SecProbe.io

CORRESP
1
filename1.htm

corresp

February 09, 2005

VIA FEDEX

Mr. H. Christopher Owings

Assistant Director

Division of Corporation Finance

Securities and Exchange Commission

450 Fifth Street, N.W.

Washington, D.C. 20549-0445

    Re:

    El Paso Corporation

    2003 10-K SEC File No. 1-14365, filed 9-30-04

    8-K SEC File No. 1-14365, filed 10-28-04, 8-23-04

    10-15-04 supplemental response

Dear Mr. Owings:

     We are in receipt of your letter dated December 16, 2004 with respect to the above referenced
filings. Below are the comments set out in your letter followed by our responses.

8-23-04 8-K

    1.
    Our prior comment 7 noted that your year-end 2003 reserve report projected annual U.S.
production of 880 MMCFE/day for 2004. Your response included a schedule of fields with
significant 2004 production shortfalls. The Gulf of Mexico region’s shortfall was 51
MMCFE/day of the total 65 MMCFE/day shortfall for your total domestic production. The four
individual GOM fields listed have a total of 27.8 MMCFE/day shortfall which leaves 23.2
MMCFE/day unaccounted. This shortfall difference is larger than that for all the remaining
areas — 14 MMCFE/day total for Onshore and Texas Gulf Coast. If you have omitted a property
(South Timbalier 212?) from your schedule, please furnish a correction. If not, please
explain why there is such a large unaccounted volume.

     Response:

     We have updated the table submitted in our previous response. This update includes six
additional GOM fields (highlighted in bold) that were not included in our initial response. The
revised table accounts for a total of 72 MMcfe/day of shortages for our domestic production.

Mr. H. Christopher Owings

February 09, 2005

Page 2

Division Level Comparison (Net MMcfe/d)

    Year End

    Aug. YTD

    Field

    2003 Forecast

    Actual

    Difference

    Texas Gulf Coast

    291

    297

    +6

    Gulf of Mexico

    356

    305

    -51

    Onshore

    Coal Bed Methane

    131

    131

    —

    Arklatex

    94

    80

    -14

    Rockies

    22

    16

    -6

    Total Onshore

    247

    227

    -20

Field Level Comparison (Major Differences, Net MMcfe/d) (updates are indicated in bold
type)

    Aug

    Year End 2003

    YTD Ave

    Field

    Division

    Forecast

    Actual

    Difference

    Remarks

    WD 137

    GOM

    27.25

    12.86

    -14.4

    A-1 well unexpectedly
experienced water encroachment
and loaded up. The well is
currently shut in.

    Holly

    Onshore-Aklatex

    39.78

    30.25

    -9.5

    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

    -6.5

    Delay in planned recompletions.

    EB 1003

    GOM

    7.79

    1.62

    -6.2

    A-4 well recompletion sanded
up; A recent workover restored
production, but at much lower
rate.

    SMI 223

    GOM

    22.96

    17.22

    -5.7

    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.

    EC 81/84

    GOM

    25.5

    21.1

    -4.4

    Production performance for
EC 81 C-3 (-2.4),
EC 84 C-1 (-1.1) and
EC 81 A-1 (-0.9).

    MP 265

    GOM

    8.5

    4.4

    -4.1

    Recompletion was deferred
because the existing
completion is still producing.

Mr. H. Christopher Owings

February 09, 2005

Page 3

    Aug

    Year End 2003

    YTD Ave

    Field

    Division

    Forecast

    Actual

    Difference

    Remarks

    VK 385

    GOM

    8.0

    4.5

    -3.5

    VK 429 A-3 PUD drilling was
deferred due to surface
facility delays. This well
will be drilled in 2005.

    EI 370/371/

372/384/385

    GOM

    8.2

    5.1

    -3.1

    Timing and performance of new
wells A-11 (-1.2) and A-12
(-1.9).

    HI 85

    GOM

    7.2

    4.1

    -3.1

    Production performance for
A-1 (-1.5), A-2 (-0.6) and A-3
(-1.0).

    HI 351/368

    GOM

    7.0

    4.0

    -3.0

    Recompletion work was deferred
due to delay in obtaining
co-owner approval.

    N. Shongaloo

    Onshore-

Arklatex

    15.12

    12.97

    -2.12

    Delay in planned recompletions.

    Bear Creek

    Onshore-

Arklatex

    21.30

    19.49

    -1.8

    Sold interests in some PUD
wells to 3rd party
investor program and
experienced some performance
variance.

    Blue Creek West

    Onshore-

CBM

    9.70

    8.21

    -1.5

    Delay in new well hookups,
delay in drilling new wells
and well performance.

    WC 515A/526

    GOM

    2.89

    1.41

    - 1.5

    WC 516 A2 recompletion lasted
only one month before tubing
parted and well was lost.

    Short Creek

    Onshore-

CBM

    13.02

    11.67

    -1.4

    Delay in new well hookups and
facility constraints as new
wells came on line at higher
than expected rates.

    Total Variance

Explained

    -71.9

    Represents >100% of total
variance of 65 MMcfe/day.

    2.
    We also asked that you “Address how you intend to reverse/attenuate this apparent
(11%/quarter) decline.” You replied, “... in June 2004, we announced a back-to-basics plan
for our production 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 expected to stabilize production by
improving the production mix across our operating areas and generate more predictable
returns.”

Mr. H. Christopher Owings

February 09, 2005

Page 4

This appears to be a verbatim rendition of the second-to-last paragraph on page 11 —
UNREGULATED BUSINESSES — PRODUCTION SEGMENT — of your 2003 Form 10-K.

    (a)
    Supplementally, address the internal controls you have in place to
provide the conservatism in your reserve estimates that are necessary for the
proved classification. Discuss the procedures — e.g. internal peer review
— you have implemented to complement the structural changes disclosed on pages
195-196.

     Response:

     We believe the following internal controls and procedures provide for conservatism in the
preparation of our estimates of proved reserves:

    •
    We updated and enhanced our documentation with regard to the booking of proved
reserves through updating our reserves reporting manual which is based on SEC guidelines
for booking proved reserves. We will also provide enhanced training in 2005 for all
engineers involved in the reserves estimation process with respect to compliance with
SEC guidelines.

    •
    We created a centralized reserves evaluation and reporting function that is
separate from our operating regions. As part of this revised evaluation process,
the following review steps are performed:

    •
    Engineering review of the data provided by the operating
regions and estimation of proved reserves.

    •
    Review of proved reserves estimates with manager and reservoir
engineers.

    •
    Review of proved reserves estimates with the President of our
Production and Non-regulated business unit.

    •
    Review of proved reserves estimation processes with the
Reserves Reporting Committee (see the description of this committee below).

    •
    The use of compensation programs that do not consider proved reserves or
reserves replacement targets. Also, please see our response below to Question No.
8.

    •
    The use of more frequent internal audit reviews to monitor the reserves
estimation process.

    •
    The use of Ryder Scott Company to prepare an independent bottoms-up reserves
estimate for a minimum of 80% of our reserves for comparison with our internally
generated reserves estimates.

Mr. H. Christopher Owings

February 09, 2005

Page 5

    •
    The appointment of our independent reserve engineer by our Audit Committee to
whom the reserve engineer reports annually, including in executive session.

    •
    The formation of an internal committee (the Reserves Reporting Committee) to
provide oversight of our reserves estimation processes. This committee is staffed
with appropriate technical, financial reporting and legal expertise.

     All of these internal controls and procedures provide for multiple levels of additional
oversight of our reserve estimation process. We believe this ongoing oversight, including the
involvement of our Board of Directors, provides strict compliance with SEC proved reserves
definitions, resulting in more conservative estimates.

    (b)
    Supplementally, explain how you intend to improve your production mix.

     Response:

     We intend to improve our production mix by allocating more capital to long-life, shallower
decline projects and to development projects in longer reserve life areas. We have already
accomplished this through a more rigorous capital review process and a more balanced allocation of
our capital to development and exploration projects, supplemented by acquisition activities. Our
4th quarter 2004 production volumes exhibited a more balanced geographic split with 31%
coming from long-life onshore production, versus 23% in the first quarter of 2004.

    3.
    On page 13 of the same (Form 10-K) section, you state, “The accuracy of any reserve estimate
is a function of the quality of available data and of engineering and geological
interpretations and judgment. As a result, estimates of different engineers often vary.” We
believe this statement requires amplification in the case of proved reserves. By definition,
proved reserves are much more likely of recovery than not and should be conservatively
estimated. We believe that competent engineers — with comparable experience and information
relating to the properties under investigation — who are apprised of this fact, will
independently estimate proved reserve volumes that are similar. Supplementally, affirm to us
that you and your third party engineers employ these views. Address whether your “Improved
training regarding SEC guidelines for booking proved reserves” (page 196) encompasses these
concepts. If you are unable to affirm, support your position.

     Response:

     The El Paso Production Company Reserve Reporting Manual describes the methods and procedures
we employ in estimating and reporting proved reserves. All engineers directly involved in
estimating and reporting reserves are responsible for adhering to the procedures and guidelines set
forth in the manual. In addition, our independent reserve engineer has been instructed to follow
the SEC guidelines in their estimation process of proved reserves.

Mr. H. Christopher Owings

February 09, 2005

Page 6

     The manual strictly prescribes that proved reserves be estimated in accordance with SEC rules
and regulations, and the standard of “reasonable certainty” be applied to proved reserve estimates.
To provide further clarification on “reasonable certainty”, the manual includes supplemental
guidance published by the SEC, which states that in cases where “there is little supporting data
for decline rates, recovery factors, reservoir drive mechanisms etc., a conservative approach is
appropriate until there is enough supporting data to justify the use of more liberal parameters for
the estimation of proved reserves. The concept of reasonable certainty implies that, as more
technical data becomes available, a positive, or upward, revision is much more likely than a
negative, or downward, revision.”

     We believe that the additional controls and procedures described in response #2 and included
in our Reserve Reporting Manual demonstrate that we have adopted policies and procedures to ensure
that we utilize the concept of “reasonable certainty” in our estimates of proved reserves disclosed
in our public documents.

10-28-04 8-K

    4.
    We note your third quarter, 2004 U.S. production decline to 738 MMCFE/day from 801 MMCFE/day
in the second quarter. Supplementally, discuss the principal drilling and production results
that contributed to this decrease. Address your production enhancement plans for the fourth
quarter.

     Response:

     The decline in domestic production from the second quarter to the third quarter of 2004 is
attributable to a combination of natural declines of existing wells and a reduction in the level of
drilling activity that had previously resulted in supporting production levels, primarily in the
Texas Gulf Coast and offshore Gulf of Mexico regions. The following is a list of wells/fields that
experienced the largest declines in production over the period:

    •
    Texas Gulf Coast — Fitzhenry #1 (-15 MMcfe/d)

This well was drilled in the first quarter and produced at a consistent rate of 50 MMcf/d
(gross) during the second quarter. During the third quarter the production began declining
naturally due to pressure depletion.

    •
    South Texas — Samano, Monte Christo, and Jeffress fields (combined -24 MMcfe/d)

Drilling activity significantly dropped in 2004 in these three fields. New wells drilled in
late 2003 and early 2004, while beginning at high production rates, began exhibiting their
characteristically steep initial decline rates during the second and third quarters. In the
past, high levels of drilling activity in the area helped offset these declines.

    •
    Offshore GOM — West Delta Block 136 (-11 MMcfe/d)

The A-1 well was producing at 20 MMcfe/d (gross) until it started producing water and then
watered out in the early part of the third quarter.

    •
    Offshore GOM — South Timbalier Block 212 (-6.2 MMcfe/d)

Both producing wells on this block, C-1 and C-2, began producing water, which significantly
impacted gas production during the third quarter.

Mr. H. Christopher Owings

February 09, 2005

Page 7

    •
    Offshore GOM — South Timbalier Block 204 (-8 MMcfe/d)

Production from this block has been on a natural decline of approximately 50 percent
annually, since 2002.

     During the first quarter of 2004, we experienced disappointing drilling results. As a
result, our new management team significantly reduced our drilling activities to institute a new,
more rigorous, risk analysis process. This new standardized program was designed to emphasize
strict capital discipline. After we instituted the new, more rigorous, risk analysis process, we
increased our domestic drilling activities in the third quarter of 2004. Our fourth quarter 2004
daily equivalent production of 779 MMcfe/day (of which 717 MMcfe/day was domestic) brought our
year-to-date equivalent production to 829 MMcfe/day, which met the low end of the guidance that we
provided to the market in our June 2004 investor presentation.

10-K

Restatement Methodologies, page 100

    5.
    We note your response 3. Supplementally, with a view towards possible disclosure, submit to
us your restated proved reserves for 1998 and 1999 with a summary of the “reserve over
production ratio” calculations you used.

     Response:

     The restated proved reserves for year end 1998 and 1999 are as follows:

    1998

    1999

    Gas (MMcf)

    1,798,606

    2,192,879

    Oil (MBbl)

    37,488

    44,781

    NGL (MBbl)

    5,916

    10,859

    Total MMcfe*

    2,059,040

    2,526,719

    *

    In calculating equivalents, we use a generally recognized standard in which one Bbl of oil
is equal to six Mcf of natural gas.

     The calculation sheets for determining these reserve estimates are attached as Exhibits 1 and
2. Because of limited quarterly reserve details available for this time period, the basic
methodology involved using the results of the restated 12/31/2000 reserves and cash flows along
with the production and commodity price for each prior quarter. This information and data was then
used to restate the reserves and present value for