Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-B is not contained herein, and will not be contained, to the best or registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐
Indicate by check mark whether the registrant is large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definition of “large accelerated filer,” accelerated filer” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
At June 30, 2019, the end of the registrant’s most recently completed second fiscal quarter; the aggregate market value of common equity held by non-affiliates was $8,024,089.
At March 6, 2020, 52,231,899 shares of registrant’s Common Stock were outstanding.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
This summary of significant accounting policies of Royale Energy, Inc. (in these notes sometimes called “Royale Energy,” “Royale,” or the “Company”) is presented to assist in understanding Royale Energy’s financial statements. See Note 2 – Merger With Matrix Oil Management Corporation And Formation Of RMX below.
These consolidated financial statements include the accounts of our controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. The financial statements and notes are representations of Royale Energy’s management, which is responsible for their integrity and objectivity. These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the financial statements.
Description of Business
Royale Energy is an independent oil and gas producer which also has operations in the area of turnkey drilling. Royale Energy owns wells and leases in major geological basins located primarily in California, Texas, Oklahoma, Colorado, and Utah. Royale Energy offers fractional working interests and seeks to minimize the risks of oil and gas drilling by selling multiple well drilling projects which do not include the use of debt financing.
Use of Estimates
The accompanying financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and 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. Actual results could differ from those estimates.
Estimated quantities of crude oil and condensate, NGLs and natural gas reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and condensate, NGLs and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and natural gas that are ultimately recovered. See Note 17 - Supplemental Information About Oil And Gas Producing Activities (Unaudited) for further detail.
Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, asset retirement obligations, valuation of derivative instruments and valuation allowances for deferred tax assets, among others. Although we believe these estimates, actual results could differ from these estimates.
Liquidity and Going Concern
The primary sources of liquidity have historically been issuances of common stock and operations. There are factors that give rise to substantial doubt about the Company’s ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business and the sale of non-strategic assets.
The Company’s 2019 consolidated financial statements reflect a working capital deficiency of $3,425,012 and a net loss from operations of $845,071. These factors raise substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.
Management’s plans to alleviate the going concern by cost control measures that include the reduction of overhead costs and the sale of non-strategic assets. There is no assurance that additional financing will be available when needed or that management will be able to obtain financing on terms acceptable to the Company and whether the Company will become profitable and generate positive operating cash flow. If the Company is unable to raise sufficient additional funds, it will have to develop and implement a plan to further extend payables, attempt to extend note repayments, and reduce overhead until sufficient additional capital is raised to support further operations. There can be no assurance that such a plan will be successful.
Restricted Cash
Royale sponsors turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay Royale the full contract price upon execution of the drilling agreement. Each participant earns an undivided interest in the well bore at the completion of the well. A portion of the funds received in advance of the drilling of a well from a working interest participant are held for the expressed purpose of drilling a well. If something changes, the Company may designate these funds for a substitute well. Under certain conditions, a portion of these funds may be required to be returned to a participant. Once the well is drilled, the funds are used to satisfy the drilling cost. Royale classifies these funds prior to commencement of drilling as restricted cash based on guidance codified as under the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 230-10-50-8. In the event that progress payments are made from these funds, they are recorded as Prepaid Expenses and Other Current Assets.
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the statement of financial position that sum to the total of the same amounts shown in the statement of cash flows.
|
|
Year Ended December 31,
|
|
|
|
2019
|
|
|
2018
|
|
Cash and cash equivalents
|
|
$
|
1,031,014
|
|
|
$
|
1,853,742
|
|
Restricted cash
|
|
|
2,845,515
|
|
|
|
4,501,300
|
|
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows
|
|
|
3,876,529
|
|
|
|
6,355,042
|
|
Equity Method Investments
Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected in revenue and other income in our consolidated statements of income. 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 as called for under ASC 323. 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.
The earnings from RMX reflected in these financial statements as Investment in JV, reflect our share of net earnings or losses directly attributable to this equity method investment. We evaluated our investment in RMX as of December 31, 2019, and determined that any losses were not other than temporary.
Revenue Recognition
On January 1, 2018, we adopted the new ASC 606, Revenue from Contracts with Customers and all the related amendments (“new revenue standard”) using the modified retrospective method.
We evaluated the effect of transition by applying the provisions of the new revenue standard to contracts with remaining obligations as of January 1, 2018. No cumulative adjustment to retained earnings was necessary as a result of adopting this standard.
A significant portion of our revenues are derived from the sale of crude oil and condensate, natural gas liquids (“NGLs”) and natural gas under spot and term agreements with our customers.
|
|
Year Ended December 31,
|
|
|
|
2019
|
|
|
2018
|
|
Oil & Condensate Sales
|
|
$
|
1,504,936
|
|
|
$
|
1,211,818
|
|
Natural Gas Sales
|
|
|
824,339
|
|
|
|
385,803
|
|
NGL Sales
|
|
|
-
|
|
|
|
1,741
|
|
|
|
$
|
2,329,275
|
|
|
$
|
1,599,362
|
|
The pricing in our hydrocarbon sales agreements are variable, determined using various published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications.
In limited cases, we may also collect advance payments from customers as stipulated in our agreements; payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheet.
Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenue in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons.
We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, and such reimbursements are recorded as cost reimbursements.
We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. Those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore, we act as a principal only in regards to the sale of our share of production and recognize revenue for the volumes associated with our net production.
The Company frequently 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. The Company typically guarantees a cost to drill to the third-party drilling participants and records a loss or gain on the difference between the guaranteed price and the actual cost to drill the well. When monies are received from third parties for future drilling obligations, the Company records the liability as Turnkey Drilling Obligations. Once the contracted depth for the drilling of the well is reached and a determination as to the commercial viability of the well (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss.
Crude oil and condensate
For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks or vessels.
Natural Gas and NGLs
When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control, as defined in the new revenue standard, is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs.
The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated statement of operations, since we make those payments in exchange for distinct services with the exception of natural gas sold to PG&E where transportation is netted directly against revenue. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the customer.
Turnkey Drilling Obligations
These Turnkey Agreements are managed by the Company for the participants of the well. The collections of pre-drilling AFE amounts are segregated by the Company and the gains and losses on the Turnkey Agreements are recorded in income or expense at the time of the casing point election in accordance with ASC 932-323-25 and 932-360. The Company manages the performance obligation for the well participants and only records revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied.
Supervisory Fees and Other
These amounts include proceeds from the Master Service Agreement (“MSA”) with RMX for the providing of land, engineering, accounting and support services for the RMX joint venture. Revenues earned under the MSA were recorded at the end of each month that services were performed, in conformity with the Agreement. The service fee income was deemed earned at the end of each month that services were performed as prescribed by the contract. During 2018, we recognized $1,620,000 or 49.3% of our total revenues from these services. Royale had a single supervisory fee customer, that being RMX, which represented 100% of the Supervisory Fee income. On December 31, 2018, Royale received notice of cancelation of the MSA by RMX effective March 31, 2019. For the year ended 2019, the Company recognized $540,000 in supervisory fees from RMX. Also included in the caption are Pipeline and Compressor fees which are received and allocated based on production volumes.
Oil and Gas Property and Equipment
Successful efforts
Royale Energy uses the “successful efforts” method to account for its exploration and production activities. Under this method, Royale Energy 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 Energy amortizes the costs of productive wells under the unit-of-production method.
Royale Energy 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 Energy 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 Cost
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 Energy’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.
Depreciation, Depletion and Amortization
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 drilling phase commences with the development of the detailed engineering design and ends when the 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.
Impairment
We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of income. During 2019 and 2018, impairment losses of $977,682 and $1,183,515, respectively, were recorded on various capitalized base and land costs as well as certain fields acquired through the merger with the matrix entities.
Upon the sale or retirement of a complete field of a proved property, Royale Energy eliminates the cost from its books, and the resultant gain or loss is recorded to Royale Energy’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 Energy’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 Energy’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.
Turnkey Drilling
Royale Energy sponsors turnkey drilling agreement arrangements in proved and unproved 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 Energy the full contract price upon execution of the agreement. Royale Energy 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 Energy 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 and the interest is conveyed to the participant.
A certain portion of the turnkey drilling participant’s funds received are non-refundable. The Company holds all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At December 31, 2019 and 2018, Royale Energy had Deferred Drilling Obligations of $5,232,675 and $6,213,283, respectively.
If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, Royale would retain the non-refundable portion of the contact 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.
Other Receivables
Our other receivables consist of receivables from direct working interest investors and industry partners. We provide for uncollectible accounts receivable using the allowance method of accounting for bad debts. Under this method of accounting, a provision for uncollectible accounts is charged directly to bad debt expense when it becomes probable the receivable will not be collected. The allowance account is increased or decreased based on past collection history and management’s evaluation of accounts receivable. All amounts considered uncollectible are charged against the allowance account and recoveries of previously charged off accounts are added to the allowance. At December 31, 2019 and 2018, the Company established an allowance for uncollectable accounts of $1,791,162 and $2,296,384, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. During 2019, the Company closed a number of accounts as uncollectable, offsetting the allowance in the amount of $519,333.
Revenue Receivables
Our revenue receivables consist of receivables related to the sale of our natural gas and oil. Once a production month is completed, we receive payment approximately 15 to 30 days later. Historically, Royale has not had issues related to the collection of revenue receivables, and as such has determined that an allowance for revenue receivables is not currently necessary.
Equipment and Fixtures
Equipment and fixtures are stated at cost and depreciated over the estimated useful lives of the assets, which range from three to seven years, using the straight-line method. Repairs and maintenance are charged to expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in income. Maintenance and repairs, which neither materially add to the value of the property nor appreciably prolong its life, are charged to expense as incurred. Gains or losses on dispositions of property and equipment, other than oil and gas, are reflected in operations.
Income (Loss) Per Share
Basic and diluted losses per share are calculated as follows:
|
|
Year Ended December 31,
|
|
|
|
2019
|
|
|
2018
|
|
|
|
Basic
|
|
|
Diluted
|
|
|
Basic
|
|
|
Diluted
|
|
Net Loss
|
|
$
|
(348,383
|
)
|
|
$
|
(348,383
|
)
|
|
$
|
(23,504,327
|
)
|
|
$
|
(23,504,327
|
)
|
Less: Preferred Stock Dividend
|
|
|
734,725
|
|
|
|
734,725
|
|
|
|
594,613
|
|
|
|
594,613
|
|
Less: Preferred Stock Dividend in Arrears
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Net Loss Attributable to Common Shareholders
|
|
|
(1,083,108
|
)
|
|
|
(1,083,108
|
)
|
|
|
(24,098,940
|
)
|
|
|
(24,098,940
|
)
|
Weighted average common shares outstanding
|
|
|
50,871,447
|
|
|
|
50,871,447
|
|
|
|
44,174,209
|
|
|
|
44,174,209
|
|
Effect of dilutive securities
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Weighted average common shares, including Dilutive effect
|
|
|
50,871,447
|
|
|
|
50,871,447
|
|
|
|
44,174,209
|
|
|
|
44,174,209
|
|
Per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss
|
|
$
|
(0.02
|
)
|
|
$
|
(0.02
|
)
|
|
$
|
(0.55
|
)
|
|
$
|
(0.55
|
)
|
For the years ended December 31, 2019 and 2018, Royale Energy had dilutive securities of 23,947,519 and 24,049,443, respectively. These securities were not included in the dilutive loss per share due to their antidilutive nature.
Stock Based Compensation
Royale has a stock-based employee compensation plan, which is more fully described in Note 11 - Stock Compensation Plan. The Company has adopted ASC 718 for share-based payments. This topic requires that the cost resulting from all share-based payment transactions be recognized in the financial statements. It further establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires all entities to apply a fair-value based measurement method in accounting for share-based payment transactions with employees except for equity instruments held by employee stock ownership plans. Shares issued in connection with a business combination as part of the consideration transferred in exchange for the acquiree are treated within the scope of ASC 805.
Income Taxes
Royale utilizes the asset and liability approach to measure deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with the Income Taxes Topic of the ASC740. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Under the Topic, deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
The provision for income taxes is based on pretax financial accounting income. Deferred tax assets and liabilities are recognized for the expected tax consequences of temporary differences between the tax basis of assets and liabilities and their reported net amounts.
Fair Value Measurements
According to Fair Value Measurements and Disclosures Topic of the ASC, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in period subsequent to initial recognition, the reporting entity shall disclose information that enable users of its financial statements to assess the inputs used to develop those measurements and for recurring fair value measurements using significant unobservable inputs, the effect of the measurements on earnings for the period.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining fair value, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considers counterparty credit risk in its assessment of fair value. Carrying amounts of the Company’s financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities.
The fair value hierarchy distinguishes between (1) market participant assumptions developed based on market data obtained from independent sources (observable inputs) and (2) an entity’s own assumptions about market participant assumptions developed based on the best information available in the circumstances (unobservable inputs). The fair value hierarchy consists of three broad levels, which gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are described below:
Level 1: Quoted prices (unadjusted) in active markets that are accessible at the measurement date for assets or liabilities.
Level 2: Directly or indirectly observable inputs as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.
Level 3: Unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management’s estimates of market participant assumptions
At December 31, 2019 and 2018, Royale Energy does not have any financial assets measured and recognized at fair value on a recurring basis. The Company estimates asset retirement obligations pursuant to the provisions of ASC 410, “Asset Retirement and Environmental Obligations”. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 3 – Oil and Gas Properties, Equipment and Fixtures for further discussion of the Company’s asset retirement obligations.
Accounts Payable and Accrued Expenses
At December 31, 2019 and 2018, the components of accounts payable and accrued expenses consisted of:
|
|
2019
|
|
|
2018
|
|
Trade Payables including accruals
|
|
|
3,107,012
|
|
|
|
2,589,518
|
|
Direct working interest investors related accruals
|
|
|
1,811,649
|
|
|
|
1,223,588
|
|
Current drilling efforts accrued expenses
|
|
|
508,246
|
|
|
|
413,701
|
|
Accrued Liabilities
|
|
|
393,245
|
|
|
|
391,641
|
|
Employee related accruals
|
|
|
195,998
|
|
|
|
232,010
|
|
Deferred rent
|
|
|
14,884
|
|
|
|
32,752
|
|
Federal and State income taxes payable
|
|
|
-
|
|
|
|
12,323
|
|
|
|
|
6,031,034
|
|
|
|
4,895,533
|
|
Accrued– Non-current
At December 31, 2019, the Company had non-current accrued liabilities of $1,306,605 and accrued unpaid guaranteed payment of $1,616,205, due to certain Matrix principals, from periods prior to the Merger. See NOTE 2 – Merger with Matrix Oil Management Corporation and Formation of RMX.
Note Settlements
On August 2, 2017, one year from the date of issuance, two notes totaling $1,580,000 matured, with a default rate of 25%. In the first quarter 2018, the $300,000 note was converted into 750,000 shares of Royale common stock, and Royale agreed to a cash settlement with the holder of the $1,280,000 note for $1,900,000.
Business Combinations
From time-to-time, the Company acquires businesses in the oil and gas industry. Royale primarily targets businesses in geological basins that the Company considers to be in a focus area. 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.
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.
Accounting Standards
Recently Adopted
ASU 2017-12, Derivatives and hedging – Targeted Improvement to Accounting for Hedging Activities
In August 2017, the FASB issued an ASU to amend the hedge accounting rules to simplify the application of hedge accounting guidance and better portray the economic results of risk management activities in the financial statements. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirements to separately measure and report hedge ineffectiveness and eases certain hedge effectiveness assessment requirements. The guidance was effective beginning in 2019. Adoption of this standard did not have a material impact on our consolidated financial statements.
ASU 2016-02 and 2018-11, Leases
In February 2016, the FASB established Topic 842, Leases, by issuing Accounting Standards Update (ASU) No. 2016-02, which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. Topic 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. The new standard establishes a right-of-use model (“ROU”) that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases with a term longer than 12 months. As a public company, the new standard is effective for us on January 1, 2019. A modified retrospective transition approach is the implementation methodology we have selected; applying the new standard to all leases existing at the date of initial application, in this case January 1, 2019. Consequently, financial information has not been updated and the disclosures required under the new standard have not been provided for dates and periods before January 1, 2019.
The new standard provides a number of optional practical expedients for the transition. We have elected the ‘package of practical expedients’, which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. We do not expect to elect the use-of hindsight or the practical expedient pertaining to land easements; the latter not being applicable to us. We have elected all of the new standard’s available transition practical expedients.
The standard did not materially impact our consolidated results of operations, earnings per share, and had no impact on cash flows. The most significant effects relate to: (1) the recognition of new ROU assets in long-term assets on the balance sheet; (2) lease liabilities, both short-term and long-term, on our balance sheet; and, (3) providing significant new disclosures about our leasing activities. We do not expect a significant change in our leasing activities as a result of the adoption of this new pronouncement. See Note 9- Operating Leases
NOTE 2 – MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX
Merger
On March 7, 2018, Royale Energy, Inc. (“Royale Energy,” formerly known as Royale Energy Holdings, Inc., a Delaware corporation), Royale Energy Funds, Inc. (“REF,” formerly known as Royale Energy, Inc., a California corporation), and Matrix Oil Management Corporation (“Matrix”) and its affiliates were notified by the California Secretary of State of the filing and acceptance of agreements of merger by the California Secretary of State, to complete the previously announced merger between the companies (the “Merger”). In the Merger, REF was merged into a newly formed subsidiary of Royale Energy, and Matrix was merged into a second newly formed subsidiary of Royale Energy pursuant to the Amended and Restated Agreement and Plan of Merger among REF, Royale Energy, Royale Merger Sub, Inc., (“Royale Merger Sub”), Matrix Merger Sub, Inc., (“Matrix Merger Sub”) and Matrix (the “Merger Agreement”). Additionally, in connection with the merger, all limited partnership interest of two limited partnership affiliates of Matrix (Matrix Permian Investments, LP, and Matrix Las Cienegas Limited Partnership), were exchanged for Royale Energy common stock using conversion ratios according to the relative values of each partnership. All Class A limited partnership interests of another Matrix affiliate, Matrix Investments, LP (“Matrix Investments”) were exchanged for Royale Energy Common stock using conversion ratios according to the relative value of the Class A limited partnership interests, and $20,124,000 of Matrix Investments preferred limited partnership interests were converted into 2,012,400 shares of Series B Convertible Preferred Stock of Royale Energy. Another Matrix affiliate, Matrix Oil Corporation (“Matrix Operator”), was acquired by Royale Energy by exchanging Royale Energy common stock for the outstanding common stock of Matrix Oil Corporation using a conversion ratio according to the relative value of the Matrix Oil Corporation common stock. Matrix, Matrix Oil Corporation and the three limited partnership affiliates of Matrix called the “Matrix Entities.”
The Merger had been previously approved by the respective holders of all outstanding capital stock of REF, Matrix, Royale Energy, Matrix Merger Sub and Royale Merger Sub on November 16, 2017, as previously reported in our Current Report on Form 8-K dated November 16, 2017. The Merger and related transactions are described in more detail in our Form 8-K dated March 7, 2018 (SEC File No. 000-55912).
As a result of the Merger, REF became a wholly owned subsidiary of Royale Energy, and each outstanding share of common stock of REF at the time of the Merger was converted into one share of common stock of Royale Energy. The common stock of Royale Energy is traded on the Over-The-Counter QB (OTCQB) Market System (symbol ROYL).
Under ASC 805, Business Combinations, which among other things requires the assets acquired and liabilities assumed to be measured and recorded at their fair values as of the acquisition date, the Company was determined to be the acquirer and as such, the acquisition was accounted for as a business combination.
The preliminary allocation of the purchase price was determined in arms’ length negotiations between the parties. Substantially all of the value of the transaction was related to the value of the oil and gas assets acquired with minimal value ascribed to the other assets. The Company considered two valuation methods in its determination of fair value for the oil and natural gas properties; the discounted cash flow analysis and comparable transaction analysis. Assumptions for the discounted cash flow analysis include commodity price, operating costs and capital outlay for future development of the acquired properties, pricing differentials, reserve risking, and discount rates. NYMEX strip pricing, less applicable pricing differentials, was utilized in the discounted cash flow analysis. Risking levels in the discounted cash flow analysis are determined based on a variety of factors, such as existing well performance, offset production and analogue wells. Discount rates used in the discounted cash flow analysis were determined by using the estimated cost of capital, discount rates, as well as industry knowledge and experience. The comparable transaction analysis was performed to establish a range of fair values for similarly situated oil and gas properties that were recently bought or sold in arms-length, observable market transactions. The range of value observed from the Company’s analysis of recent market transactions was then utilized as a basis for evaluating the fair value determined via the discounted cash flow method. The Company’s fair value conclusion indicated that the discounted cash flow method valuation is in line with the same range as the comparable transactions reviewed, when considering the comparable transactions. Other current liabilities assumed in the acquisition, were carried over at historical carrying values because the assets and liabilities are short term in nature and their carrying values are estimated to represent the best estimate of fair value.
The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed:
|
|
March 7, 2018
|
|
Consideration:
|
|
|
|
|
Value of Royale Common Stock issued
|
|
$
|
9,546,068
|
|
Value of Series B Convertible Preferred Stock issued
|
|
|
20,124,000
|
|
Total consideration
|
|
$
|
29,670,068
|
|
Fair Value of Liabilities Assumed:
|
|
Current liabilities
|
|
|
19,624,592
|
|
Other liabilities
|
|
|
3,125,394
|
|
Asset Retirement obligations
|
|
|
1,419,544
|
|
Total fair value of liabilities assumed
|
|
|
24,169,530
|
|
Total consideration plus liabilities assumed
|
|
$
|
53,839,598
|
|
Fair Value of Assets Acquired:
|
|
Cash
|
|
$
|
548,805
|
|
Current assets
|
|
|
1,073,532
|
|
Proved and unproved crude oil and gas properties
|
|
|
51,214,512
|
|
Land
|
|
|
1,002,750
|
|
Total Fair Value of Assets Acquired
|
|
$
|
53,839,598
|
|
In accordance with ASC 805, the following unaudited supplemental pro forma condensed results of operations present combined information as though the business combination had been completed as of January 1, 2018. The unaudited supplemental pro forma financial information was derived from the historical revenues and direct operating expenses of Royale Energy, Inc. and Matrix Oil Management Corporation and its affiliates. These unaudited supplemental pro forma results of operations for the consolidated companies as of December 31, 2018, are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the consolidated company for the periods presented or that may be achieved by the consolidated company in the future.
|
|
Year ended December 31, 2018
|
|
|
|
Royale Energy, Inc.
|
|
|
Matrix Oil Management Corp
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
723,172
|
|
|
$
|
1,199,684
|
|
|
$
|
1,922,856
|
|
Net Loss
|
|
$
|
(1,633,713
|
)
|
|
$
|
(149,936
|
)
|
|
$
|
(1,783,649
|
)
|
Net Loss available to common shareholders
|
|
$
|
(1,633,713
|
)
|
|
$
|
(149,936
|
)
|
|
$
|
(1,783,649
|
)
|
Pro forma Loss per common share Basic and diluted
|
|
$
|
(0.04
|
)
|
|
$
|
(0.00
|
)
|
|
$
|
(0.04
|
)
|
Amounts previously estimated have changed during the measurement period. The changes in estimates included an increase of $2,581,641 million of oil and gas properties and a decrease of $2,581,641 million in accounts receivable and other current assets. We recorded measurement-period adjustments in the fourth quarter of 2018. Depletion expense increased by an immaterial amount as a result of these measurement-period adjustments and all amounts referenced below are inclusive of these measurement period adjustments. As of December 31, 2018, the purchase accounting for the Matrix acquisition was complete.
|
|
Original
|
|
|
Adjustment
|
|
|
Revised
|
|
Cash
|
|
$
|
548,805
|
|
|
$
|
-
|
|
|
$
|
548,805
|
|
Current Assets
|
|
$
|
3,655,173
|
|
|
$
|
(2,581,641
|
)
|
|
$
|
1,073,532
|
|
Oil and gas properties
|
|
$
|
48,632,870
|
|
|
$
|
2,581,641
|
|
|
$
|
51,214,512
|
|
Formation of RMX and Asset Contribution
On April 13, 2018, Royale Energy, Inc., and two of Royale’s subsidiaries, Royale Energy Funds, Inc. and Matrix Oil Management Corporation (the “Royale Entities”) completed the Subscription and Contribution Agreement (“Contribution Agreement”), in which the Royale Entities and CIC RMX LP (“CIC”) entered into the Contribution Agreement and certain other agreements providing that the Royale Entities would contribute certain assets to RMX Resources, LLC (“RMX”), a newly formed Texas limited liability company formed to facilitate the investment from CIC. In exchange for its contributed assets, Royale received a 20% equity interest in RMX, an equity performance incentive interest and up to $20.0 million to pay off Royale Entities senior lender, Arena Limited SPV, LLC., in full, and to pay Royale Entities trade payables and other outstanding obligations. CIC contributed an aggregate of $25.0 million in cash to RMX in exchange for (i) an 80% equity interest in RMX with preferred distributions until certain thresholds are met, (ii) a warrant (“Warrant”) to acquire up to 4,000,000 shares of Royale’s common stock at an exercise price of $.01 per share and registration rights pursuant to a Registration Rights Agreement.
The Contribution Agreement was completed in a two-step closing and funding, with the First Closing consummated on April 4, 2018 and the Second Closing consummated on April 13, 2018 with the Royale Entities. In connection with the Second Closing, the parties entered into a letter agreement related to the preliminary Settlement Statement process. The parties agreed that, in lieu of the payment originally contemplated under Section 1.6(v) of the Contribution Agreement, the Royale Entities would receive the sum of $4,000,000, subject to adjustment. The $4,000,000 delivered at the Second Closing was an advance against amounts due the Royale Entities as Purchase Price, and the advance was subject to further adjustment in accordance with the Contribution Agreement.
RMX has a six-member board of managers. Royale has two seats on the board giving it a third of the Board. Royale has designated Michael McCaskey and Johnny Jordan as its members of the RMX board. The return targets for CIC through its funding of RMX provide for a “waterfall” style return profile with the first distributions going to CIC until it has received all Unpaid Preferred Return and Unpaid Preferred Enhanced Return, as defined by the Company’s Agreement.
As part of the formation of the joint venture, Royale contributed Matrix Oil Corporation (“MOC”) to RMX. MOC has the permits and licenses to operating oil and gas properties in California. It was the operating entity for the Matrix group of companies that were acquired on February 28, 2018, discussed above. This allows the RMX joint venture to be the operator of record for the contributed assets.
Royale accounts for its ownership interest in RMX following the equity method of accounting, in accordance with ASC 323. Pursuant to the Subscription and Contribution agreement, Royale has an initial equity value of $6.25 million or 20% of the total equity of the joint venture with CIC having an initial equity value of $25.0 million or 80% of the total equity of the joint venture.
The Royale Entities contributed 100% of their interest in the Sansinena Field, 100% of the Sempra Field, 50% of the Bellevue Field, 100% of the Whittier Main Field, and 50% of the Whittier Field. The result of the transfer of oil and gas properties and surface rights for cash as described above and a 20% interest in RMX resulted in Royale recording a loss of approximately $17.9 million. The issuance by Royale of warrants to acquire 4,000,000 shares of Royale common stock, by CIC, caused Royale to record a loss of approximately $1.44 million. In addition, the Contribution Agreement called for an effective date of the property transfer of February 28, 2018 which required a purchase price adjustment of approximately $334,000 in the form of a cash contribution to RMX and an increase in the loss on the sale. The transfer of MOC to RMX as the operating company provided an amount due Royale of approximately $640,000, which was recorded as a due from affiliate during the period in 2018.
Under the provisions of the Amended and Restated Limited Liability Company Agreement of RMX Resources, LLC (“RMX Agreement”) dated March 27, 2018, the gains and losses of the partnership are distributed as if all of RMX’s assets were sold for cash at a price equal to their book basis and all RMX liabilities were satisfied at their book basis and all of the remaining assets of RMX were distributed in accordance with Section 5.4 of the RMX Agreement. Notwithstanding the above, for each fiscal year or other relevant period, deductions attributable to exploration costs, IDCs, and operating and maintenance costs shall be allocated 100% to the CIC members pro rata in accordance with their Class B percentage interests for each fiscal year.
The RMX joint venture has a senior revolving loan facility with Washington Federal Bank. The borrowing base of the facility is $25.0 million with $19,403,800 drawn at December 31, 2019.
RMX MSA
As part of the joint venture, RMX entered into a Master Service Agreement (“MSA”) calling for Royale Energy to provide land, engineering and support services for the joint venture. For these services, Royale received $180,000 per month for the first year. These amounts are included in Supervisory Fees, Service Agreement and Other as more fully described in Note 1.
On December 31, 2018, Royale was formally notified of RMX’s intent to terminate the MSA as of March 31, 2019. The Termination Notice called for Royale to continue to provide accounting and other services through March 31, 2019.
Post-Closing
On March 11, 2019, Royale entered into a Settlement Agreement with RMX Resources to resolve differences resulting from the calculation of certain post-closing amounts as called for under Section 7.3 of the Subscription and Contribution Agreement. In settlement of these differences, Royale has agreed to assign its remaining interests in the Bellevue Field, located in Kern County and the W. Whittier Field located in Los Angeles County, California to RMX. These fields accounted for 5.145 and 140.647 Mboe in reserves and were valued at $67,671 and $2.4 million, respectively using SEC pricing and discounted at 10 percent at December 31, 2018.
Royale will continue to be responsible for the liability for the payment of all royalties and suspended funds incurred prior to March 1, 2018. Also as part of this Settlement Agreement, RMX will offer Royale the right, but not the obligation to participate in a portion of the working interest, in a number of wells to be drilled in the Sansinena, Sempra, Whittier and/or East LA properties in Los Angeles County, California.. The minimum number of wells to be offered to Royale in each year is 2 net wells as determined by an agreed upon methodology. The Agreement also calls for certain credits toward future drilling costs of the offered wells. The Company recorded a loss of $1,237,126 on the settlement, recorded in Loss on Sale of Assets in the Statement of Operations.
In conjunction with the merger between the Matrix entities and Royale, there were $1,254,204 of assets included on the books of Matrix for which documentary support could not be identified. At December 31, 2018 the Company concluded that these amounts were a contingent liability and recorded them in Current - Accrued Liabilities. On October 11, 2019, the Company received documentary support enabling management to conclude that the liability was no longer probable and should be derecognized. The Company recorded a gain of $1,254,204 on extinguishment, recorded in Loss on Sale of Assets in the Statement of Operations.
Listed below is summarized information the Company’s investment in RMX:
|
|
Twelve Months Ended
December 31, 2019
|
|
|
March 27, 2018
(Inception) through
December 31, 2018
|
|
|
|
RMX Resources, LLC
|
|
|
RMX Resources, LLC
|
|
Balance Sheet:
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
72,401,841
|
|
|
$
|
71,758,262
|
|
Total Liabilities
|
|
$
|
41,573,426
|
|
|
$
|
38,838,608
|
|
Members Equity
|
|
$
|
30,828,415
|
|
|
$
|
32,919,654
|
|
Results of Operations:
|
|
|
|
|
|
|
|
|
Net operating revenue
|
|
$
|
16,392,305
|
|
|
$
|
8,773,661
|
|
Loss from operations
|
|
$
|
1,456,290
|
|
|
$
|
(181,464
|
)
|
Net income
|
|
$
|
(2,091,239
|
)
|
|
$
|
1,669,654
|
|
NOTE 3 – OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES
Oil and gas properties, equipment and fixtures consist of:
|
|
Year ended December 31,
|
|
|
|
2019
|
|
|
2018
|
|
Oil and Gas
|
|
|
|
|
|
|
|
|
Producing properties, including intangible drilling costs
|
|
$
|
7,792,156
|
|
|
$
|
9,340,779
|
|
Undeveloped properties
|
|
|
46,990
|
|
|
|
25,582
|
|
Lease and well equipment
|
|
|
3,304,565
|
|
|
|
3,350,893
|
|
|
|
|
11,143,711
|
|
|
|
12,717,254
|
|
Accumulated depletion, depreciation and amortization
|
|
|
(6,559,182
|
)
|
|
|
(6,402,657
|
)
|
Net capitalized costs Total
|
|
$
|
4,584,529
|
|
|
$
|
6,314,597
|
|
Commercial and Other
|
|
2019
|
|
|
2018
|
|
Real estate, including furniture and fixtures
|
|
$
|
-
|
|
|
$
|
83,405
|
|
Vehicles
|
|
|
40,061
|
|
|
|
40,061
|
|
Furniture and equipment
|
|
|
1,097,428
|
|
|
|
1,095,149
|
|
|
|
|
1,137,489
|
|
|
|
1,218,615
|
|
Accumulated depreciation
|
|
|
(1,131,028
|
)
|
|
|
(1,125,722
|
)
|
|
|
|
6,461
|
|
|
|
92,893
|
|
Net capitalized costs Total
|
|
$
|
4,590,990
|
|
|
$
|
6,407,490
|
|
The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31:
|
|
Year ended December 31,
|
|
|
|
2019
|
|
|
2018
|
|
Acquisition - Proved
|
|
$
|
-
|
|
|
$
|
-
|
|
Acquisition - Unproved
|
|
|
-
|
|
|
|
-
|
|
Development
|
|
|
9,680,298
|
|
|
|
3,838,998
|
|
Exploration
|
|
|
-
|
|
|
|
-
|
|
The guidance set forth in the Continued Capitalization of Exploratory Well Costs paragraph of the Extractive Activities Topic of the FASB ASC requires that we evaluate all existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a fiscal period. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2019 and 2018. We did not charge any previously capitalized exploratory well costs to expense upon adoption of Topic. Undeveloped properties are not subject to depletion, depreciation or amortization.
|
|
Year ended December 31,
|
|
|
|
2019
|
|
|
2018
|
|
Beginning balance at January 1
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Ending balance at December 31
|
|
|
-
|
|
|
|
-
|
|
Results of Operations from Oil and Gas Producing and Exploration Activities
The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) are as follows:
|
|
Year Ended December 31,
|
|
|
|
2019
|
|
|
2018
|
|
Oil and gas sales
|
|
$
|
2,329,275
|
|
|
$
|
1,599,362
|
|
Production related costs (Lease Operating)
|
|
|
(1,764,538
|
)
|
|
|
(1,613,368
|
)
|
Impairment
|
|
|
(977,682
|
)
|
|
|
(1,183,515
|
)
|
Depreciation, depletion and amortization
|
|
|
(468,143
|
)
|
|
|
(722,935
|
)
|
|
|
|
|
|
|
|
|
|
Results of operations from producing and exploration activities
|
|
$
|
(881,088
|
)
|
|
$
|
(1,920,456
|
)
|
Income Taxes (Benefit)
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Net Results
|
|
$
|
(881,088
|
)
|
|
$
|
(1,920,456
|
)
|
NOTE 4 – ASSET RETIREMENT OBLIGATION
The Asset Retirement and Environmental Obligations Topic of the ASC requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at the estimated fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is included as part of Depreciation, Depletion and Amortization in the Consolidated Statement of Operations The fair value of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset. During the year ended December 31, 2019, the Company recorded $922,698 in increased costs related to estimates for abandonment of its’ share of certain California oil properties. These estimates relate to properties likely to be abandoned in the current period. As a result, the Company has recorded them as impairment expense at year end 2019.
|
|
2019
|
|
|
2018
|
|
Asset retirement obligation
|
|
|
|
|
|
|
|
|
Beginning of the year
|
|
$
|
2,366,456
|
|
|
$
|
1,000,908
|
|
Liabilities incurred during the period
|
|
|
210,643
|
|
|
|
595,583
|
|
Settlements
|
|
|
-
|
|
|
|
(52,636
|
)
|
Merger Additions
|
|
|
-
|
|
|
|
1,419,544
|
|
Sales
|
|
|
(33,026
|
)
|
|
|
(486,585
|
)
|
Changes in estimates
|
|
|
922,698
|
|
|
|
-
|
|
Accretion expense
|
|
|
165,651
|
|
|
|
(110,358
|
)
|
End of year
|
|
$
|
3,632,422
|
|
|
$
|
2,366,456
|
|
The Company records accretion expense as part of Depreciation, Depletion and Amortization
NOTE 5 – NOTES PAYABLE
On October 3, 2018, the Company issued a promissory note for a principal amount of $517,585 to Forza Operating, LLC. At an interest rate of 5.5%. Beginning October 3, 2018, principal and interest is due and payable in 12 monthly installments of $44,428. The note was the result of an agreement regarding the plugging and abandonment of the CL&F #1 and the CL&F #1 SWD wells. The Company agreed to include the current joint interest billing balance due to Forza Operating of $233,367 and Royale’s share of future plugging and abandonment costs of $284,218. At December 31, 2019 and 2018, Royale Energy had Notes Payable of $55,573 and $390,839, respectively, as a current liability.
NOTE 6 – INCOME TAXES
Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. In 2016, the Company adopted Accounting Standards Update (ASU) 2015-17 and has classified all of its deferred tax assets and liabilities as noncurrent on its balance sheet.
On December 22, 2017, the U.S. enacted significant changes to U.S. tax law following the passage and signing of H.R.1, “An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (the “Tax Act”). The Tax Act permanently reduces the U.S. federal corporate tax rate from a maximum 35% to 21%, eliminated corporate Alternative Minimum Tax, modified rules for expensing capital investment, and limits the deduction of interest expense for certain companies. ASC 740 requires filers to record the effect of tax law changes in the period enacted. However, the SEC issued Staff Accounting Bulletin (“SAB”) 118 that permits filers to record provisional amounts during a measurement period ending no later than one year from the date of enactment. For the period ending December 31, 2018, the Company re-measured the applicable deferred tax assets based on the rates at which they are expected to reverse. The gross deferred tax assets and liabilities have been adjusted and a corresponding offset has been recorded to the full valuation allowance against the Company’s net deferred tax assets, which resulted in no net effect to its provision for income taxes and effective tax rate. No other provisional adjustments have been made as a result of the Act.
Significant components of the Company’s deferred assets and liabilities at December 31, 2019 and 2018, respectively, are as follows:
|
|
2019
|
|
|
2018
|
|
Deferred Tax Assets (Liabilities):
|
|
|
|
|
|
|
|
|
Statutory Depletion Carry Forward
|
|
$
|
367,149
|
|
|
$
|
367,149
|
|
Net Operating Loss
|
|
|
6,489,891
|
|
|
|
7,121,912
|
|
Other
|
|
|
595,990
|
|
|
|
708,057
|
|
Share-Based Compensation
|
|
|
86,510
|
|
|
|
86,510
|
|
Capital Loss / AMT Credit Carry Forward
|
|
|
9,458
|
|
|
|
9,458
|
|
Charitable Contributions Carry Forward
|
|
|
3,890
|
|
|
|
6,158
|
|
Allowance for Doubtful Accounts
|
|
|
466,060
|
|
|
|
597,519
|
|
Oil and Gas Properties and Fixed Assets
|
|
|
5,404,787
|
|
|
|
5,987,061
|
|
Investment in RMX Joint Venture
|
|
|
(1,238,551
|
)
|
|
|
(1,247,847
|
)
|
Section 481(a) Adjustments
|
|
|
(214,859
|
)
|
|
|
-
|
|
|
|
$
|
11,970,325
|
|
|
$
|
13,635,977
|
|
Valuation Allowance
|
|
|
(11,970,325
|
)
|
|
|
(13,635,977
|
)
|
Net Deferred Tax Asset
|
|
$
|
-
|
|
|
$
|
-
|
|
The Company recorded a full valuation allowance against the net deferred tax assets in 2016. At the end of 2017, management reviewed the reliability of the Company’s net deferred tax assets, and due to the Company’s continued cumulative losses in recent years, Royale and its management concluded it is not “more-likely-than-not” its deferred tax assets will be realized. As a result, the Company will continue to record a full valuation allowance against the deferred tax assets in 2019. The Company will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed. Royale Energy, Inc. and its subsidiaries have available net operating loss carryforwards of $22.9 million generated in tax years ended before January 1,2018, which if not utilized, begin to expire in the year 2024. Royale Energy, Inc. has no net operating loss carryforwards generated after December 31, 2017, which can be carried forward indefinitely.
A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2019 and 2018, respectively, to pretax income is as follows:
|
|
2019
|
|
|
2018
|
|
Tax (benefit) computed at statutory rate of 21% at December 31, 2019 and 2018, respectively
|
|
$
|
(71,680
|
)
|
|
$
|
(4,935,909
|
)
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in taxes resulting from:
|
|
|
|
|
|
|
|
|
Meals & Entertainment
|
|
|
1,583
|
|
|
|
1,320
|
|
Investor Incentive Expense
|
|
|
-
|
|
|
|
7
|
|
Transaction Costs
|
|
|
-
|
|
|
|
160,927
|
|
Loss on Warrants Issued to RMX
|
|
|
-
|
|
|
|
302,398
|
|
Prior-year true-up for Books
|
|
|
1,461,914
|
|
|
|
2,075,440
|
|
Deferred State Taxes, net of federal benefit
|
|
|
214,161
|
|
|
|
(1,009,601
|
)
|
Other non-deductible expenses
|
|
|
59,674
|
|
|
|
(264,359
|
)
|
Change in valuation allowance
|
|
|
(1,665,652
|
)
|
|
|
3,669,777
|
|
Provision (benefit)
|
|
|
-
|
|
|
|
-
|
|
The components of the Company’s tax provision are as follows:
|
|
2019
|
|
|
2018
|
|
Current tax provision (benefit) - federal
|
|
$
|
-
|
|
|
$
|
-
|
|
Current tax provision (benefit) - state
|
|
|
-
|
|
|
|
-
|
|
Deferred tax provision (benefit) - federal
|
|
|
-
|
|
|
|
-
|
|
Deferred tax provision (benefit) - state
|
|
|
-
|
|
|
|
-
|
|
Total provision (benefit)
|
|
$
|
-
|
|
|
$
|
-
|
|
In January 2007, Royale adopted additional provisions from the Income Taxes Topic of the ASC, which clarified the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. As a result of our implementation of the Topic at the time of adoption and at December 31, 2018, the Company did not recognize a liability for uncertain tax positions. Currently, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our balance sheets. We do not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years 2013 through 2018 remain open to examination by the taxing jurisdictions in which we file income tax returns.
NOTE 7 - SERIES B PREFERRED STOCK
Pursuant to the terms of the Merger all Class A limited partnership interests of Matrix Investments, LP (“Matrix Investments”) were exchanged for Royale Common stock using conversion ratios according to the relative value of the Class A limited partnership interests, and $20,124,000 of Matrix Investments preferred limited partnership interests were converted into 2,012,400 shares of Series B Convertible Preferred Stock of Royale. The Board of Directors of Royale Energy, prior to the merger, authorized 3,000,000 shares of Series B Convertible Preferred, which carries a liquidation preference and a 3.5% dividend, payable in cash or Paid-In-Kind shares. The Series B Convertible Preferred Stock is convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible Preferred Stock. The Series B Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares. Additionally, the Series B Convertible Preferred shares will automatically convert to common at any time in which the Volume Weighted Average Price (VWAP) of the common stock exceeds $3.50 per share for 20 consecutive trading days, the shares are registered with the SEC and the volume of common shares trades exceeds 200,000 shares per day. The shareholders of the Series B Convertible Preferred may vote the number of shares into which they would be entitled to convert, beginning in 2020.
For 2019 and 2018, the board has authorized the payment of all dividends of Series B Convertible Preferred shares, as Paid-In-Kind shares. During 2019 the Company had issued 73,473 and 59,461 shares for the year ended 2019 and 2018 respectively, representing a value of $734,725 and $594,613 for the same periods. No cash was used to pay dividends on Series B preferred shares in 2019 or 2018.
NOTE 8 - COMMON STOCK
In April 2016, Royale entered in a securities purchase agreement and related agreements with one investor. Under the terms of the agreement, the investor purchased 622,316 shares of Royale’s common stock at $0.3214 per share, and received warrants to purchase up to 311,158 shares (the “Warrants’) of stock at $0.5356 per share for three (3) years, for a total of $200,000 in gross proceeds. In July 2016, Royale entered in securities purchase agreements and related agreements with three investors. Under the terms of the agreement, the investors purchased 2,392,500 shares of Royale’s common stock at $0.40 per share, and received warrants to purchase up to 478,500 shares (the “Warrants’) of stock at $0.80 per share for two (2) years, for a total of $957,000 in gross proceeds. On April 13, 2018, Royale Energy, Inc., and two of Royale’s subsidiaries, Royale Energy Funds, Inc. and Matrix Oil Management Corporation (the “Royale Entities”) completed the Subscription and Contribution Agreement (“Contribution Agreement”), in which the Royale Entities and CIC RMX LP (“CIC”) entered into the Contribution Agreement and certain other agreements providing that the Royale Entities would contribute certain assets to RMX Resources, LLC (“RMX”), a newly formed Texas limited liability company formed to facilitate the investment from CIC. As part of the agreement a warrant (“Warrant”) was issued to acquire up to 4,000,000 shares of Royale’s common stock at an exercise price of $.01 per share and registration rights pursuant to a Registration Rights Agreement. As further described in NOTE 2 – Merger with Matrix Oil Management Corporation and Formation of RMX .
During the year 2019, the Company issued shares of its Common Stock in lieu of cash payments for salaries, fees or incentives to various officers and board members, including our CEO.
NOTE 9 - OPERATING LEASES
The Company has elected a modified retrospective transition approach for the implementation methodology of ASC 842, Leases. Consequently, financial information has not been updated and the disclosures required under the new standard have not been provided for dates and periods before January 1, 2019.
The standard did not materially impact our consolidated results of operations, earnings per share, and had no impact on cash flows. The most significant effects relate to: (1) the recognition of new ROU assets in long-term assets on the balance sheet; (2) lease liabilities, both short-term and long-term, on our balance sheet; and, (3) providing significant new disclosures about our leasing activities.
The interest rate used in each lease analysis was the risk-free rate for the period of the lease plus 400 basis points as the Company’s risk premium.
The Company has two office leases. One at 1870 Cordell Court, El Cajon, California, the location of its corporate offices and one at 104 W. Anapamu, Santa Barbara, California, the location of the Company’s CEO and engineering team. The corporate office lease was entered into on August 31, 2016 and expires on October 31, 2021 with initial monthly payments of $6,148 with escalations. The lease in Santa Barbara was initiated in December of 2006 and, through several extensions and renewals, will expire in March of 2022. The initial base rental payment was $5,086 with various adjustments to market and planned escalations. These two leases were initially recorded as operating leases at January 1, 2019 as listed below.
|
|
Debit/Credit
|
|
Operating Lease – ROU Asset
|
|
|
483,504
|
|
Operating Lease Liability – Current
|
|
|
(140,831
|
)
|
Operating Lease Liability – Long-Term
|
|
|
(342,673
|
)
|
In July 2019, we entered into a 60 month agreement with MRC for the leasing of two Xerox machines with monthly payments of $1,049. This lease was initially recorded as a financing lease on July 31, 2019 as listed below:
|
|
Debit/Credit
|
|
Financing Lease - ROU Asset
|
|
|
54,655
|
|
Financing Lease Liability - Current
|
|
|
(9,725
|
)
|
Financing Lease Liability - Long-Term
|
|
|
(44,930
|
)
|
The new standard provides practical expedients for an entity’s ongoing accounting. We have elected the short-term lease recognition exemption for all leases that qualify. This means, for those leases that qualify, we will not recognize ROU assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. We also currently expect to elect the practical expedient to not separate lease and non-lease components for all of our finance leases. For our real estate operating leases, we have only considered the fixed portion of our lease payment commitment and have excluded the variable components from the capitalized ROU and lease liability.
Lease expense for operating as well as finance leases are included in General and Administrative expense and interest expense on the Consolidated Statement of Operations, while the lease expense for those leases that are short-term are included in Oil and Gas Lease Operating Expenses. The amounts are as follows:
|
|
Year ended
December 31, 2019
|
|
Operating lease expense
|
|
|
184,374
|
|
Financing lease expense
|
|
|
10,757
|
|
Operating – short-term
|
|
|
7,886
|
|
Short Term - field
|
|
|
6,000
|
|
Total lease expense
|
|
|
209,017
|
|
The following tables summarized the operating and financing lease obligations.
Lease Obligations
|
|
Operating
Lease
Obligations
|
|
|
Financing
Lease Obligations
|
|
|
Total
Lease
Obligations
|
|
2020
|
|
|
173,809
|
|
|
|
12,588
|
|
|
|
186,397
|
|
2021
|
|
|
179,630
|
|
|
|
12,588
|
|
|
|
192,218
|
|
2022
|
|
|
24,408
|
|
|
|
12,588
|
|
|
|
36,996
|
|
Thereafter
|
|
|
-
|
|
|
|
19,931
|
|
|
|
19,931
|
|
Total undiscounted lease payments
|
|
$
|
377,847
|
|
|
|
57,695
|
|
|
|
435,542
|
|
Less: Amount representing interest
|
|
|
35,174
|
|
|
|
7,025
|
|
|
|
42,199
|
|
Total Operating & Financing lease liabilities
|
|
$
|
342,673
|
|
|
|
50,670
|
|
|
|
393,343
|
|
Long-term lease liabilities as of December 31, 2019
|
|
$
|
152,314
|
|
|
|
9,958
|
|
|
|
162,272
|
|
Long-term lease liabilities as of December 31, 2019
|
|
$
|
190,359
|
|
|
|
40,712
|
|
|
|
231,071
|
|
NOTE 10 - RELATED PARTY TRANSACTIONS
Significant Ownership Interests
Our Chief Executive, Johnny Jordan, had been an employee of Matrix prior to the Merger. Pursuant to this employment, he had accrued certain unpaid salaries, which were assumed by the Company. At December 31, 2019 Mr. Jordan was owed $22,107 in accrued unpaid guaranteed payments.
Our Chief Financial Officer, Stephen Hosmer has participated individually in 179 wells under the 1989 policy. During 2019 and 2018, Stephen did not participate in fractional interests. At December 31, 2019, the Company had a receivable balance of $15,524 due from Stephen Hosmer for normal drilling and lease operating expenses.
Donald Hosmer has participated individually in 179 wells under the 1989 policy. During 2019 and 2018, Donald did not participate in fractional interests. At December 31, 2019, Royale had a receivable balance of $3,441 due from Donald Hosmer for normal drilling and lease operating expenses.
At December 31, 2019, we had a total payable of $32,367 due to RMX Resources, LLC and its subsidiary, Matrix Oil Corporation, related to certain lease operating expenses for wells operated by RMX Resources, LLC. For the same period, the Company also had prepaid expenses and other current assets of $2,680,155 primarily for the drilling of three wells, expected to commence in 2020.
Royale had outstanding accrued unpaid guaranteed payments for unpaid salaries due to certain Matrix employees, for periods prior to the Merger. At December 31, 2019, the balance due was $1,306,605.
Michael McCaskey and Jeffery Kerns, each former directors of Royale, have consulting agreements to provide services as directed and at the discretion of the Company. Mr. Kerns wife is a director.
NOTE 11 - STOCK COMPENSATION PLAN
On October 10, 2018, the Company entered into an Incentive Stock Option Award Agreement with Stephen M. Hosmer, Chief Financial Officer. Mr. Hosmer was granted 250,000 options to purchase common stock at an exercise price of $0.31 per share. These options were granted for a period of 10 years and will expire after October 10, 2028. These options become vested exercisable immediately. These options were valued using the Black-Scholes methodology. The Black-Scholes assumptions were as follows: Exercise price per share, $0.31; Current stock price (as of the close on October 10, 2018) $0.34; Risk-free interest rate of 3.22%; Time to maturity of 10 years; and, Stock volatility of 66.48%. The Black-Scholes model, using the values listed above, valued each option at $0.26 making the award of $250,000 options worth $64,954. There were no other stock options issued in 2019 and 2018.
A summary of the status of Royale Energy’s stock option plan as of December 31, 2019 and 2018, and changes during the years ending on those dates is presented below:
|
|
2019
|
|
|
2018
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
Exercise
|
|
|
|
|
|
|
Exercise
|
|
|
|
Shares
|
|
|
Price
|
|
|
Shares
|
|
|
Price
|
|
Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding and Exercisable at Beginning of Year
|
|
|
250,000
|
|
|
$
|
0.31
|
|
|
|
-
|
|
|
|
|
|
Granted or Vested
|
|
|
-
|
|
|
|
|
|
|
|
250,000
|
|
|
$
|
0.31
|
|
Exercised
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
|
|
Forfeited
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding and Exercisable at Year End
|
|
|
250,000
|
|
|
$
|
0.31
|
|
|
|
250,000
|
|
|
$
|
0.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average Fair Value of Options Granted During the Year
|
|
$
|
-
|
|
|
|
|
|
|
$
|
64,954
|
|
|
|
|
|
At December 31, 2019, Royale Energy’s stock price, $0.11, was less than the weighted average exercise price, and as such the outstanding and exercisable stock options had no intrinsic value.
All stock options were fully vested at December 31, 2019 and 2018.
During 2019 and 2018, we recognized $0 and $64,954, respectively, in compensation costs for the vested stock options. The Company will incur no future expense related to these options.
NOTE 12 - SIMPLE IRA PLAN
In April 1998, the Company established a Simple IRA pension plan covering all employees. The Company will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction contributions up to a limit of 3% of the employee’s compensation for the year. The employer contribution for the years ending December 31, 2019 and 2018, were $30,336 and $35,312 respectively.
NOTE 13 - ENVIRONMENTAL MATTERS
Royale Energy has established procedures for the continuing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. Management monitors these laws and regulations and periodically assesses the propriety of its operational and accounting policies related to environmental issues. The nature of Royale Energy’s business requires routine day-to-day compliance with environmental laws and regulations. Royale Energy incurred no material environmental investigation, compliance and remediation costs in 2019 or 2018.
Royale Energy is unable to predict whether its future operations will be materially affected by these laws and regulations. It is believed that legislation and regulations relating to environmental protection will not materially affect the results of operations of Royale Energy.
NOTE 14 - CONCENTRATIONS
The Company bids its gas sales on a month to month basis and generally sells to a single customer without commitment to future gas sales to any particular customer. The Company normally sells approximately 32% of its monthly natural gas production to one customer on a month to month basis. Since we are able to sell our natural gas to other readily available customers, the loss of any one customer would not have an adverse effect on our overall sales operations.
The Company maintains cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per institution for our interest bearing accounts in the years ended December 31, 2019 and 2018. At December 31, 2019 and 2018, cash in banks exceeded the FDIC limits by approximately $3.4 million and $5.7 million, respectively. The Company has not experienced any losses on deposits.
NOTE 15 - COMMITMENTS AND CONTINGENCIES
The Company may become involved from time to time in litigation on various matters, which are routine to the conduct of its business. The Company believes that none of these actions, individually or in the aggregate, will have a material adverse effect on its financial position or results of operations, though any adverse decision in these cases or the costs of defending or settling such claims could have a material effect on its business.
The Company sponsors turnkey drilling agreement arrangements in proved and unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations. The contracts require the participants pay Royale the full contract price upon execution of the agreement. Royale typically begins the drilling activities within 12 months of funding and reaches total depth between 10 and 30 days after drilling begins.
NOTE 16 - SUBSEQUENT EVENTS
In late 2019 and continuing into 2020, there was a global outbreak of novel coronavirus (COVID-19) that has resulted in changes in global supply and demand of certain mineral and energy products. While the direct and indirect negative impacts that may affect the Company cannot be determined, they could have a prospective material impact to the Company's operations, cash flows and liquidity.
NOTE 17 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interests owned by Royale Energy which are located solely in the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells, with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion.
Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineering consultant Netherland, Sewell & Associates, Inc., the net reserve value of its proved developed and undeveloped reserves was approximately $57.8 million at December 31, 2018, based on the average Henry Hub natural gas price spot price of $3.10 per MCF and for oil volumes, the average West Texas Intermediate price of $65.56 per barrel as applied on a field-by-field basis. Netherland, Sewell & Associates, Inc. provided reserve value information for the Company’s California, Texas, Oklahoma, Utah and Louisiana properties. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves.
The technical persons responsible for preparing the reserves estimates presented in the report of Netherland, Sewell & Associates, Inc., meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Netherland, Sewell & Associates, Inc. is a firm of independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an interest in our properties and are not employed on a contingent basis. All activities and reports performed and completed by Netherland, Sewell & Associates, Inc. with regards to our reserve valuation estimates are reviewed Royale’s management.
These estimates are furnished and calculated in accordance with requirements of the Financial Accounting Standards Board and the Securities and Exchange Commission (SEC). Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions, and the fact that the bases for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent management’s assessment of future profitability or future cash flows to Royale Energy. Management’s investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here.
It should be recognized that applying current costs and prices and a 10 percent standard discount rate does not convey absolute value. The discounted amounts arrived at are only one measure of the value of proved reserves.
Changes in Estimated Reserve Quantities
The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2019 and 2018, and changes in such quantities during each of the years then ended, were as follows:
Total Proved Reserves
|
|
|
|
2019
|
|
|
2018
|
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
1,146,400
|
|
|
|
2,986,200
|
|
|
|
202
|
|
|
|
2,132,221
|
|
Revisions of previous estimates
|
|
|
1,052,086
|
|
|
|
(890,032
|
)
|
|
|
(79,136
|
)
|
|
|
(401,498
|
)
|
Production
|
|
|
(27,663
|
)
|
|
|
(292,472
|
)
|
|
|
(20,329
|
)
|
|
|
(135,396
|
)
|
Extensions, discoveries and improved recovery
|
|
|
22,042
|
|
|
|
2,516,046
|
|
|
|
-
|
|
|
|
25,014
|
|
Merger Acquisition
|
|
|
-
|
|
|
|
-
|
|
|
|
11,375,784
|
|
|
|
13,459,933
|
|
Purchase of minerals in place
|
|
|
-
|
|
|
|
-
|
|
|
|
29,300
|
|
|
|
116,110
|
|
Sales of minerals in place
|
|
|
(21,865
|
)
|
|
|
(12,842
|
)
|
|
|
(10,159,421
|
)
|
|
|
(12,210,184
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves end of period
|
|
|
2,171,000
|
|
|
|
4,306,900
|
|
|
|
1,146,400
|
|
|
|
2,986,200
|
|
Proved Developed
|
|
|
|
2019
|
|
|
2018
|
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
148,600
|
|
|
|
1,914,900
|
|
|
|
202
|
|
|
|
1,798,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
|
232,200
|
|
|
|
2,790,300
|
|
|
|
148,600
|
|
|
|
1,914,900
|
|
Proved Undeveloped
|
|
|
|
2019
|
|
|
2018
|
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
997,800
|
|
|
|
1,071,300
|
|
|
|
-
|
|
|
|
333,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
|
1,938,800
|
|
|
|
1,516,600
|
|
|
|
997,800
|
|
|
|
1,071,300
|
|
At December 31, 2019, our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 890,032 MCF 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. At December 31, 2019, our previously estimated proved developed and undeveloped oil reserve quantities were revised upward by approximately 1,052,086 BBL of oil. This upward revision was mainly the result an increase in the quantity and quality of undrilled wells, in which the Company has the right to participate.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The future net cash inflows are developed as follows:
•
|
Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.
|
•
|
The estimated future production of proved reserves is priced on the basis of year-end prices.
|
•
|
The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development costs by year are as follows:
|
2020
|
$
|
10,331,900
|
|
2021
|
|
4,500,000
|
|
2022
|
|
4,511,800
|
|
Thereafter
|
|
1,244,100
|
|
|
|
|
|
Total
|
$
|
20,587,800
|
|
The resulting future net revenue streams are reduced to present value amounts by applying a ten percent discount.
Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes.
Changes in standardized measure of discounted future net cash flow from proved reserve quantities
The standardized measure of discounted future net cash flows is presented below for the years ended December 31, 2019 and 2018.
This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the ten percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes.
|
|
2019
|
|
|
2018
|
|
Future cash inflows
|
|
|
143,045,000
|
|
|
|
87,467,200
|
|
Future production costs
|
|
|
(28,967,400
|
)
|
|
|
(22,390,900
|
)
|
Future development costs
|
|
|
(20,587,800
|
)
|
|
|
(7,256,900
|
)
|
Future income tax expense
|
|
|
(28,046,940
|
)
|
|
|
(17,345,820
|
)
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
65,442,860
|
|
|
|
40,473,580
|
|
|
|
|
|
|
|
|
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(35,801,989
|
)
|
|
|
(9,827,666
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
|
29,640,871
|
|
|
|
30,645,914
|
|
|
|
|
|
|
|
|
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(624,744
|
)
|
|
|
(40,557
|
)
|
|
|
|
|
|
|
|
|
|
Revisions of previous quantity estimates
|
|
|
14,035,099
|
|
|
|
(71,162
|
)
|
Net changes in prices and production costs
|
|
|
(14,331,770
|
)
|
|
|
11,683,159
|
|
Sales of minerals in place
|
|
|
(272,507
|
)
|
|
|
(3,061,278
|
)
|
Purchases of minerals in place
|
|
|
-
|
|
|
|
287,300
|
|
Merger Acquisition
|
|
|
-
|
|
|
|
29,903,670
|
|
Extensions, discoveries and improved recovery
|
|
|
2,157,052
|
|
|
|
59,191
|
|
Accretion of discount
|
|
|
2,900,123
|
|
|
|
2,670,000
|
|
|
|
|
|
|
|
|
|
|
Net change in income tax
|
|
|
(4,868,296
|
)
|
|
|
(12,429,097
|
)
|
|
|
|
|
|
|
|
|
|
Net increase (decrease)
|
|
|
(1,005,043
|
)
|
|
|
29,001,226
|
|
Future Development Costs
In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves. The following table estimates the costs to develop and produce our proved reserves in the years 2020 through 2022.
Future development cost of:
|
|
2020
|
|
|
2021
|
|
|
2022
|
|
Proved developed reserves (PDP)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Proved non-producing reserves (PDNP)
|
|
|
126,900
|
|
|
|
-
|
|
|
|
11,800
|
|
Proved undeveloped reserves (PUD)
|
|
|
10,205,000
|
|
|
|
4,500,000
|
|
|
|
4,500,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,331,900
|
|
|
$
|
4,500,000
|
|
|
$
|
4,511,800
|
|
Common assumptions include such matters as the real extent and average thickness of a particular reservoir, the average porosity and permeability of the reservoir, the anticipated future production from existing and future wells, future development and production costs and the ultimate hydrocarbon recovery percentage. As a result, oil and gas reserve estimates and discounted present value estimates are frequently revised in subsequent periods to reflect production data obtained after the date of the original estimate. If the reserve estimates are inaccurate, production rates may decline more rapidly than anticipated, and future production revenues may be less than estimated.
Additional data relating to Royale Energy’s oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to Royale Energy’s Financial Statements, beginning on page F-1.
Historic Development Costs for Proved Reserves
In each year we expend funds to drill and develop some of our proved undeveloped reserves. We have incurred no cost in any of the past three fiscal years to drill and develop reserves that were classified as proved undeveloped reserves as of December 31 of the immediately preceding year.
RMX Resources, LLC
Royale has a 20% interest in RMX Resources, LLC, as described in Note 2 – Merger With Matrix Oil Management Corporation And Formation Of RMX
The estimates listed below of proved oil and gas reserves and revenues, both developed and undeveloped represent the gross volume attributable to RMX as a whole and to the 20 percent interest of RMX held by Royale. The reserve values were prepared by independent petroleum engineering consultants Netherland, Sewell & Associates, Inc. These estimates do not include probable or possible reserves and revenue and are presented on the same bases as that of Royale. RMX is not subject to U.S. Federal or state income taxes related to crude oil and natural gas production. RMX has elected to be taxed as a partnership; therefore, the reserve information provided below does not consider Federal or state income taxes.
Total Proved Reserves
|
|
|
|
2019
|
|
|
2018
|
|
|
|
Net to Royale (20%)
|
|
|
Net to Royale (20%)
|
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period –
(2018 - at formation of RMX)
|
|
|
4,219,140
|
|
|
|
4,378,060
|
|
|
|
3,739,820
|
|
|
|
4,403,654
|
|
Revisions of previous estimates
|
|
|
(188,726
|
)
|
|
|
(3,388,497
|
)
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
(49,894
|
)
|
|
|
(23,023
|
)
|
|
|
(41,240
|
)
|
|
|
(25,594
|
)
|
Extensions, discoveries and improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchase of minerals in place
|
|
|
-
|
|
|
|
-
|
|
|
|
520,560
|
|
|
|
-
|
|
Sales of minerals in place
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves end of period
|
|
|
3,980,520
|
|
|
|
966,540
|
|
|
|
4,219,140
|
|
|
|
4,378,060
|
|
Proved Developed
|
|
|
|
Net to Royale (20%)
|
|
|
Net to Royale (20%)
|
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period – (2018 at formation of RMX)
|
|
|
993,080
|
|
|
|
635,180
|
|
|
|
791,073
|
|
|
|
660,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
|
1,186,080
|
|
|
|
653,920
|
|
|
|
993,080
|
|
|
|
635,180
|
|
Proved Undeveloped
|
|
|
|
Net to Royale (20%)
|
|
|
Net to Royale (20%)
|
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period – (2018 at formation of RMX)
|
|
|
3,226,060
|
|
|
|
3,742,880
|
|
|
|
2,917,721
|
|
|
|
3,742,880
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
|
2,794,440
|
|
|
|
312,620
|
|
|
|
3,226,060
|
|
|
|
3,742,880
|
|
Changes in Standardized measure of discounted future net cash flow from proved reserve quantities
This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the ten percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. Because RMX was formed in April of 2018, this analysis only provides the reserve information as of year-end without a comparison and reciliation to a beginning reserve report.
|
|
2019
|
|
|
2018
|
|
|
|
Net to Royale
(20%)
|
|
|
Net to Royale
(20%)
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
|
247,894,600
|
|
|
|
305,586,180
|
|
Future production costs
|
|
|
(72,400,860
|
)
|
|
|
(84,222,980
|
)
|
Future development costs
|
|
|
(22,142,340
|
)
|
|
|
(28,801,620
|
)
|
Future income tax expense
|
|
|
(46,005,420
|
)
|
|
|
-
|
|
Future net cash flows
|
|
|
107,345,980
|
|
|
|
192,561,580
|
|
|
|
|
|
|
|
|
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(61,882,856
|
)
|
|
|
(118,962,940
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
|
45,463,124
|
|
|
|
73,598,640
|
|
|
|
|
|
|
|
|
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(1,308,378
|
)
|
|
|
(810,635
|
)
|
Formation of RMX Joint Venture
|
|
|
-
|
|
|
|
60,282,536
|
|
Net changes in prices and production costs and revisions of previous quantity estimates
|
|
|
(14,702,806
|
)
|
|
|
-
|
|
Sales of minerals in place
|
|
|
-
|
|
|
|
-
|
|
Purchases of minerals in place
|
|
|
-
|
|
|
|
8,673,117
|
|
Extensions, discoveries and improved recovery
|
|
|
-
|
|
|
|
-
|
|
Accretion of discount
|
|
|
7,359,864
|
|
|
|
5,453,622
|
|
Net change in income tax
|
|
|
(19,484,196
|
)
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease)
|
|
|
(28,135,516
|
)
|
|
|
73,598,640
|
|