ROYL 10-K & 10-Q changes, risk factors and insider trading
Royale Energy, Inc. · OTC · Crude Petroleum & Natural Gas · CIK 1694617 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Risk Factors
As a smaller reporting company, as defined in Rule 12b-2 of the Exchange Act, Royale is not required to provide the information required by this Item.
No wording changes found in this section.
Full comparison: every changed paragraph (0)
Management's Discussion & Analysis (MD&A)
Largest changes
“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. …”see in full comparison
“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. …”see in full comparison
“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. …”see in full comparison
“Management considers the estimation of proved oil and natural gas reserve quantities to be the most critical of these estimates, because those quantities drive the rate at which the Company depletes its oil and gas properties under the unit-of-production method and are the basis on which proved properties are tested for impairment. Reserve quantities are estimates, not exact measurements, and their estimation requires the application of significant judgment. …”see in full comparison
“During 2025, we recorded a $18,710 gain on settlement of asset retirement obligation liability due mainly to finalizing the plugging and abandonment of three natural gas sites in California. During the years ended December 31, 2025 and 2024, we recorded impairments of $27,250 and $400,719, respectively, on various lease and land costs in our California natural gas fields where the carrying value exceeded the fair value. …”see in full comparison
“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. …”see in full comparison
Full comparison: every changed paragraph (58)
Management’s
Discussion and Analysis isof theFinancial Company’sCondition and
Results of Operations provides management’s analysis of itsthe Company’s 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”
included elsewhere in this Annual
Report.
Critical
Accounting PoliciesEstimates
The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. We consider an accounting estimate to be critical if it requires difficult, subjective, or complex judgments and if changes in those judgments could materially affect our financial condition or results of operations. Our most critical accounting estimates relate to (i) estimates of proved oil and natural gas reserves, (ii) asset retirement obligations, (iii) impairment of oil and natural gas properties under the successful efforts methods of accounting for oil and gas related operations. These estimates involve significant judgment because they rely on assumptions about future commodity prices, production profiles, operating and development costs, and other economic factors that are inherently uncertain.
Estimates of proved oil and natural gas reserves
Management considers the estimation of proved oil and natural gas reserve quantities to be the most critical of these estimates, because those quantities drive the rate at which the Company depletes its oil and gas properties under the unit-of-production method and are the basis on which proved properties are tested for impairment. Reserve quantities are estimates, not exact measurements, and their estimation requires the application of significant judgment. The estimates depend on a number of subjective assumptions, including projected production decline rates of producing wells, the timing and volume of production from proved undeveloped locations, the commodity prices prescribed by SEC rules (the unweighted average of the first-of-the-month prices for the prior twelve months), future development and operating costs, and judgments about whether wells are, with reasonable certainty, expected to be economically producible. These assumptions are inherently uncertain, are developed by the Company’s reservoir engineering specialist, and are revised as additional production history, well performance data, commodity prices and economic conditions become available. Accordingly, actual reserves and the timing and amount of future production may differ materially from the estimates used, and revisions can occur from period to period.
Changes in estimated proved reserves have a direct and measurable effect on the Company’s results of operations. Depreciation, depletion and amortization expense was $259,438 for the year ended December 31, 2025, compared to $308,523 for 2024; the decrease of $49,085, or 15.9%, resulted from an increase in expected recoverable reserves that lowered the unit-of-production depletion rate. Because depletion is computed by comparing capitalized cost to remaining recoverable reserves, a downward revision in estimated proved reserves would increase the depletion rate and depletion expense and could indicate that the carrying amount of a proved property is not recoverable, while an upward revision would have the opposite effect. Holding current-year production and net capitalized costs constant, a hypothetical 10% reduction in estimated proved reserves would have increased 2025 depreciation, depletion and amortization expense by approximately $17,640.
Asset Retirement Obligations
We recognize an asset retirement obligation (“ARO”) for the estimated present value of the future costs to plug and abandon wells, remove equipment and facilities, and restore land and surface conditions. ARO estimates require significant judgment regarding the timing of retirement activities, future regulatory requirements, expected inflation rates, technological changes, and the credit-adjusted discount rate used to measure the obligation. Because these obligations typically will not be settled for many years, the ultimate costs may differ materially from our recorded estimates. Changes in estimated settlement dates, cost assumptions, or discount rates are recognized prospectively and may result in significant increases or decreases in the ARO liability and corresponding asset.
Impairment of Oil and Natural Gas Properties (Successful Efforts Method) We evaluate our proved oil and natural gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset group may not be recoverable. Under the successful efforts method, impairment is assessed at the lowest level for which identifiable cash flows are largely independent, which is generally a field or reservoir. The recoverability test compares the carrying amount of the asset group to the estimated undiscounted future net cash flows expected to result from the use and eventual disposition of the assets.
Estimating future cash flows requires significant judgment regarding future commodity prices, production profiles, operating and development costs, reserve estimates, and the timing of development activities. These assumptions are inherently uncertain and are based on management’s expectations of future economic and operating conditions, which may differ materially from actual results.
If the carrying amount of an asset group exceeds the estimated undiscounted future net cash flows, we measure the impairment loss as the amount by which the carrying amount exceeds fair value. Fair value is typically determined using a discounted cash flow model that incorporates Level 3 inputs, including internally developed price forecasts, production estimates, cost assumptions, and a market-participant discount rate. Because our asset base is relatively small and concentrated, changes in commodity prices, reserve estimates, or operating cost assumptions may have a more pronounced impact on the recoverability of our properties than would be the case for larger, more diversified producers. Actual results may differ materially from our estimates, and such differences could result in impairment charges in future periods.
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.
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.
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.
For
the year ended December 31, 2024,2025, we hadincurred a net loss of $1,251,680
compared to a net loss of $2,159,016 compared to the net loss of $1,832,187 during the year in 2023.2024. Total
revenues from operations in 20242025 were $2,227,035,$1,947,203, ana increasedecrease of $66,441$315,136 or 3.1%, 13.9%,
from the total revenues of $2,160,594$2,262,339 in 2023,2024, due
to higher oil production volumesmainly due to drillinglower activityoil prices during 2024.2025. Total expenses for operations in 20242025 were
$4,183,060 $5,706,355,
a decrease of $504,684$1,605,127 or 8.1%,27.7%, from total expenses of $6,211,039$5,788,187 in 2023,2024, mainly due to lower lease operating expenses,
lease impairments and credit loss expenses during 2024.2025.
During
the year ended 2024,December 31, 2025, revenues from oil and gas
production increaseddecreased $50,215$319,631 or 2.4%14.23% to $2,164,241$1,926,442 from the 20232024 revenues of $ 2,114,026.
This increase was mainly$2,246,073,mainly due to higherlower oil productioncommodity volumesprices due to 2024 drilling activity.during
2025. The net sales volume of oil and condensate
for the year ended December 31, 20242025 was approximately 26,57325,976 barrels of oil with an
average price of $64.23 versus approximately 26,570 barrels with an average price of $72.83 versus approximately 22,399
barrels with an average price of $74.27 per barrel, in 2023.2024. This represents ana increase decrease
in net sales volume of approximately 4,174593 barrels
or 18.6%,2.2%, which was highermainly due to some wells completedbeing andoffline putduring onlinethe period in 20242025 anddue
to atweather therelated endissues ofin 2023.our Texas Jameson field. The net sales volume of natural gas
for the year ended December 31, 2024,2025, was approximately
117,219 Mcf with an average price of $2.20 per Mcf, versus 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 2023.2024. This
represents aan decreaseincrease in net sales volume of approximately 11,754813 Mcf or 9.2%.
The0.7%, decrease in natural gas production volume wasprimarily due to lower production volumes on existing wells duecoming toonline naturalduring declines.the period in
2025.
Oil
and natural gas lease operating expenses increaseddecreased by $251,503 $659,840
or 14.5%,33.3%, to $1,983,173$1,323,333 for the year ended December 31, 2024,2025, from $1,731,670
$1,983,173 for the year in 2023.2024. This increasedecrease was mainly due to repairslower
workover-related costs and restoration of well equipment inrepairs on our Texas Jameson field during 2025 as we attempted to increase production in 2024. During 2025,
we also recorded settlement of accounts payable of $105,494 with a vendor due to weatheran equipment failure which occurred during a workover.
relatedAdditionally, damage.during 2025, we recorded a settlement of accounts payable of $53,583 due to the write-off of accounts payable. When measuring
lease operating costs on a production or lifting cost basis, in 2024,2025, the $1,983,173$1,323,333 equates to a $7.19
$4.85 per Mcfe or $30.61 per BOE lifting
cost versus a $6.60$7.19 per Mcfe or $50.70 per BOE lifting cost in 2023.2024.
The
aggregate of SupervisoryOther Fees and OtherOperating Revenue was $62,794$20,761 for the year ended
December 31, 2024,2025, an increase of $16,226$4,495 or 34.8%27.6% from $46,568
during$16,266 thefor year in 2023. This increase was mainly2024, due to higher interestrental income received in 2024 due to our higher cash balances.2025.
Depreciation,
depletion and amortization expense decreased to $308,523 $259,438
from $346,866,$308,523, a decrease of $38,343$49,085 or 11.1%15.9% for the year ended December 31,
2024, 2025, as compared to 2023.2024. The depletion rate is calculated
using production by comparing capitalized cost to the recoverable reserves
remaining. The decrease in depreciationdepreciation, depletion and amortization
expense was due to aan increase in expected recoverable reserves which decreased the depletion
rate.
General
and administrative expenses decreased by $91,275$1,637 or 5.3%0.1% from $1,725,015
$1,633,740 for the year ended December 31, 2023,2024, to $1,633,740$1,632,103 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 2023.2025. Legal and accounting expense increaseddecreased to $446,593 in 2025, compared
to $582,413 in 2024, compared to $435,372 in 2023, a $147,041$135,820 or 33.8%23.3% increase.decrease. This
increase decrease 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 sharesshares,
also describedduring in Note 14.2024. Marketing expense
for the year ended December 31, 2024,2025, decreased $3,381,$44,589, or 1.0%,12.9%, to $347,044,$302,455, compared to $350,425 $347,044
for the year in 2023.2024. Marketing expense
varies from period to period according to the number of marketing events attended by personnel and their associated
costs.
At December 31, 2025, Royale had a Deferred Drilling Obligation of $14,277,496. During 2025, we removed $2,755,500 of drilling obligations as we participated in drilling and completion of one gross (0.0035 net) successful oil well in the Texas Permian basin, while incurring expenses of $1,433,351, resulting in a gain of $1,322,149. 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 $4,955,044, resulting in a gain of $1,607,677.
During 2025, we recorded a $18,710 gain on settlement of asset retirement obligation liability due mainly to finalizing the plugging and abandonment of three natural gas sites in California. During the years ended December 31, 2025 and 2024, we recorded impairments of $27,250 and $400,719, respectively, on various lease and land costs in our California natural gas fields where the carrying value exceeded the fair value. During 2025 and 2024, we also recorded Credit Loss expenses of $137,221 and $450,743, respectively, which arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment 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 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.
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 income for the year ended December 31, 20242025 and 2023,2024, was $304,873
$66,079 and $1,970,$46,528, respectively. The higher 20242025 interest income was due to higher bank balances during 2025. Interest expense for the
year ended December 31, 2025 and 2024, was $404,051 and $304,873, respectively. The higher 2025 interest expense was due
to the $1.4$1.9 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.
At
December 31, 2024,2025, Royale had current assets totaling $10,155,158 $10,510,193
and current liabilities totaling $20,166,091,$22,061,032, aan $10,010,933$11,550,839 working
capital deficit. We had cash and cash equivalents at December 31,
2025 2024of $1,099,044 and restricted cash of $7,175,950 compared to cash and cash equivalents 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, 2023.2024.
Ordinarily,
we fund our operations and cash needs from our available
credit and cash flows generated from operations. We believe there is somedoubt doubt
that the Company has the ability to meet liquidity demands
through cash-flow from operations. In that event, the Company willexpects to 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 participateparticipation in the drilling and completion
of several non-operated wells in the Permian Basin in Texas.
At December 31, 2024,2025, our other receivables net, which consists of
joint interest billing receivables from direct working interest participants and industry partners, totaled $868,429,$793,608, compared to $868,429
$1,036,401 at December 31, 2023,2024, a $167,972$74,821 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.owners. At December 31,
2024, 2025, revenue receivable was $764,653,$694,729, a decrease of $113,725,$69,924, compared to $878,378 $764,653
at December 31, 2023,2024, due to lower uncollected
production volumes and commodity prices at year end 20242025 when compared to year end 2023. 2024.
At December 31, 2024,2025, our accounts payable
and accrued expenses totaled $6,966,605,$6,033,878, ana increasedecrease of $1,484,531$932,727 from the accounts payable at
December 31, 20232024 of $5,482,074,
mainly due to$6,966,605, mainly due to higherlower trade payables primarilyand relatedlower revenue payables to drillingdirect costsworking duringinterest 2024.owners at year
end 2025.
Operating
Activities. For the years ended December 31, 2024 2025
and 2023,2024, cash used in operating activities totaled $2,210,999$2,699,820 and $769,919,$2,362,855, respectively.
This $1,441,080$366,965 difference in cash used was
mainly due to thea differencedecrease in non-cashaccounts payable and accrued expenses especiallydue leaseto impairments,payments made during 2025 and thelower differencerevenue payables to direct
inworking prepaymentsinterest mainly for drilling costs, when comparing 2024 and 2023.owners.
Investing
Activities. Net cash provided by investing activities
totaled $3,192,264$2,584,264 and $2,409,291$3,344,120 for the years ended December 31, 20242025 and
2023, 2024, respectively. The $759,856 difference was due to cash
receipts of approximately $5.6 million in 2025 and $8.3 million in 2024 and $7.9 million in 2023 in direct
working interest turnkey investments. Also, during 2025,
our turnkey drilling expenditures were approximately $2.7 million as we participated in the drilling and completion of one gross (0.0035
net) well in the Permian basin. 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 totaled$488,387 and $1,393,377 for the yearyears ended December 31, 2024.2025 Netand cash2024, used in financing
activities totaled $11,985 for the year ended December 31, 2023.respectively. The difference in cash provided was due
to receipt of $500,000 during 2025 and $1.4 million received in 2024 from the note
payable discussed in Note 8.15. During the yearyears ended
December 31, 20242025 and 2023,2024, $6,623$11,613 and $11,985,$6,623, respectively, were used for principal
payments on our financing lease payments.
During
2024, 2025, our overall proved developed and undeveloped oil reserves
increased by 9.6%171.1% and our previously estimated proved developed and undeveloped
oil reserve quantities were revised upward by approximately 32
107 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 decreasedincreased by 17.1% mainly due to production362.3% and
our previously estimated proved developed and undeveloped
natural gas reserve quantities were revised upward by approximately 4688 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 1718 – Supplemental Information About Oil and Gas Producing Activities
(Unaudited), to our Financial Statements.
During
2023, 2024, our overall proved developed and undeveloped oil reserves decreased
increased by 41.5%9.6% and our previously estimated proved developed and
undeveloped oil reserve quantities were revised downwardupward by approximately 185
32 thousand barrels. This downwardupward revision was mainly the
result of aan decreaseincrease 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. 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 1718 – Supplemental Information About Oil
and Gas Producing Activities (Unaudited), to our Financial Statements.
What changed in the latest 10-Q
Risk Factors
Not applicable to smaller reporting companies.
No wording changes found in this section.
Full comparison: every changed paragraph (0)
Management's Discussion & Analysis (MD&A)
Largest changes
“Interest income for the six months ended June 30, 2026 and 2025 was $22,136 and $37,862, respectively. Interest expense for the six months ended June 30, 2026 and 2025 was $283,563 and $195,112, respectively. For the three months ended June 30, 2026 and 2025, interest expense was $142,582 and $97,933, respectively, the higher interest expense in 2026 was due to the higher notes payable balances related to the debt restructuring due to the paid-in-kind agreement.”see in full comparison
“Interest income for the three months ended March 31, 2026 and 2025, was $10,882 and $18,579, respectively. The higher 2025 interest income was due to higher bank balances during the period in 2025. Interest expense for the three months ended March 31, 2026 and 2025, was $140,981 and $97,179, respectively. The higher 2026 interest expense was due to the increase in notes payable, and the commencement of interest on notes related to the 2024 debt restructuring.”see in full comparison
We have had recurring operating and net losses and cash used in operations, and the financial statements reflect a working capital deficiency ofsee in full comparison$12,396,063$12,927,831 and an accumulated deficit of$95,385,998.$96,199,116. These factors raise substantial doubt about our ability to continue as a going concern. We anticipate that our primary sources of liquidity will be from the sale of oil and gas in the course of normal operations, the sale of oil and gas property, sales of participation interests, and the possible issuance of debt and/or equity. Management has plans to continue to increase revenues by making commitments to participate with industry partners in drilling wells in the Permian basin and will also continue to drill and workover wells in our Texas Jameson field. Although there are no assurances, Management believes that expected increases in revenue together with reduced capital expendituresexpendituresfor drilling willallowimprove theCompanyCompany’s liquidity position; however, these plans have not alleviated the substantial doubt about our ability tomeetcontinueitsasliquidityaneedsgoingthroughconcern for theremaindertwelveofmonths2026.following the date these financial statements are issued.
During the firstsee in full comparisonthreesix months of 2026, revenues from oil and gas production increased$88,971$414,272 or18.8%,50.6%, to$563,119$1,232,774 from revenues of$474,148$818,502 during the firstthreesix months of 2025. This increase was mainly due to higher oil production volumesduringandthehigherquarteroilincommodity2026.prices, partially offset by lower realized natural gas prices. The net sales volume of oil and condensate for thethreesix months endedMarchJune31,30,2026,2026 was approximately7,20013,832 barrels with an average pricepriceof$72.14$84.44 per barrel, versus5,68810,500 barrels with an average price of$71.99$66.80 per barrel for the firstthreesix months of 2025.ThisTherepresentsnet sales volume of natural gas for the six months ended June 30, 2026 was approximately 61,036 Mcf with anincreaseaverage price of $0.66 per Mcf, versus 50,801 Mcf with an average price of $2.26 per Mcf for the same period in 2025. For the quarter ended June 30, 2026, revenues from oil and gas production increased $325,301 or 94.5% to $669,655 from the 2025 second quarter revenues of $344,354, mainly due to higher oil production volumes and commodity prices. The net sales volume of1,512oil and condensate for the quarter ended June 30, 2026 was approximately 6,632 barrelsorwith26.6%.anTheaveragehigherpriceproductionofvolumes$97.78wereperduebarrel,toversuswells4,812broughtbarrelsonlinewithandanouraverageadditionalprice of $60.67 per barrel for the secondinterestsquarteracquired in existing wells inof 2025. The net sales volume of natural gas for thethree monthsquarter endedMarchJune31,30,2026,2026 was approximately 26,710 Mcf with an average34,326price of $0.19 per Mcf, versus 28,035 Mcf with an average price of$1.03 per Mcf, versus 22,767 Mcf with an average price of $2.79$1.83 per Mcf for thesamesecondperiod in 2025. This represents an increase in net sales volumequarter of11,559 Mcf or 50.8%.2025.
General and administrative expenses weresee in full comparison$474,055$1,001,350 for thethreesix months endedMarchJune31,30, 2026, compared to$466,418$852,046 for the same period in 2025, a change of$7,637$149,304 or1.6%.17.5%. For the second quarter of 2026, general and administrative expenses were $527,295 compared to $385,628 for the second quarter of 2025, an increase of $141,667 or 36.7%. These increases were mainly due to higher employee related compensation expenses. For the firstthreesix months of 2026, marketing expensesincreasedwere$35,619 or 51.6% to $104,654,$193,882, compared to$69,035$166,528 for the firstthreesix months of 2025, and $89,228 for the second quarter of 2026 compared to $97,493 for the same quarter in 2025. Marketing expense varies from period to period according to the number of marketing events attendedattendedby personnel and their associated exhibition and travel costs.
“Oil and natural gas lease operating expenses increased by $349,218 or 71.6%, to $836,701 for the six months ended June 30, 2026, from $487,483 for the same period in 2025. For the second quarter of 2026, lease operating expenses increased $132,282 or 43.5%, to $436,420 from $304,138 for the same quarter in 2025. These increases were mainly due to higher surface use fees, workover costs, and equipment repairs and maintenance during the periods in 2026. The 2025 six-month amount is presented net of the $105,494 settlement received from a vendor for an equipment failure during a workover.”see in full comparison
Full comparison: every changed paragraph (20)
Royale is an independent oil and natural gas producer.
Royale’s 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 primarily acquired and developed producing and non-producing natural gas properties in California. In
December December
2018, Royale became the operator of a newly acquired oil and gas property in Texas. The most significant factors affecting our
results 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 costscost associated with abandonment of wells.
For the six months ended June 30, 2026 and 2025, we incurred net losses of $1,632,747 and $1,290,501, respectively. For the three months ended June 30, 2026 and 2025, we incurred net losses of $813,118 and $608,550, respectively. These higher losses during the periods in 2026 were mainly due to higher lease operating expenses, increased general and administration expenses, higher interest expenses and lower gains on the settlement of asset retirement obligations.
For
the three months ended March 31, 2026 and 2025, we incurred a net loss of $819,629 and $681,951, respectively. The difference was primarily
due to a settlement recorded during the period in 2025 of approximately $105,000 from a vendor for an equipment failure during a workover.
During
the first threesix months of 2026, revenues from
oil and gas production increased $88,971$414,272 or 18.8%,50.6%, to $563,119$1,232,774 from revenues of $474,148
$818,502 during the first threesix months of 2025. This
increase was mainly due to higher oil production volumes duringand thehigher quarteroil incommodity 2026.prices, partially offset by lower realized natural gas
prices. The
net sales volume of oil and condensate for the threesix months ended MarchJune 31,30, 2026,2026 was approximately 7,20013,832 barrels with an average
price price
of $72.14$84.44 per barrel, versus 5,68810,500 barrels with an average price of $71.99$66.80 per barrel for the first threesix months of 2025. ThisThe representsnet
sales volume of natural gas for the six months ended June 30, 2026 was approximately 61,036 Mcf with an increaseaverage price of $0.66 per Mcf,
versus 50,801 Mcf with an average price of $2.26 per Mcf for the same period in 2025. For the quarter ended June 30, 2026, revenues from
oil and gas production increased $325,301 or 94.5% to $669,655 from the 2025 second quarter revenues of $344,354, mainly due to higher
oil production volumes and commodity prices. The net sales volume of 1,512oil and condensate for the quarter ended June 30, 2026 was approximately
6,632 barrels orwith 26.6%.an Theaverage higherprice productionof volumes$97.78 wereper duebarrel, toversus wells4,812 broughtbarrels onlinewith andan ouraverage additionalprice of $60.67 per barrel for the second
interestsquarter acquired in existing wells inof 2025. The net sales volume of natural gas for the three monthsquarter ended MarchJune 31,30, 2026,2026 was approximately 26,710 Mcf with an average
34,326price of $0.19 per Mcf, versus 28,035 Mcf with an average price of $1.03 per Mcf, versus 22,767 Mcf with an average price of $2.79$1.83 per Mcf for the samesecond period in 2025.
This represents an increase in net sales volumequarter of 11,559 Mcf or 50.8%.2025.
Oil and natural gas lease operating expenses increased by $349,218 or 71.6%, to $836,701 for the six months ended June 30, 2026, from $487,483 for the same period in 2025. For the second quarter of 2026, lease operating expenses increased $132,282 or 43.5%, to $436,420 from $304,138 for the same quarter in 2025. These increases were mainly due to higher surface use fees, workover costs, and equipment repairs and maintenance during the periods in 2026. The 2025 six-month amount is presented net of the $105,494 settlement received from a vendor for an equipment failure during a workover.
Oil
and natural gas lease operating expenses increased by $216,936 or 118.3%, to $400,281 for the three months ended March 31, 2026, from
$183,345 for the same period in 2025. This increase was partially due to a settlement recorded during the period in 2025 of $105,494
with a vendor due to an equipment failure which occurred during a workover. During the first three months of 2026, we also had higher
surface use fees and higher outside operated lease operating expenses when compared to the same period in 2025.
The
aggregate of supervisory fees and other income was $239$10,725 and $13,088$15,119
for the six months ended June 30, 2026 and 2025, respectively, and $10,486 and $2,031 for the three months endedthen Marchended. 31,These 2026 and 2025, respectively,differences
a decrease of $12,849were mainly due to higherthe timing of the receipt of rental incomefees during the firstperiods quarterin of2026 and 2025.
Depreciation,
depletion and amortization expense was $99,561$210,141 for the three six
months ended MarchJune 31,30, 2026, compared to $73,218$115,480 for the same period in 2025, and $110,580 for the second quarter of 2026 compared to
$42,262 for the second quarter of 2025. The depletion rate is calculated using production as a percentage of reserves. TheThis increase in
depletion expense was due to aan decreaseincrease in oil and gas assets during the third quarter of 2025 due to our purchase of additional interests
in expectedexisting recoverable reserves which increased the depletion rate.wells.
At MarchJune 31,30, 2026, Royale Energy had a Deferred Drilling
Obligation Obligation
of $14,799,496.$17,549,496, compared to $14,277,496 at December 31, 2025 and $14,799,496 at March 31, 2026. During the first threesix months
of 2026, although we participated in the drilling of andtwo completion of a wellwells in the Texas Permian
basin, and we did not book turnkey gains or losses
as we waited for the wells to be completed and the final costs to be determined. At MarchJune 31,30, 2025, Royale Energy had
a Deferred Drilling
Obligation of $12,032,996.$13,282,996. During the first 3six months of 2025, although we participated in the drilling and completion
of a well in the Texas Permian
basin, we did not book turnkey gains or losses as we waited for the well to be completed and the final costs to be determined.
General
and administrative expenses were $474,055 $1,001,350
for the threesix months ended MarchJune 31,30, 2026, compared to $466,418$852,046 for the same period in 2025,
a change of $7,637$149,304 or 1.6%.17.5%. For the second
quarter of 2026, general and administrative expenses were $527,295 compared to $385,628 for the second quarter of 2025, an increase of
$141,667 or 36.7%. These increases were mainly due to higher employee related compensation expenses. For the first threesix months of 2026,
marketing expenses increasedwere $35,619 or 51.6% to $104,654,$193,882, compared to
$69,035 $166,528 for the first threesix months of 2025, and $89,228 for the second quarter of 2026 compared
to $97,493 for the same quarter in 2025. Marketing expense varies from period to period according to the number of marketing events attended
attended by personnel and their associated exhibition and travel costs.
Legal
and accounting expense decreasedwas to $124,238$299,257 for the three-monthsix-month period in 2026,
compared to $245,506$305,712 for the same period in 2025, a
$121,268 $6,455 or 49.4%2.1% decrease.change. ThisFor decreasethe second quarter of 2026, legal and accounting expense
was $175,019 compared to $60,206 for the second quarter of 2025, primarily due to lowerthe auditingdelay feesin related to theour 2025 audit and its related fees, which
occurred didn’t conclude
untilduring the second quarter 2026.
During
the threesix months ended MarchJune 31,30, 2026 and
2025, we recorded Credit Loss expenses of $32,906 and $13,126, respectively, 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 threesix months ended
March 31,June 30, 2026 and 2025, we recorded gains on settlement of asset
retirement liabilityobligations of $5,676$8,132 and $5,353,$30,912, respectively, due to quarterly
reconciliations of our asset retirement obligation.obligation and, in
2025, the finalization of the plugging and abandonment of three natural gas sites in California. During the threesix months ended MarchJune 31, 30,
2025, we recorded lease impairments of $27,250
on various lease and land costs in our California natural gas fields where the carrying
value exceeded the fair value.
Interest income for the six months ended June 30, 2026 and 2025 was $22,136 and $37,862, respectively. Interest expense for the six months ended June 30, 2026 and 2025 was $283,563 and $195,112, respectively. For the three months ended June 30, 2026 and 2025, interest expense was $142,582 and $97,933, respectively, the higher interest expense in 2026 was due to the higher notes payable balances related to the debt restructuring due to the paid-in-kind agreement.
Interest
income for the three months ended March 31, 2026 and 2025, was $10,882 and $18,579, respectively. The higher 2025 interest income was
due to higher bank balances during the period in 2025. Interest expense for the three months ended March 31, 2026 and 2025, was $140,981
and $97,179, respectively. The higher 2026 interest expense was due to the increase in notes payable, and the commencement of interest
on notes related to the 2024 debt restructuring.
At
March 31,June 30, 2026, we had current assets totaling $10,257,782 $13,642,559
and current liabilities totaling $22,653,845,$26,570,390, resulting in a $12,396,063$12,927,831 working
capital deficit. We had $758,615$2,832,913 in cash and $6,736,325 $6,711,325
in restricted cash at MarchJune 31,30, 2026, compared to $1,099,044 in cash and $7,175,950
in restricted cash at December 31, 2025.
At
March 31,June 30, 2026, our other receivables, which consist
of joint interest billing receivables from direct working interest investors and
industry partners, totaled $743,671$803,398 compared to $793,608
at December 31, 2025. At MarchJune 31,30, 2026, revenue receivable was $784,531,$777,590, compared
to $694,729 at December 31, 2025, due to higher production volumes and commodity
prices duringin the period in 2026 when compared to the
fourthsecond quarter of 2025.2026. At MarchJune 31,30, 2026, our accounts payable and accrued expenses totaled $6,126,592,$7,315,027, compared to $6,033,878
at December
31, 2025, which was mainlyhigher due to higherour participation in the drilling andof liabilitytwo accrualsPermian basin wells during the period in 2026.
We have had recurring operating and net losses and
cash used in operations,
and the financial statements reflect a working capital deficiency of $12,396,063$12,927,831 and an accumulated deficit of $95,385,998.
$96,199,116. These factors
raise substantial doubt about our ability to continue as a going concern. We anticipate that our primary sources
of liquidity will be
from the sale of oil and gas in the course of normal operations, the sale of oil and gas property, sales of participation
interests, and
the possible issuance of debt and/or equity. Management has plans to continue to increase revenues by making commitments
to participate
with industry partners in drilling wells in the Permian basin and will also continue to drill and workover wells in our
Texas Jameson
field. Although there are no assurances, Management believes that expected increases in revenue together with reduced capital
expenditures expenditures
for drilling will allowimprove the CompanyCompany’s liquidity position; however, these plans have not alleviated the substantial
doubt about our ability to meetcontinue itsas liquiditya needsgoing throughconcern for the remaindertwelve ofmonths 2026.following the date these financial statements are issued.
Operating
Activities. Net cash used byin operating activities
totaled $1,051,755$173,241 and $617,612$2,247,911 for the threesix months ended MarchJune 31,30, 2026 and 2025,
respectively, a $434,143$2,074,670 or 70.3%92.3% increase.decrease Thisin increasecash
used. The decrease in cash used was mainly due to increasesincreased inaccounts other and revenue receivablespayable during
the three-monthsix month period in 2026 whenas comparedwe toparticipated in the samedrilling
of periodtwo inPermian 2025.basin wells.
Investing
Activities. Net cash provided by investing
activities totaled $274,836$1,449,650 and $569,051$1,808,069 for the threesix months ended MarchJune 31,30, 2026 and 2025,
respectively, a $294,215 or 51.7% decrease.respectively. During the three-monthsix-month period
in 2026, we received $522,000approximately $3.3 million in drilling funds, we also used
$200,000 in the acquisition of direct working interests, whileand our drilling and lease expenditures were approximately $47,000.$1.6 million,
we also used $200,000 in the acquisition of direct working interests. During
the three-monthsix-month period in 2025, we received $575,000approximately $1.8
million in drilling funds while our drilling and lease expenditures were approximately $6,000.$16,900.
Financing Activities. Net cash used in financing activities
totaled totaled
$3,135$7,165 and $2,771$5,625 for the threesix months ended MarchJune 31,30, 2026 and 2025, respectively, and the funds were used for principal payments
on on
our financing lease payments.obligations.
ROYL insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 0 Form 4 filings and open-market sales in 0 filings. Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
No Form 4 stock transactions in this period.
Well-known investors holding ROYL (13F)
None of the 59 investors we track reported a position in their latest 13F.