Unassociated Document

This letter responds to your letter dated April 10, 2013, to Donald H. Hosmer regarding our Form 10-K for the year ended December 31, 2011 (the “2011 10-K”). On April 16, 2013, we filed Royale Energy’s Form 10-K for the year ended December 31, 2012 (the “2012 10-K”). The disclosure changes that have been made in response to your comments have been made in the 2012 10-K, which include a change in our revenue recognition policy and a restatement of our financial statements for 2011.

We note your response to comment one of our letter dated January 30, 2013, stating you believe that the provisions of ASC 932-360-55-3 through 55-9 are not applicable because “...the investor purchases only the contractual right to participate in drilling and production from a specific wellbore and does not receive the conveyance of a lease interest” although you also state that the sale of interests in your oil and gas projects is

We also note that on page 13 of your Form 10-K, you state that “Royale Energy usually sells a portion of the working interest in each lease that it acquires to third party investors and retains a portion of the prospect for its own account” also that you derive revenue “...from sales of working interests to high net worth individuals.”

Response: The statement in our January 30 letter that “the investor purchases only a contractual right to participate in drilling and production from a specific wellbore” is not inconsistent with the statement in the 2011 10-K that we derive revenue from sales of working interests. A wellbore interest is a form of working interest. Typically, working interests are considered to be undivided interests in an oil and gas lease, in which the working interest owner has the right to participate in all oil and gas drilling and production activities from the leased property while the lease is in effect. A wellbore interest, on the other hand, typically refers to the right to participate in drilling and production from a specific well being drilled on the lease. When a wellbore interest is sold, the buyer does not receive an interest in the larger leased property, which may include other potential drilling locations and additional development opportunities, but he does receive the rights in the leasehold as it relates to the wellbore, including rights and obligations to participate in drilling and production of the particular location in which he purchased the wellbore interest.

As we explained in our letter dated January 17, 2013 (responding to comment 7 of your letter dated December 18, 2013), “Although Royale Energy’s operating agreements do not usually address whether investors have a right to participate in subsequent wells in the same area of interest as a proposed well, it is the Company’s policy to offer to investors in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well.” This would include subsequent wells on the same oil and gas lease as the lease where the wellbore interest was located, as well as other Royale leases in the same area of interest.

When Royale Energy sells fractional working interests to raise capital to drill oil and natural gas wells, generally it agrees to drill these wells on a turnkey contract basis, so that the holders of the fractional interests prepay a fixed amount for the drilling and completion of a specified number of wells. Under a turnkey contract, Royale Energy recognizes gross revenue for the amount paid by the purchaser and agrees to pay the expense of drilling and development of the well for the participants. Sometimes the actual drilling and development

The fractional working interests that Royale Energy sells to investors are wellbore interests, in which the investor acquires the right to participate in drilling and production from a specific well being drilled on an oil and gas lease. When a wellbore interest is sold, the investor does not receive an interest in the larger leased property, which may include other potential drilling locations and additional development opportunities, but the investor does receive the rights in the leasehold as it relates to the wellbore, including rights and obligations to participate in drilling and production of the particular location in which he purchased the wellbore interest.

•	Please describe the specific rights that are conveyed to the third party in the turnkey drilling agreements, clarifying the extent to which the third party obtains a legal (undivided or otherwise) economic interest in the project or property.

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Tell us whether at the time you enter into the turnkey drilling agreements you have already acquired the working interest in the properties that are subject to the drilling agreement or if this transaction occurs once you have secured the drilling agreement (in which case also clarify whether the third party to the drilling agreement acquires their interest from you or directly from the previous property owner).

Response:

In the three years from 2009 through 2011 that were covered by the table attached to our March 20 letter, we drilled 22 wells, of which 20 were drilled on unimproved property. The acquisition of the property where those wells were drilled was as follows:

•	Given that part of your rationale appears to be based on the view of lease interest costs being “only a small part of the transactions,” explain why you have not included amounts shown in your table for other land costs in your analysis, and discuss your view on materiality in greater detail.

Response:

Other land costs, listed in the Table 3 attached to our March 20 letter, include drilling title opinions, legal expenses defending our rights to the titled mineral rights, and county recording fees associated with acquiring the leased mineral rights. With the exception of the recording fees, all other fees were incurred before drilling commenced, but after we entered into turnkey drilling contacts.

Materiality was based upon the lease interest costs as a percentage of the wells’ total cost. If we only include payments as specified in the mineral lease agreements, those costs were only 1.12% of the total cost for the three year ended December 31, 2011. If we were to include lease costs and other land costs, those costs were only 2.37% of the total cost for the three years ending December 31, 2011. If we were to compare the total lease and land costs for unproved properties recorded on our balance sheet for activities during the three years ended December 31, 2011, those costs would represent only 2.65% of the total cost capitalized during the time period. Additionally, as mentioned above, of those land costs representing 2.65% of our total costs capitalized, those costs were only incurred 27% of the time prior to us entering a turnkey drilling contract.

Response:

The turnkey drilling contract does not allocate costs among the lease acquisition and drilling and completion costs. As part of our reporting to investors for tax purposes, capital costs, including lease costs, are reported separately from intangible drilling costs, but of course that report is not delivered to investors until after drilling is complete.

•	Please describe your obligations under the turnkey drilling agreements; also any rights or recourse available to the third party in the event you are unable or unwilling to complete the contracted drilling services that have been specified.

Response:

The turnkey drilling agreement obligates Royale to drill, test, log and complete the well or wells (including plugging and abandoning, if a dry hole). This is a contractual right, and the Company could be sued for damages for failure to perform under the contract. After completion of the well, well operations are conducted subject to a model A.A.P.L. Form 610 Operating Agreement, in which the Company serves as Operator.

As part of your response, please provide us a sample turnkey drilling contract that illustrates the most common rights and obligations of the parties involved; also describe the extent to which the sample contract does not reflect the salient terms of any material provisions that you occasionally include in other contracts.

Please understand that FASB ASC 932-360-55-9 applies to conveyances of interests in oil and gas properties, a term that is broadly defined in the Glossary at FASB ASC 932-360-20, to include operating and non-operating interests such as fee ownerships, leases, concessions, revenue interests, royalty interests, and oil and gas production payments.

Given the description provided in your response and related disclosures, it appears you may have not fully considered how the nature of interests conveyed with your turnkey drilling agreements correlate with this definition. Unless you are able to show how the economic interests conveyed do not represent interests in properties as defined, you will need a reasonable method of allocating proceeds between the interests in unproved properties that you sell and the drilling services you provide. Please explain your method with details sufficient to understand how the amounts allocated to unproved properties compare to your costs of the properties upon entering into the agreements.

Response:

We propose to allocate proceeds between the interest in unproved properties and drilling services would be to estimate costs to (i) identify, and acquire related property interest and (ii) drill and complete the well and to allocate the funds specified to identify

For instance, if Royale estimated the cost to acquire the related interest in a well to be 5% of the well’s total turnkey drilling contract price, and the total sales of turnkey drilling contracts were $1 million, the Company would allocate $50,000 of received funds as a recovery of actual costs to acquire the unproved property interest. If the originally estimated cost to acquire the interest exceeds the actual costs to acquire the interest, the excess would be recorded as revenue. If, on the other hand, the actual costs exceed the original estimated cost to acquire the interest, the difference between the two amounts would be used as Royale’s carrying amount.

Based on our historic property acquisition costs, this change would not materially affect our financial statements in any prior period, so we do not propose to amend previous filings to revise any prior financial statements in light of this change.

We have read your response letter dated April 2, 2013, explaining that “pre-drilling costs typically range between 22% and 30% of total project costs, most if not all of which are incurred at or prior to the entry of the turnkey contract.” You clarify that such costs include “...selling costs related to the acquisition of executed turnkey contracts and sales commissions in instances where interests are sold by FINRA members” and that you consider these to be pre-contract costs as defined in FASB ASC 605-35-25-39.

However, we understand from our phone conference on March 28, 2013 that you are contemplating the inclusion of such costs when computing your percentage of completion and revenue recognition once you begin drilling. Given the nature of these costs, and the discussion of input and output measures in FASB ASC 605-35-25-75, 76 and 77, we believe this would be incorrect. This guidance clarifies that when costs incurred are used to estimate progress towards completion, contract costs that do not relate to contract performance should be excluded, regardless of whether these are properly deferred pre-contract costs or costs incurred subsequently during the term of the turnkey agreement.

Moreover, while the discussion of selling costs in 605-35-25-37(d) may lead you to consider the guidance on pre-contract costs in 605-35-25-41(a), (e) and (f), if you are unable to conclude that recoverability of such costs from a specific anticipated contract is probable, these costs would not be included in contract costs or inventory or otherwise deferred. We understand you have determined that pre-contract costs will be expensed as incurred because you are not able to conclude that recoverability is probable. In either case, since these costs do not relate to contract performance (e.g., site preparation, drilling, logging, or completion and testing) these should be excluded when computing the percentage of completion. Please ensure that your accounting policy disclosure clarifies your handling of such costs in deciding whether to expense or capitalize based on your assessment of probability, and when computing percentage of completion.

Please also ensure that your accounting policy note indicates how a determination to incur completion and testing costs impacts your percentage of completion computations and whether incremental compensation is provided under these circumstances.

Please develop and establish procedures for reviewing and confirming the acceptability of the results of your percentage of completion computations by alternative measures that involve observation and inspection to comply with FASB ASC 605-35-25-78. Tell us how you intend to comply with this requirement.

We understand that you would prefer to characterize your change to utilize the percentage of completion method as a change in accounting principle rather than an error correction even though you are unable to support your earlier practice of recognizing contract revenue to offset pre-contract costs expensed in advance of drilling. Unless you are able to demonstrate that the differences between the two methods are not material, you should comply with FASB ASC 250-10-45-23, and 50-7 through 11.

We have read your response to prior comment three, including the deferred tax asset valuation analysis provided on March 26, 2013. However, we do not see details of the specific positive evidence that would ordinarily be contemplated under FASB ASC 740-10-30-22 to overcome the negative evidence represented by the cumulative loss you have incurred in recent years. Please describe any additional positive evidence or details necessary to understand how the analysis submitted is sufficient to overcome the negative evidence indicating your deferred tax assets should be offset by a valuation allowance.

A strong earnings history exclusive of the loss that created the future deductible amount (tax loss carryforward or deductible temporary difference) coupled with evidence indicating that the loss (for example, an unusual, infrequent, or extraordinary item) is an aberration rather than a continuing condition.

In December 2011, Royale’s bids to lease 100,000 acres were accepted. Royale was anticipating a sale of its recently acquired North Slope acreage. We began to actively market the acreage in 2011 through 2012 for $100 an acre. With a total cost basis of $3.3 million, we were anticipating on selling the acreage for $10 million, generating over $6.7 million in taxable income. Our estimated sales price was recently substantiated with another company purchasing acreage immediately adjacent to our acreage for $171 an acreage, and the recent announcement of our joint venture agreement with land costs at $100 an acre.

In addition, it should be said that Royale recently announced that it has signed a letter of intent with a third party to obtain funding for exploration costs for development of the Alaska property. However, because this did not occur until March 2013, it did not affect our decision to take a $9 million valuation allowance for the deferred tax asset at the end of 2012, as reported in our 2012 10-K. The Alaska transaction will be significant in relation to the size of the deferred tax asset.

Royale has a strong earnings history as outlined in our Year End Valuation Analysis on Deferred Tax Assets. Our continued operation over the three years ended December 31, 2011 generated approximately $2.8 million. The reason for the three year cumulative losses stems from continued impairments of our oil and natural gas assets. These continued impairments were the result of significant reductions in natural gas prices over the last three years. At the end of 2011, management reviewed it operations and production and estimated natural gas prices could not fall enough in 2012 to warrant additional impairments of our natural gas assets. Looking back at 2012, we made the correct assumption concerning natural gas prices and its effect on the value of our oil and natural gas assets; we didn’t need to impair any of our oil and natural gas assets during 2012.

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).