Royale Energy, Inc.
7676 Hazard Center Drive, Suite 1500
San Diego, California 92108
619-881-2800
![](https://capedge.com/proxy/CORRESP/0001162677-13-000013/royallogo.jpg)
January 17, 2013
VIA EDGAR
H. Roger Schwall
Assistant Director
Division of Corporation Finance
Securities and Exchange Commission
Washington, D.C. 20549
Attention: Paul Monsour, Staff Attorney
RE: Royale Energy, Inc.
Form 10-K for Fiscal Year Ended December 31, 2011
Filed March 15, 2012
File No. 000-22750
Dear Mr. Monsour:
This letter responds to your letter dated December 18, 2012, 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:
Item 2. Description of Property, page 7
1. | We note that your MCF equivalent for barrels of oil is "based on a 10 to 1 ratio of the price per barrel of oil to the price per M CF of natural gas." As an equivalency of six to one is the ratio typically used for this purpose, revise to explain your basis for choosing this particular ratio. See Instruction 3 to Item 1202(a)(2) of Regulation S-K. |
Response: Royale Energy has historically (at least since fiscal 1996) reported our MCF equivalent using a 10-1 ratio. We have done this because, although a six to one ratio is more widely used for this purpose, the price differential has historically been much wider than a six to one ratio, and we have felt that the 10-1 ratio gives a better picture of this one measurement. Our engineers do not rely on this ratio in reporting our oil and gas reserves, relying instead on the actual prices of oil and natural gas during the measurement period, and accordingly the ratio does not figure in our financial reporting. Given our low ratio of oil to gas in our reserves and production, a change in this ratio would not materially affect our reporting (and would not affect financial results at all). |
For example, our oil production in 2011 was 2,264 bbls, which produces the following ratios: |
x 10 | x 6 | Difference |
22,640 | 13,584 | 9,056 bbls |
We propose to include the following explanation in our 10-K for the fiscal year ended December 31, 2012 (the “2012 10-K”): |
Royale Energy has historically used a 10 – 1 ratio of the price per barrel of oil to the price per MCF of natural gas because the company believes it is a more realistic indicator of the actual ratio of oil to natural gas prices than the 6 – 1 ratio used by other oil and gas producers in reporting similar measurements of production.
2. | Please provide the ongoing activity information required by Item 1206 of Regulation S-K. |
Response: Future filings will comply with this comment. We propose to add the following disclosure to our 2012 10-K: |
As of December 31, 2012, Royale Energy was in the process of drilling one well in California and had recently finished drilling another California well.
3. | If applicable, please provide the delivery commitment information required by Item 1207 of Regulation S-K. |
Response: None of our arrangements and contracts for sale of oil and gas contain delivery commitments. As disclosed on page 9 of the 2011 10-K, we generally sell our oil and natural gas at prices then prevailing on the spot market and do not have any material long term contracts for the sale of natural gas at a fixed price. |
4. | Please provide the total gross and net productive well information required by Item 1208(a) of Regulation S-K. We note the related disclosure at page 9. |
Response: Future filings will comply with this comment. We propose to add the following disclosure to our 2012 10-K, immediately after the Developed and Undeveloped Leasehold table (which appears on page 8 of our 2011 10-K): |
Gross and Net Productive Wells |
As of December 31, 2012, Royale Energy owned interests in the following oil and gas wells in both gross and net acreage: |
Gross Wells | Net Wells | |
Oil | _____ | _____ |
Gas | _____ | _____ |
Total | _____ | _____ |
Item 7. MD&A
Capital Resources and Liquidity, page 17
5. | We note that the price of natural gas, which comprised almost 99% of your reserves and 98% of your production for the year ended December 31, 2011, has been depressed. At the same time, reference to your most recent Form 10-Q, filed on November 13, 2012, shows that your working capital deficit has continued to increase. In light of these factors, please disclose how you intend to finance the development of your proved undeveloped reserves going forward, if known. See Item 1203(d) of Regulation S-K. Similarly, based on these trends and if these conditions were to persist, please discuss the extent to which you would expect to curtail activities. We note the general discussion under the risk factor captioned "We Require Substantial Capital for Exploration and Development" at page 6. See Items 303(a)(1) and (a)(2) of Regulation S-K. |
Response: |
We propose to include the following disclosure in the Capital Resources and Liquidity discussion in our 2012 10-K: |
Our capital expenditure commitments occur as we decide to drill wells to develop our prospects. We generally do not decide to drill any prospect until we have sold a portion of the working interest in a prospect to third parties to diversify our risk and receive a portion of the funds to drill each prospect. We place funds that we receive from working interest sales in a separate cash account until they are required for expenditures on each well.
The Company has traditionally relied on available credit and cash flows from operations for capital expenditures for oil and gas drilling and development, in addition to the cash generated from selling a portion of the working interest in prospects to third parties As discussed in Results of Operations, page __, the Company’s revenues both from oil and gas sales and from sales of working interests declined in 2012. As a result of the decline in natural gas prices, we curtailed our drilling efforts in 2012. we drilled only two wells in 2012, compared to seven wells in 2011. The decline in revenue also led the Company to seek alternate financing sources for its drilling activities.
To finance development of reserves, the Company has taken the following actions:
· | In October 2012, the Company obtained $3 million from sale of a convertible note. See, The Company’s Prospectus Supplement filed pursuant to Rule 424(b) on October 29, 2012, and the Company’s Form 8-K filed on October 29, 2012. The Company used these proceeds for general corporate purposes, including to reduce outstanding bank debt and for capital expenditures on oil and gas development. The note may, at the Company’s option, be repaid by converting the interest and principal amounts due to common stock, thus |
· | reducing the Company’s cash needs to service its debt. |
· | In February 2012, the Company entered into a sales agreement with C. K. Cooper & Company, Inc., to sell up to $10 million of common stock in an “at the market” offering as defined in Rule 415. In 2012, the Company sold approximately $4.8 million of common stock pursuant to the sales agreement. The company expects to sell additional common stock pursuant to the sales agreement in 2013. |
· | Beginning in January 2012, the Company began extensive cost cutting measures in General and Administrative, Legal and Accounting, and Marketing expense. These measures enabled us to reduce our operating expenses by approximately $1 million for 2012, compared to 2011, and expect that these measures will carry forward into 2013. |
We expect that these measures will be sufficient to meet our liquidity demands for the foreseeable future.
6. | Additionally, we note that your deferred revenue from turnkey drilling, a current liability, greatly exceeds the sum of your cash balance and cash flows provided by operating activities. Please discuss known commitments for capital expenditures and any expected material change to the mix and relative cost of your capital resources. |
Response: We drilled a well in December 2012 pursuant to a turnkey drilling arrangement, which reduced our outstanding capital expenditure commitments We expect to address our working capital commitments from a recent debt financing, recent sales of common stock in the fourth quarter of 2012 pursuant to an ATM sales agreement, current cash reserves, and recently undertaken cost cutting measures, as discussed in response to Comment 5, above. We will address our capital expenditure commitments fully in our 10-K for the year ended December 31, 2012. |
Notes to Financial Statements
Note 1 — Summary of Significant Accounting Policies Revenue Recognition, page F-8
7. | We note your discussion regarding turnkey drilling agreements under which you arrange to share drilling costs with investors to develop leasehold acreage you have acquired. We understand that investor funds designated to cover pre-drilling costs are non-refundable and reported as revenue when received, while funds designated for drilling costs are deferred until drilling occurs. |
Please expand your disclosure to provide further details of these arrangements, such as (i) the nature of the interests both conveyed and retained, (ii) typical percentages of the interests, (iii) an explanation for any differences between these interests and responsibility for costs, (iv) any provisions for cost recovery that alter sharing of returns in a manner that is not proportional to the interests held, (v) identity of the operator of the properties, (vi) the status of the underlying properties in advance of drilling, clarifying
whether oil and gas reserves have been established, and (vii) if reserves are found, the manner by which future development or operation of the properties would progress.
Please tell us how you view your agreements in the context of the guidance in FASB ASC 932-360-55. For example, it should be clear how you determined that guidance in subparagraphs 55-3, 55-4, 55-5, 55-7 and 55-9 did not apply, if this is your view. We would like to understand the manner by which you have apportioned funds received between conveyances of property interests and the provision of drilling services, including your rationale.
For drilling services, you should address your application of the guidance in FASB ASC 605-35-25-11 through 25-13 in determining that you would segment your accounting for funds related to pre-drilling and drilling. |
Response: |
Expansion of Turnkey Agreement Disclosures |
We propose to revise the discussion of Revenue Recognition in Note 1 of the financial statements for the years ended December 31, 2012 and 2011, as follows: |
Revenue Recognition
Royale Energy recognizes revenues from the sales of oil and natural gas upon transfer of title, net of royalties, in the period of delivery. Settlements for oil and natural gas sales can occur up to two months after the end of the month in which the oil and natural gas were produced. We estimate and accrue for the value of these sales using information available to us at the time our financial statements are generated.
Royale Energy recognizes revenues from the sale of natural gas in which the Company has an interest with other producers using the entitlements method of accounting. Under this method we recognize revenue based on our entitled ownership percentage of sales of natural gas delivered to purchasers. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total natural gas production. When we receive more than our entitled share, a liability is recorded. Gas imbalances on our production at December 31, 2012, 2011, and 2010 and 2009, were not significant.
Royale Energy enters into turnkey drilling agreements with investors to develop leasehold acreage it has acquired. In these arrangements, Royale Energy acquires a working interest in a prospect pursuant to an oil and gas lease, and it sells a portion of that working interest to investors with the turnkey drilling agreement to develop the lease. A working interest in an oil and gas lease is an ownership interest in which the working interest holder is responsible to bear the cost of drilling, testing completing, equipping and operating a well. Royale Energy
typically acts as operator of the projects in which it sells working interests to investors.
When Royale Energy sponsors a turnkey drilling project for sale, a calculation is made to estimate the pre-drilling costs and the drilling costs. A percentage for each is calculated. The turnkey drilling project is then sold to investors who investors enter into a signed contract with Royale Energy. In this agreement, the investor agrees to share in the pre-drilling costs, which include lease costs, and other costs as required so that the drilling of the project can proceed. As stated in the contract, the percentage of the pre-drilling costs that the investor contributes is non-refundable, and thus on its financial statements, Royale Energy recognizes these non-refundable payments as revenue since the pre-drilling costs have commenced. The remaining investment is held and reported by Royale Energy as deferred revenue from turnkey drilling until drilling is complete. Once drilling begins, it is generally completed within 10-30 days.
In a turnkey drilling agreement, Royale Energy agrees to sell a percentage of its working interest to investors and to pay for all costs of drilling, testing, completing and equipping the well for initial production at a fixed price. If the actual costs of these activities exceed the turnkey price that Royale charged to investors, Royale is responsible to pay the excess cost. If the actual costs are less than the turnkey price, Royale retains the excess of the turnkey price over actual costs. Royale bears 100% of the risk that actual costs will exceed estimated costs of a project, for both Royale’s working interest and the working interest sold to investors.
Royale Energy usually retains 50% of the working interest it owns, and Royale recognizes its proportional share as the basis for Royale Energy's oil and gas assets. If the well is completed as a commercially productive well, Royale Energy and the investors bear the cost of operating the well proportionately according to each party’s working interest percentage.
Royale Energy bases the price at which it sells working interests under the turnkey drilling agreement on its estimates of pre-drilling and drilling costs, described above. In addition, the turnkey drilling price also is based on Royale’s estimates of the costs of identifying, analyzing and marketing prospects for our turnkey drilling agreements, and is based upon the historical cost to obtain those funds. Revenues covering the pre-drilling and drilling costs are recognized when drilling is completed.
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.
If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, the deferred funds received would be returned to the investors. Included in cash and cash equivalents are amounts for use in completion of turnkey drilling programs in progress.
FASB ASC 932-360-55 |
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 participates in drilling with other oil and gas industry participants in the types of arrangements covered by the ASC subparagraphs.
The accounting treatment discussed in subparagraphs 932-360-55-3, 55-4, 55-5, and 55-7 do not apply to Royale’s turnkey drilling agreements. In these cases, Royale is participating in the drilling project as a working interest owner, and it has sold a portion of the working interest to other working interest owners under the turnkey drilling agreements. It does not retain a carried royalty or other non-operating interest.
FASB ASC 605-35-25
Regarding pre-drilling and drilling services and ASC 605-35-25-11 through 25-13, Royale’s current revenue recognition policy was adopted in 2004 as response to comments from the staff. Attached as Appendix 1 are excerpts of comments from and responses to the staff from comment letters in 2003 and 2004, as a result of which the current revenue recognition policy of the Company was established.
We have reviewed our policy regarding pre-drilling and drilling services in light of your comment and ASC 605-35-25-11 through 13. We propose to change our revenue recognition policy, beginning in 2013 and for the fiscal year ending December 31, 2012, to recognize all pre-drilling and drilling services that we provide under turnkey drilling agreements at the time that drilling of the well is completed. We will note this change in our critical accounting policies in the MD&A section of the 2012 Form 10-K, as well as in Note 1 to the financial statements for fiscal 2012.
We have reviewed our financial statements for 2011 and 2012, and we have determined that this change in our accounting policy would not have significantly affected our financial results for these periods. Our quarterly reports for 2013 will reflect the changed policy for the quarterly periods in 2012 as well as 2013. While there will be changes in the reported turnkey drilling revenues for the first three quarters of 2012 as a result of timing, the financial results for 2012 would not materially change as a result of this policy change.
We are continuing to evaluate the best way to recognize revenue from our turnkey drilling agreements as well as whether to change the terms of our turnkey drilling contracts, and we may, of course, change our revenue recognition policy again in the
future if we determine that another change would be appropriate under generally accepted accounting principals and the relevant FASB guidance.
Note 5 — Financial Information Relating to Industry Segments, page F-16 |
8. | For each year presented, the amounts identified as 'lease impairment' appear to have been evenly split between your two reported segments. As disclosure on page F-9 indicates these relate to oil and gas properties that have been impaired, tell us your rationale for attributing any portion of these charges to your turnkey drilling services segment and explain your logic in dividing them equally. |
Response: As discussed in response to Comment 7 above, the Company expects to sell approximately 50% of it’s the acreage it acquires for development to third party, working interest investors. When lease acreage that it has acquired is identified as 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. Accordingly, it attributes 50% of the impaired property to the turnkey drilling segment. |
Note 7 — Income Taxes, page F-20 |
9. | We note that you report cumulative losses for the three and five year periods ended December 31, 2011. In view of this, explain to us your basis for concluding that it is more likely than not that your deferred tax assets will be realized and that a full valuation allowance is not required. As part of your response, describe the positive and negative evidence you considered in evaluating the need for a valuation allowance and explain the relative weights you assigned to this evidence and your rationale. Given the guidance in FASB ASC 740-10-30-23, explaining that a cumulative loss in recent years is a significant piece of negative evidence that is difficult to overcome, we would like to understand the extent to which you have adhered to the guidance in FASB ASC 740-10- 30-16 through 740-10-30-23 in conducting your analysis. |
Response: 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 FASB Accounting Standards Codification. 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.
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.
The Company had statutory percentage depletion carry forwards of approximately $2,100,000 at December 31, 2011. The depletion carryforwards have no expiration date. The Company also had a net operating loss carry forward totaling approximately $5,200,000 at December 31, 2011. Approximately $1,100,000 of the net operating loss will expire in 2027, $1,600,000 will expire in 2028, $1,500,000 will expire in 2029, $300,000 will expire in 2030 and the remaining portion, $700,000, will expire in 2031.
Significant management judgment is required in assessing the realizability of the Company’s deferred tax assets. The Company considers all available evidence, both positive and negative, in assessing the extent to which a valuation allowance should be applied against its deferred tax assets. If, based on its assessment, the Company determines that it is more likely than not (intended to mean a likelihood that it is more than 50%) that some portion or all of the deferred tax assets will not be realized, a valuation allowance is established.
Under provisions of FASB ASC 740, forming a conclusion that a valuation allowance is not needed is difficult when there is negative evidence such as historical losses, uncertainty of future profitability and determination of exact net operating losses subject to section 382 limitations.
The ultimate realization of deferred tax assets is dependent upon generation of future taxable income in each tax jurisdiction during the periods in which the temporary differences become deductible. Management considers the scheduled reversal of deferred liabilities, projected future taxable income, tax planning strategies, and the ability to carry-back tax attributes in making this assessment.
The Company performs an annual evaluation to determine if it is more likely than not that some portion of the deferred tax assets will not be realized. The Company recorded income for financial statement purposes in 2010, 2006, and 2005 but incurred losses from 2007 through 2009 and again in 2011.
.
Valuation Analysis
The Company considers the following in its analysis to determine if the deferred tax assets are “more likely than not” realizable:
1. | historical pre-tax book results of operations to determine if they had accumulated profits or losses over the past three years; |
2. | lease impairments recorded in the past three years; |
3. | permanent differences between book and tax income; |
4. | expiration date of the net operating loss carryforwards; and |
5. | forecasting results of operations to determine what portion, if any, of the deferred tax assets will be utilized. |
At December 31, 2011, after a thorough review of the facts and circumstances in accordance with the guidance of SFAS No. 109, management determined, based on its assessment of both positive and negative evidence and objective and subjective evidence that it is more likely than not that the Company:
· | will not realize its depletion deferred tax asset carryover; therefore, it recorded a valuation allowance for the entire balance of the related deferred tax asset. |
· | will realize the net operating loss carryforward; therefore, no valuation allowance was deemed necessary. |
The Company will re-evaluate the realizability of its deferred tax assets as of December 31, 2012 using the analysis above. |
* * *
We acknowledge that:
· | The Company is responsible for the adequacy and accuracy of the disclosure in the filing; |
· | Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and |
· | The Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. |
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).
Very truly yours,
/s/ Stephen M. Hosmer
Stephen M. Hosmer,
Co-President, Co-Chief Executive Officer and
Chief Financial Officer
Appendix 1
Excerpts from Comment Responses Dated December 11, 2003, and November 12, 2004
December 11, 2003
LEE POLSON
512.499.3626
Direct Fax: 512.536.5719
lee.polson@strasburger.com
VIA FEDERAL EXPRESS
H. Roger Schwall
Assistant Director
Division of Corporation Finance
Securities and Exchange Commission
450 Fifth Street N.W.
Washington, D.C. 20549-0405
RE: | Royale Energy, Inc. |
Form S-3/A filed on November 12, 2002 |
File No. 333-60918 |
File No. 0-22750 |
Form 10-KSB/A for the year ended December 31, 2001 |
Form 10-KSB/A for the year ended December 31, 2002 |
Form 10-QSB for the quarter ended September 30, 2002 |
Dear Mr. Schwall:
On behalf of Royale Energy, Inc. (“Royale Energy”), we submit this response to the Commission’s letters dated December 2, 2002 and December 4, 2002, commenting on the referenced filings. Today we have filed Amendment No. 2 to the Form 10-KSB for the year ended December 31, 2001 (the “2001 10-KSB”), Amendment No. 1 to the Form 10-KSB for the year ended December 31, 2002 (the “2002 10-KSB”), and Amendment No. 1 to the Form 10-QSB for the quarter ended September 30, 2002 (the “9-30-02 10-QSB”) which incorporate disclosures in response to your comments. We also enclose (via Federal Express) copies of the 2001 10-KSB/A, 2002 10-KSB/A, and 9-30-02 10-QSB, together with copies marked to show changes from the previously filed versions. Both the marked and unmarked copies are keyed with numbers in the right margins of the pages to refer to your numbered comments. Certain of the responses refer to disclosures that were made in the 2002 10-KSB in response to comments. Where appropriate we indicated whether amendments were also made to the 2001 10-KSB in response to comments, or whether we felt that additional changes to the 2001 10-KSB were not necessary.
The following numbered responses correspond to the numbered comments in your letters.
{Unrelated Material Omitted}
Note 1 – Summary of Significant Accounting Policies
Revenue Recognition
11. | It is Royale's policy to recognize the entire remaining investment amount as revenue upon commencement of drilling. Royale's experience is that drilling averages 45 days or less. With such a short time period from commencement to completion the recognition of revenue throughout the drilling process, as opposed to the current policy, is not materially different. |
We reviewed uncompleted drilling projects at the end of 2001 and 2000 and determined that the difference between the revenue recognized at commencement under Royale's current policy was not materially different than revenue recognized throughout the drilling process. At the end of 2001, we had one well that had been spud on October 30, 2001, but was not completed until March 2, 2002. The delay was due to rains in the area which flooded the drilling site. At December 31,2001, the well was approximately 90% complete. At the end of 2000, all wells that had been started were completed. |
{Unrelated Material Omitted}
We trust that we have completely responded to your comments concerning the 10-KSB. If you have questions or additional comments, please contact me at 512-499-3626 (fax 512-499-3660, e-mail lee.polson@strasburger.com).
Very truly yours,
Lee Polson
November 12, 2004
LEE POLSON
512.499.3626
lee.polson@strasburger.com
H. Roger Schwall
Securities and Exchange Commission
450 Fifth Street N.W.
Washington, D.C. 20549
Attention: Michael Pressman
RE: | Royale Energy, Inc. |
Form 10-KSB for the Year Ended December 31, 2002 |
Form 10-KSB for the Year Ended December 31, 2001 |
Dear Mr. Pressman:
On behalf of Royale Energy, Inc., we submit this response to the Commission’s letter dated February 18, 2004, commenting on the referenced filings. Today we have filed Amendment No. 2 to Royale Energy’s Form 10-KSB for the year ended December 31, 2002 (“2002 10-KSB/A-2”), which incorporates disclosures required in response to the comments. In addition, we have filed Amendment No. 1 to Royale Energy’s Form 10-KSB for the year ended December 31, 2003 (“2003 10-KSB/A-1”), in which we have made corresponding changes to conform to the changes made in the 2002 10-KSB/A-2. We submitted (via Federal Express) four copies of the 2002 10-KSB/A-2 marked to show changes from Amendment No. 1, and four copies of the 2003 10-KSB/A-1 marked to show changes from the original filing. The marked copies are keyed with numbers in the right margin of pages to indicate changes made in response to comments.
The following numbered responses correspond to the numbered comments in your letter.
{Unrelated material omitted}
Note 1 – Summary of Significant Accounting Policies |
Revenue Recognition |
8. | We note your response to our prior comment number 11 and do not concur with your revenue recognition policy related to turnkey drilling projects. Revenue should be recognized when it is realized or realizable and earned. Revenue generally is realized or realizable when all of the following criteria are met: |
· | Persuasive evidence of an arrangement exists, |
· | Delivery has occurred or services have been rendered, |
· | The seller’s price to the buyer is fixed and determinable, and |
· | Collectibility is reasonably assured. |
It would appear that the drilling services you provide to investors would not be rendered at the time you commenced drilling. Rather such services would be considered rendered at the time drilling was completed to the specified depth. The recognition of revenue upon completion of drilling appears to be further supported by the fact that you must return the deferred funds to the investors in the event you are unable to drill the wells and a suitable replacement well is not found. |
Restate your financial statements to recognize turnkey drilling revenue upon the completion of the drilling projects or provide further detailed evidence to support you revenue recognition policy is in compliance with authoritative accounting guidance. |
Royale Energy has changed its revenue recognition policy to recognize turnkey drilling revenue upon completion of drilling rather than on commencement of drilling. As noted on page 3 of Royale Energy’s 2002 10-KSB/A-2, the company typically completes drilling of its wells within 7 – 14 days after commencement, so the timing differential caused by this change is small. The company and its auditors reviewed the company’s work in process for the past three years to determine whether a restatement of its financial statements is required by this change. Based on that review, the company determined that revising its revenue recognition policy did not result in a material change in its financial statements. Enclosed as Attachment 8 is a copy of the auditors’ workpapers1 regarding the effect of changing the revenue recognition policy. |
The following disclosure of the change is included in the MD&A section of the 2002 10-KSB/A-2: |
Royale Energy derives DWI revenue from sales of working interests to high net worth individuals. DWI investments are non-refundable. The DWI revenue is divided into payments for pre-drilling costs and for drilling costs. DWI investments are non-refundable. Pre-drilling costs include lease acquisition, geologic and geophysical costs, and other organizational costs of the project which have been incurred by Royale Energy prior to entering the drilling contract between the investors and Royale Energy. The drilling contract provides that the pre-drilling costs are due and payable to Royale Energy when the contract is entered, and those pre-drilling costs are recognized as revenue when the investor makes the investment and enters the contract. Prior to 2002, the company held the remaining investment in trust as deferred revenue until
1 In August 2004, Royale Energy changed auditors. The analysis and attached workpapers concerning this issue were prepared by the former auditors, Brown Armstrong (the “2002 auditors”), who performed the 2002 audit.
the well was spudded (begun). The company has changed its revenue recognition policy, so that the funds held in trust would not be recognized as revenue by the company until drilling of the well is complete, in line with what the company believes to be standard industry practice. This policy change did not result in a material change in the company’s drilling revenues in 2002 or 2001 because, at the end of each of those years, none wells were in the process of being drilled. Royale Energy recognizes the pre-drilling revenue portion when the investor deposits money with Royale Energy. The company holds the remaining investment in trust as deferred revenue until the well is spudded (begun).
See 2002 10-KSB/A-2, page 11. A similar change was made in Item 1, Description of Business – Plan of Business, page 2-3, in Note 1 of the Financial Statements, page F-7, and in appropriate places on pages 11, 2 and F-10-F11 of the 2003 10-KSB/A-1.
{Unrelated material omitted}
We trust that this information completely responds to your comments. Please contact us if you have questions or require additional information.
Very truly yours,
Lee Polson