books, and the resultant gain or loss is recorded to Royale’s Statement of Operations. Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in Royale’s Statement of Operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should Royale’s turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy its obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method. The Company sponsors turnkey drilling agreement arrangements in properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete its obligations are incurred with any excess booked against its property account to reduce any basis in its own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs Royale incurs during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for its own account; and are recognized only upon making this determination after Royale’s obligations have been fulfilled. The contracts require the participants to pay Royale the full contract price upon execution of the agreement. Royale completes the drilling activities typically between 10 and 30 days after drilling begins. The participant retains an undivided or proportional beneficial interest in the property, and is also responsible for their proportionate share of operating costs. Royale retains legal title to the lease. The participants purchase a working interest directly in the well bore. In these working interest arrangements, the participants are responsible for sharing in the risk of development, but also sharing in a proportional interest in rights to revenues and proportional liability for the cost of operations after drilling is completed. Since the participant’s interest in the prospect is limited to the well, and not the lease, the participant does not have a legal right to participate in additional wells drilled within the same lease. However, it is the Company’s policy to offer to participants in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well with similar turnkey drilling agreement terms. A certain portion of the turnkey drilling participant’s funds received are non-refundable. The Company records a liability for all funds invested as deferred drilling obligations until each individual well is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At December 31, 2024 and 2023, Royale had deferred drilling obligations of $11,457,996 and $9,761,927 respectively. If Royale is unable to drill the wells, and a suitable replacement well is not found, Royale would retain the non-refundable portion of the contract and return the remaining funds to the participant. Included in restricted cash are amounts for use in completion of turnkey drilling programs in progress. 14 Table of Contents Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value. Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, plant products and gas reserve volumes and the future development costs. Actual results could differ from those estimates. Going Concern At December 31, 2024, the Company has an accumulated deficit of $93,504,469, a working capital deficiency of $10,010,933 and a stockholders’ deficit of $12,329,315. As a result, our financial statements include a “going concern qualification” reflecting substantial doubt as to our ability to continue as a going concern. See Note 1 to our audited financial statements. We do not possess funds necessary to implement our 2025 budget. Royale is continuing its drilling efforts with its direct working interest owners. In addition, we are exploring commitments to provide additional financing, but there is no guarantee that we will be able to secure additional financing on acceptable terms, or at all, needed to fully fund our 2025 drilling budget and to support future operations. Results of Operations for the Year Ended December 31, 2024, as Compared to the Year Ended December 31, 2023 For the year ended December 31, 2024, we had a net loss of $2,159,016 compared to the net loss of $1,832,187 during the year in 2023. Total revenues from operations in 2024 were $2,227,035, an increase of $66,441 or 3.1%, from the total revenues of $2,160,594 in 2023, due to higher oil production volumes due to drilling activity during 2024. Total expenses for operations in 2024 were $5,706,355, a decrease of $504,684 or 8.1%, from total expenses of $6,211,039 in 2023, mainly due to lower lease impairments during 2024. During the year ended 2024, revenues from oil and gas production increased $50,215 or 2.4% to $2,164,241 from the 2023 revenues of $ 2,114,026. This increase was mainly due to higher oil production volumes due to 2024 drilling activity. The net sales volume of oil and condensate for the year ended December 31, 2024 was approximately 26,573 barrels of oil with an average price of $72.83 versus approximately 22,399 barrels with an average price of $74.27 per barrel, in 2023. This represents an increase in net sales volume of approximately 4,174 barrels or 18.6%, which was higher due to wells completed and put online in 2024 and at the end of 2023. The net sales volume of natural gas for the year ended December 31, 2024, was approximately 116,406 Mcf with an average price of $1.94 per Mcf, versus 128,160 Mcf with an average price of $3.47 per Mcf for the year in 2023. This represents a decrease in net sales volume of approximately 11,754 Mcf or 9.2%. The decrease in natural gas production volume was due to lower production volumes on existing wells due to natural declines. Oil and natural gas lease operating expenses increased by $251,503 or 14.5%, to $1,983,173 for the year ended December 31, 2024, from $1,731,670 for the year in 2023. This increase was mainly due to repairs and restoration of well equipment in our Texas Jameson field due to weather related damage. When measuring lease operating costs on a production or lifting cost basis, in 2024, the $1,983,173 equates to a $7.19 per Mcfe lifting cost versus a $6.60 per Mcfe lifting cost in 2023. The aggregate of Supervisory Fees and Other Revenue was $62,794 for year ended December 31, 2024, an increase of $16,226 or 34.8% from $46,568 during the year in 2023. This increase was mainly due to higher interest income received in 2024 due to our higher cash balances. Depreciation, depletion and amortization expense decreased to $308,523 from $346,866, a decrease of $38,343 or 11.1% for the year ended December 31, 2024, as compared to 2023. The depletion rate is calculated using production by comparing capitalized cost to the recoverable reserves remaining. The decrease in depreciation expense was due to a increase in expected recoverable reserves which decreased the depletion rate. General and administrative expenses decreased by $91,275 or 5.3% from $1,725,015 for the year ended December 31, 2023, to $1,633,740 in 2024. This decrease was due to lower board related expenses due to cost reduction measures and higher overhead offsets in 2024 when compared to 2023. Legal and accounting expense increased to $582,413 in 2024, compared to $435,372 in 2023, a $147,041 or 33.8% increase. This increase was primarily due to higher legal fees related to our debt facility entered into during the first quarter of 2024, and preparation of the transaction documents related to the conversion of the Series B Convertible Preferred shares described in Note 14. Marketing expense for the year ended December 31, 2024, decreased $3,381, or 1.0%, to $347,044, compared to $350,425 for the year in 2023. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs. 15 Table of Contents At December 31, 2024, Royale had a Deferred Drilling Obligation of $11,457,996. During 2024, we removed $6,562,721 of drilling obligations as we participated in drilling and completion of four gross (0.0722 net) successful oil wells in the Texas Permian basin, while incurring expenses of $4,955,045, resulting in a gain of $1,607,677. At December 31, 2023, Royale had a Deferred Drilling Obligation of $9,761,927. During 2023, we removed $6,228,038 of drilling obligations as we completed one gross (0.3176 net) oil well in our Texas Jameson field and participated in drilling and completion of two gross (0.0145 net) successful oil wells in the Texas Permian basin and one dry well in southern California, while incurring expenses of $4,120,538, resulting in a gain of $2,107,500. During 2024, we recorded Credit Loss expense of $450,743 which arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment (“P&A”) and our period end oil and natural gas reserve values. We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges appears doubtful. During the period in 2024, we also recorded lease impairments of $400,719 on various lease and land costs in our California fields where the carrying value exceeded the fair value. During 2024, we also recorded a gain on sale of assets of $17,500 as we received a credit for well equipment sold during a 2021 sales transaction. During 2023, we recorded lease impairments of $1.6 million on lease and land costs in our California fields where the carrying value exceeded the fair value. In 2023, we recorded a gain on other of $54,975 as we reconciled employee related items previously recorded as liabilities. In 2023, we also recorded a gain on other of approximately $57,000 on our share of prior years property tax refunds received by RMX Resources, LLC. During 2023, we recorded a write down of $22,690 on certain well equipment that were either written down to their current market value or written off as they were no longer useable. Interest expense for the year ended December 31, 2024 and 2023, was $304,873 and $1,970, respectively. The higher 2024 interest expense was due to the $1.4 million note payable obtained in February 2024, discussed in Note 15 and the new notes payable related to the debt restructuring, discussed in Note 14. In 2024 and 2023, we did not have an income tax expense due to the use of a percentage depletion carryover valuation allowance created from the current and past operations resulting in an effective tax rate less than the new federal rate of 21% plus the relevant state rates (mostly California, 8.8%). Capital Resources and Liquidity At December 31, 2024, Royale had current assets totaling $10,155,158 and current liabilities totaling $20,166,091, a $10,010,933 working capital deficit. We had cash and cash equivalents at December 31, 2024 of $1,877,163 and restricted cash of $6,025,000 compared to cash and cash equivalents of $2,202,521 and restricted cash of $3,325,000 at December 31, 2023. Ordinarily, we fund our operations and cash needs from our available credit and cash flows generated from operations. We believe there is some doubt that the Company has the ability to meet liquidity demands through cash-flow from operations. In that event, the Company will seek alternative capital sources through additional sales of equity or debt securities, or the sale of property, which may not be available at all, or on terms we deem reasonable. We have plans to increase oil and gas revenue with commitments to participate in the drilling and completion of several non-operated wells in the Permian Basin in Texas. At December 31, 2024, our other receivables net, which consists of joint interest billing receivables from direct working interest participants and industry partners, totaled $868,429, compared to $1,036,401 at December 31, 2023, a $167,972 decrease. This decrease was mainly due to lower accounts receivables from payment of Joint Interest Bills by direct working interest owners for lease operating expenses of our Texas Jameson wells. At December 31, 2024, revenue receivable was $764,653, a decrease of $113,725, compared to $878,378 at December 31, 2023, due to lower uncollected production volumes and commodity prices at year end 2024 when compared to year end 2023. At December 31, 2024, our accounts payable and accrued expenses totaled $6,966,605, an increase of $1,484,531 from the accounts payable at December 31, 2023 of $5,482,074, mainly due to mainly due to higher trade payables primarily related to drilling costs during 2024. 16 Table of Contents We have not engaged in hedging activities nor do we use derivative instruments to manage market risks. Operating Activities. For the years ended December 31, 2024 and 2023, cash used in operating activities totaled $2,210,999 and $769,919, respectively. This $1,441,080 difference in cash used was mainly due to the difference in non-cash expenses especially lease impairments, and the difference in prepayments mainly for drilling costs, when comparing 2024 and 2023. Investing Activities . Net cash provided by investing activities totaled $3,192,264 and $2,409,291 for the years ended December 31, 2024 and 2023, respectively. The difference was due to cash receipts of approximately $8.3 million in 2024 and $7.9 million in 2023 in direct working interest turnkey investments. During 2024, our turnkey drilling expenditures were approximately $5.1 million as we participated in the drilling and completion of four gross (0.0722 net) Texas oil wells in the Permian basin. During 2023, our turnkey drilling expenditures were approximately $5.5 million as we drilled and completed one gross (0.3176 net) oil well in our Texas Jameson field and participated in the drilling and completion of two gross (0.0145 net) Texas oil wells in the Permian basin and the drilling one gross (0.5679 net) California oil well. Financing Activities. Net cash provided by financing activities totaled $1,393,377 for the year ended December 31, 2024. Net cash used in financing activities totaled $11,985 for the year ended December 31, 2023. The difference in cash was due to receipt of $1.4 million from the note payable discussed in Note 8. During the year ended December 31, 2024 and 2023, $6,623 and $11,985, respectively, were used for principal payments on our financing lease payments. Changes in Reserve Estimates During 2024, our overall proved developed and undeveloped oil reserves increased by 9.6% and our previously estimated proved developed and undeveloped oil reserve quantities were revised upward by approximately 32 thousand barrels. This upward revision was mainly the result of an increase in proved undeveloped oil reserves from drilling locations which the Company had previously estimated. Our overall proved developed and undeveloped natural gas reserves decreased by 17.1% mainly due to production and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised upward by approximately 4 thousand cubic feet of natural gas. This upward revision was mainly the result of an increase in proved undeveloped natural gas reserves from drilling locations which the Company had previously estimated. See Note 17 – Supplemental Information About Oil and Gas Producing Activities (Unaudited), to our Financial Statements. During 2023, our overall proved developed and undeveloped oil reserves decreased by 41.5% and our previously estimated proved developed and undeveloped oil reserve quantities were revised downward by approximately 185 thousand barrels. This downward revision was mainly the result of a decrease in proved undeveloped oil reserves from drilling locations which the Company had previously estimated. Our overall proved developed and undeveloped natural gas reserves decreased by 58.2% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 720 thousand cubic feet of natural gas. This downward revision was mainly the result of a decrease in proved undeveloped natural gas reserves from drilling locations which the Company had previously estimated. See Note 17 – Supplemental Information About Oil and Gas Producing Activities (Unaudited), to our Financial Statements. Item 7A Qualitative and Quantitative Disclosures About Market Risk Not a required disclosure for smaller reporting companies. Item 8 Financial Statements and Supplementary Data See pages F-1, et seq., included herein. Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None