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EP 06-08-2005 Correspondence

      Lisa
      A. Stewart

      President

      Production and
      Nonregulated Business

      Production

VIA UPS
NEXT-DAY

March 23,
2005

Mr. Ron
Winfrey

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

Dear
Ron,

Per our discussion
on March 22, 2005, please find enclosed a copy of El Paso’s Reserve Reporting
Manual.

Our response to
your question regarding footnote 1 to the first table on our February 22, 2005
press release is as follows:

The reconciliation
of our proved reserves from December 31, 2003 to December 31, 2004, excluded
from the beginning balance the proved reserves related to certain of our
international natural gas and oil operations that we began treating as
discontinued operations in our financial statements in the second quarter of
2004. The decision to treat these operations as discontinued operations was
based on management’s decision to exit these countries as part of El Paso’s long-term
strategy.

The proved reserves
excluded from the December 31, 2003 beginning balance were as
follows:

       Bcfe

      Canada

      115.2

      Indonesia

      41.0

      Hungary

      4.4

      Total

      160.6

The proved reserves
in Canada were sold in the first quarter of 2004, while the Indonesia proved
reserves were sold in the third quarter of 2004. We are currently in
negotiations to sell our proved reserves in Hungary.

El Paso
Production

1001 Louisiana
Street    Houston, Texas  77002

PO
Box 2511    Houton, Texas  77252.2511

tel
713.420.3775    fax 713.420.7063

Ron
Winfrey

March 23,
2005

Page two of
two

Beginning with our
June 30, 2004 quarterly report on Form 10-Q, we began separately reporting the
results of these operations as discontinued operations in accordance with the
provisions of FASB Statement No. 144. As a result, we adjusted the historical
periods presented in our second and third quarter 2004 Form 10-Q to
appropriately segregate our continuing and discontinued operations as is
required by that standard. In our 2004 Form 10-K, we will also be required to
segregate all periods between our continuing and discontinued operations, and we
will exclude the discontinued operations from our Supplemental Natural Gas and
Oil Operations disclosures.

Please let me know
if you have additional questions.

Sincerely,

/s/ Lisa A.
Stewart

Lisa A.
Stewart

LAS/pk

EL PASO
PRODUCTION

COMPANY

RESERVE

REPORTING

MANUAL

September
2004

Revised:
9/29/2004

CONTENTS

      CONTENTS

      1

      EXECUTIVE
      SUMMARY

      3

      POLICY

      4

      ROLES
      AND RESPONSIBILITIES

      5

      RESERVE
      DEFINITIONS

      6

      RESERVE
      DETRMINATION METHODS

      13

      RESERVE
      REPORTING PROCEDURES

      16

      APPENDIX
      A - SEC REGULATION S-X RULE 4-10

      APPENDIX
      B - SPE PROFESSIONAL QUALIFICATIONS OF RESERVE
      ESTIMATORS

      APPENDIX
      C - SEC INTERPRETIVE GUIDANCE

EXECUTIVE
SUMMARY

The following
document has been prepared for the use of the El Paso Production Company (EPPC)
staff, management and officers. It is intended to document the policies and
procedures of the corporation in connection with the estimation of proved
reserves for the purpose of financial reporting.

The objectives of
the documentation are to ensure consistent and correct application of the
Securities and Exchange Commission (SEC) regulations governing this aspect of
financial reporting, and to clarify the roles and responsibilities of the
parties involved in the reserve estimation and reporting process.

Please note that
the Securities Act of 1933 subjects to potential civil liability every expert
who, with his or her consent, has been named as having prepared or certified any
part of the registration statement, or as having prepared or certified any
report or valuation used in connection with the registration statement. These
experts include accountants, attorneys, engineers or appraisers.

This document makes
frequent reference to Securities and Exchange Commission Regulation S-X Rule
4-10 (see Appendix A). Users of this manual are encouraged to read the rule
thoroughly, as it is the only relevant rule regarding reserves definitions in
connection with United States financial reporting. Reserves definitions
promulgated by other non-governmental organizations, such as the Society of
Petroleum Engineers, American Petroleum Institute, World Petroleum Congress,
etc. are very similar in most respects to the SEC definitions, but differ in
subtle (yet important) ways. They are not recognized by the SEC for financial
reporting purposes, so a discussion of them has been intentionally
omitted.

POLICY

EPPC’s reserve
reporting policy is to maintain its hydrocarbon reserve base to accurately
reflect its value in accordance with industry and regulatory definitions and
guidelines. The Company’s reserve estimates should be supported with respect to
volume, categorization, production rate and value by well-documented engineering
and geological data.

Reserves should
reflect the best estimates possible based on all available relevant data. When
judgment is required by the engineer preparing the estimate, the judgment should
be supported by sound engineering principles and supplemented with the
experience of the individual.

EPPC should strive
to book reserves at the earliest date possible while conforming to the
disclosure and financial reporting requirements of the Securities and Exchange
Commission (SEC). Therefore,

    (1)

      Reserves will
      be categorized and calculated consistently and accurately in accordance
      with the definitions and requirements of the Securities and Exchange
      Commission Regulation SX, Rule 4-10.

    (2)

      Reserve
      calculations and categorizations will be properly documented, retained in
      an organized manner and available for
review.

    (3)

      Reserves and
      reserve changes will be maintained and presented in a manner suitable for
      management review, performance measurement and external
      reporting.

ROLES AND
RESPONSIBILITIES

Manager -
Reserve Engineering Evaluation (REE)

Manager of REE is
responsible for reviewing and approving the proven reserves and is also
responsible for insuring compliance with SEC guidelines prior to submittal to
senior management of EPPC.

The Manager of REE
is also responsible for the following items, with respect to reserve
reporting:

Standardization

    1)

      Standardize
      use of Aries (reserve forecasting and economic software licensed by
      Landmark Graphics) for all reserve
reporting.

    2)

      Ensure
      consistency in Aries database structure.

    3)

      Obtain
      standard pricing assumptions.

Training

    1)

      Provide
      documentation and training regarding SEC Proved Reserves Definitions to
      all engineers, management and officers involved in the estimation review
      and approval of proved reserves.

    2)

      Maintain
      training records.

Reporting

    1)

      Proved
      reserve and discounted future net cash flow estimates to the Financial
      Reporting department for inclusion in SEC
disclosures.

    2)

      Proved
      reserve and discounted future net cash flow estimates to certain banks as
      part of loan covenants or other structured financial
      arrangements.

    3)

      Proved
      reserve estimates for Energy Information Agency
  disclosure.

    4)

      Quarterly and
      Annual Consolidated Reserve Reports for internal
    management.

    5)

      Monthly
      reporting of new well reserves for the EPPC Capital Management
      System.

    6)

      Ad hoc
      reports as needed.

Review and
Monitoring

    1)

      Quarterly
      review of reserve estimates prepared by REE engineering staff.

    2)

      Review
      documentation and work processes associated with the proved reserve
      estimation process. This includes engineering files, notes, and databases.

Auditing

    1)

      Coordinate
      annual third-party reserve review process.

    2)

      Select major
      properties to be reviewed by third-party reserve company to ensure
      representative coverage of company reserve
base.

Reservoir
Engineering Evaluations Staff

The REE engineering
staff is responsible and accountable for the engineering accuracy of the
Company’s proved reserves estimates. They must ensure that all reserves are
estimated consistently with the SEC rules and sound engineering practice, that
documentation to support the reserves estimates is sufficient and complete, and
is organized and stored in a secured site within the REE department. Each
engineer will monitor and make necessary revisions for the wells and fields
within their area of responsibility. All fields will be reviewed at least
annually.

The REE engineers
are responsible for creating and entering into the Aries SEC reserves database
an economic case which describes the expected production characteristics of each
proved wellbore completion (producing, behind pipe and undeveloped). This
includes expected future production and ultimate recovery, capital and
abandonment costs and timing; operating costs and taxes (including applicable
tax credits and abatements); ownership interests and reversions; and price
deducts from NYMEX markers.

The REE engineers
should have a level of training and experience that meets the Professional
Qualifications of Reserve Estimators and Reserve Auditors as stipulated by the
Society of Petroleum Engineers of AIME in its Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserve Information (see Appendix B).

Division
Reservoir Engineering Staff

The reservoir
engineering staff of each division of EPPC is responsible for providing all
technical (engineering and geologic) data required by the REE staff to properly
evaluate reserves for that division. They are expected to inform the REE staff
of new wells or completions, significant performance deviations in existing
completions, and any other changes in operating conditions, in a timely
manner.

Director -
Financial Accounting

The Financial
Reporting department is responsible for preparing and submitting all SEC
disclosures relating to Oil and Gas Operations including -

    1)

      Capitalized
      Costs

    2)

      Net
      quantities of proved reserves

    3)

      Results of
      Operations

    4)

      Standardized
      Measure of discounted Future Net Cash Flows (SFAS 69
      disclosure)

    5)

      Ceiling
      Test

    6)

      Asset
      Retirement Obligations (SFAS 143
disclosure)

RESERVES
DEFINITIONS

Proved
Reserves

Proved reserves are
quantities of hydrocarbons which are anticipated to be commercially recovered
from known accumulations in the future. Proved reserves have six
characteristics. They are 1) estimated quantities, 2) of oil, gas, and natural
gas liquids, that are 3) recoverable, 4) in future years, 5) from known
reservoirs, 6) under existing economic and operating conditions. Each of these
is discussed below.

Items 3-5 are to be
demonstrated by engineering and geological data with “reasonable certainty.” The
SEC does not define the term “reasonable certainty”. However, interpretive
guidance released by the SEC in the late 1990’s (see Appendix C) can be used as
a guide when booking reserves.

“Estimated
quantities”

Estimation of
reserves is done under conditions of uncertainty. The method of estimation is
called “deterministic” if a single best estimate of reserves is made based on
known geological, engineering, and economic data. The method of estimation is
called “probabilistic” when the known geological, engineering and economic data
are used to generate a range of estimates and their associated probabilities.
Although probabilistic methods are used for many analyses, the SEC currently
does not recognize probabilistic methods as acceptable estimations of proved
reserves. Therefore, proved reserve estimates for financial reporting and
disclosure purposes should be done using the deterministic method, incorporate
known parameters, and comply with the requirement of “reasonable certainty” of
recovery.

“Oil, gas and
natural gas liquids”

Crude
oil is defined as a
mixture of hydrocarbons that exists in the liquid phase in natural underground
reservoirs and remains liquid at atmospheric pressure and 60 degrees Fahrenheit
after passing through surface separation facilities. Crude oil is reported in
barrels of 42 US gallons at atmospheric pressure and 60 degrees Fahrenheit.
Volumes reported as crude oil include:

      A)

      Liquids
      technically defined as crude oil, and

      B)

      Small amounts
      of hydrocarbons that existed in the gaseous phase in natural underground
      reservoirs but which are liquid at atmospheric pressure and 60 degrees
      Fahrenheit after being recovered from natural gas wells or from oil well
      (casinghead) gas in lease separators. These reserves are technically
      “condensate”; however, they are generally commingled with the crude stream
      and it is not practical to measure and report their volumes separately.

Natural
gas is a mixture of
hydrocarbons and impurities that exists either in the gaseous phase or in
solution with crude oil in natural underground reservoirs. Natural gas may be
classified as follows:

      A)

      associated
      gas - commonly known as gas-cap gas, it overlies and is in contact with
      crude oil in the reservoir.

      B)

      dissolved gas
      - dissolved in crude oil in the reservoir.

      C)

      non-associated
      gas - in reservoirs that do not contain significant quantities of crude
      oil.

Natural gas volumes
are reported in thousands of cubic feet (MCF) at the pressure and temperature
bases adopted by the respective applicable regulatory agency. All agencies use a
temperature base of 60 degrees Fahrenheit and a pressure base that varies from
14.65 psig to 15.025 psig. The appropriate pressure base for a given state or
area should be verified with the appropriate regulatory agency.

Natural gas
processed in an NGL extraction facility in which the company has an in-kind
right to the liquid product is reported on a dry gas (residue) basis. All other
gas is reported on a wet (separator) gas basis.

Gas reserves
include volumes that are expected to be sold or used in facilities as part of
the production activity. Natural gas reserves will be reduced to reflect
shrinkage due to processing.

Natural gas
liquids are hydrocarbons
that are not removable from the gas stream by mechanical separation and are
generally not liquids at room temperature, such as ethane and propane. In cases
where these liquids are to be extracted, they should be reported net of volumes
retained by the plant as a processing fee. If the plant is owned fully or in
part by the company, then the portion of plant liquids recovered from the
company’s share of the gas that is attributable to its ownership in the plant
should also be included as reserves.

“Recoverable”

In general,
reserves are considered recoverable if actual production or conclusive formation
tests support the commercial producibility of the reservoir. In certain cases,
reserves may be deemed “recoverable” on the basis of well logs and/or core
analysis that indicate the subject reservoir is hydrocarbon-bearing and is
analogous to reservoirs in the same area that are producing or have demonstrated
the ability to produce on formation tests.

“Future”

Reserves that have
already been produced are not part of proved reserves. This includes oil in
storage or transit; however, gas that has been reinjected for pressure
maintenance may be considered proved if it