roy32013corresp.htm

This letter responds to your letter dated January 30, 3013, to Donald H. Hosmer regarding our Form 10-K for the year ended December 31, 2011 (the “2011 10-K”). The numbered responses below correspond to the numbered comments in your letter:

We note that you have proposed to revise your accounting for amounts received under your turnkey drilling arrangements in response to prior comment 7, to defer revenue recognition for receipts designated as pre-drilling until drilling has been completed. However, you have not addressed all of the concerns outlined in our prior comment, such as your application of FASB ASC 932-360-55-9, allocation of funds between the conveyance and provision of services, and your selection of guidance based on the status of properties underlying these contracts.

FASB A SC 932- 360-40-8 and 55-9 would not require funds received under the conveyance/drilling contracts to be accounted for as recovery of costs. Further, your response to prior comment 8, stating that when lease acreage is impaired, "...the Company attributes 50% of the impaired property to properties from which it would otherwise have expected to recover its costs from turnkey drilling," indicates that you generally anticipate recovering acquisition and drilling costs by entering into the conveyance/drilling arrangements.

Please submit a detailed explanation of why you believe this guidance does not apply to your situation. Please include a schedule listing all of the interests underlying the agreements for which you received funding and recognized revenues during the three years presented, also showing the contract and drilling dates, amounts designated as drilling and pre-drilling, revenue recognized each period (reconciled to the amounts reported in your financial statements), and a description of the underlying properties, including their reserve status upon entering into the contract and upon completing your drilling obligation.

Given that you generally retain an interest in the underlying properties, we understand that you benefit from drilling that is accomplished with funds provided by the counterparties to the extent of your interest in the well or by virtue of the information obtained. Please clarify whether this properly characterizes your economic interests and explain the extent to which funds provided by the counterparties generally cover all costs of drilling.

Response: Oil and gas lease expense typically accounts for only a small portion of the costs involved in Royale’s drilling projects. For projects marketed and drilled during the three calendar years ending December 31, 2011, leasing costs accounted for less than 2% of each project’s total cost.

The remainder of each project’s total cost is used to cover geologic and geophysical expenses, due diligence costs and marketing expenses for sales of interests to investors, and ultimately, drilling, testing and completion costs. Royale’s real prospect acquisition costs, compared to the other costs involved in development of a project, are relatively insignificant.

The turnkey drilling agreement and the operating agreement that govern Royale Energy’s relationship with investors in projects does not provide for transfer of leases to the investors, who only purchase interests in the wellbore associated with each project. Most leases which the Company acquires contain enough acreage for more than one drilling project.

Because only a small amount (approximately 2%) of the goods and services attributable to the sale of interests in projects by Royale Energy is attributable to lease costs, we do not believe it is appropriate to attribute the entire proceeds from the sale on an interests to recovery of capital costs of the lease interest sold. To do so would attribute an amount far larger than actual lease cost to recovery of that cost. We enclose a spreadsheet containing a Turnkey Agreement Sale Analysis with the

The guidance discussed in FASB ASC subparagraphs 932-360-55-3, 55-4, 55-5, 55-7 and 55-9 is followed in those instances where Royale Energy participates in drilling with other oil an gas industry participants in the types of arrangements covered by those subparagraphs. However, Royale’s turnkey drilling agreements with investors does not fall under these paragraphs 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. (For instance, the investor has no property right to participate in additional activities on the lease where the well is located.)

Furthermore, Royale Energy drills wells on prospects on which it has a significant success rate. Royale Energy has a completion rate of more than 65% of projects drilled. Although Royale Energy’s drilling prospects are usually not located on leases that have significant proved reserves using SEC reserve definitions, it has a significant chance of success in drilling producing wells on the properties it selects.

It is correct that sale of interests in Royale’s oil and gas projects is similar to subparagraph 55-9 to the extent that part of an interest in property is sold and uncertainty exists as to recovery of the cost applicable to the interest retained, but Royale’s original cost basis of the lease interests are only a small part of the transactions.

As disclosed in Item 1 – Description of Business – Plan of Business, on page 2 of the 2011 10-K, Royale Energy pays its proportionate share of the actual cost of drilling, testing and completing the projects which it develops (assuming that Royale has accurately estimated the costs of completing the turnkey drilling agreements with investors). The Company does benefit from drilling by virtue of the information obtained, but it also pays its proportionate cost of that drilling. The funds provided by investors in the projects are intended to cover the turnkey cost of drilling their proportionate share and to recoup the costs expended on marketing the interests, geologic and geophysical expenses and due diligence on the properties, but we do not agree that it is correct that Royale benefits to the extent of its retained interest in the wells from funds provided by counterparties. We account for our turnkey drilling agreements as joint ventures in accordance with ASC 932-323-25-1.

segment upon making an impairment assessment, which is your basis for then allocating an impairment charge to this segment, and that you otherwise report interests in oil and gas properties as assets of the oil and gas segment.

We note that most of the impairment charge of $2,027,697 that you attributed to the drilling segment during 2011 was recognized after the end of the third quarter, when total assets of this segment were $1,261,668 (as disclosed on page 8 of your 2011 third quarter report); and that you have no disclosure to explain how the segment incurs impairment substantially in excess of its assets. We also note that you have an impairment accounting policy disclosure on page F-9 that does not correlate with your segment accounting. Therefore, the disclosure accompanying the segment details on page F-16, asserting that your accounting policies for the segments are the same as for the consolidated entity, should be revised to clarify that this does not extend to your accounting for impairment.

Please also revise your disclosures to explain your rationale for attributing impairment charges to the drilling segment for assets that are until that point considered to be part of your oil and gas segment. You are required to address asymmetrical allocations to comply with FASB ASC 280-10-50-29(e).

Response: We reviewed Note 5 and discovered that we had improperly reported impairment charges by segment in each of the past three years. Impairments to our assets typically consist of (i) reserve impairments (ii) impairments to leases under development, that occur during the g & g and due diligence phase preceding drilling, and (iii) impairments to furnishings, fixtures and equipment. Under our impairment accounting policy, lease impairments are divided evenly between the oil and gas exploration and development segment and the turnkey drilling contract segment. Reserve impairments and FF&E impairments are attributable only to the oil & gas exploration and development segment, because they apply only to the oil and natural gas assets that are retained and owned by Royale Energy. Usually, reserve impairments comprise the majority of our impairment expense. In the years reported in our 2011 10-K, all impairments were assigned one half to oil and gas exploration and one half to the turnkey drilling segment.

	2011		2010		2009
	O&G E&P	Turnkey	O&G E&P	Turnkey	O&G E&P	Turnkey

As Reported	$2,264,529	$2,264,529	$250,072	$250,072	$967,930	$967,930

Adjusted To
Reserve Impairment	4,516,098		298,261		1,816,662
Lease Impairment	6,480	6,480	100,942	100,942	56,083	56,083
FF&E Impairment					7,033
Total	4,522,578	$ 6,480	$399,202	$100,942	1,879,778	56,083

As we do not believe this correction of information contained in Note 5 is a material change in the financial statements for fiscal 2011, we propose to provide the corrected information in the Company’s financial statements and Form 10-K for fiscal 2012, rather than amend the 2011 Form 20-K.

We note that you have not complied with prior comment nine from our letter dated December 18, 2012, concerning your cumulative loss situation and decision to not recognize a valuation allowance for the related deferred tax assets. We also note that while you indicate you had completed "a thorough review of the f acts and circumstances" including an "assessment of both positive and negative evidence and objective and subjective evidence" you did not identify or describe these underlying details in your reply. Please explain to us why you believe it is more likely than not that you will overcome the cumulative losses and realize the tax assets. You should describe the specific evidence that you have considered and the extent of your assumptions about future operations in formulating your view. Please submit the analysis that you referenced in your response.

Response: We attach the analysis that was provided to our tax preparer, KPMG, and our auditor, Padgett, Stratemann & Co., LLP, on March 12, 2012, which contains the analysis you requested. At the end of 2011, the Company believed that it was more likely than not that it would have sold all or a part of its Alaska acreage, which would have resulted in taxable income in 2012 and the utilization of our deferred tax assets. Our previous response to the comment letter dated December 18, 2012, mistakenly excluded the conclusion section of this analysis.

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).