November 9, 2009
Mr. Terence O’Brien
Division of Corporation Finance
United States Securities and Exchange Commission
Mail Stop 4631
Washington, D.C. 20549-4631
RE: | ESP Resources, Inc. | |
Form10-Kfor the Fiscal Year Ended December 31, 2008 | ||
Filed April 15, 2009 | ||
Form10-Qfor the Fiscal Quarters Ended March 31, 2009 and June 30, 2009 | ||
File No. 0-52506 |
Dear Mr. O’Brien:
Thank you for your comments dated August 28, 2009 in respect to certain filings for ESP Resources, Inc. on Forms 10-K for the year ended December 31, 2008 and 10-Q for the quarters ended March 31, 2009 and June 30, 2009, that were filed with the Commission on April 15, 2009, May 20, 2009 and August 19, 2009 respectively.
For your convenience, the text of the Staff's comments has been included in this letter and the numbers below correspond to the numbered paragraphs in the comment letter. For clarity, the Staff’s comments are in italics. In connection with responding to the Staff's comments, the Company hereby acknowledges that it is responsible for the adequacy and accuracy of the disclosure in its filings under the Securities Exchange Act of 1934; the Staff's comments and the changes to the disclosure in the Company's filings in response to the Staff's comments do not foreclose the Commission from taking any action with respect to the Company's filings; 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.
The following are our detailed responses to your comments.
Form 10-K for the Fiscal Year Ended December 31. 2008
Application of Critical Accounting Policies, page 26
Oil and Gas Properties. page 26
1. | We note the additional disclosures you intend to include in future filings in response to comment 2 in our letter dated August 28, 2009. In addition to the descriptions of the material factors considered and the material assumptions used in estimating the fair value, please quantify the material assumptions. For example, please disclose the amount of reserves estimated as available for sale, the estimated selling price, the price per thousand cubic feet of natural gas that would cover your estimated extraction costs, when you estimate that the well will begin producing natural gas for sale from each well, your share of the estimated earnings from each well, and any other material assumptions used to estimate fair value. |
RESPONSE:
We will quantify our material assumptions in future filings, as applicable, in the assessment of fair value of unproved properties. We refer to the discussion of material assumptions in Item 3 below. As discussed in Item 4 below, our oil and gas properties are currently classified as unproved. As such, we do not have reserve reports prepared on the SEC basis for these properties, and the cost of preparing these reports would be unduly burdensome.
Note1 -Basis of Presentation, Nature of Operations and Significant Accounting Policies, page 36
Reverse Merger, page 36
2. | We note your response to comment 4 in our letter dated August 28, 2009. It continues to remain unclear how you determined the quoted market price of your common stock is not the fair value of these securities. In this regard, we note that your shares were being regularly traded during December 2008 and subsequent thereto. Further, we note that you issued common shares to consultants during March 2009 in which you based the fair value of those shares on the quoted trading prices on the day the shares were issued without the use of a discount.Inaddition, we did not note a significant difference in trading volume in March 2009 as compared to December 2008. We continue to believe that the use of quoted market prices when equity securities are issued generally provide clear evidence of fair value, except in instances in which there is a limited to no market for the equity securities. This exception does not appear to be representative of your common shares trading history. To the extent that you believe a discount should be applied to the quoted market price, please provide us with the objective and verifiable evidence as to how you determined the amount of the discount. |
RESPONSE:
We intend to amend our Form 10-K for the year ended December 31, 2008 to reflect the acquisition of Pantera Petroleum at the fair value of the stock on the date of acquisition. The description of the reverse merger in the footnotes to the December 31, 2008 financials and our discussion of our analysis of the impairment of goodwill will be revised to read as follows:
Reverse Merger
On December 29, 2008, the Company closed an Agreement for Share Exchange with ESP Delaware and ESP Enterprises, Inc. (“Enterprises”), a Colorado corporation and the sole shareholder of ESP Delaware whereby the Company acquired 100% ownership of ESP Delaware in exchange for 14,634,146 shares of common stock of the Company which represented approximately 76% of the Company. Immediately prior to the share exchange, the Company had 4,572,283 shares issued and outstanding.
Due to the change in control of the Company this transaction was accounted for as a reverse merger in accordance with SFAS No. 141 whereby ESP Delaware was considered the accounting acquirer. The transaction was valued at $0.76 per share based on the average trading price of the Company’s stock for the three days before and after the announcement of the transaction. The total consideration paid was $3,461,218 based on the 4,572,283 shares of common stock retained by the existing shareholders of the Company. The net assets of ESP Nevada were recorded at fair value on the date of acquisition. Management has reviewed the operations of ESP Nevada for the existence of intangible assets and has determined that there are none. The go-forward financial statements presented herein are those of ESP Delaware. The results of operations of ESP Nevada are included from the date of the acquisition forward. Net assets acquired were as follows:
Cash | $ | 13,260 | ||
Notes receivable | 278,004 | |||
Property and equipment | 2,536 | |||
Unproven Oil & Gas properties | 1,067,382 | |||
Prepaid expenses | 16,102 | |||
Deposit | 1,510 | |||
Goodwill | 2,559,879 | |||
Related party debt | (67,354 | ) | ||
Liabilities assumed | (49,911 | ) | ||
Notes payable, net | (360,190 | ) | ||
Net assets acquired | $ | 3,461,218 |
Goodwill
All goodwill relates to the business acquired in the reverse merger transaction described above. The changes in the carrying amount of goodwill for the year ended December 31, 2008, are as follows.
Balance, December 31, 2007 | $ | - | ||
Goodwill acquired during the year | 2,559,879 | |||
Impairment losses | (2,559,879 | ) | ||
Balance, December 31, 2008 | $ | - |
Goodwill was tested for impairment as of December 31, 2008. All goodwill relates to Pantera Petroleum, which was acquired in the reverse merger on December 29, 2008. Management has estimated the fair value of this reporting unit and has determined that the goodwill was impaired as of December 31, 2008. An impairment loss of $2,559,879 was recognized for the year ended December 31, 2008. The fair value of that reporting unit was estimated using the expected present value of future cash flows. The goodwill was fully impaired because there were no expected future cash flows in excess of those that were already used to value the oil and gas properties at fair value on the date of acquisition which was two days earlier.
3. | We note your response to comment 5 in our letter dated August 28, 2009. Please provide us with the present value analysis you prepared to compare to the carrying value, as referenced in your response letter. Please also provide us with a detailed discussion as to how you determined each of the material assumptions used to prepare the present value analysis are reasonable. |
RESPONSE:
We are enclosing the present value analysis in the attached spreadsheet, separately analyzing the Sibley 84#1 re-entry well, the Sibley 84#2 new drill, and the Gulf Baker 83#1 re-entry well. The initial target zones are the Devonian for the 84#1, the Lower Wolfcamp for the 83#1, and the Yates/7 Rivers formation for the 84#2. As stated previously, the Company purchased a 10% working interest, the same being a 7.5% net revenue interest, in the Block 83 84 Project JV for the rights in these 3 wells for $800,000 in total, carry to the tanks.
Material Assumptions:
Oil Price: We assumed $60 per barrel (/bbl). This assumption is mostly for the 84#2 which is a new oil drill, as 84#1 and 83#1 are predominantly gas wells. As 2010 and 2011 are the pertinent time frames for projections given the estimated reserve potential of 84#2 of 50,000 barrels and an estimated 80 barrel per day (b/d) base case production, we compared $60/bbl to the U.S. Government Energy Information Administration’s Annual Energy Outlook 2009 Reference Case (Updated). We also compared them to NYMEX futures prices (which we include below as of October 21, 2009). Both projections from the EIA and the futures curve indicate prices above $60/bbl.
Gas Price: We assumed $3.00/mmbtu. This assumption applies to the two re-entry wells, 84#1 and 83#1 as they are predominantly gas wells. Again, we compared our assumption to the U.S. Government Energy Information Administration’s Annual Energy Outlook 2009 Reference Case (Updated). We also compared them to NYMEX futures prices (which we include below as of October 21, 2009). Both projections from the EIA and the futures curve indicate prices above $3/mmbtu.
Working Interest: Full projections on each well are run on a 100% Working interest with a 75% net revenue interest. The company has a 10% working interest, the same being a 7.5% net revenue interest, which is reflected in expected value analysis.
Decline Rate: Assumed a 20% decline rate for the 84#1 and 83#1 which is within the operator’s experience in this field and is reasonable for these wells. Assume a 0% decline rate for 84#2 as it is a relatively shallow (4000’) new oil drill with smaller potential reserves. The production rate of 80 bbl/day seems reasonable given the production in the nearby Apache operated fields and those of Chaparral located 1 mile to the south and southeast.
Production Rates: Assumed a base case of 2.5 million cubic feet per day (mmcf/d), upside of 3.5 mmcf/d, and downside of 1.5mmcf/d for each of the 84#1 and 83#1. This is based on the operator’s analysis of the area production along with the logs of the wells themselves. Assumed a base case of 80 barrels per day (bbl/day) for the 84#2 with a downside of 40 bbl/day, and an upside of 100 bbl/day. 84#2 is targeting the Yates/7 Rivers formation. The Chaparral field, Fort Stockton SW Unit, located 1 mile south and southeast, has produced over 1.2 million barrels. Conversations with the operator and Apache reveals that Apache is also currently drilling infield development wells in this formation and producing these wells at a rate of 80-100 bbl/d.
Reserves: Using area production and a log analysis, the operator has established potential reserve estimates. While Lakehills Production, the operator, did an analysis of the area production and a log analysis of the old logs to come up with estimates of potential reserves in each zone, the operator is not an independent, third party reserve engineer in the business of being a reserve engineer. However, as a petroleum engineer and an operator, he performed the estimates in his professional judgment, but can’t present in the format the Commission requires. The operator did not assign categories, whether proved or unproved. They are estimates of potential based on his analysis with the area production, the logs, and his field experience. It’s a prediction of what might be found to be present when it’s actually developed, and tested.
Well 84#1: This re-entry well was completed in 1973 in the Ellenburger formation from 22,420’-726’ and produced 0.65 billion cubic feet (bcf) gas before being plugged in 1978. Since the Ellenburger was squeezed and did not perform as well as other Ellenburger wells in the area, because of the cost, it was deemed not worth attempting a recompletion in this zone. The target zones are the Fusselman formation from 19,320-365’ and the Devonian formation from 18,985-19,050’. The Fusselman was completed and produced in the Dixel well in the section adjacent to Section 84 to the east and tested at 2 mmcf/d before being taken back to the Ellenburger. Section 84 is over 1 mile away. The Devonian has not produced in the immediate area but is prolific in the area to the south and east of section 84. The log analysis indicates a 8-10% primary porosity and exhibits inter-crystalline secondary porosity. Based on equivalent production, the operator estimates the potential reserves from these two zones to be 6 bcf. Additional potential reserves are 4-5 bcf in the 16,500-17,300’ Lower Wolfcamp, and 3-4 bcf in the 15,200-16,400’ Lower Wolfcamp. The Atoka is estimated at 1.5 -2 bcf potential reserves.
We assumed a completion in the Devonian with a 4 bcf reserve potential for expected value calculations, which is reasonable based on the above analysis of the logs and area production, along with the operator’s experience in the field.
Well 83#1: This re-entry well was completed in 1974 as an Ellenburger producer and produced 0.774 bcf gas before being plugged and abandoned in late 1979. A recompletion in the Ellenburger zone was deemed to be uneconomical. Prior to being plugged, a completion was attempted in the Lower Wolfcamp from 17,202’ -17,248’. According to the operator’s analysis, the well potentialed at 3.5 mmcf/d with little water, but was not produced. Based on reserves in the area, this well is estimated to have potential reserves of 4-5 bcf in the Lower Wolfcamp from 16,500’-17,250’ and another 3 bcf from 15,200’-16,400’. The Upper Wolfcamp 11,600’-900’ is estimated to have potential reserves of an additional 2.5 -3 bcf. The Legacy – Sibley #2 well in Section 76 (2 miles NW) produced 3.8 bcf from this zone. Additional potential reserves include the Atoka 17,650-920’ at 1-1.5 bcf. We assumed just producing the Lower Wolfcamp with potential reserves of 4 bcf for expected value calculations.
Well 84#2: As described above, we assumed 50,000 barrels in potential reserves based on the area production by Apache and Chapparel, their infield drilling program, and their daily production rates in the Yates/7-Rivers formation. This is a new drill.
Operating Expense, Tax rates, Days in Production: As these are re-entry wells, there is limited operating expense of $3000/month and assumed operations of 27.25 days/month. Tax rates are statutory.
Discount Rate: We assumed 10% which we believe is industry standard for the re-entry wells given the conditions.
Expected Value: This is the weighted average of the present value of the downside, base, and upside cases, along with a total failure case, where the weights are the probabilities of occurrence of those values. Given the uncertainty of the ability of Trius Energy as managing joint venturer to have adequate capital to complete the projects as contracted to do, along with the uncertainty given any operational problems, we assigned a 40% probability to a 0 case outcome, with a 20% probability to each of the other outcomes. This generated a $341,284 present value for each of the 84#1 and 83#1 and a $105,445 present value for the 84#2. Our total 10% interest is calculated at a combined $788,013 for the total 3 well project.
4. | We note that the Sibley 84#1 well was producing from the Devonian and Fusselman zones and began selling natural gas. In addition, we note your statement that the Lower Wolfcamp zone is a productive zone. As such, it is unclear how you determined that the property is properly classified as unproved. | |
Please provide us with a detailed explanation as to how you determined that the reserves on the property do not meet the definition of proved reserves. In this regard, we note your press release dated June 2, 2008, in which you stated, "Block 83 84 can potentially produce 6.5 million cubic feet of gas per day from its two re-entry wells, along with 80 or more barrels of oil per day from the Sibley 84 #2. Based on published production data and geological and engineering calculations, recoverable reserves in the Block 83 84 Project are estimated to be more than 27 Bcf of gas and 50,000 barrels of oil." Please reconcile the statements in your press release regarding potential reserves and recoverable reserves, which appear to be undefined terms, with the disclosures in your fiscal year 2008 Form 10-K and subsequent filings that the property is properly classified as unproved. | ||
Please provide us with a detailed description of the studies that have been conducted to determine the amount of proved reserves within each zone on the property. Please provide us with a copy of the report(s) from the studies that have been conducted for the Fusselman, Devonian, Wolfcamp, Atoka, and any other productive zone and the corresponding wells to determine the amount of proved reserves to date. If no such studies have been completed, please explain to us how the Sibley 84#1 well began producing and selling natural gas without having a study completed to determine the amount of proved reserves. Please also tell us the additional evidence that is required to determine the amount of proved reserves, as defined by Rule 4-10(a)(22) of Regulation S-X. | ||
In future filings, please ensure your disclosures provide investors with a complete understanding of the status of determining the amount of proved reserves, including the studies that need to be completed to determine the full amount of proved reserves located on the property. Please also explain why management has not been able to complete these studies to determine the full amount of proved reserves, especially in light of the fact that one of the wells did produce natural gas for a short period of time. |
RESPONSE:
Under the definition of 17 CFR Section 210.4 -10, Subsection A(2), the Block 83 84 Project JV’s three well project does not meet the definition of proved reserves. While true there was production in 84#1 from the Devonian and Fusselman zones, it was so limited as to not rise to the definitional level of being economical to a reasonable certainty, especially in light of the unexpected water problem very shortly after production began, in addition to the subsequent blowout. The target zones in the 84#1 and 83#1 have not produced in these particular wells, aside from the small production in 84#1 before the water inflow and blowout. For 84#1, along with 83#1 and the undrilled prospect 84#2, the recovery of natural gas and crude oil is subject to reasonable doubt because of uncertainty as to economic factors, geology, and reservoir characteristics. As an example, 84#1’s target zones of the Devonian and Fusselman produced an uneconomical amount of water unexpectedly, and the economical producibility of those zones does not rise to the level of reasonable certainty.
Using area production and a log analysis, Lakehills Production, the operator, has established potential reserve estimates. We reference our answer in question #3 above as to reserve estimates. While Lakehills Production, the operator, did an analysis of the area production and a log analysis of the old logs to come up with estimates of potential reserves in each zone, the operator is not an independent, third party reserve engineer in the business of being a reserve engineer. However, as an engineer, he performed the estimates in his professional judgment, but can’t present in the format the Commission requires. As such, the operator did not prepare a formal report as an independent reserve engineer and did not assign categories to the estimates, whether proved or unproved. They are estimates of potential based on his analysis with the area production, the logs, and his field experience. It’s a prediction of what might be found to be present when and if it is actually developed, and tested. The 84#2 is undrilled, and 83#1 has not been re-entered. The 84#1 is still under development given the water issues and blowout.
After re-entry in the 84#1 after the blowout and 83#1, we must still test each zone to see what is productive or not productive. These are very aged wells that haven’t been touched in a very long time, since 1978 for 84#2 and 1979 for 83#1 when they were plugged and abandoned. These wells are drilled approximately 22,000+ feet, or approximately 4 miles below the earth, and anything could have happened in 30 years to make the wells not economical. Over time, more of these wells have been tapped in different zones like the Fusselman and Devonian and Lower Wolfcamp in this field which we are targeting, and become productive, but those wells’ economic productibility does not assure to a reasonable certainty the economic producibility of the 84#1 and 83#1, due to many factors including the age of the 84#1 and 83#1 and the 1 mile spacing for the wells in this field.
It was always intended to get an independent reserve analysis once economic producibility is supported to the level of a reasonable certainty. However, that has not occurred yet. At that time, we intend to obtain the analysis from an independent, third party reserve engineer. Until then, it is a misuse of limited capital to obtain that report until proof of economic producibility to the level of reasonable certainty occurs.
We intend to write down these properties to a significant degree as of September 30, 2009 due to the decreased probability of Trius Energy obtaining additional financing for these projects.
Form 10-Q for the Fiscal Quarter Ended March 31, 2009 (Draft)
Item4T.Controls and Procedures
5. | As previously requested, please revise your draft disclosure to specifically state the conclusion your principal executive and principal financial officers made regarding the effectiveness of your disclosure controls and procedures as of March 31, 2009 (i.e., disclosure controls and procedures were not effective). Refer to Item 307 of Regulation S-K for guidance. Please also refer to your response to comment 21 in your letter filed on EDGAR on September 28, 2009. |
RESPONSE:
We intend to amend the Form 10-Q for the quarter ended March 31, 2009 to include the following revised discussion of our controls and procedures:
As required by Rule 13a-15 under the Securities Exchange Act of 1934, as of the end of the period covered by this quarterly report, being March 31, 2009, we have carried out an evaluation of the effectiveness of the design and operation of our company’s disclosure controls and procedures. This evaluation was carried out under the supervision and with the participation of our company’s management, including our company’s President and Chief Executive Officer. Based upon that evaluation, our principal executive officer and principal financial officer concluded that, as of the end of the period covered in this report, our disclosure controls and procedures were not effective to ensure that information required to be reported in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the required time periods and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. In connection with the completion of the review and issuance of the Form 10-Q report on our financial statements for the quarter ended March 31, 2009, we identified deficiencies that existed in the design or operation of our internal control over financial reporting that it considers to be “material weaknesses.” The PCAOB has defined a material weakness as a “significant deficiency or combination of significant deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.” The material weaknesses persisted during the period covered by this report.
These material weaknesses are a result of the lack of a formal communication procedure for reportable activities occurring in the Company’s subsidiary, ESP Petrochemicals, Inc., to the chief executive officer of the Company, who is also the officer in charge of the Company’s reporting obligations.
Prior to the reverse acquisition, which occurred on December 30, 2008, there was one employee of ESP Resources, Inc., one physical location in Texas where employees maintained offices and the Company did not have any subsidiaries. Every Company transaction was approved by the Company’s chief executive and financial officer. Following the reverse merger transaction, the Company’s chief executive and financial officer continued to handle the transactions involving the Company’s investments prior to December 30, 2009. At that time, the chief executive officer of ESP Petrochemicals, Inc. was appointed the president of the Company and oversaw the operations of ESP Petrochemicals, Inc. The principal offices of the Company were also moved from Texas to Louisiana. The Company continues to operate in this manner, with the Company’s chief executive and financial officer residing and working in Texas and the Company’s president residing and working at the Company’s principal office in Louisiana.
While the Company (i) is not aware of any reportable events that have not been disclosed in a timely manner and (ii) together with its subsidiary, continues to employee less than ten people, the chief executive and financial officer believes that the expansion of the Company’s operations and geographic distance between the principal officers of the Company merit the implementation of a more formal procedure for periodically communicating the Company’s activities to the chief executive and financial officer. The Company proposes to conduct at least weekly conference calls to review the transactions in which the Company and its subsidiary have participated in the previous week and to immediately communicate of significant events. The chief executive and financial officer feels that these additional procedures will provide reasonable assurance that the Company’s controls and procedures will meet their objectives.
In order to respond to the risk described above, the Form 10-Q was reviewed by both the Company’s chief executive and president to confirm that all required transactions had been adequately disclosed.
Our management, including our principal executive officer and principal financial officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error or fraud. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs. Due to the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected.
To address the material weaknesses, we performed additional analysis and other post-closing procedures in an effort to ensure our consolidated financial statements included in this quarterly report have been prepared in accordance with generally accepted accounting principles. Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.
Form 10-0 for the Fiscal Quarter Ended June 30, 2009
Note 4 - Accounts Receivable and Allowance for Doubtful Accounts
6. | Please confirm to us that you will include disclosures that provide investors with the explanation you included in your response letter as to how you determined Turf's outstanding accounts receivable balance is collectible in future filings. Refer to your response to comment 16 in our letter dated August 28, 2009. |
RESPONSE:
We will include disclosures that provide investors with the following explanation in future filings:
ESP began discussions with Turf concerning a potential acquisition of the assets and business of Turf in early July, 2008. An approximate value of the acquisition was reviewed between the principals of Turf and ESP along with descriptions of the assets, receivables, current customer base, payables, debt structures, notes, and inventories of Turf. The principals agreed that any purchase price of the Turf business would have a cash component and a stock component of ESP stock. The principals of ESP agreed to supply wholesale chemicals to Turf to assist Turf in increasing their business prospects and supplying their current and potential customer base while ESP continued the due diligence necessary to complete the Turf acquisition. The principals of both companies agreed that any wholesale chemicals supplied by ESP to Turf and invoiced during this period would be deducted from the cash portion of the transaction at closing. During the period from July 22, 2008 – December 29, 2008, ESP supplied Turf with $202,192.62 of wholesale chemicals and storage equipment tanks. During this period, the price of oil declined from $143 per barrel to below $35 per barrel. The decline in oil product pricing caused several of the clients for Turf and ESP to scale back their use of petrochemicals at their field locations. This event hampered the ability of ESP to raise additional equity funds through the sale of securities of the company. Discussions between the principals of Turf and ESP continued and a letter of intent outlining the terms and conditions of a purchase of Turf was executed in February 2009. At the time of signing of the LOI, ESP anticipated the sale of company securities to raise approximately $1,000,000 in new equity for the company. To date, we have not been successful in the capital raise. The LOI with Turf has been extended indefinitely in anticipation of a successful equity raise by ESP. During the period of January1, 2009 – May 31, 2009, ESP provided an additional $55,170.15 of wholesale chemicals to Turf. The LOI with Turf provides that in the event that a transaction is not completed, Turf would begin making payments on the outstanding invoices and an interest rate of 5% per annum would be added to the outstanding receivable until paid.
During the months of August and September, 2009, ESP has made significant progress towards the sale of company securities in an equity raise and has negotiated terms and conditions upon which the equity raise could be completed with several individuals who have expressed an interest in funding the equity raise. We anticipate receipt of funds in the amount of $700,000 - $1,000,000 before year end.
ESP and Turf have agreed verbally that the purchase of the Turf business will consist of $100,000 cash plus all of the outstanding invoices and amounts due ESP as the cash portion of the final negotiated purchase price plus ESP stock to fulfill the remainder of the total purchase price. We anticipate closing the Turf transaction within two weeks following receipt of the equity infusion, likely during the first quarter of 2010.
Note 5 - Notes receivable
7. | We note your response to comment 17 in our letter dated August 28, 2009. Based on your response, it appears that you are relying on the value of the concessions held by Aurora and Boreal. Please provide us with your detailed assessment of each of the factors considered and how you weighted the impact of each factor in estimating the amount you believe is collectible. For example, please provide us with your detailed calculation of the estimated fair value of the concessions held by Aurora and Boreal and how you factored into your estimate the fall in oil and gas prices, the contraction of credit and financing, and the curtailment of exploration activities by major oil and gas companies. Please also explain what rights you have to encourage the sale of the concessions to repay the notes receivable, if Aurora and Boreal do not have available cash as of the due date. Please note that this discussion should be provided in future filings. |
RESPONSE:
We do not have detailed calculations of the estimated fair value of the concessions held by Aurora and Boreal. Management has reviewed concessions in the area where possible; however, the availability of data is limited because each concession is privately held. In addition, each concession is unique and objective comparisons of value are virtually impossible. Management uses this information as a subjective indicator of value and trends in the area, matched with the value of the data available for the concessions held by Aurora and Boreal. While substantive quantitative work has been done to analyze the data available on the concessions from Aurora and Boreal, it is a unique property. Because of the lack of objective data from comparative properties, management has used its judgment and the review of qualitative information in order to value these notes.
Based on our further evaluation of the notes, we expect to write these notes down to $0 as of September 30, 2009.
We will provide a discussion of our determination of the valuation allowance on the notes receivable from Aurora and Boreal in future filings.
We believe that it is probable that the notes receivable from Aurora and Boreal are impaired. The amount of the impairment has been estimated based on management’s judgment of the liquidation value of the underlying assets in the companies. We provided a valuation allowance on our notes receivable from Aurora and Boreal. In determining the amount of the valuation allowance, management considered the following factors:
- Estimated potential sale prices of Aurora and Boreal’s concessions compared to other concession properties in Paraguay. While no exact comparisons are available as each concession is unique in geography and data available, potential liquidation value of the concessions is a factor.
- Our limited ability to compel Aurora and Boreal to sell the concessions in order to repay the notes
- Precipitous fall in oil and gas prices
- Contraction in credit and financing
- Curtailing of exploration activities by major oil and gas companies
Management used its experience and judgment to weigh these factors and determine the amount of the allowance.
Note 9 - Guarantee liability
8. | We note your response to comment 19 in our letter dated August 28, 2009. With reference to paragraph 11 of FIN 45, please tell us the circumstances in which you issued the guarantee to the director of Aurora and Boreal for the $120,000 note receivable. |
RESPONSE:
The guarantee was issued to a member of the Board of Directors of Aurora and Boreal. The director had over time contributed monies to the development of the concessions held by Aurora and Boreal. Artemis Energy, Plc, a company organized under the laws of the United Kingdom, and a party to the Share Purchase Agreement and their subsequent amendments, had verbally guaranteed to repay those monies. The director expressed a lack of confidence in Artemis Energy’s willingness to fulfill that guarantee and his unwillingness to continue working without additional guarantees. As the director runs the day to day operations in Paraguay, heads the oil and gas industry group, ensures compliance with local laws, and is not easily replaced, the Company deemed it in its best interest to protect its investment by providing an additional guarantee to ensure the director’s continued employment and commitment to the development of the concessions. Therefore, we provided the guarantee to the director in order to entice him to remain on the Board.
Under the terms of the guarantee, if we were required to perform on the guarantee payment to the director we would take over the director’s position in his note receivable from Aurora and Boreal. In accordance with paragraph 11 of FIN 45, we recorded the guarantee liability and recorded the offsetting debit to a receivable from Aurora and Boreal related to our contingent receivable from those companies. We then evaluated the collectability of that contingent note receivable together with our direct notes receivable from Aurora and Boreal.
Item 4T. Controls and Procedures
9. | We note the disclosures you intend to include in an amendment to your second quarter of fiscal year 2009 Form 10-Q in response to comment 21 in our letter dated August 28,2009. Please further revise this disclosure to refer to June 30, 2009, rather than March 31, 2009. |
RESPONSE:
We intend to amend the Form 10-Q for the quarter ended June 30, 2009 to include the following revised discussion of our controls and procedures:
As required by Rule 13a-15 under the Securities Exchange Act of 1934, as of the end of the period covered by this quarterly report, being June 30, 2009, we have carried out an evaluation of the effectiveness of the design and operation of our company’s disclosure controls and procedures. This evaluation was carried out under the supervision and with the participation of our company’s management, including our company’s President and Chief Executive Officer. Based upon that evaluation, our principal executive officer and principal financial officer concluded that, as of the end of the period covered in this report, our disclosure controls and procedures were not effective to ensure that information required to be reported in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the required time periods and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. In connection with the completion of the review and issuance of the Form 10-Q report on our financial statements for the quarter ended June 30, 2009, we identified deficiencies that existed in the design or operation of our internal control over financial reporting that it considers to be “material weaknesses.” The PCAOB has defined a material weakness as a “significant deficiency or combination of significant deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.” The material weaknesses persisted during the period covered by this report.
These material weaknesses are a result of the lack of a formal communication procedure for reportable activities occurring in the Company’s subsidiary, ESP Petrochemicals, Inc., to the chief executive officer of the Company, who is also the officer in charge of the Company’s reporting obligations.
Prior to the reverse acquisition, which occurred on December 30, 2008, there was one employee of ESP Resources, Inc., one physical location in Texas where employees maintained offices and the Company did not have any subsidiaries. Every Company transaction was approved by the Company’s chief executive and financial officer. Following the reverse merger transaction, the Company’s chief executive and financial officer continued to handle the transactions involving the Company’s investments prior to December 30, 2008. At that time, the chief executive officer of ESP Petrochemicals, Inc. was appointed the president of the Company and oversaw the operations of ESP Petrochemicals, Inc. The principal offices of the Company were also moved from Texas to Louisiana. The Company continues to operate in this manner, with the Company’s chief executive and financial officer residing and working in Texas and the Company’s president residing and working at the Company’s principal office in Louisiana.
While the Company (i) is not aware of any reportable events that have not been disclosed in a timely manner and (ii) together with its subsidiary, continues to employee less than ten people, the chief executive and financial officer believes that the expansion of the Company’s operations and geographic distance between the principal officers of the Company merit the implementation of a more formal procedure for periodically communicating the Company’s activities to the chief executive and financial officer. The Company proposes to conduct at least weekly conference calls to review the transactions in which the Company and its subsidiary have participated in the previous week and to immediately communicate of significant events. The chief executive and financial officer feels that these additional procedures will provide reasonable assurance that the Company’s controls and procedures will meet their objectives.
In order to respond to the risk described above, the Form 10-Q was reviewed by both the Company’s chief executive and president to confirm that all required transactions had been adequately disclosed.
Our management, including our principal executive officer and principal financial officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error or fraud. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs. Due to the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected.
To address the material weaknesses, we performed additional analysis and other post-closing procedures in an effort to ensure our consolidated financial statements included in this quarterly report have been prepared in accordance with generally accepted accounting principles. Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.
If you have any additional comments or questions, please feel free to contact us.
Best regards,
/s/
Chris Metcalf
Chief Executive Officer
ESP Resources, Inc.