SEC Company Response from EL PASO — Oct 15, 2004
EL PASO CORP/DE (CIK 0001066107)
Date: Oct. 15, 2004 · CIK: 0001066107 · Accession: 0001066107-04-000151
AI Filing Summary & Sentiment
Referenced dates: September 29, 2004
Letter
Division of Corporate Finance United States Securities and Exchange Commission El Paso Corporation Draft 2003 10-K SEC File No. I-14365, Submitted 6-22-04 8-K SEC File No. I-14365 Filed 8-23-04 Supplemental engineering information submitted 6-16-04, 7-9-04 and 8-10-04
Dear Mr. Owings,
In your letter dated September 29, 2004, you asked El Paso Corporation to provide additional information regarding engineering disclosures in our Draft Annual Report on Form 10-K for the year ended December 31, 2003, in our Form 8-K filed on August 23, 2004, and in our supplemental engineering information submitted in June, July, and August 2004. The following are our responses to your questions.
Draft 10-K
Natural Gas and Oil Reserves, page 11
1. Here and page 180, you disclose that you have excluded proved reserves related to your equity ownership in various entities. Paragraph 14(c) of Financial Accounting Standard 69 requires your separate disclosure of such volumes. Please amend your document to comply with FAS 69.
Response
We note your comment and have included the following details on page 12 and page 188 of our 2003 Form 10-K: “The tables below exclude reserve information related to our equity ownership interests in UnoPaso; the Merchant Energy segment's interests in Sengkang in Indonesia and Aguaytia in Peru; and the Field Services segment's interest in GulfTerra. Combined proved reserve balances for these equity investment interests were 255,278 MMcf of natural gas and 7,105 MBbls of oil or natural gas equivalents of 297,909 MMcfe, all net to our ownership interests.”
Net Production, Sales Prices, Transportation and Production Cost, page 16
2. Supplementally, tell us how you deduct projected transportation cost in your standardized measure calculation, i.e. as a production cost component or as a product price reduction. If the latter, reconcile the differences between the nominal 12-31-03 spot prices - $32.55/BO and $5.97/MMBTU - and your average year-end prices - $31.02/BO and $5.89/MCFG.
Response
The projected transportation cost for the domestic U.S. properties was treated as a product price reduction in the standardized measure calculation. The projected transportation cost for the Canadian properties was treated as a production cost component in the standardized measure calculation. As of September 2004, we have sold all of our Canadian properties.
The December 31, 2003 spot prices used in our domestic calculations were $6.03 per MMBtu for Henry Hub natural gas and $32.52 per barrel for oil. The average realized price in the domestic cash flows for natural gas was $5.79 per Mcf and for oil was $31.10 per barrel. The differences between the spot prices and the realized prices are due to product quality, regional basis differentials, transportation and a Btu adjustment. We have attached our 2003 year end pricing letter as Exhibit 1. It shows the regional price variation taken into account during our analysis that results in the average realized prices of $5.79 per Mcf and $31.10 per barrel. In addition the average Btu adjustment for the domestic properties was 1.04 MMBtu/Mcf.
The December 31, 2003 spot prices used in our Canadian calculations were US$5.02/MMBtu for AECO natural gas (C$6.15 /GJ, C$6.49/MMBtu) and US$32.52 per barrel for oil (C$42.05/BO). The average realized price in the Canadian cashflows for natural gas was US$5.18 per Mcf (C$6.70/Mcf) and US$29.43 per Barrel for oil (C$38.05/BO). The difference between the spot prices and the realized prices are also due to product quality, regional basis differentials, and Btu adjustment. The average BTU adjustment for the Canadian properties was 1.07 MMBtu/Mcf.
Restatement Methodology, page 98
3. Amend your document here to compare your historical and restated proved reserves for 1998 and 1999.
Response
As disclosed on page 35 of our 2003 Form 10-K, our financial results for the impacts of the historical restatements for the years ended December 31, 1999 and 2000 have not been audited. The 1998 and 1999 proved reserve values only impact the beginning retained earnings adjustment that is included in our audited financial statements as of January 1, 2001. Since these values are not required disclosures in our 2003 Form 10-K, the historical and restated proved reserves for these periods were not included in document.
Net proved developed and undeveloped reserves, pages 181, 182
4. On pages 96-97, the stated methodology for reconstructing your estimated proved oil and gas reserves (presumably) precludes revisions due to performance. Your proved natural gas estimates for year-end 2002 include a negative revision of 154 BCF even though the nominal year-end spot gas price and increased substantially - $2.64/MMBTU for 2001 to $4.75/MMBTU for 2002 - from the previous year-end. Amend your document to explain this seeming inconsistency.
Response
The negative revision in 2002 was due to the quarter to quarter net back price changes in the Rocky Mountain area. This change in basis differential had a major impact on project economics, which in turn, caused significant changes in proved reserves, primarily proved undeveloped. The Rocky Mountain netback price dropped drastically in the second quarter 2002, therefore uneconomic reserves were written off. Prices did recover during fourth quarter 2002, however, El Paso had sold its interest in properties located in Utah during the fourth quarter. As a result, the reserves that were written off due to the low prices experienced in the second and third quarters were not rebooked with the upward change in prices at year end 2002. The table below shows the comparison of the Henry Hub and the Natural Buttes bench mark prices in $ per MMBTU:
Quarter
Henry Hub
Natural Buttes
Q4 202
$4.79
$2.84
Q3 2002
$3.80
$1.12
Q2 2002
$3.26
$0.85
Q1 2002
$3.41
$2.66
Q4 2001
$2.70
$1.98
We included the following footnote to the reserves tables on pages 187 and 188 of our Form 10-K which states: “Revisions reflect a number of items such as product price changes and changes in product differentials.”
5. Amend your disclosure of proved liquid reserves to separate NGL volumes from crude oil per FAS 69, paragraph 10.
Response
The amount of NGL volumes at year-end 2003 is not material as it only represents approximately 4% of our total proved reserves. We note your comment and have included the following footnote on page 186 of our Form 10-K: “(1) Includes oil, condensate and natural gas liquids. Our year end 2003 natural gas liquids were 18,550 MBbls.” For future filings with the Commission, we will continue to evaluate the significance of our NGL reserve volumes for separate disclosure consideration.
Standardized Measure…,page186
6. Here you state, “These [investment and operating] decisions are based on various factors including…corporate investment criteria.” Supplemetally, tell us your specific corporate investment criteria that applies at year-end 2003. Explain whether you have claimed proved undeveloped reserves at year-end 2003 that did not meet these criteria.
Response
We have not claimed any proved undeveloped reserves at year-end 2003 that did not meet our corporate investment criteria. All projects in the year-end 2003 reserve estimates were validated by our two external engineers, Ryder Scott Company and Huddleston and Company. All projects are planned to be drilled and the company is adequately funded to develop these projects. Our corporate parent has allocated $850 million in capital to the Production segment for 2004 and we expect a similar allocation for 2005.
8-K
7. We understand that your U.S. properties produced 901 MMCFE/day and 805 MMCFE/day for the first and second quarters of 2004, respectively. Your supplemental reserve report projects an average of 880 MMCFE/day (=321,082 MMCFE/365 days) for 2004. Supplementally, please explain the apparent shortfall in your production from your projections. Include schedules of significant differences from your projections for your major fields. Address how you intend to reverse/attenuate this apparent (11%/quarter) decline.
Response
Our average domestic production through August 2004 was 829 MMcfe/day compared to the year end 2003 forecast of 894 MMcfe/day for the same period, or a variance of 65 MMcfe/day. The major difference is due to the following: (average net MMcfe/day thru August, 2004).
Division Level Comparison (Net MMcfe/d)
Year End 2003 Forecast
Aug. YTD Actual
Difference
Field
Texas Gulf Coast
+6
Gulf of Mexico
-51
Onshore
CBM
Arklatex
Rockies
-6
Total Onshore
Field Level Comparison (Major Differences, NET MMcfe/d)
Field
Division
Year End 2003 Forecast
Aug
YTD Ave
Actual
Difference
Remarks
WD 137
GOM
27.25
12.86
-14.39
A-1 well unexpectedly experienced water encroachment and loaded up. The well is currently shut in.
Holly
Onshore-Aklatex
39.78
30.25
-9.54
Reduced rig program from 4 to 2. Sold interest in some PUD wells to 3rd party investor program.
Rockies
Onshore-Rockies
22.06
15.56
-6.50
Delay in planned recompletions
EB 1003
GOM
7.79
1.62
-6.17
A-4 well recompletion sanded up; A recent workover restored prod but at much lower rate
SMI 223
GOM
22.96
17.22
-5.74
Both wells experienced downhole scaling problems. The operator initiated remedial action which resulted in unexpected downtime; however, current production has been restored at rates similar to year-end performance.
N. Shongaloo
Onshore-
Arklatex
15.12
12.97
-2.15
Delay in planned recompletions
Bear Creek
Onshore-
Arklatex
21.30
19.49
-1.81
Sold interest in some PUD wells to 3rd party investor program and experiencing some performance variance.
Blue Creek West
Onshore-
CBM
9.70
8.21
-1.49
Delay in new well hookups, delay in drilling new wells and well performance.
WC 515A/526
GOM
2.89
1.41
- 1.48
WC 516 A2 recompletion lasted only one month before tubing parted and well was lost.
Short Creek
Onshore-
CBM
13.02
11.67
-1.35
Delay in new well hookups and facility constraints as new wells came on line at higher than expected rates.
Total Variance Explained
50.62
Represents 78% of total variance of 65 MMcfe/day.
In an effort to improve the performance of our Production business and to stabilize our daily production, in June 2004 we announced a back-to-basics plan for our business. This plan emphasizes strict capital discipline designed to improve capital efficiency through the use of standardized risk analysis, a heightened focus on cost control, and a rigorous process for booking proved natural gas and oil reserves. This back-to-basics approach is designed to stabilize production by improving the production mix across our operating areas, thereby generating more predictable income and cash flows in this business. We will continue to monitor the performance of our wells and to the extent it is warranted we will reflect revisions in our reserves in subsequent quarterly periods.
Supplemental Information
Oklahoma CBM
8. Supplementally, compare the PUD reserves for horizontal wells you attributed here with the EUR for all the producing horizontal wells in the field. Tell us if you obtained the CBM gas content from desorption test and, if so, how many different wells were sampled.
Response
We have attached as Exhibit 2, the email Ace Alexander sent to Mr. Winfrey on September 20, 2004 which substantially addresses this question. Additionally, El Paso has 57 desorption samples from 10 wells in the Oklahoma CBM.
Gulf of Mexico
9. We note you attributed proved reserves to the EI 364 A-1 well solely on the basis of open hole well logs. Topic 12 of Accounting Series Release No. 257 of the Staff Accounting Bulletins requires such attribution to be supported by comparison with similar reservoirs in the same field. Explain to us your attribution here of proved reserves.
Response
We have attached as Exhibit 3, the email Ace Alexander sent to Mr. Winfrey on September 20, 2004 which substantially addresses this question. Additionally, there are correlative productive intervals in EI 349, located directly north of this block.
10. Your estimated proved reserves for EI 371 A-11 (TB 10 sand) were reduced to 40% of the volumetric calculations which indicates serious uncertainty here. We did not find any downhole log information in your supplemental information. Please explain your proved reserve estimation methodology here.
Response
We have attached as Exhibit 4, the email Ace Alexander sent to Mr. Winfrey on September 17, 2004 which addresses the first part of this question. Additionally, we have noticed the original supplemental informational write-up on the TB-10 sand erroneously referred to the oil-water contact established in the EI 372 A-3. The oil water contact was established in the EI 372 A-2. The log for this well was included in the original response. The TB-10 sand was also productive in the EI 372 A-3 in a separate fault block.
The original supplemental response can be found in “Response to 5/25/2004 SEC Letter, RE: Supplemental Materials from May 25, 2004 Meeting File No. 1-14365”, Appendix 2, Exhibit D-2-7”.
Should you have any further questions regarding our responses to your questions or need further information, please contact me at (713) 420-3040 or Jeff Beason at (713) 420-5611.
Sincerely,
/s/ D. Dwight Scott
Show Raw Text
CORRESP 1 filename1.htm El Paso Correspondence October 15, 2004 Mr. H. Christopher Owings, Jr. Assistant Director Division of Corporate Finance United States Securities and Exchange Commission 450 Fifth Street, N.W. Washington, D.C. 20549-0308 RE: El Paso Corporation Draft 2003 10-K SEC File No. I-14365, Submitted 6-22-04 8-K SEC File No. I-14365 Filed 8-23-04 Supplemental engineering information submitted 6-16-04, 7-9-04 and 8-10-04 Dear Mr. Owings, In your letter dated September 29, 2004, you asked El Paso Corporation to provide additional information regarding engineering disclosures in our Draft Annual Report on Form 10-K for the year ended December 31, 2003, in our Form 8-K filed on August 23, 2004, and in our supplemental engineering information submitted in June, July, and August 2004. The following are our responses to your questions. Draft 10-K Natural Gas and Oil Reserves, page 11 1. Here and page 180, you disclose that you have excluded proved reserves related to your equity ownership in various entities. Paragraph 14(c) of Financial Accounting Standard 69 requires your separate disclosure of such volumes. Please amend your document to comply with FAS 69. Response We note your comment and have included the following details on page 12 and page 188 of our 2003 Form 10-K: “The tables below exclude reserve information related to our equity ownership interests in UnoPaso; the Merchant Energy segment's interests in Sengkang in Indonesia and Aguaytia in Peru; and the Field Services segment's interest in GulfTerra. Combined proved reserve balances for these equity investment interests were 255,278 MMcf of natural gas and 7,105 MBbls of oil or natural gas equivalents of 297,909 MMcfe, all net to our ownership interests.” Net Production, Sales Prices, Transportation and Production Cost, page 16 2. Supplementally, tell us how you deduct projected transportation cost in your standardized measure calculation, i.e. as a production cost component or as a product price reduction. If the latter, reconcile the differences between the nominal 12-31-03 spot prices - $32.55/BO and $5.97/MMBTU - and your average year-end prices - $31.02/BO and $5.89/MCFG. Response The projected transportation cost for the domestic U.S. properties was treated as a product price reduction in the standardized measure calculation. The projected transportation cost for the Canadian properties was treated as a production cost component in the standardized measure calculation. As of September 2004, we have sold all of our Canadian properties. The December 31, 2003 spot prices used in our domestic calculations were $6.03 per MMBtu for Henry Hub natural gas and $32.52 per barrel for oil. The average realized price in the domestic cash flows for natural gas was $5.79 per Mcf and for oil was $31.10 per barrel. The differences between the spot prices and the realized prices are due to product quality, regional basis differentials, transportation and a Btu adjustment. We have attached our 2003 year end pricing letter as Exhibit 1. It shows the regional price variation taken into account during our analysis that results in the average realized prices of $5.79 per Mcf and $31.10 per barrel. In addition the average Btu adjustment for the domestic properties was 1.04 MMBtu/Mcf. The December 31, 2003 spot prices used in our Canadian calculations were US$5.02/MMBtu for AECO natural gas (C$6.15 /GJ, C$6.49/MMBtu) and US$32.52 per barrel for oil (C$42.05/BO). The average realized price in the Canadian cashflows for natural gas was US$5.18 per Mcf (C$6.70/Mcf) and US$29.43 per Barrel for oil (C$38.05/BO). The difference between the spot prices and the realized prices are also due to product quality, regional basis differentials, and Btu adjustment. The average BTU adjustment for the Canadian properties was 1.07 MMBtu/Mcf. Restatement Methodology, page 98 3. Amend your document here to compare your historical and restated proved reserves for 1998 and 1999. Response As disclosed on page 35 of our 2003 Form 10-K, our financial results for the impacts of the historical restatements for the years ended December 31, 1999 and 2000 have not been audited. The 1998 and 1999 proved reserve values only impact the beginning retained earnings adjustment that is included in our audited financial statements as of January 1, 2001. Since these values are not required disclosures in our 2003 Form 10-K, the historical and restated proved reserves for these periods were not included in document. Net proved developed and undeveloped reserves, pages 181, 182 4. On pages 96-97, the stated methodology for reconstructing your estimated proved oil and gas reserves (presumably) precludes revisions due to performance. Your proved natural gas estimates for year-end 2002 include a negative revision of 154 BCF even though the nominal year-end spot gas price and increased substantially - $2.64/MMBTU for 2001 to $4.75/MMBTU for 2002 - from the previous year-end. Amend your document to explain this seeming inconsistency. Response The negative revision in 2002 was due to the quarter to quarter net back price changes in the Rocky Mountain area. This change in basis differential had a major impact on project economics, which in turn, caused significant changes in proved reserves, primarily proved undeveloped. The Rocky Mountain netback price dropped drastically in the second quarter 2002, therefore uneconomic reserves were written off. Prices did recover during fourth quarter 2002, however, El Paso had sold its interest in properties located in Utah during the fourth quarter. As a result, the reserves that were written off due to the low prices experienced in the second and third quarters were not rebooked with the upward change in prices at year end 2002. The table below shows the comparison of the Henry Hub and the Natural Buttes bench mark prices in $ per MMBTU: Quarter Henry Hub Natural Buttes Q4 202 $4.79 $2.84 Q3 2002 $3.80 $1.12 Q2 2002 $3.26 $0.85 Q1 2002 $3.41 $2.66 Q4 2001 $2.70 $1.98 We included the following footnote to the reserves tables on pages 187 and 188 of our Form 10-K which states: “Revisions reflect a number of items such as product price changes and changes in product differentials.” 5. Amend your disclosure of proved liquid reserves to separate NGL volumes from crude oil per FAS 69, paragraph 10. Response The amount of NGL volumes at year-end 2003 is not material as it only represents approximately 4% of our total proved reserves. We note your comment and have included the following footnote on page 186 of our Form 10-K: “(1) Includes oil, condensate and natural gas liquids. Our year end 2003 natural gas liquids were 18,550 MBbls.” For future filings with the Commission, we will continue to evaluate the significance of our NGL reserve volumes for separate disclosure consideration. Standardized Measure…,page186 6. Here you state, “These [investment and operating] decisions are based on various factors including…corporate investment criteria.” Supplemetally, tell us your specific corporate investment criteria that applies at year-end 2003. Explain whether you have claimed proved undeveloped reserves at year-end 2003 that did not meet these criteria. Response We have not claimed any proved undeveloped reserves at year-end 2003 that did not meet our corporate investment criteria. All projects in the year-end 2003 reserve estimates were validated by our two external engineers, Ryder Scott Company and Huddleston and Company. All projects are planned to be drilled and the company is adequately funded to develop these projects. Our corporate parent has allocated $850 million in capital to the Production segment for 2004 and we expect a similar allocation for 2005. 8-K 7. We understand that your U.S. properties produced 901 MMCFE/day and 805 MMCFE/day for the first and second quarters of 2004, respectively. Your supplemental reserve report projects an average of 880 MMCFE/day (=321,082 MMCFE/365 days) for 2004. Supplementally, please explain the apparent shortfall in your production from your projections. Include schedules of significant differences from your projections for your major fields. Address how you intend to reverse/attenuate this apparent (11%/quarter) decline. Response Our average domestic production through August 2004 was 829 MMcfe/day compared to the year end 2003 forecast of 894 MMcfe/day for the same period, or a variance of 65 MMcfe/day. The major difference is due to the following: (average net MMcfe/day thru August, 2004). Division Level Comparison (Net MMcfe/d) Year End 2003 Forecast Aug. YTD Actual Difference Field Texas Gulf Coast 291 297 +6 Gulf of Mexico 356 305 -51 Onshore CBM 131 131 0 Arklatex 94 80 14 Rockies 22 16 -6 Total Onshore 247 227 20 Field Level Comparison (Major Differences, NET MMcfe/d) Field Division Year End 2003 Forecast Aug YTD Ave Actual Difference Remarks WD 137 GOM 27.25 12.86 -14.39 A-1 well unexpectedly experienced water encroachment and loaded up. The well is currently shut in. Holly Onshore-Aklatex 39.78 30.25 -9.54 Reduced rig program from 4 to 2. Sold interest in some PUD wells to 3rd party investor program. Rockies Onshore-Rockies 22.06 15.56 -6.50 Delay in planned recompletions EB 1003 GOM 7.79 1.62 -6.17 A-4 well recompletion sanded up; A recent workover restored prod but at much lower rate SMI 223 GOM 22.96 17.22 -5.74 Both wells experienced downhole scaling problems. The operator initiated remedial action which resulted in unexpected downtime; however, current production has been restored at rates similar to year-end performance. N. Shongaloo Onshore- Arklatex 15.12 12.97 -2.15 Delay in planned recompletions Bear Creek Onshore- Arklatex 21.30 19.49 -1.81 Sold interest in some PUD wells to 3rd party investor program and experiencing some performance variance. Blue Creek West Onshore- CBM 9.70 8.21 -1.49 Delay in new well hookups, delay in drilling new wells and well performance. WC 515A/526 GOM 2.89 1.41 - 1.48 WC 516 A2 recompletion lasted only one month before tubing parted and well was lost. Short Creek Onshore- CBM 13.02 11.67 -1.35 Delay in new well hookups and facility constraints as new wells came on line at higher than expected rates. Total Variance Explained 50.62 Represents 78% of total variance of 65 MMcfe/day. In an effort to improve the performance of our Production business and to stabilize our daily production, in June 2004 we announced a back-to-basics plan for our business. This plan emphasizes strict capital discipline designed to improve capital efficiency through the use of standardized risk analysis, a heightened focus on cost control, and a rigorous process for booking proved natural gas and oil reserves. This back-to-basics approach is designed to stabilize production by improving the production mix across our operating areas, thereby generating more predictable income and cash flows in this business. We will continue to monitor the performance of our wells and to the extent it is warranted we will reflect revisions in our reserves in subsequent quarterly periods. Supplemental Information Oklahoma CBM 8. Supplementally, compare the PUD reserves for horizontal wells you attributed here with the EUR for all the producing horizontal wells in the field. Tell us if you obtained the CBM gas content from desorption test and, if so, how many different wells were sampled. Response We have attached as Exhibit 2, the email Ace Alexander sent to Mr. Winfrey on September 20, 2004 which substantially addresses this question. Additionally, El Paso has 57 desorption samples from 10 wells in the Oklahoma CBM. Gulf of Mexico 9. We note you attributed proved reserves to the EI 364 A-1 well solely on the basis of open hole well logs. Topic 12 of Accounting Series Release No. 257 of the Staff Accounting Bulletins requires such attribution to be supported by comparison with similar reservoirs in the same field. Explain to us your attribution here of proved reserves. Response We have attached as Exhibit 3, the email Ace Alexander sent to Mr. Winfrey on September 20, 2004 which substantially addresses this question. Additionally, there are correlative productive intervals in EI 349, located directly north of this block. 10. Your estimated proved reserves for EI 371 A-11 (TB 10 sand) were reduced to 40% of the volumetric calculations which indicates serious uncertainty here. We did not find any downhole log information in your supplemental information. Please explain your proved reserve estimation methodology here. Response We have attached as Exhibit 4, the email Ace Alexander sent to Mr. Winfrey on September 17, 2004 which addresses the first part of this question. Additionally, we have noticed the original supplemental informational write-up on the TB-10 sand erroneously referred to the oil-water contact established in the EI 372 A-3. The oil water contact was established in the EI 372 A-2. The log for this well was included in the original response. The TB-10 sand was also productive in the EI 372 A-3 in a separate fault block. The original supplemental response can be found in “Response to 5/25/2004 SEC Letter, RE: Supplemental Materials from May 25, 2004 Meeting File No. 1-14365”, Appendix 2, Exhibit D-2-7”. Should you have any further questions regarding our responses to your questions or need further information, please contact me at (713) 420-3040 or Jeff Beason at (713) 420-5611. Sincerely, /s/ D. Dwight Scott D. Dwight Scott Executive Vice President and Chief Financial Officer El Paso Corporation