Andrews Kurth LLP
600 Travis, Suite 4200
Houston, Texas 77002
September 13, 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 |
Gentlemen:
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 last week 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 of Amendment No. 1. Finally, the Registrant is providing three options with respect to the SFAS 69 disclosures made in Note 17 to the financial statements.
While the Registrant has provided three options for the SFAS 69 reconciliation table on page F-29, the Registrant wishes to note its strong preference for Option 1. In that option, the Everlast reserves are shown in place on June 12, 2005, coupled with the CEP purchase of those reserves, but at the reduced internal estimate. This option reflects the Registrant’s current disclosure in Amendment No. 1, as adjusted for production from January 1, 2005 through June 12, 2005. The Registrant believes this is the best disclosure, as the reserve numbers match the Registrant’s financial statement presentation and SFAS 69 treatment reflecting the Registrant’s acquisition of its properties in the Robinson’s Bend Field.
Should the Staff find Option 1 unacceptable, the Registrant proposes to use Option 2. This disclosure is similar to Option 1 in that it shows the CEP purchase of the reserves, but it also shows a sale by Everlast of reserves in place on June 12, 2005. As discussed during our telephone conference, this option would allow for the 2004 ending reserves to match the 2005 beginning reserves.
Finally, if neither Option 1 nor Option 2 are acceptable to the Staff, the Registrant is prepared to make its disclosure in the manner of Option 3. The Registrant does not prefer this option, for it reflects no purchase or sale of reserves in place, which is inconsistent with the disclosure relating to Everlast’s 2003 acquisition of these properties in the Robinson’s Bend Field.
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 tables set forth a summary of our estimated net proved reserves attributable to our properties in the Robinson’s Bend Field and certain 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. NSAI, an independent petroleum engineering firm, has prepared estimates as of January 1, 2006 of our proved reserves. Our internal proved reserve estimates are equal to or lower in each category of reserves than the NSAI estimates as of the same date.
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:
| As of December 31, |
||||||||||||
| 2003 |
2004 |
2005 |
||||||||||
| SEC reserve data: |
||||||||||||
| 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 | ||||||
Our net proved reserves estimate used to prepare our financial statements as of December 31, 2005 included elsewhere in this prospectus was 112.0 Bcf. In arriving at such estimate, we began with a reserve report prepared by NSAI, an independent reserve engineering firm, which indicated that proved reserves as of December 31, 2005 were 162.9 Bcf. We then made three adjustments totaling 50.9 Bcf that are described in detail in footnote (c) to the table in CEP’s Pro Forma Internal Proved Reserves below and in Note 17 to the historical consolidated financial statements included elsewhere in this prospectus, to arrive at our own internal estimate of proved reserves as of December 31, 2005 of 112.0 Bcf. The proved reserve estimate of 112.0 Bcf was used for financial statement purposes for the period ended December 31, 2005 contained elsewhere in this prospectus.
The proved reserve estimates of 162.2 Bcf for 2004 and 163.7 Bcf for 2003, which are the proved reserve estimates used in the 2004 and 2003 Everlast financial statements included elsewhere in this prospectus, were prepared by using internal estimates. 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 of 162.9 Bcf, which was prepared based upon 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 considered to be 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 by NSAI in preparing 2005 proved reserves estimate. Based upon this inconsistency, we adopted the roll-back approach described above and in Note 2 and Note 17 to the historical financial statements included elsewhere in this prospectus. The previous reserve estimates were 173.4 Bcf in 2004 and 166.3 Bcf in 2003.
20
The following table presents our pro forma internal estimates of proved reserves for 2003 and 2004 and our 2005 estimate of proved reserves (as described in “SEC reserve data” section above). We are presenting this data for comparative purposes.
| As of December 31, |
||||||||||||
| 2003 |
2004 |
2005 |
||||||||||
| Pro Forma |
Pro Forma |
Actual |
||||||||||
| CEP’s internal reserve data: |
||||||||||||
| Estimated net proved reserves: |
||||||||||||
| Natural gas (Bcf) |
109.6 | 108.1 | 112.0 | |||||||||
| Proved developed reserves (Bcf) |
86.9 | 87.5 | 89.3 | |||||||||
| Proved undeveloped reserves (Bcf) |
22.7 | 20.6 | 22.7 | |||||||||
| Proved developed reserves as a percent of total reserves |
79 | % | 81 | % | 80 | % | ||||||
| Standardized Measure (in millions)(a) |
$ | 151.3 | $ | 156.8 | $ | 295.4 | ||||||
| Natural gas price—SONAT Gas Daily (price per MMBtu)(b) |
$ | 5.92 | $ | 6.05 | $ | 10.06 | ||||||
Our internal pro forma estimates of proved reserves for the Robinson’s Bend field are lower than independent estimates of proved reserves prepared at December 31, 2005. We have a lower estimate of proved reserves as a result of our decisions to (i) reflect our interpretation of recent performance data on new wells drilled in the field, (ii) implement a less aggressive drilling schedule than the schedule our predecessor used, and (iii) to remove the volumes associated with the Torch net profits interest. We prepared pro forma internal reserve estimates of 108.1 Bcf and 109.6 Bcf for 2004 and 2003, respectively, to provide a comparison of reserve estimates for each of the three years presented on a consistent basis using the same reserve assumptions used to estimate the reserves as of December 31, 2005. Footnote (c) provides additional information on how we developed our internal reserve estimates for 2005 and our pro forma internal reserve estimates for 2003 and 2004.
| (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 SONAT Gas Daily Price on the last business day of the relevant period. |
| (c) | Our internal estimates of SEC proved reserves as of December 31, 2005 were used to prepare our historical financial statements. The internal and pro forma internal net proved reserve estimates of 112.0 Bcf, 108.1 Bcf and 109.6 Bcf as of December 31, 2005, 2004 and 2003, respectively, included in the table above were prepared by us based on our internal reserve estimates as of December 31, 2005, which we then rolled back to the years ended 2004 and 2003 for comparison purposes. This rollback was conducted using the same assumptions and drilling program as those we used to construct our internal estimated reserves as of December 31, 2005, and by making appropriate adjustments for actual production, prices and development activity. Our internal reserve estimate as of December 31, 2005, was based on the year-end 2005 reserve report prepared by NSAI. We started with the net proved reserve estimate of 162.9 Bcf included in that NSAI year-end 2005 reserve report and then adjusted the estimates downward to 112.0 Bcf to reflect: |
21
| • | A reduction of 29.7 Bcf of proved developed non-producing reserves and proved undeveloped reserves based upon our interpretation of recent performance data of recently completed wells in the Robinson’s Bend Field; |
| • | A reduction of 15.4 Bcf of proved undeveloped reserves based on our current drilling program of 20 gross wells per year over the next six years, as compared to a more aggressive drilling schedule in the NSAI report; and |
21.1
| • | A reduction of 5.8 Bcf for proved reserves attributable the NPI, which NSAI did not deduct from the net proved reserve estimates in its reserve report. |
The year-end 2005 internal reserve estimate of 112.0 Bcf was used to prepare the 2005 financial statements included elsewhere in this prospectus because it represents our best estimate of our proved reserves using all information available at that time. However, our internal 2004 and the 2003 pro forma reserve estimates are not those used to prepare the 2004 and 2003 financial statements included elsewhere in this prospectus because they reflect our reserve assumptions based upon the interpretation of well performance data not available to Everlast in 2004 and 2003, and the reserve estimates included in Everlast’s financial statements reflect an accelerated drilling program in 2004 and 2003, rather than our current drilling program.
22
Natural Gas Data
SEC 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.
| As of December 31, |
||||||||||||
| 2003 |
2004 |
2005 |
||||||||||
| SEC reserve data: |
||||||||||||
| Net proved reserves used to prepare financial statements—See Notes 2 and 17 of the historical financial statements (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 as recorded in Note 17 of the historical consolidated financial statements(a) |
$ | 194.2 | $ | 206.8 | $ | 295.4 | ||||||
| Natural gas price—SONAT Gas Daily (price per MMBtu)(b) |
$ | 5.92 | $ | 6.05 | $ | 10.06 | ||||||
Our net proved reserves estimate used to prepare our financial statements as of December 31, 2005 included elsewhere in this prospectus was 112.0 Bcf. In arriving at such estimate, we began with a reserve report prepared by NSAI, an independent reserve engineering firm, which indicated that proved reserves as of December 31, 2005 were 162.9 Bcf. We then made three adjustments totaling 50.9 Bcf that are described in detail in footnote (c) to the table in CEP’s Pro Forma Internal Proved Reserves below and in Note 17 to the historical consolidated financial statements included elsewhere in this prospectus, to arrive at our own internal estimate of proved reserves as of December 31, 2005 of 112.0 Bcf. The proved reserve estimate of 112.0 Bcf was used for financial statement purposes for the period ended December 31, 2005 contained elsewhere in this prospectus.
The proved reserve estimates of 162.2 Bcf for 2004 and 163.7 Bcf for 2003, which are the proved reserve estimates used in the 2004 and 2003 Everlast financial statements included elsewhere in this prospectus, were prepared by using internal estimates. 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 of 162.9 Bcf, which was prepared based upon 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 considered to be 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 by NSAI in preparing 2005 proved reserves estimate. Based upon this inconsistency, we adopted the roll-back approach described above and in Note 2 and Note 17 to the historical financial statements included elsewhere in this prospectus. The previous reserve estimates were 173.4 Bcf in 2004 and 166.3 Bcf in 2003.
CEP’s Pro Forma Internal Proved Reserves
Our internal estimates of proved reserves for the Robinson’s Bend Field are lower than independent estimates of proved reserves prepared at December 31, 2005. We have a lower estimate of proved reserves as a result of our decisions to (i) reflect our interpretation of recent performance data on new wells drilled in the field, (ii) implement a less aggressive drilling schedule than the schedule our predecessor used, and (ii) remove the volumes associated with the Torch net profits interest. We prepared pro forma internal reserve estimates of 108.1 Bcf and 109.6 Bcf for 2004 and 2003, respectively, to provide a comparison of reserve estimates for each of the
107
three years presented on a consistent basis using the same reserve assumptions used to estimate the reserves as of December 31, 2005.
The following table provides a reconciliation between our pro forma internal estimates of proved reserves and the independent estimates (as described in “SEC reserve data” section above). All of the data presented in this table is based upon the independent reserve report prepared by NSAI, an independent reserve engineering firm, at December 31, 2005 using the SEC definition of proved reserves. Footnote (c) to the table below provides additional information on how we developed our internal reserve estimates for 2005 and our pro forma internal reserve estimates for 2003 and 2004. This data is included for comparative purposes.
| As of December 31, |
||||||||||||
| 2003 |
2004 |
2005 |
||||||||||
| Pro Forma | Pro Forma | Actual | ||||||||||
| CEP’s internal reserve data: |
||||||||||||
| Independent net proved reserves estimate, including roll-backs to make reserves SEC compliant (Bcf) |
163.7 | 162.2 | 162.9 | |||||||||
| Impact of different internal assumptions (Bcf) |
(35.8 | ) | (35.6 | ) | (29.7 | ) | ||||||
| Impact of our drilling program (Bcf) |
(18.3 | ) | (18.5 | ) | (15.4 | ) | ||||||
| Impact of net profits interests volumes (Bcf) |
— | — | (5.8 | ) | ||||||||
| Internal reserves estimate(c) (Bcf) |
109.6 | 108.1 | 112.0 | |||||||||
| Proved developed reserves (Bcf) |
86.9 | 87.5 | 89.3 | |||||||||
| Proved undeveloped reserves (Bcf) |
22.7 | 20.6 | 22.7 | |||||||||
| Proved developed reserves as a percent of total reserves |
79 | % | 81 | % | 80 | % | ||||||
| Standardized measure as recorded in Note 17 of the historical consolidated financial statements |
$ | 194.2 | $ | 206.8 | $ | 295.4 | ||||||
| Impact of different internal assumptions, PDP, PDNP |
(15.8 | ) | (14.8 | ) | — | |||||||
| Impact of different internal assumptions, PUD |
(6.5 | ) | (7.8 | ) | — | |||||||
| Impact of using our drilling program |
(20.6 | ) | (27.4 | ) | — | |||||||
| Internal standardized measure estimate(a) |
$ | 151.3 | $ | 156.8 | $ | 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 SONAT Gas Daily Price on the last business day of the relevant period. |
| (c) | Our estimates of SEC proved reserves were used to prepare our historical financial statements. Our internal and pro forma internal net proved reserve estimates of 112.0 Bcf, 108.1 Bcf and 109.6 Bcf as of December 31, 2005, 2004 and 2003, respectively, included in the table above were prepared by us based on our internal reserve estimates as of December 31, 2005, which we then rolled back to the years ended 2004 and 2003 for comparison purposes. This rollback was conducted using the same assumptions and drilling program as those we used to construct our internal estimated reserves as of December 31, 2005, and by making appropriate adjustments for actual production, prices and development activity. Our internal reserve estimate as of December 31, 2005, was based on the year-end 2005 reserve report prepared by NSAI. We |
108
| started with the net proved reserve estimate of 162.9 Bcf included in that NSAI year-end 2005 reserve report and then adjusted the estimates downward to 112.0 Bcf to reflect: |
| • | A reduction of 29.7 Bcf of proved developed non-producing reserves and proved undeveloped reserves based upon our interpretation of recent performance data of recently completed wells in the Robinson’s Bend Field; |
| • | A reduction of 15.4 Bcf of proved undeveloped reserves based on our current drilling program of 20 gross wells per year over the next six years, as compared to a more aggressive drilling schedule in the NSAI report; and |
| • | A reduction of 5.8 Bcf for proved reserves attributable the NPI, which NSAI did not deduct from the net proved reserve estimates in its reserve report. Based on natural gas prices at December 31, 2004 and 2003, the NPI was at a cumulative deficit and no reserves were attributable to the net overriding royalty interest. |
The year-end 2005 internal reserve estimate of 112.0 Bcf was used to prepare the 2005 financial statements included elsewhere in this prospectus because it represents our best estimate of our proved reserves using all information available at that time. However, our internal 2004 and the 2003 pro forma reserve estimates are not those used to prepare the 2004 and 2003 financial statements included elsewhere in this prospectus because they reflect our reserve assumptions based upon the interpretation of well performance data not available to Everlast in 2004 and 2003, and the reserve estimates included in Everlast’s financial statements reflect an accelerated drilling program in 2004 and 2003, rather than our current drilling program.
109
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
AND EVERLAST ENERGY LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| • | to correct the misclassification of revenues related to a long-term, fixed price natural gas sales contract accounted for as a derivative contract; |
| • | to expense operating costs originally capitalized; |
| • | to capitalize and amortize deferred financing costs originally expensed; |
| • | to capitalize certain property costs originally expensed; and |
| • | to account for a net profits interest as an overriding royalty interest. |
In 2003 and 2004, Everlast recorded depletion expense based on a depletion base that understated future development costs that are required to be included in the depletion base under the full cost method. In addition, recorded depletion expense was based on reserve estimates that incorrectly included certain proved undeveloped reserves. For purposes of reserve determination, it is inappropriate to include proved undeveloped reserves that are not immediately adjoining currently producing wells. The original year-end proved reserves for 2003 and 2004 were adjusted to remove these proved undeveloped reserves. In 2003, Everlast’s original accounting was based on a proved reserve estimate of 166.3 Bcf, while the revised accounting was based on a proved reserve estimate of 163.7 Bcf. Similarly, in 2004, Everlast’s original accounting was based on a proved reserve estimate of 173.4 Bcf, while the revised accounting was based on a proved reserve estimate of 162.2 Bcf. These adjustments resulted in additional depletion expense and reduction of net income of $0.7 million and $76,000 for the years ended December 31, 2003 and 2004, respectively, and an increase in accumulated depletion of $0.8 million at December 31, 2004.
In 2003 and 2004, the cost estimates associated with plugging and abandoning wells should have been computed based on estimates of future costs, including inflation through the period in which the actual cash outflows would be incurred. The impact of correcting the expense to include all such future costs in the asset retirement obligation results in an increase in the asset retirement obligation along with an associated asset retirement asset of $0.8 million at December 31, 2004, and additional accretion expense and reduction of net income of $57,000 and $70,000 for the years ended December 31, 2003 and 2004, respectively.
As part of CEP’s cut-off procedures, CEP identified certain costs incurred in 2003 and 2004 which should have been included in expenses and liabilities in different periods. Recording these costs in the correct periods resulted in additional liabilities of $108,000 and an increase in oil and gas properties of $51,000 at December 31, 2004 and an increase in operating expenses and reduction of net income of $25,000 and $37,000 for the years ended December 31, 2003 and 2004, respectively.
In 2003, Everlast assumed one long term, fixed price natural gas sales contract in connection with the acquisition of the Properties from Torch. This contract met the definition of a derivative under SFAS No. 133 and Everlast accounted for it by recording changes in the fair value of the contract to the income statement. Everlast’s original accounting was to record in “Gas sales” the volumes sold at the current spot price and to record the difference between volumes sold at the spot price and volumes sold at the contractual price in “Loss from mark-to-market activities.” In addition, the change in the fair value of this contract in 2003 was originally recorded as a gain in “Loss from mark-to-market activities.” Since these contracts physically delivered and Everlast was paid the contractual amount, it was incorrect to recognize gas revenues at spot prices with an offset in loss from mark-to-market activities. Accordingly, the financial statements for the year-ended December 31, 2003 have been restated to record all activity related to this contract in “Gas sales”. This resulted in a reduction of gas sales by approximately $1.9 million, the net of these errors, and a corresponding reduction in loss from mark-to-market activities. There was no impact on total revenues or net income in 2003.
F-15
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
AND EVERLAST ENERGY LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Indirect costs associated with acquiring business operations were capitalized by Everlast when it acquired the Properties in January 2003. These costs should have been included as operating costs in the accompanying financial statements and approximately $0.1 million has been expensed (with a corresponding reduction of net income) resulting in a decrease in “Natural gas properties and related equipment (full cost accounting method)-properties being amortized.”
In 2004, Everlast completed a modification of its line of credit and wrote-off all deferred financing costs associated with the previous facility. In accordance with the guidance in EITF 98-14, Debtors Accounting for
F-15.1
OPTION 1
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
AND EVERLAST ENERGY LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following table sets forth costs incurred for gas producing activities for the period from February 7, 2005 (inception) to December 31, 2005, for the period from January 1, 2005 to June 12, 2005, and for the years ended December 31, 2004 and 2003:
| Successor |
Predecessor | |||||||||||
| CEP |
Everlast | |||||||||||
| For the period February 7, 2005 (inception) to December 31, 2005 |
For the period January 1, 2005 to June 12, 2005 |
For the year ended December 31, 2004 |
For the year ended December 31, 2003 | |||||||||
| (In ‘000’s) | (In ‘000’s) | |||||||||||
| Costs incurred for the period: |
||||||||||||
| Acquisition of properties |
||||||||||||
| Proved |
$ | 158,707 | $ | 201 | $ | 1,310 | $ | 50,877 | ||||
| Unproved |
188 | — | — | — | ||||||||
| Exploration costs |
— | — | — | — | ||||||||
| Development costs |
7,851 | 3,998 | 5,674 | 2,040 | ||||||||
| Total costs incurred |
$ | 166,746 | $ | 4,199 | $ | 6,984 | $ | 52,917 | ||||
(b) Results of Operations
The revenues and expenses associated directly with gas producing activities are reflected in the Consolidated Statement of Operations. Substantially all of CEP’s and Everlast’s operations are gas producing activities, and those gas activities are located in a single geographic location.
(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.
F-28
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
AND EVERLAST ENERGY LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
CEP acquired its properties in the Robinson’s Bend Field on June 13, 2005. CEP produced a total of 2.5 Bcf of gas from the date of acquisition to December 31, 2005. In order to calculate the “purchases of reserves in place” of 114.5 Bcf presented in the table below, CEP added the 2.5 Bcf of production in the period from June 13, 2005 to December 31, 2005 to the year-end reserve estimate of 112 Bcf.
| 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 | — | ||||||||
| Revisions of previous estimates |
— | — | 2,173 | — | ||||||||
| Extensions and discoveries |
— | — | 824 | — | ||||||||
| Purchases of reserves in place |
114,550 | — | — | 168,311 | ||||||||
| Sales of reserves in place |
— | — | — | — | ||||||||
| 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 reserve estimate as of December 31, 2005 of 112.0 Bcf was based on the year-end 2005 reserve report prepared by NSAI, an independent reserve engineering firm, for CCG. In preparing its reserve estimate, CEP adjusted the NSAI reserve estimate of 162.9 Bcf downward to reflect CEP’s management’s interpretation of the available information resulting in CEP’s internal estimate of 112.0 Bcf of proved reserves at the end of 2005. These adjustments include: |
| – | A Reduction of 29.7 Bcf Based on Current Well Performance: The information on which CEP based this adjustment includes its interpretation of well performance data from 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). At year-end 2005, CEP believed it had enough data to analyze the performance of new wells. 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 current 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 29.7 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 potentially reducing its ability to prepare a reliable estimate of reserves. Following our acquisition of the Properties from Everlast, CEP substantially continued the drilling program of Everlast which was incorporated in the NSAI estimate of 162.9 Bcf as of December 31, 2005. This 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 current drilling program is designed to provide a steady and constant return by drilling an |
F-29
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
AND EVERLAST ENERGY LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| average of 20 wells per year over a six year period. Due to this difference in drilling programs, certain proved undeveloped reserves that were included in the NSAI estimate at December 31, 2005 based on the previous 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 Attributable to the NPI: CEP removed 5.8 Bcf of reserves that are attributed to the NPI based on our internal estimates using an overriding royalty interest approach. NSAI did not reduce its proved reserve estimates for reserves attributable to the NPI. |
CEP used its 112.0 Bcf proved reserve estimate to prepare the 2005 financial statements. The reserve estimates of 162.2 Bcf for 2004 and 163.7 Bcf for 2003 used to prepare the 2004 and 2003 financials statements were also prepared by CEP using internal estimates.
CEP prepared the estimates of the 2004 and 2003 proved reserves for financial statement purposes by starting with NSAI’s December 31, 2005 proved reserve estimate of 162.9 Bcf, which was based upon the prior accelerated drilling program and reserve assumptions, and rolling that back to year-end 2004 and 2003 by making appropriate adjustments for actual production, prices and development activity. The roll back process was necessary because the reserve report prepared by NSAI for Everlast for year end 2004 was not considered to be based on the Securities and Exchange Commission (SEC) definition of proved reserves, which CEP uses for financial statement preparation purposes. The reserve report prepared by NSAI for Everlast for year end 2003, while based on the SEC definition of proved reserves, included different assumptions than those used by NSAI in preparing the 2005 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, which resulted in a downward revision of the 2005 NSAI reserve estimate by 29.7 Bcf, 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.
(d) Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas Reserves, Including a Reconciliation of Changes Therein
The following table sets forth the standardized measure of the discounted future net cash flows attributable to CEP’s and Everlast’s proved gas reserves. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below.
Future cash inflows are calculated by applying year-end prices of gas, relating to the proved reserves, to the year-end quantities of those reserves. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because CEP and Everlast are both non-taxable entities.
F-30
OPTION 2
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
AND EVERLAST ENERGY LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following table sets forth costs incurred for gas producing activities for the period from February 7, 2005 (inception) to December 31, 2005, for the period from January 1, 2005 to June 12, 2005, and for the years ended December 31, 2004 and 2003:
| Successor |
Predecessor | |||||||||||
| CEP |
Everlast | |||||||||||
| For the period February 7, 2005 (inception) to December 31, 2005 |
For the period January 1, 2005 to June 12, 2005 |
For the year ended December 31, 2004 |
For the year ended December 31, 2003 | |||||||||
| (In ‘000’s) | (In ‘000’s) | |||||||||||
| Costs incurred for the period: |
||||||||||||
| Acquisition of properties |
||||||||||||
| Proved |
$ | 158,707 | $ | 201 | $ | 1,310 | $ | 50,877 | ||||
| Unproved |
188 | — | — | — | ||||||||
| Exploration costs |
— | — | — | — | ||||||||
| Development costs |
7,851 | 3,998 | 5,674 | 2,040 | ||||||||
| Total costs incurred |
$ | 166,746 | $ | 4,199 | $ | 6,984 | $ | 52,917 | ||||
(b) Results of Operations
The revenues and expenses associated directly with gas producing activities are reflected in the Consolidated Statement of Operations. Substantially all of CEP’s and Everlast’s operations are gas producing activities, and those gas activities are located in a single geographic location.
(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.
F-28
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
AND EVERLAST ENERGY LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
CEP acquired its properties in the Robinson’s Bend Field on June 13, 2005. CEP produced a total of 2.5 Bcf of gas from the date of acquisition to December 31, 2005. In order to calculate the “purchases of reserves in place” of 114.5 Bcf presented in the table below, CEP added the 2.5 Bcf of production in the period from June 13, 2005 to December 31, 2005 to the year-end reserve estimate of 112 Bcf.
| 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 | — | ||||||||
| Revisions of previous estimates |
— | — | 2,173 | — | ||||||||
| Extensions and discoveries |
— | — | 824 | — | ||||||||
| Purchases of reserves in place |
114,550 | — | — | 168,311 | ||||||||
| Sales of reserves in place |
— | (160,245 | ) | — | — | |||||||
| Production |
(2,525 | ) | (1,970 | ) | (4,527 | ) | (4,566 | ) | ||||
| Ending Balance |
112,025 | — | 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 reserve estimate as of December 31, 2005 of 112.0 Bcf was based on the year-end 2005 reserve report prepared by NSAI, an independent reserve engineering firm, for CCG. In preparing its reserve estimate, CEP adjusted the NSAI reserve estimate of 162.9 Bcf downward to reflect CEP’s management’s interpretation of the available information resulting in CEP’s internal estimate of 112.0 Bcf of proved reserves at the end of 2005. These adjustments include: |
| – | A Reduction of 29.7 Bcf Based on Current Well Performance: The information on which CEP based this adjustment includes its interpretation of well performance data from 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). At year-end 2005, CEP believed it had enough data to analyze the performance of new wells. 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 current 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 29.7 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 potentially reducing its ability to prepare a reliable estimate of reserves. Following our acquisition of the Properties from Everlast, CEP substantially continued the drilling program of Everlast which was incorporated in the NSAI estimate of 162.9 Bcf as of December 31, 2005. This 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 current drilling program is designed to provide a steady and constant return by drilling an |
F-29
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
AND EVERLAST ENERGY LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| relatively short time period, was to drill and complete 197 gross wells within a five-year period. CEP’s current drilling program is designed to provide a steady and constant return by drilling an |
F-29.1
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
AND EVERLAST ENERGY LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| average of 20 wells per year over a six year period. Due to this difference in drilling programs, certain proved undeveloped reserves that were included in the NSAI estimate at December 31, 2005 based on the previous 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 Attributable to the NPI: CEP removed 5.8 Bcf of reserves that are attributed to the NPI based on our internal estimates using an overriding royalty interest approach. NSAI did not reduce its proved reserve estimates for reserves attributable to the NPI. |
CEP used its 112.0 Bcf proved reserve estimate to prepare the 2005 financial statements. The reserve estimates of 162.2 Bcf for 2004 and 163.7 Bcf for 2003 used to prepare the 2004 and 2003 financials statements were also prepared by CEP using internal estimates.
CEP prepared the estimates of the 2004 and 2003 proved reserves for financial statement purposes by starting with NSAI’s December 31, 2005 proved reserve estimate of 162.9 Bcf, which was based upon the prior accelerated drilling program and reserve assumptions, and rolling that back to year-end 2004 and 2003 by making appropriate adjustments for actual production, prices and development activity. The roll back process was necessary because the reserve report prepared by NSAI for Everlast for year end 2004 was not considered to be based on the Securities and Exchange Commission (SEC) definition of proved reserves, which CEP uses for financial statement preparation purposes. The reserve report prepared by NSAI for Everlast for year end 2003, while based on the SEC definition of proved reserves, included different assumptions than those used by NSAI in preparing the 2005 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, which resulted in a downward revision of the 2005 NSAI reserve estimate by 29.7 Bcf, 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.
(d) Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas Reserves, Including a Reconciliation of Changes Therein
The following table sets forth the standardized measure of the discounted future net cash flows attributable to CEP’s and Everlast’s proved gas reserves. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below.
Future cash inflows are calculated by applying year-end prices of gas, relating to the proved reserves, to the year-end quantities of those reserves. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because CEP and Everlast are both non-taxable entities.
F-30
OPTION 3
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
AND EVERLAST ENERGY LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following table sets forth costs incurred for gas producing activities for the period from February 7, 2005 (inception) to December 31, 2005, for the period from January 1, 2005 to June 12, 2005, and for the years ended December 31, 2004 and 2003:
| Successor |
Predecessor | |||||||||||
| CEP |
Everlast | |||||||||||
| For the period February 7, 2005 (inception) to December 31, 2005 |
For the period January 1, 2005 to June 12, 2005 |
For the year ended December 31, 2004 |
For the year ended December 31, 2003 | |||||||||
| (In ‘000’s) | (In ‘000’s) | |||||||||||
| Costs incurred for the period: |
||||||||||||
| Acquisition of properties |
||||||||||||
| Proved |
$ | 158,707 | $ | 201 | $ | 1,310 | $ | 50,877 | ||||
| Unproved |
188 | — | — | — | ||||||||
| Exploration costs |
— | — | — | — | ||||||||
| Development costs |
7,851 | 3,998 | 5,674 | 2,040 | ||||||||
| Total costs incurred |
$ | 166,746 | $ | 4,199 | $ | 6,984 | $ | 52,917 | ||||
(b) Results of Operations
The revenues and expenses associated directly with gas producing activities are reflected in the Consolidated Statement of Operations. Substantially all of CEP’s and Everlast’s operations are gas producing activities, and those gas activities are located in a single geographic location.
(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.
F-28
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
AND EVERLAST ENERGY LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
CEP acquired its properties in the Robinson’s Bend Field on June 13, 2005. CEP produced a total of 2.5 Bcf of gas from the date of acquisition to December 31, 2005. The 2005 beginning balance of 160.2 Bcf in the following table represents Everlast’s 2004 ending balance less 1.9 Bcf of production through June 12, 2005.
| 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(a) |
160,245 | 162,215 | 163,745 | — | ||||||||
| Revisions of previous estimates |
(45,695 | ) | — | 2,173 | — | |||||||
| Extensions and discoveries |
— | — | 824 | — | ||||||||
| Purchases of reserves in place |
— | — | — | 168,311 | ||||||||
| Sales of reserves in place |
— | — | — | — | ||||||||
| 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 | |||||||||
| (a) | CEP acquired the Robinson’s Bend properties from Everlast on June 13, 2005. |
| • | 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 reserve estimate as of December 31, 2005 of 112.0 Bcf was based on the year-end 2005 reserve report prepared by NSAI, an independent reserve engineering firm, for CCG. In preparing its reserve estimate, CEP adjusted the NSAI reserve estimate of 162.9 Bcf downward to reflect CEP’s management’s interpretation of the available information resulting in CEP’s internal estimate of 112.0 Bcf of proved reserves at the end of 2005. These adjustments include: |
| – | A Reduction of 29.7 Bcf Based on Current Well Performance: The information on which CEP based this adjustment includes its interpretation of well performance data from 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). At year-end 2005, CEP believed it had enough data to analyze the performance of new wells. 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 current 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 29.7 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 potentially reducing its ability to prepare a reliable estimate of reserves. Following our acquisition of the Properties from Everlast, CEP substantially continued the drilling program of Everlast which was incorporated in the NSAI estimate of 162.9 Bcf as of December 31, 2005. This drilling program, which was designed to provide maximum returns in a |
F-29
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
AND EVERLAST ENERGY LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| relatively short time period, was to drill and complete 197 gross wells within a five-year period. CEP’s current drilling program is designed to provide a steady and constant return by drilling an |
F-29.1
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
AND EVERLAST ENERGY LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| average of 20 wells per year over a six year period. Due to this difference in drilling programs, certain proved undeveloped reserves that were included in the NSAI estimate at December 31, 2005 based on the previous 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 Attributable to the NPI: CEP removed 5.8 Bcf of reserves that are attributed to the NPI based on our internal estimates using an overriding royalty interest approach. NSAI did not reduce its proved reserve estimates for reserves attributable to the NPI. |
CEP used its 112.0 Bcf proved reserve estimate to prepare the 2005 financial statements. The reserve estimates of 162.2 Bcf for 2004 and 163.7 Bcf for 2003 used to prepare the 2004 and 2003 financials statements were also prepared by CEP using internal estimates.
CEP prepared the estimates of the 2004 and 2003 proved reserves for financial statement purposes by starting with NSAI’s December 31, 2005 proved reserve estimate of 162.9 Bcf, which was based upon the prior accelerated drilling program and reserve assumptions, and rolling that back to year-end 2004 and 2003 by making appropriate adjustments for actual production, prices and development activity. The roll back process was necessary because the reserve report prepared by NSAI for Everlast for year end 2004 was not considered to be based on the Securities and Exchange Commission (SEC) definition of proved reserves, which CEP uses for financial statement preparation purposes. The reserve report prepared by NSAI for Everlast for year end 2003, while based on the SEC definition of proved reserves, included different assumptions than those used by NSAI in preparing the 2005 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, which resulted in a downward revision of the 2005 NSAI reserve estimate by 29.7 Bcf, 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.
(d) Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas Reserves, Including a Reconciliation of Changes Therein
The following table sets forth the standardized measure of the discounted future net cash flows attributable to CEP’s and Everlast’s proved gas reserves. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below.
Future cash inflows are calculated by applying year-end prices of gas, relating to the proved reserves, to the year-end quantities of those reserves. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because CEP and Everlast are both non-taxable entities.
F-30