CRAIG G. ONGLEY
(214) 777-4241
congley@krcl.com
February 26, 2014
H. Roger Schwall, Assistant Director
United States Securities and Exchange Commission
Division of Corporation Finance
Washington, D.C. 20549
Re: | TransCoastal Corporation |
| Amendment No. 3 to Registration Statement on Form S-1 |
| Filed January 17, 2014 |
| File No. 333-191566 |
| Amendment No. 1 to Form 10-Q for Fiscal Quarter Ended September 30, 2013 |
| Filed January 24, 2013 |
| File No. 1-14665 |
Dear Mr. Schwall:
With regards to your letter dated January 31, 2014, we have responded to the staff's comments and numbered our responses to correspond with the comment number in your letter. Please see our responses below:
Amendment No. 3 to Registration Statement on Form S-1 filed January 17, 2014
General
1. | We note that your auditor’s consent has been omitted. Please obtain and include a currently dated and signed consent from your auditor in the next amendment. |
RESPONSE:
An updated auditor's consent is attached to this amendment as Exhibit 23.1A.
Prospectus Summary, page 1
2. | In prior comment 3, we requested that you furnish to us certain technical support for the proved developed non-producing and the proved undeveloped reserves presented in your third party reserve report. It appears you have omitted: |
● | The production histories later than May 2010 for the analogy wells in support of the estimated PUD reserves for the Savell 4, 5, 6 and 7 PUD locations. Please include the Texas RRC lease numbers for these analogy wells. |
● | The estimated ultimate recoveries for these same analogy wells as well as their producing rate vs. time plot projections. |
● | An explanation regarding the inclusion in the third party cash flow projections of the capital cost for new tank batteries and compressors as presented in your spreadsheet titled “Pampa PDNP AFE”. We found no such cost in our review of the third party report. |
Please furnish these items to the addressee as previously requested.
RESPONSE:
The analog wells for the Savell PUD wells are located 1- 5 miles south – southeast of the Savell A #1H and include the following:
Well Name | API # | Initial Prod Rate | Date |
Hodges #1H | 42-405-30211 | 2.8mmcfpd | 4/2008 |
Tartt #3H | 42-405-30261 | 4.1mmcfpd | 8/2009 |
Tartt #1H | 42-405-30220 | 4.2mmcfpd | 6/2008 |
Tartt #2H | 42-405-30222 | 7.5mmcfpd | 7/2008 |
Boles #1H | 42-405-30259 | 7.2mmcfpd | 7/2009 |
Hopkins #1H | 42-405-30215 | 7.3mmcfpd | 5/2008 |
HT & BRRCP #1 | 42-405-30216 | 5.2mmcfpd | 4/2009 |
The histories for these wells are included and match a b-factor of 0.9 with an initial decline greater than 95%. These wells were completed in the 2008-2009 time frame. Improvements in completion techniques support better decline efficiencies and higher EURs. The Hodges #1H exhibits a b-factor of 1.4 indicative of reservoir potential deliveries. Utilizing this potential, the “Type Curve” in the third party Reserve Report utilized an initial rate of 5 mmcfpd (vs. 5.5 average), a b-factor of 1.4 (supported by the Hodges #1H and industry publications) and an initial decline of 76% (based on anticipated better completion practices).
The entire Shelby County Area was searched for James Lime producers with the strongest and longest performance histories. The Marathon operated, USA Bridges #1 (horizontal) API # 42-419-30726, exhibits a b-factor of 1.4 with a projected EUR of over 10.7 bcf (cumulative to date > 5.7 bcf).
Regarding the tank batteries/compressors in the Pampa Area; the $50,000/well to Return Wells to Production is an average as we do not know exactly what costs will be involved to complete this remediation. Wells currently not producing on leases that currently have production will not need additional capacity unless the total production from the lease exceeds the current capacity. TCC has some leases that currently are not producing and the existing capacity of these surface facilities will need to be upgraded. TCC has made the assumption that these additional funds can be met within the overall estimate of $50,000/well.
Additional documents consisting of a map of the analog wells and their production/decline curve have been sent on a flash drive via FedEx to Mr. Ronald Winfrey
3. | We note that the information provided in response to our prior comment 4 confirms the average gas production of 955 MCFG/mo for the Meers leases during the fourth quarter of 2012. As we noted in our prior comment, this rate including the most recent December, 2012 rate of 744 MCFG/mo is well below the 1278 MCFG/mo initial rate used in your reserve estimate. We re-issue our prior comment 4, in part, and ask that you provide us with the technical evidence and a narrative statement supporting your estimate of the future production rate and the reserves presented in the reserves report for the Meers leases, or revise your estimates and amend your document to remove these reserves from your filing. |
RESPONSE:
We have recalculated our projections using the hindsight of all 12 months of 2012 and have arrived at an average of 1161 MCF. While we believe our estimates to be more accurate due to the December weather anomaly we have adjusted our economic projections using that number and over the life of the wells the difference in our estimate goes from $2,997,780 to $2,853,460 or a difference of $144,320 over the 15 year estimate which we believe not to be material. We have included the economic projections for both the original and revised cases on the supplemental flash drive.
4. | Based on the illustrations and example calculations you provided in response to our prior comment 6, we note the average monthly gas price you have calculated from the monthly gas and NGL sales statements differs in each instance from the gas price for the same lease used in the third party reserves report and noted as the PHDWin price in the “Summary” of the spreadsheet entitled “SEC-NGL Pricing 2012.” Please clarify for us why the prices used in the reserves report differ from the calculated prices you have provided to us. |
RESPONSE:
Please find on the supplemental flash drive a spreadsheet showing our calculations. What the spreadsheet attempts to provide is a “factor” that when multiplied by the assumed “going forward” projection of natural gas pricing will accurately determine the value of both the NGLs processed from the produced wellhead volume, as well as, the residual (after shrinkage) natural gas from each of TCC’s leases. The spreadsheet values are based on actual historical production, actual historical values received for both NGLs (on a component specific basis and based on the location of the production and the purchaser marketing the commodities), and any other charges specific to the individual lease such as contractual specific terms and efficiency of the individual plant. On the other side, the “going forward” economics are based on an arithmetic average of the 12-month trailing average of NYMEX Pricing which is not necessarily the same as the value received for TCC’s produced gas, nor the market price of the processed NGLs.
We have added a tab titled “pricing” which shows that the residual gas pricing received by TCC ranged from 84% to 91% of the NYMEX pricing which TCC is directed to use under SEC guidance in the evaluation.
5. | We also re-issue our prior comment 6, in part, and ask you to “[i]llustrate for us how you calculated the projected gas prices for the WAB-Evelyn 3, Pugh and Meers C properties to be $11.40, $5.46 and $17.55 per MCF, respectively.” Please provide a step-by-step illustration of how you arrive at the prices as noted for the three leases in the third party report. Please include the starting input values, tell us the source of this data and the extent to which the third party engineering firm verified this information before incorporating it into the reserve report. Also, please provide us with the 2012 monthly natural gas and NGL sales statements for the Meers C property. |
RESPONSE:
The revenue received for TCC’s natural gas production is comprised of two parts; first, the dollar amount received for the liquids processed from the gross wellhead production (which is each component recovered multiplied by the dollar amount received per month for each component, less any line loss, any losses due to plant inefficiencies, less any contractual “percent of proceeds” negotiated by the purchaser/processor, and less any taxes and fees), and second, the resulting “shrunk” volume of gross wellhead gas multiplied by the $/mcf paid by each individual purchaser for the “residual” natural gas.
In the spreadsheet provided, each lease (or well in Montague County) is depicted individually and formatted the same. Row 6 (Gross Wellhead Volume in mcf) and Row 7 (Gross Wellhead BTU) are inputted directly from the purchaser/processor monthly Production Settlement Statements. Row 8 (Wellhead BTU Factor) is then calculated from these two rows. Rows 10 and 11 (Net Residual Value and Net Liquids Value in $ are also inputted from the Production Settlement Statements and subsequently added together to determine the total amount received from each individual lease/well, Row 13 (Net Total Value in $). When this Net Total Value ($) is divided by the Gross Wellhead Volume (mcf), a $/mcf is calculated in Row 15 which represents the effective $/mcf received by TCC for each mcf produced from their leases. Row 17 is also sourced from the monthly Settlement Statements and depicts what the Purchaser/Processor paid each month for the residual (after liquids removal) natural gas. Row 19 is then calculated by dividing Row 15 by Row 17 and represents a “faux” btu factor which when multiplied by the Gross Wellhead Production (mcf) will equal the total amount received each month from the lease/well. This factor is utilized within PHDWin to account for the value of the liquids relative to any reference price.
There is a separate tab in the worksheet provided illustrating what each purchaser of TCC’s natural gas had paid on a monthly basis for the residual gas. This price paid by each individual purchaser is slightly different from each other and all are different from the Nymex average. TCC’s calculations in the spreadsheet are done on an arithmetic average which will give a different value than if they were calculated on a weighted average based on monthly production (the Nymex calculation was done utilizing an arithmetic average).
The reason these actual values are different from the Nymex Average is that the average received by TCC is different from the Nymex Average on a 12 month average.
6. | We note that the 2013 annual projected production cost for your proved producing reserves is $604 thousand in your third party reserve report while your incurred historical 2012 production cost (page F-29) is $1.1 million. Given that these costs apply essentially to the same properties, please explain this difference to us. Furnish us with a production cost line item comparison between those costs incurred in 2012 and those projected for 2013. We may have further comment. |
RESPONSE:
We have included with the supplemental documents on the flash drive a spreadsheet which details the actual production costs for our operations in 2012. Please note that to the right of the final column you will see three notes detailing extra ordinary non-recurring expenses which were deducted from the total operating expenses ($1,114,585-$488,320= $626,265. From the remainder we determined that our average production expense was approximately $50,000 per well.
Marketing, page 35
7. | We note that you have filed your marketing agreement with Valero as Exhibit 10.14. The “General Provisions” of the contract, on page 2, indicate that it corporates the “latest Valero Marketing and Supply Company’s General Provisions, currently dated June 2004. Please tell us how you considered filing the original agreement which contains the incorporated terms either as a separate agreement or as an attachment to this exhibit. As currently filed, the terms are not available for investor inspection. |
RESPONSE:
We have modified the Exhibit 10.14 to include the general provisions of the Valero Agreement. Please see Exhibit 10.14.
Selling Stockholders, page 41
8. | In your response letter, you again indicate that you have deleted the column entitled “Components.” However, review of the amendment indicates that the column is still there. Please advise or revise. |
RESPONSE:
We have removed the column entitled "Components". Please see pages 41 to 42.
Amendment No. 1 to Form 10-Q for Fiscal Quarter Ended September 30, 2013
Management's Discussion and Analysis of Financial Condition and Results of Operations, page 13
Results of Operations, page 14
Revenue, page 14
9. | We note your response to prior comment 9 and re-issue it in part as you have not provided the requested disclosure for all periods presented. Please expand your revenue discussions to identify (and quantify) changes resulting from production quantities, prices and other factors. Other factors should be described and where necessary quantified. In this manner, we note that production volumes and average selling prices of oil and natural gas have been omitted for all periods presented. Please revise throughout MD&A to include these disclosures. |
RESPONSE:
We have modified our 10-Q MD & A to reflect your comments and are filing a second amended Form 10-Q with the requested modifications.
We have also supplied a clean and redlined copy of the amended S-1 and amended 10-Q via EDGAR for your use. Please contact the undersigned should you have any questions.
| Sincerely,
KANE RUSSELL COLEMAN & LOGAN PC |
| |
|
|
|
|
|
|
|
|
| By: | /s/ Craig G. Ongley |
|
|
| Craig G. Ongley |
|
7
