ROYALE ENERGY, INC. Global Pandemic
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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
Merger with
On
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Joint Venture with
On
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. These 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.
Royale's financial statements include its pro rata ownership of wells. Royale usually sells a portion of the working interest in each well it drills or participates in to third party investors 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.
Business Combinations
From time-to-time, the Company acquires businesses in the oil and gas industry. Businesses are included in the 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.
Fair value considerations include the evaluation of the underlying documentation supporting receivables, property, other assets and liabilities. If the documentation and support for a receivable or other asset represented by the seller is not deemed acceptable by the Company's auditors, the receivable or other asset is not considered in the purchase price until such time as the receivable or other asset can be proven to a level acceptable to the Company's auditors.
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Any receipts by the company of cash or other assets, subsequent to the transaction date for which the merger documentation was considered insufficient at the time of the merger, the company recognizes as a current liability. At such time as the documentation is deemed acceptable, the liability is relieved with a credit to earnings in the period of determination.
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 2019 and 2018, impairment losses of
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.
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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.
Royale 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 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 its 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 investor 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
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
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.
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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.
Going Concern
At
Results of Operations for the Year Ended
The merger between
For the year ended
Loss from Operations$ (845,071 ) $ (3,204,056 ) Other Income (Expense): Interest Expense (20,559 ) (177,171 )
Gain (Loss) on Investment in Joint Venture (397,936 ) 333,931 Gain on Settlement of Payables
897,708 287,134
Other Gain 172,523 -
Loss on Hedging Activities - (105,130 )
Loss on Issuance of Stock Warrants - (1,439,990 )
Loss on Sale of Assets, net (155,048 ) (19,199,045 )
Loss Before Income Tax Expense $ (348,383 ) $ (23,504,327 ) In 2019, the majority of the net loss resulted from a loss from operations of
During the year ended 2019, revenues from oil and gas production increased
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Oil and natural gas lease operating expenses increased by
The aggregate of supervisory fees and other income was
Depreciation, depletion and amortization expense decreased to
General and administrative expenses decreased by
At
During the first quarter in 2019, we recorded a loss on the sale of assets of
Bad debt expense for 2019 and 2018 were
Interest expense decreased to
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In 2019 and 2018, 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
Capital Resources and Liquidity
At
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.
At
Shortly before completion of the Merger, in
The Company recognized
We have not engaged in hedging activities nor do we use derivative instruments to manage market risks.
Operating Activities. For the years ended
Investing Activities. Net cash provided by investing activities totaled
Financing Activities. Net cash used by financing activities totaled
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Table of Contents Changes in Reserve Estimates
During 2019, our overall proved developed and undeveloped natural gas reserves increased by 44.2% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately .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-29.
During 2018, our overall proved developed and undeveloped reserves increased by 40.1% and our previously estimated proved developed and undeveloped reserve quantities were revised downward by approximately .40 million cubic feet of natural gas. This downward revision was mainly the result of one location with previously estimated proved undeveloped natural gas reserves which the Company had decided not to drill. See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-29.
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