Royale Energy, Inc.
7676 Hazard Center Drive, Suite 1500
San Diego, California 92108
619-881-2800
September 27, 2013
VIA EDGAR
Karl Hiller
Branch Chief
Division of Corporation Finance
Securities and Exchange Commission
Washington, D.C. 20549
Attention: Mark Wojciechowski, Staff Accountant
RE: Royale Energy, Inc.
Form 10-K for Fiscal Year Ended December 31, 2012
Filed April 16, 2013
File No. 000-22750
Dear Mr. Wojciechowski:
This letter responds to your letter dated August 14, 2013, to Donald H. Hosmer regarding our Form 10-K for the year ended December 31, 2012. The following numbered responses correspond to the numbered comments in your August 14 letter.
Form 10-K for the Fiscal Year ended December 31, 2012
Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
| 1. | We understand from your July 15, 2013 letter that you would prefer to limit compliance with our comments to future filings, rather than amend your annual and subsequent interim reports. However, given the nature of the unresolved issues that are the subject of the comments in this letter we are unable to consider your materiality analysis complete. If you wish to renew your request once the remaining issues are resolved please update your assessment of materiality and resubmit your request. |
Response:
We have noted your comments and will update our assessment of materiality and will re-evaluate our request after resolution of remaining issues.
Financial Statements
Note 1 - Summary of Significant Accounting Policies
Revenue Recognition, page F-8
| 2. | We note there continues to be ambiguity in your accounting for pre-drilling costs as referenced in your response to prior comment two. We understand that you are not able to properly capitalize such costs to the property account under FASB ASC 932-360-25, nor to establish probable recovery and capitalize under the contract accounting literature of FASB ASC 605-35-25. In the disclosure you have proposed you state “pre-drilling costs…are expensed as incurred” but also state that the “remaining deferred revenues covering pre-drilling and drilling costs are recognized in the period in which a well is drilled and logged.” This appears to suggest that when recognizing pre-drilling costs, you also book an entry to reduce the amounts initially recognized as deferred revenues. Please advise of the extent to which pre-drilling expenses have been matched with recognition of proceeds received under these agreements in your Statements of Operations, either as revenue or as a reduction to costs, so that we may better understand your reference to remaining deferred revenues. Please understand that we continue to be un-persuaded by your March 20, 2013 response to comment 1, concerning the successful efforts guidance on conveyances which is the subject of the following comment. |
Response:
After reviewing your comments to our prior proposed revisions to our Revenue Recognition section of our 2012 10K, we propose to clarify our accounting for pre-drilling costs. Specifically, we will clarify our disclosure to state that we use the “successful efforts” method to account for exploration and production activities. Under this method, costs are accumulated on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells are capitalized and amortized on the unit-of-production method. We address your other comments related to recognition of proceeds under our turnkey drilling agreements in our response to Question 3 below. We will address our revenue recognition policy and policy on property, plant and equipment as a whole after our response to Question 3.
| 3. | We have read the policy disclosure proposed in your response to prior comment three, concerning your allocation of proceeds under your turnkey drilling arrangements, your position on contract accounting described in response to prior comment four, and have further considered your accounting generally for arrangements to perform drilling services in conjunction with conveyances of partial interests in unproved oil and gas properties. Given that you have chosen the successful efforts method of accounting, we do not see how revenue recognition for any proceeds under the arrangement would be consistent with the guidance in FASB ASC 932-360-40-8 and 55-6 unless you have fulfilled your drilling obligation and all costs capitalized have been recovered. |
In other words, this would generally require all proceeds under the agreements to be reported as recovery of property costs that are capitalized for the property underlying the agreements, including costs pertaining to the interests you have retained. Given that you incur a substantial obligation for
future performance upon entering into these agreements, if all related property costs have been fully recovered (reduced to zero) at the outset of the agreement, as may be expected when you have not yet undertaken significant exploration or development, the balance of the proceeds may need to be shown as a deferred drilling obligation rather than revenue, and reduced in subsequent periods as further costs are incurred, offsetting such costs in the property account.
Under this methodology, we would not expect revenue or gain recognition unless total costs capitalized for the property have been recovered (reduced to zero), and you have no remaining obligation under the agreements. We note that you describe circumstances generally consistent with those of a pooling of assets in a joint undertaking, as outlined in FASB ASC 932-360-40-7, 55-4 and 55-5; and although you state in your March 20, 2013 response to comment 1 "We account for our turnkey drilling agreements as joint ventures in accordance with ASC 932-323-25-1," you did not address the guidance specifically applicable to conveyances in the context of joint ventures in FASB ASC 932-360-55-6.
Please submit an analysis on the applicability of this guidance and the effects on your financial statements; you should ensure that your position is clearly associated with specific accounting literature - if you do not believe this guidance applies be very clear about your reasons. Please also submit a schedule quantifying the effects on revenues, expenses, assets and liabilities for all historical annual and quarterly periods that would arise in the event you are unable to support your prior accounting for these agreements.
Response:
In a typical transaction between industry participants, one E & P company might assign an interest in a well or lease to be developed to another such company. The assignor would incur costs to develop the well and be reimbursed for the assignee’s share, in which case the reimbursement would be a recovery of costs. Indeed, this is the way in which Royale Energy accounts for cost recovery when it participates with other industry players in drilling and development. But the turnkey drilling agreements which Royale Energy sells are sold to non-industry participants who are passive investors. These investors do not take the risk of cost overruns (which Royale Energy bears), but pay a fixed price. Royale Energy usually sells about 50% of its lease interest to investors under this turnkey arrangement, and it treats these turnkey drilling services as a separate industry segment for financial reporting purposes. In the separate turnkey drilling segment, Royale has a cost of sales component and in effect sells an inventory of oil and gas development prospects, which it develops at a profit or loss on the turnkey contract price.
After further review of the literature, Royale Energy has reconsidered its application of the percentage of completion method of revenue recognition, and will report revenue, going forward, on a completed well by well basis accordingly when recognizing revenue for its turnkey drilling agreements. Since all drilling costs are incurred within 10-30 days, the majority, if not all, of the costs and revenues will be recognized in the same period. Costs associated with acquisition of leased mineral rights will be capitalized, as they are now, pending further information about the existence of future benefits as outlined in FASB ASC 932-360-25-3. As industry practice, conveyance of interest to the turnkey drilling agreement participants occurs after the well has been drilled and tested, when there is no further substantial uncertainty about recovery of costs applicable to the interest. Once that determination is made, the leased mineral costs are treated as unproved property or proved property, and treated accordingly. As it relates to revenue recognition, the transition from SEC SAB 104 to the percentage of completion method is immaterial. The support and discussion given to the Commission in our June 24, 2013 response to your June 10, 2013 letter illustrates the immateriality of our revised revenue recognition policy.
In all turnkey drilling agreements Royale Energy has entered into in recent years, the arrangements with participating buyers have been in the form of contracts for the sale of services under fixed price turnkey drilling agreements with the participants whereby Royale Energy charges an upfront fee for services of drilling the well, administration and oversight. Royale Energy recognizes revenue only after (a) there are no continuing obligations under the agreement; (b) substantial uncertainty about recovery of costs applicable to the retained interest has been eliminated; (c) proved reserves have been established prior to conveyance; and (d) conveyance to the participants of proportional interests in future revenues as well as proportional obligations for reimbursement of future expenses of operations has been established in a separate operating agreement.1 In short, the buyers receive a working interest similar to that described in ASC 932-323-25-1, whereby the buyers retain an undivided or proportional interest in the property. Therefore, neither FASB ASC 932-360-40-7, 40-8, 55-4 or 55-5 would apply. We will explain in more detail in subsequent paragraphs why each of these sections does not apply, as well as the accounting literature that does apply for Royale Energy’s revenue recognition policy.
FASB ASC 932-360-40-7 and 40-8 do not apply – FASB ASC 932-360-40-7 and 40-8 outline the types of conveyances in which there is no gain or loss on conveyance, and 40-9 outlines when gain or loss is recognized. Section 40-8 states, “a gain shall not be recognized at the time of the conveyance” when (a) “a part of an interest owned is sold and substantial uncertainty exists about the recovery of the costs applicable to the retained interest” and (b) the seller has a substantial obligation for future performance, such as an obligation to drill a well or to operate the property without proportional reimbursement for that portion of the drilling or operating costs applicable to the interest sold.”
FASB ASC 932-360-40-9 and 55-11 do apply – By the time Royale Energy has completed its drilling obligation, substantial uncertainty about recovery of costs has been eliminated, and terms for proportionate sharing of costs of future operations have been established with the buyer in the operating agreement. Therefore, Sections 40-9 and 55-11 apply, and gain or loss is recognized. Subsequent to participants paying a fixed price, Royale Energy completes its contractual obligations by drilling wells. Royale Energy pays all actual costs incurred to drill such wells, and depending on whether actual costs incurred are lower or higher than those estimated in the turnkey drilling agreements, the Company may realize a gain or loss. Upon fulfilling the drilling obligation, Royale Energy has eliminated substantial uncertainty about the recovery of the costs applicable to the retained interest, and is able to convey a proportional interest. Upon satisfying its obligations under the turnkey drilling agreement and eliminating uncertainty about recovery of costs for its retained interest, the Company conveys a working interest in a proved property’s well bore or interest constituting part of an amortization base and will recognize the sale of an asset, and gain or loss as specified in FASB ASC 932-360-40-9 and 55-11. Paragraphs 932-360-40-7 through 40-8 are not applicable to the turnkey drilling agreements because 40-7 and 40-8 apply only in instances where substantial uncertainty exists about the recovery of costs at the time of conveyance. In any event, FASB ASC 932-360-40-8 makes no reference requiring that all capitalized costs are to be recovered.
FASB ASC 932-360-55-4 does not apply - FASB ASC 932-360-55-4 outlines the accounting treatment of how “an assignment of part of an operating interest in an unproved property in exchange for a free
1 Royale Energy uses the industry standard A.A.P.L. Form 610 Operating Agreement.
well with provision for joint ownership and operation is a joint undertaking by the parties. The assignor shall record no cost for the obligatory well; the assignee shall record no cost for the mineral interest acquired. All drilling, development, and operating costs incurred by either party shall be accounted for as specified by this Topic.” Section 55-4 does not apply because Royale Energy’s turnkey drilling agreements do not involve exchanging a free well. However, if Royale Energy were to exchange an operating interest in an unproved property for a free well, then the Company would follow the accounting literature specified in 55-4. In those instances involving a free well, Royale Energy would not record any cost for the obligatory well. Royale Energy would use any funds received as a recovery of property costs that would be capitalized for the property underlying the related transaction including those costs pertaining to the interests Royale would retain.
FASB ASC 932-360-55-5 does not apply – In arrangements involving a carried interest, as stated in ASC 932-360-55-5, “the assignee (the carrying party) agrees to defray all (emphasis added) costs of drilling, developing, and operating the property and is entitled to all (emphasis added) of the revenues from production from the property…until all (emphasis added) of the assignee’s costs have been recovered, after which the assignor will share in both costs and production.” The major principles in a carried interest (e.g. relating to 100% defrayment of costs and 100% recovery) do not apply to Royale Energy’s current working interest arrangements in its turnkey drilling agreements.
FASB ASC 932-360-55-6 does not apply - FASB ASC 932-360-55-6 outlines the accounting treatment for when “a part of an operating interest owned may be exchanged for a part of an operating interest owned by another party. The purpose of such an arrangement is to avoid duplication of facilities, diversify risks, and achieve operating efficiencies. No gain or loss shall be recognized by either party at the time of the transaction.” Royale Energy’s turnkey drilling agreements do not involve exchanging operating interests; therefore, Section 55-6 does not apply. However, if Royale Energy were to exchange a part of an operating interest for another, the Company would follow the accounting literature and would not record a gain or a loss at the time of the transaction.
FASB ASC 932-360-55-6 further discusses how “each party shall account for its own cost under the provision of this Subtopic” with regards to carried interest or a free well. FASB ASC 932-360-55-5 goes on to define a carried interest transaction. If Royale Energy’s interest were to be carried, the Company would follow the accounting literature and not account for any costs or revenues until after recoupment of the carried costs by the carrying party. Subsequent to payout, Royale would account for its share of the revenues, operating expenses, and subsequent development costs. In circumstances where Royale would be the carrying party, Royale would record all costs, including those carried, and all revenue from the property including those applicable to the recovery of costs carried during the payout period.
Royale Energy’s turnkey drilling agreements do not convey a carried interest to the participant as defined by FASB ASC 932-360-55-5 nor are the wells free to Royale Energy as outlined in FASB ASC 932-360-55-4. Royale Energy’s turnkey drilling agreements do not entitle the participants “to all of the revenue from the production from the property until all of the (participants’) costs have been recovered,” nor do the agreements assign “a part of an operating interest in an unproved property in exchange for a free well.” Therefore, neither 55-4 nor 55-5 applies. Royale Energy pays drilling costs, and depending on whether actual drilling costs are more or less than the estimated costs in which the turnkey drilling agreement is based and charged to the participants, Royale Energy may realize a gain or a loss on the services provided to the participants under the turnkey drilling agreement
In the Comment Letter dated August 14, 2013, the Commission stated that circumstances Royale Energy has described in the past are generally consistent with those of a pooling of assets in a joint
undertaking as outlined in FASB ASC 932-360-40-7, 55-4, and 55-5 and goes on to state that we’ve not addressed the guidance in FASB ASC 932-360-55-6 in the context of joint ventures. The above discussion concerning FASB ASC 932-360-40-8, 55-4, 55-5, and 55-6 outlines the circumstances as to when these sections would be applicable, and when they would not be applicable. With the inclusion of the proposed revised notes to our Revenue Recognition policy section, as referenced below, readers of our Form 10K should have greater clarification as to when FASB ASC 932-360- 55-4, 55-5, and 55-6 would apply.
Our prior reference to FASB ASC 932-323-25-1, with regards to our turnkey drilling agreement, applies to joint interest operations, in which “each working interest owner retains an undivided interest in the jointly operated property. This [working interest] is usually included in the financial statements of the participant through direct inclusion of its proportional share of the expenses, revenues, and assets.” Royale Energy and its turnkey drilling participants qualify under joint venture activities as specified above, and are reporting their proportional share of the expenses, revenues, and assets as those costs are incurred by each participant. Since Royale’s turnkey drilling agreements do not meet the criteria outlined in FASB ASC 932-360-40-7, 55-4, 55-5, and 55-6, Royale Energy’s agreements do not qualify for the pooling of assets in a joint undertaking as discussed in those sections. When sections FASB ASC 932-360-40-7, 55-4, 55-5, and 55-6 do not apply, section FASB ASC 932-323-25-1 becomes applicable.
Royale Energy believes that the appropriate account for recording the participant’s payment on the full contract price upon execution of the turnkey drilling agreement should be titled “Deferred Drilling Obligations” rather than titled as “Deferred Revenue from Turnkey Drilling”. The change in title does not impact revenues, profits or assets. Because of the short duration of the drilling period (typically from 10 days to 30 days), Royale Energy records revenues and reduces the liability at the time the work is completed and there is no continuing obligation, and only after uncertainty about recovery of costs applicable to the retained interest has been eliminated. To the extent that Royale Energy co-invests with its participants, the turnkey fee Royale Energy charges its participants under the turnkey drilling agreement is reduced by Royale Energy’s proportionate interest in the wells. Royale Energy accrues for a loss on the turnkey drilling agreement at the time that the Company knows that cost overruns to the buyer’s proportion of estimated costs in the Company’s fixed price contract with the buyer can be estimated.
Royale Energy capitalizes its portion of expenditures under its share of working interests according to guidance in ASC 932-360-25 on the successful efforts method.
We have stated the entirety of our revenue recognition policy and policy on property, plant and equipment that we propose to submit in future filings below that help describe the circumstances of our agreements and the related revenue recognition.
Notes to Financial Statements
Revenue Recognition
Royale Energy generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured.
Revenues from the production of oil and natural gas properties in which the Royale Energy has an interest with other producers are recognized on the basis of Royale Energy’s net working interest. Differences between actual production and net working interest volumes are not significant.
Royale Energy earns a portion of its revenues from turnkey drilling agreement arrangements whereby Royale Energy charges participants a fee for services of drilling the well, administration and oversight. The contracts require that 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. Royale Energy recognizes revenue from a turnkey drilling agreement upon completion of services using the percentage of completion contract method on a completed well by well basis and provided that there are no continuing obligations to perform under the turnkey drilling agreement and only after substantial uncertainty about recovery of costs applicable to the retained interest has been eliminated. 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. On a partially completed contract, Royale Energy classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Deferred Drilling Obligations”. Because Royale Energy co-invests with its participants, the turnkey fee it charges the participants under the turnkey drilling agreement is reduced by Royale Energy’s proportionate interest in the wells.
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.
Property, Plant and Equipment
Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.
The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets.
Royale 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 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.
Proved oil and gas properties held and used by Royale Energy are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.
Royale Energy estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated evaluation assumptions for crude oil commodity prices. Annual volumes are based on field production profiles, which are also updated annually. Prices for natural gas and other products are based on assumptions developed annually for evaluation purposes.
Impairment analyses are generally based on proved reserves. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount the carrying value exceeds fair value.
Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that Royale Energy expects to hold the properties. The valuation allowances are reviewed at least annually.
Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable to any interest retained nor any substantial obligation for future performance by Royale Energy. When an unproved property is sold, and there is substantial uncertainty concerning the recovery of costs, Royale Energy does not record a gain or loss, but treats all related funds received as a recovery of cost.
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.
We trust that our letter fully responds to your comments. If you have additional questions or comments, please contact our legal counsel, Lee Polson, Strasburger & Price, LLP, 720 Brazos Street, Suite 720, Austin Texas 78701 (telephone 512.499.3626, fax 512.536.5719; email lee.polson@strasburger.com). Lee will see to it that the appropriate people at Royale Energy are informed and become involved in answering your comments.
Very truly yours,
/s/ Stephen M. Hosmer
Stephen M. Hosmer,
Co-President, Co-Chief Executive Officer and
Chief Financial Officer
