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    ROYL   US78074G2003

ROYALE ENERGY, INC.

(ROYL)
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ROYALE ENERGY : Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-K)

03/30/2021 | 05:56pm EDT

2020 Challenges

In December 2019, a novel strain of coronavirus (which triggers a respiratory disease called COVID-19) was reported in Wuhan, China. The World Health Organization has declared the outbreak to constitute a "Public Health Emergency of International Concern." The COVID-19 outbreak has caused a major reduction in the consumption of hydrocarbon-based transportation fuels as airlines have grounded flights worldwide and countries around the world have asked residents to suspend automobile travel. In addition to a substantial loss of demand for crude oil, in March 2020, Saudi Arabia entered into a price war with Russia and added additional supplies of crude oil to an already over supplied market. The result has been a precipitous decline in the price of crude oil received by the Company. As a result, the Company has seen a reduction in its oil and natural gas revenues and resulting cash flows for the year 2020.



General


The following discussion should be read in conjunction with Royale's Financial Statements and Notes thereto and other financial information relating to Royale included elsewhere in this document.

Since 1993, Royale has primarily 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.

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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 a portion of the working interest in each well it drills or participates in to third-party participants 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.

The Company recorded amounts received from the Master Service Agreement ("MSA") with RMX for providing land, engineering, accounting and back-office support as part of revenues. Revenues earned under the MSA were recorded at the end of each month that services were performed in conformity with the Agreement with an offsetting receivable from the RMX joint venture. The service fee income was treated as earned at the end of each month that services were performed.



Equity Method Investments


Investments in entities over which the Company has significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents Royale's proportionate share of net income generated by the equity method. Equity method investments are included as noncurrent assets on the consolidated balance sheet.

Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.



Business Combinations


From time-to-time, the Company acquires businesses in the oil and gas industry. Businesses are included in the Company's consolidated financial statements from the date of acquisition. We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the fair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date is incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items for which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however, this period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement period will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party transaction-related costs as expense currently in the period in which they are incurred.

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.

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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 2020 and 2019, impairment losses of $0 and $977,682, 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.

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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, 2020 and 2019, Royale had deferred drilling obligations of $3,127,500 and $5,232,675 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 cash and cash equivalents 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.



Deferred Income Taxes


Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. All available evidence, both positive and negative, must be considered to determine whether, based on the weight of that evidence, a valuation allowance for deferred tax assets is needed. The Company uses information about the Company's financial position and its results of operations for the current and preceding years.

The Company must use its judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence is commensurate with the extent to which it can be objectively verified. The more negative evidence that exists, the more positive evidence is necessary and the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion or all of the deferred tax asset. A cumulative loss in recent years is a significant piece of negative evidence that is difficult to overcome.

Future realization of a tax benefit sometimes will be expected for a portion, but not all, of a deferred tax asset, and the dividing line between the two portions may be unclear. In those circumstances, application of judgment based on a careful assessment of all available evidence is required to determine the portion of a deferred tax asset for which it is more-likely-than-not a tax benefit will not be realized.




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Going Concern


At December 31, 2020, the Company has an accumulated deficit of $82,298,785, a working capital deficiency of $4,044,437 and a stockholders' deficit of $28,360,701. 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 2021 budget. Royale is in the process of selling two property groups and has recorded a current asset of $1.5 million as Long-Term Assets Held for Sale. 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, if needed to fully fund our 2021 drilling budget and to support future operations.

Results of Operations for the Year Ended December 31, 2020, as Compared to the Year Ended December 31, 2019

For the year ended December 31, 2020, we had a net loss of $8,148,147 compared to the net loss of $348,383 during the year in 2019. The table below reflects the major components of other income and expense.



                                               Year Ended December 31,
                                                 2020             2019
Loss from Operations                         $  (2,674,329 )   $ (845,071 )

Other Income (Expense):
Interest Expense                                   (12,949 )      (20,559 )

Gain (Loss) on Investment in Joint Venture (6,185,995 ) (397,936 ) Gain on Settlement of Payables

                     166,300        897,708
Other Gain                                         551,906        172,523
Gain (Loss) on Sale of Assets, net                   6,920       (155,048 )
Loss Before Income Tax Expense               $  (8,148,147 )   $ (348,383 )




In 2020, the majority of the net loss resulted from a $6,185,995 write down of our investment in RMX Resources, LLC, due to year end 2020 reserve valuations and other considerations, see Note 2 - RMX Joint Venture. In 2019, the majority of the loss resulted from a loss from Operations of $845,071.

During the year ended 2020, revenues from oil and gas production decreased $786,472 or 33.8% to $1,542,803 from the 2019 revenue of $2,329,275. This decrease was due to lower prices realized for the sale of oil and gas in 2020. The net sales volume of oil for the year ended December 31, 2020 was 31,210 barrels of oil with an average price of $37.96 versus approximately 27,663 barrels with an average price of $54.40 per barrel, for the year in 2019. This represents an increase in net sales volume of 3,547 barrels or 12.8%. The net sales volume of natural gas for the year ended December 31, 2020, was approximately 160,406 Mcf with an average price of $2.23 per Mcf, versus 292,472 Mcf with an average price of $2.82 per Mcf for the year in 2019. This represents a decrease in net sales volume of 132,066 Mcf or 45.2%. The decrease in natural gas production volume was due to certain wells that were offline and waiting on workovers and to lower volumes on existing wells due to natural declines.

Oil and natural gas lease operating expenses decreased by $366.865 or 20.8%, to $1,397,673 for the year ended December 31, 2020, from $1,764,538 for the year in 2019. This was lower in 2020 due to decreases in workover costs and outside operated lease operating costs as certain non-operated wells were offline and waiting on workovers. When measuring lease operating costs on a production or lifting cost basis, in 2020, the $1,397,673 equates to a $4.02 per Mcfe lifting cost versus a $3.85 per Mcfe lifting cost in 2019, mainly due to lower production volumes in 2020.

The aggregate of Supervisory Fees and other income was $45,052 for year ended December 31, 2020, a decrease of $592,856 or 92.9% from $637,908 during the year in 2019. This decrease was mainly due to the loss of service agreement fees through an arrangement with RMX Resources, LLC.

Depreciation, depletion and amortization expense increased to $473,647 from $468,143, an increase of $5,504 or 1.2% for the year ended December 31, 2020, as compared to the year in 2019. The depletion rate is calculated using production by comparing capitalized cost to the recoverable reserves remaining. This increase in depreciation expense was due to the decrease in reserves owned by the Company as compared to the estimated reserves in the prior year, due to the decrease in oil and gas prices in 2020.

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General and administrative expenses increased by $117,413 or 5.9% from $1,991,819 for the year ended December 31, 2019, to $2,109,232 for the year ended 2020. This increase was primarily driven by our absorption of a greater percentage of drilling management costs. Overhead and drilling overhead offset general and administrative costs. Legal and accounting expense decreased to $279,227 for the year in 2020, compared to $751,935 for the year in 2019, a $472,708 or 62.9% decrease. This decrease was primarily due to higher legal and accounting fees in 2019 as we transitioned to new auditors and to the Matrix post-merger reporting incurred during the year in 2019. Marketing expense for the year ended December 31, 2020, decreased $301,357, or 72.6%, to $113,614, compared to $414,971 for the year in 2019. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs. During 2020 fewer marketing events were attended as the governmental mandate against large gatherings was implemented.

At December 31, 2020, Royale had a Deferred Drilling Obligation of $3,127,500. During 2020, we disposed of $6,432,675 of drilling obligations upon completing the drilling of five oil wells, three in California and two in Texas, while incurring expenses of $4,732,213, resulting in a gain of $1,700,462. At December 31, 2019, Royale had a deferred drilling obligation of $5,232,675. During 2019, we disposed of $11,961,767 of drilling obligations upon completing the drilling of eight natural gas wells and participating in the drilling of two oil wells in California, while incurring expenses of $9,051,859, resulting in a gain of $2,909,908.

During the year in 2020, as disclosed above, we recorded a loss of $6,185,995, on the write down of our investment in joint venture of RMX Resources, LLC, compared to a loss of $397,936 for our 20% share of the RMX Resources net loss of $1,989,680 in 2019. During the fourth quarter we recorded a loss on assets held for sale of $566,858, in anticipation of the sale of certain oil and gas assets during the year in 2021. During the third quarter in 2020, we recorded a gain on other of $271,310 based on the contract agreement with an industry partner in the drilling of two wells. During the year in 2020, we also recorded a gain on other of $280,596 on the receipt of a pre-Matrix merger prepayment refunds. During the year in 2020, we recorded a gain on settlement of $197,800 on the forgiveness of our Small Business Administration ("SBA") Paycheck Protection Program ("PPP") loan and a loss on settlement of $31,500 related to a 2018 seismic sales agreement. During the year in 2019, we recorded geological and geophysical expense of $264,219 related mainly to the acquisition of a seismic survey of a Northern California field, while during the year in 2020, we recorded $14,392 in geological and geophysical expenses. During the year in 2019, we recorded a gain of $897,708, mainly on the reconciliation and settlement of royalties payable. During the first quarter in 2019, we recorded a loss on the sale of assets of $1,237,126 related a settlement agreement with RMX Resources, LLC. During the fourth quarter of 2019, we recorded a gain on the sale of assets of $1,254,204 on the settlement of contingent liabilities related to the merger with Matrix. During 2019, we also recorded a $172,126 loss on the sale of leases obtained in the merger. During 2019, we recorded a gain on settlement of $834,736 on the reconciliation and settlement of royalties payable. During year in 2019, we recorded a gain of $62,972 on the settlement of accounts payable. During the year in 2019, we recorded a gain of $172,523 on the receipt of tax property tax refunds due to adjusted assessments on certain leases from prior years. We periodically review our proved properties for impairment on a field-by-field basis and charge impairments of value to the expense. During 2019, we recorded lease impairments of $977,682, respectively on various lease and land costs that were no longer viable, no lease impairments were recorded in 2020. During the year in 2019, we recorded write downs of $28,343 on certain well equipment that was either written down to their current market value or were no longer useable, no equipment write-downs occurred in 2020.

Bad debt expense for 2020 and 2019 were $1,008,003 and $60,512, respectively. During the year in 2020, approximately $203,000 was related to revenue receivable from an industry partner whose collectability was in doubt. The other bad debt expenses in 2020 and 2019 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 year-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. By contract, the Company may not collect some charges from its Direct Working Interest owners for certain wells that ceased production or had been sold during the year, to the extent that these charges exceed production revenue.

Interest expense decreased to $12,949 for the year ended December 31, 2020, from $20,559 in 2019, a $7,610 decrease. This decrease was mainly due to lower principal balances on notes payable during the year in 2020.

In 2020 and 2019, 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, 2020, Royale had current assets totaling $5,070,555 and current liabilities totaling $9,114,992, a $4,044,437 working capital deficit. We had cash and cash equivalents at December 31, 2020 of $255,112 and restricted cash of $2,146,571 compared to cash and cash equivalents of $1,031,014 and restricted cash of $2,845,515 at December 31, 2019.

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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.

At December 31, 2020, our other receivables, which consist of joint interest billing receivables from direct working interest participants and industry partners, totaled $462,777, compared to $1,189,892 at December 31, 2019, a $727,115 decrease. This decrease was mainly due to increases in accounts receivable allowances in 2020. At December 31, 2020, revenue receivable was $204,149, a decrease of $385,002, compared to $589,151 at December 31, 2019, due to lower commodity prices and lower oil and gas production volumes on existing wells. At December 31, 2020, our accounts payable and accrued expenses totaled $4,161,109, a decrease of $1,869,925 from the accounts payable at December 31, 2019 of $6,031,034, mainly related to payments made on account and lower drilling accruals at year end 2020.

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, 2020 and 2019, cash used by operating activities totaled $381,116 and $3,489,482, respectively. This $3,108,336 or 89.1% decrease in cash used was primarily due to decreases in prepaid expenses and accounts payable during the period in 2020 due to the drilling and account payments in 2020.

Investing Activities. Net cash used by investing activities totaled $1,235,485 for the year ended December 31, 2020 versus net cash provided by investing activities of $1,587,821 for the year ended December 31, 2019. During 2020, our turnkey drilling expenditures were lower as we drilled five oil wells, while in 2019, we drilled eight natural gas wells and participated in the drilling of two oil wells. Additionally, during 2020 and 2019 we received approximately $4.3 million and $11 million, respectively, in direct working interest turnkey drilling investments.

Financing Activities. For the year ended December 31, 2020, net cash provided by financing activities totaled $141,755 versus net cash used by financing activities of $576,852 for the year ended December 31, 2019. During the year in 2020, we received $207,800 in a PPP loan, of which 197,800 was forgiven. We also had principal payments of approximately $66,000 on our notes payable. During 2019, a financing agreement for a seismic survey was recognized when the terms were finalized, on which there were principal payments of approximately $186,000. Additionally, in 2019, there were principal payments of approximately $391,000 on our note with Forza Operating.



Changes in Reserve Estimates


During 2020, our overall proved developed and undeveloped natural gas reserves decreased by 38.2% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 1.5 million cubic feet of natural gas. This downward revision was mainly the result of a decrease in proved developed natural gas reserves from a decrease in economic life of wells related to a decrease in future expected product price. See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-27.

During 2019, our overall proved developed and undeveloped reserves increased by 44.2% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 0.89 million 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 contracted. See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-27.

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