Mr. Winfrey,
Please find attached, the narrative discussion of EPL’s reserve revisions that you requested. Should you have any questions please feel free to contact me via email: dbracci@eplweb.com with a copy to John Schuster at Cahill Gordon & Reindel LLP: jschuster@cahill.com.
Dina M Bracci
Controller
Energy Partners, Ltd.
Energy Partners, Ltd. reserve revision discussion
Question 1 - What was the basis for recording proved reserves in the January 20, 2005 acquisition of properties and reserves in south Louisiana. What due diligence was performed and was seismic data used in that estimation of proved reserves?
Response:
On January 20, 2005, Energy Partners, Ltd. (the Company or EPL) closed the acquisition of properties and reserves in south Louisiana. In this acquisition, the Company acquired 9 fields, 4 of which were producing through 14 wells with 8,533 thousand barrels of oil equivalent (Mboe) estimated proved reserves booked on the closing date. The Company’s December 31, 2005 Form 10-K disclosed net negative reserve revisions of 4,045 Mboe of which 5,351 Mboe were net negative revisions on the properties acquired, offset by positive revisions of 1,306 Mboe.
As the starting point for the performance of its due diligence on the reserves to be acquired, EPL obtained the detailed internal reserve data packages of the seller. The seller’s estimate of proved reserves totaled 11,044 Mboe. During the due diligence process EPL evaluated maps constructed largely from well control data, production history, pressure data, well logs (both open hole and cased hole), sidewall cores and basic seismic data to assess structural contours and faulting patterns. EPL’s review resulted in its estimate of proved reserves of 8,533 Mboe. Of the proved reserves, 2,233 Mboe were booked as proved developed producing (PDP) reserves, 2,483 Mboe were proved developed non-producing (PDNP) reserves and 3,817 Mboe were proved undeveloped (PUD) reserves.
Of the PUD reserves booked in the acquisition, approximately 60% were attributed to two remaining sand bodies, the Duval and the Pelican A, in the Lapeyrouse Field. This field was first developed in 1941. Both of these sands were believed to have significant remaining natural gas reserves located up dip of numerous productive wells.
Question 2 - Please describe the circumstances that led to the downward revision.
Response:
The revisions were derived from 3 sources: 1) drilling of development wells in PUD locations where economic quantities of hydrocarbons were not encountered 2) performance history and 3) post-acquisition year end third party reserve engineering firm interpretations. The following lays out the timeline and cause of the significant revisions:
Drilled PUD revisions, resulting in a revision of 2,142 Mboe:
The results of operations conducted during 2005 that impacted PUD reserves bookings were as follows:
1. | Bayou Penchant Field, 2 wells, determined late May 2005, were non productive which led to a revision of 448 Mboe. |
2. | Palmetto Bayou, 1 well, determined April 2005, was non productive and led to a revision of 265 Mboe. |
3. | Delarge Field, 1 well, determined March 2005, was non productive and led to revision of 151 Mboe. |
4. | Lapeyrouse, 4 wells, 1,278 Mboe all EPL operated |
a. | First well (Exposito 3) completed in February 2005 and determined the lower zone to be non productive resulting in reserve revisions, recompleted to the next zone up hole and producing in April 2005 but that zone soon watered out resulting in additional reserve revisions. The well was recompleted again in the next immediate zone, the Pelican A, one of EPL’s two largest booked sands. The well immediately started producing water contrary to the logged response of natural gas. EPL ran a series of logs and determined communication from a lower formation. In December 2005 the completion was repaired and the zone began producing natural gas. However, insufficient production history at year end in the most recently recompleted zone led the third party reserve engineering firm to revise the reserves downward. |
b. | Second well (Pettigrew) completed and producing in February 2005, first zone watered out, recompleted May 2005 to the Pelican A sand. Poor performance in the first zone led to a downward revision and condemned a third planned well (the ALM #2) which also led to downward revisions. |
c. | Fourth well (Invincible Fee #6) completed December 2005 as a successful well. However the third party reserve engineering firm believed there was not enough production history to maintain the full booking as of year end. |
Undrilled PUD revision of 666 Mboe:
1. | Lapeyrouse, 3 wells. Although, there were a number of factors that contributed to the revision, the primary factor was the high cost environment for drilling rigs, equipment and other services at year-end 2005 that was not anticipated at the acquisition date. Some of the PUD locations were rendered uneconomical due to these cost escalations, which were exacerbated by Hurricane Katrina and contributed to the lower reserve estimates of the third party reserve engineering firm at year end. |
Initial poor drilling results in the Lapeyrouse Field led the Company to conduct an extensive remapping project of the Field that lasted several months. The overall drilling results in the Lapeyrouse Field highlighted, and led to a fuller recognition of, the geological complexities of the area. Notwithstanding the existing well control data, documented historical information and extensive production allocated to the main producing sand accumulations in the field, results of wells drilled in 2005 revealed a higher level of geological complexity than was recognized at the time of the acquisition. That complexity includes a high degree of structural fragmentation with interior faulting and a lithological stratigraphic component not previously recognized. That complexity is exemplified by up dip wells being logged wet contemporaneously with continuing production from down dip wells and down dip pay being logged productive after up dip wells had apparently watered out.
PDP performance revisions of 1,830 Mboe:
This category had both positive and negative revisions, the largest being a negative revision of 1,800 Mboe at Lapeyrouse in 9 producing wells based on performance activity through the end of the fiscal year. A contributing factor was the need for compression earlier than expected as a result of unanticipated pressure declines without the benefit prior to year end of production history after being placed on compression.
PNP performance revisions of 713 Mboe:
This category is comprised of negative revisions in proved behind pipe at Lapeyrouse and Golden Meadow attributed to interpretations of the third party reserve engineering firm that were undertaken with benefit of post acquisition drilling and production history in these geologically complex field areas.
Question 3 - Please illustrate the impact of the effect of the write down on the historical financials as if the reserves had not been booked on the acquisition date.
Response:
Due to the many potential changes in reserves during the course of a year, it is the Company’s policy to only revise reserves for both positive and negative revisions on January 1 of each fiscal year using the SEC reserves as engineered by third party reserve engineers with the assistance of the Company’s staff as of December 31 of the immediately preceding year.
Consistent with the timing of the events stated above that led to the reserve revisions on the acquired south Louisiana properties as well as the Company’s existing policy and guidelines for changes in estimates as prescribed by Accounting Principals Board Opinion No. 20 (As Amended) (APB. 20), the Company did not revise the reserve volume that was used in its Depreciation, Depletion and Amortization (DD&A) calculation. Taking into account only the net negative revisions taken on the south Louisiana acquisition reserves, the impact to DD&A had the acquired reserves been booked at the revised volumes on the date of acquisition would have been an increase in DD&A of $9.5 million or a decrease in net income available to common stockholders of $6.1 million.
Since the above calculation does not take into account the many factors that occurred following the acquisition (drilling results, performance history, cost escalations, etc.) that contributed to the downward reserve revisions, alternatively, the Company has also prepared, a calculation reflecting only the impact on DD&A of the PUD drill well operations performed, had they been taken into account when the wells were determined, for this purpose assuming the date for all to be May 1, 2005 (although some determinations were made later in the year). This impact would have been a $0.8 million increase in DD&A or a $0.5 million decrease in net income available to common stockholders.