| 600 Travis, Suite 4200 Houston, Texas 77002 713.220.4200 Phone 713.220.4285 Fax andrewskurth.com
G. Michael O’Leary 713.220.4360 Phone 713.238.7130 Fax moleary@andrewskurth.com |
September 20, 2006
Mr. Donald Delaney
Mr. Karl Hiller
Mr. James Murphy
Securities and Exchange Commission
Division of Corporation Finance
100 F Street NE, Mail Stop 7010
Washington, D.C. 20549-7010
| Re: | Constellation Energy Partners LLC |
Amendment No. 1 to Registration Statement on Form S-1
File No. 333-134995
Filed August 11, 2006
Dear Mr. Delaney:
In response to the comment letter of the staff of the Securities and Exchange Commission (the “Staff”), dated August 29, 2006, with respect to the above referenced filing and as discussed in recent weeks by telephone, enclosed please find the disclosure Constellation Energy Partners LLC (fka Constellation Energy Resources LLC) (the “Registrant”) proposes to make with respect to Comment No. 3. Specifically, the Registrant is providing revised disclosure of the reserve data presented on pages 107 through 109 of Amendment No. 1, as well as corresponding changes to the presentation of that data in the Summary on pages 20 and 21, and the SFAS 69 disclosures made in Note 17 to the financial statements.
If you have any questions or comments, please call the undersigned at (713) 220-4360 or Tim Langenkamp at (713) 220-4357.
Very truly yours,
/s/ G. Michael O’Leary
G. Michael O’Leary
| cc: | H. Schwall |
J. Wynn
Summary Reserve and Operating Data
The following is a summary of our estimated net proved reserves attributable to our properties in the Robinson’s Bend Field and summary unaudited information with respect to our production and sales of natural gas, all as of the dates indicated. We have prepared the estimates of proved natural gas reserves described in this prospectus. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business—Oil and Natural Gas Data—Proved Reserves” and our historical consolidated financial statements in evaluating the material presented below.
The following table reflects our internal estimates of proved natural gas reserves based on SEC definitions that were used to prepare our financial statements for the following periods:
| Predecessor | Successor | |||||||||||
| Everlast | CEP | |||||||||||
| As of December 31, | ||||||||||||
Reserve data: | 2003 | 2004 | 2005 | |||||||||
Estimated net proved reserves: | ||||||||||||
Natural gas (Bcf) | 163.7 | 162.2 | 112.0 | |||||||||
Proved developed reserves (Bcf) | 100.7 | 101.4 | 89.3 | |||||||||
Proved undeveloped reserves (Bcf) | 63.0 | 60.8 | 22.7 | |||||||||
Proved developed reserves as a percent of total reserves | 62 | % | 62 | % | 80 | % | ||||||
Standardized Measure (in millions) (a) | $ | 194.2 | $ | 206.8 | $ | 295.4 | ||||||
Natural gas price—SONAT Gas Daily (price per Mmbtu) (b) | $ | 5.92 | $ | 6.05 | $ | 10.06 | ||||||
| (a) | Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our Standardized Measure does not include future income taxes because we are not subject to income taxes. Standardized Measure does not give effect to derivative transactions and excludes reserves attributable to the NPI. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Flow from Operations.” |
| (b) | Natural gas prices as of each period end were based on the Southern Natural Gas—Louisiana mid-point price, as published in Platts Gas Daily, which we refer to as the SONAT Gas Daily Price, on the last business day of the relevant period. |
The data presented in the table above is based on our own internal estimates prepared for the predecessor and successor companies at the corresponding year ends and was used to prepare the financial statements presented elsewhere in this prospectus. Our 2005 estimates of proved reserves are lower than the 2004 and 2003 estimates for the predecessor company because of the decision of our current management to (i) reduce our future drilling program to 20 wells per year over the next six years, (ii) reflect our interpretation of well performance data from new wells drilled in the Robinson’s Bend Field in 2004 and 2005, and (iii) reflect the impact of a revised refracture program. There was no drilling in the Robinson’s Bend Field between 1994 and late 2003. While the data from the Robinson’s Bend Field at year-end 2005 was limited, we believe it provides relevant information for the purposes of estimating reserves. The revised 20-well drilling program reflects our current intention of how we plan to develop the properties in the future. Our estimate of reserves for year-end 2005 are also approximately 5.8 Bcf lower than the year-end 2004 estimates of proved reserves due to a reduction of reserves attributed to the NPI. No corresponding adjustment was made to the year-end 2004 estimate of reserves because no amounts were due or paid in respect of the NPI at that time.
Our 2005 proved reserve estimate is 112.0 Bcf. At year-end, NSAI, an independent petroleum engineering firm, prepared an estimate of our proved reserves. NSAI also prepared an updated report at our request to provide
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a sensitivity of the estimates of the NSAI year-end reserves based on our reduced drilling program, our revised refracture program and the elimination of estimated reserves attributable to the Torch net profits interest. NSAI’s estimate of our 2005 proved reserves is materially consistent with our internal estimate.
Our 2004 and 2003 proved reserve estimates are 162.2 Bcf and 163.7 Bcf, respectively. These are our internal estimates of proved reserves that were used in the 2004 and 2003 Everlast financial statements included elsewhere in this prospectus. We prepared the estimates of 2004 and 2003 proved reserves for financial statement purposes by starting with NSAI’s December 31, 2005 net proved reserve estimate, which was prepared based upon a continuation of the assumptions used by the predecessor company, including the prior accelerated drilling program and reserve assumptions, and rolling back to year-end 2004 and 2003 by making appropriate adjustments for actual production, prices and development activity. The roll back approach was necessary because the reserve report prepared by NSAI for Everlast as of year-end 2004 was not based on the SEC definition of proved reserves, while the reserve report prepared by NSAI for Everlast as of year-end 2003, which was based on the SEC definition of proved reserves, included different assumptions than those used in NSAI in preparing 2005 proved reserves estimate. To prepare reserve estimates for these periods in compliance with the SEC definitions, we adopted the roll back approach described above and in Note 2 and Note 17 to the historical financial statements. The predecessor’s previous non-SEC compliant reserve estimates were 173.4 Bcf in 2004 and 166.3 Bcf in 2003.
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Natural Gas Data
Proved Reserves
The following table reflects our internal estimates of net proved natural gas reserves based on SEC definitions that were used to prepare our financial statements for the periods presented. The estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC in connection with this offering. The Standardized Measures shown in the table are not intended to represent the current market value of our estimated natural gas reserves.
| Predecessor | Successor | |||||||||||
| Everlast | CEP | |||||||||||
| As of December 31, | ||||||||||||
Reserve data: | 2003 | 2004 | 2005 | |||||||||
Estimated net proved reserves: | ||||||||||||
Natural gas (Bcf) | 163.7 | 162.2 | 112.0 | |||||||||
Proved developed reserves (Bcf) | 100.7 | 101.4 | 89.3 | |||||||||
Proved undeveloped reserves (Bcf) | 63.0 | 60.8 | 22.7 | |||||||||
Proved developed reserves as a percent of total reserves | 62 | % | 62 | % | 80 | % | ||||||
Standardized Measure (in millions) (a) | $ | 194.2 | $ | 206.8 | $ | 295.4 | ||||||
Natural gas price—SONAT Gas Daily (price per Mmbtu) (b) | $ | 5.92 | $ | 6.05 | $ | 10.06 | ||||||
| (a) | Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our Standardized Measure does not include future income taxes because we are not subject to income taxes. Standardized Measure does not give effect to derivative transactions and excludes reserves attributable to the NPI. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Flow from Operations.” |
| (b) | Natural gas prices as of each period end were based on the Southern Natural Gas—Louisiana mid-point price, as published in Platts Gas Daily, which we refer to as the SONAT Gas Daily Price, on the last business day of the relevant period. |
The data presented in the table above is based on our own internal estimates prepared for the predecessor and successor companies at the corresponding year ends and was used to prepare the financial statements presented elsewhere in this prospectus. Our 2005 estimates of proved reserves are lower than the 2004 and 2003 estimates for the predecessor company because of the decision of our current management to (i) reduce our future drilling program to 20 wells per year over the next six years, (ii) reflect our interpretation of well performance data from new wells drilled in the Robinson’s Bend Field in 2004 and 2005, and (iii) reflect the impact of a revised refracture program. There was no drilling in the Robinson’s Bend Field between 1994 and late 2003. While the data from the Robinson’s Bend Field at year-end 2005 was limited, we believe it provides relevant current information for the purposes of estimating reserves. The revised 20-well drilling program reflects our current intention of how we plan to develop the properties in the future. Our estimate of reserves for year-end 2005 are also approximately 5.8 Bcf lower than the year-end 2004 estimates of proved reserves due to a reduction of reserves attributed to the NPI. No corresponding adjustment was made to the year-end 2004 estimate of reserves because no amounts were due or paid in respect of the NPI at that time.
Our 2005 proved reserve estimate is 112.0 Bcf. At year-end, NSAI, an independent petroleum engineering firm, prepared an estimate of our proved reserves. NSAI also prepared an updated report at our request to provide a sensitivity of the estimates of the NSAI year-end reserves based on our reduced drilling program, our revised
refracture program and the elimination of estimated reserves attributable to the Torch net profits interest. NSAI’s estimates of our 2005 proved reserves is materially consistent with our internal estimate.
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Our 2004 and 2003 proved reserve estimates are 162.2 Bcf and 163.7 Bcf, respectively. These are our internal estimates of proved reserves that were used in the 2004 and 2003 Everlast financial statements included elsewhere in this prospectus. We prepared the estimates of 2004 and 2003 proved reserves for financial statement purposes by starting with NSAI’s December 31, 2005 net proved reserve estimate, which was prepared based upon a continuation of the assumptions used by the predecessor company, including the prior accelerated drilling program and reserve assumptions, and rolling back to year-end 2004 and 2003 by making appropriate adjustments for actual production, prices and development activity. The roll back approach was necessary because the reserve report prepared by NSAI for Everlast as of year-end 2004 was not based on the SEC definition of proved reserves, while the reserve report prepared by NSAI for Everlast as of year-end 2003, which was based on the SEC definition of proved reserves, included different assumptions than those used in NSAI in preparing 2005 proved reserves estimate. To prepare reserve estimates for these periods in compliance with the SEC definitions, we adopted the roll back approach described above and in Note 2 and Note 17 to the historical financial statements. The predecessor’s previous non-SEC compliant reserve estimates were 173.4 Bcf in 2004 and 166.3 Bcf in 2003.
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(c) Net Proved Gas Reserves
The following table sets forth information with respect to changes in CEP’s and Everlast’s proved (i.e., proved developed and undeveloped) reserves. This information excludes reserves related to royalty and net profit interests.
| Successor | Predecessor | |||||||||||
| Gas (mmcf) | CEP | Everlast | ||||||||||
| For the period February 7, 2005 (inception) to December 31, 2005 | January 1 to June 12, 2005 | 2004 | 2003 | |||||||||
Beginning Balance | — | 162,215 | 163,745 | — | ||||||||
Extensions and discoveries | — | — | 824 | — | ||||||||
Purchases of reserves in place | 160,245 | — | — | 168,311 | ||||||||
Sales of reserves in place | — | — | — | — | ||||||||
Revisions of previous estimates | (45,695 | ) | — | 2,173 | — | |||||||
Production | (2,525 | ) | (1,970 | ) | (4,527 | ) | (4,566 | ) | ||||
Ending Balance | 112,025 | 160,245 | 162,215 | 163,745 | ||||||||
Total developed reserves | 89,272 | 101,352 | 100,681 | |||||||||
Reserves and Related Estimates
CEP’s estimate of proved reserves is based on the quantities of natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters.
CEP’s 2005 proved reserve estimate is 112.0 Bcf. At year-end, NSAI, an independent petroleum engineering firm, prepared an estimate of CEP’s proved reserves. NSAI also prepared an updated report at our request to provide a sensitivity of the estimates of the NSAI year-end reserves based on our reduced drilling program, our revised refracture program and the elimination of estimated reserves attributable to the Torch net profits interest. NSAI’s estimates of our 2005 proved reserves is materially consistent with our internal estimate report.
CEP’s 2005 estimates of proved reserves are lower than our predecessor’s estimates of proved reserves primarily because of the following factors:
| • | A Reduction of 24.5 Bcf Based on Interpretation of Well Performance: The information on which CEP based this adjustment includes its interpretation of well performance data that was available at December 31, 2005 for new wells drilled and completed in the Robinson’s Bend Field in 2004 and 2005. There was no drilling in the field between 1994 and late 2003. While the data at year end 2005 is from a limited number of new wells drilled in the field in 2004 and in 2005, CEP believes it provides relevant information for the purposes of estimating reserves and CEP has interpreted the data and reflected the results of that analysis in its reserve estimates and assumptions. The majority of the 24.5 Bcf reduction in the reserve estimate at December 31, 2005 associated with CEP’s interpretation of the recent well performance data is in the proved developed non-producing (PDNP) category and the proved undeveloped (PUD) categories of reserves. |
| • | A Reduction of 15.4 Bcf Based on CEP’s Planned Drilling Program: The 112.0 Bcf estimate also reflects CEP’s planned drilling program of 20 gross wells per year for the next six years. CEP uses a six year time horizon for drilling program and reserves estimation purposes because it is consistent with what CEP uses for internal capital expenditure planning purposes and because CEP believes that using a longer time horizon would create additional uncertainty with regard to capital budgeting, therefore |
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potentially reducing its ability to prepare a reliable estimate of reserves. Everlast’s drilling program, which was designed to provide maximum returns in a relatively short time period, was to drill and complete 197 gross wells within a five-year period. CEP’s planned drilling program is designed to provide a steady and constant return by drilling an average of 20 wells per year over a six year period. Due to this difference in drilling programs, certain proved undeveloped reserves that were based on the predecessor’s accelerated drilling program and using NSAI’s reserve assumptions cannot be included in CEP’s proved reserve estimates because under CEP’s current drilling program those reserves are scheduled to be drilled more than six years after the date of the reserve report and as such are outside the time horizon CEP uses to prepare its internal estimates of proved reserves. |
| • | A Reduction of 5.8 Bcf for Reserves Attributed to the NPI: Our December 31, 2005 reserve estimates removed 5.8 Bcf of reserves that are attributed to the NPI using an overriding royalty interest approach. The estimated reserves attributed to the NPI at December 31, 2004 was zero due to the lower gas prices compared to December 31, 2005 prices. |
The 2004 and 2003 proved reserve estimates for the predecessor company are 162.2 Bcf and 163.7 Bcf, respectively. These are the estimates of proved reserves used in the 2004 and 2003 predecessor company financial statements. CEP prepared the estimates of 2004 and 2003 proved reserves for financial statement purposes by starting with NSAI’s December 31, 2005 net proved reserve estimate, which was prepared based upon the predecessor’s accelerated drilling program and reserve assumptions, and rolling back to year-end 2004 and 2003 by making appropriate adjustments for actual production, prices and development activity. The roll back approach was necessary because the reserve report prepared by NSAI for Everlast as of year-end 2004 was not based on the SEC definition of proved reserves, while the reserve report prepared by NSAI for Everlast as of year-end 2003, which was based on the SEC definition of proved reserves, included different assumptions than those used in NSAI in preparing 2005 proved reserves estimate.
Due to this inconsistency in the preparation of reserve reports for the periods presented, CEP adopted the roll back approach of reserves at December 31, 2005 to year-end 2004 and 2003 in preparing the financial statements for year end 2004 and 2003. In preparing the roll back to year-end 2004 and 2003 CEP did not adjust the estimated proved reserve volumes to reflect its reserve assumptions based upon its interpretation of recent well performance in the Robinson’s Bend Field because these assumptions were based on recent information that was not available to Everlast when it was preparing the 2004 and 2003 financials statements. In addition, CEP did not adjust the volumes to reflect its current drilling program of 20 gross wells per year for the next six years because this drilling program was not the drilling program adopted by Everlast in 2004 and 2003. The previous reserve estimates were 173.4 Bcf in 2004 and 166.3 Bcf in 2003.
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