10-K

                  SECURITIES AND EXCHANGE COMMISSION
                        Washington, D.C. 20549

                               Form 10-K

x    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
     SECURITIES EXCHANGE ACT OF 1934

              For the fiscal year ended December 31, 2003

     TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
     SECURITIES EXCHANGE ACT OF 1934

                    Commission file number: 1-9743

                          EOG RESOURCES, INC.
        (Exact name of registrant as specified in its charter)

            Delaware                          47-0684736
  (State or other jurisdiction    (I.R.S. Employer Identification No.)
of incorporation or organization)

        333 Clay Street, Suite 4200, Houston, Texas 77002-7361
        (Address of principal executive offices)    (zip code)

   Registrant's telephone number, including area code:  713-651-7000

      Securities registered pursuant to Section 12(b) of the Act:

      Title of each class        Name of each exchange on which registered

  Common Stock, $.01 par value            New York Stock Exchange
Preferred Share Purchase Rights           New York Stock Exchange

      Securities registered pursuant to Section 12(g) of the Act:

                                 None.

     Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90
days.  Yes x  No

     Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K  .

     Indicate by check mark whether the registrant is an accelerated
filer (as defined in Rule 12b-2 of the Act).  Yes x  No

     State the aggregate market value of the voting and non-voting
common equity held by non-affiliates computed by reference to the
price at which the common equity was last sold, or the average bid and
asked price of such common equity, as of March 8, 2004, and as of the
last business day of the registrant's most recently completed second
fiscal quarter.  Common Stock aggregate market value held by non-
affiliates as of March 8, 2004: $5,317,400,876, and as of June 30, 2003:
$4,806,502,591.

     Indicate the number of shares outstanding of each of the
registrant's classes of common stock, as of the latest practicable
date.  Class: Common Stock, par value $0.01 per share, on March 8,
2004, Shares Outstanding: 116,252,752.

     Documents incorporated by reference.  Portions of the following
documents are incorporated by reference into the indicated parts of
this report:  Current Report on Form 8-K filed February 24, 2004 -
Part I, II and IV; and Proxy Statement for the May 4, 2004 Annual
Meeting of Shareholders to be filed within 120 days after December 31,
2003 (Proxy Statement) - Part III.



                           TABLE OF CONTENTS
                                                                    Page
                                PART I

Item 1.  Business                                                     1
          General                                                     1
          Business Segments                                           1
          Exploration and Production                                  1
          Marketing                                                   5
          Wellhead Volumes and Prices, and Lease and Well Expenses    6
          Competition                                                 6
          Regulation                                                  7
          Enron Corp. Bankruptcy                                     10
          Other Matters                                              10
          Current Executive Officers of the Registrant               12

Item 2.  Properties
          Oil and Gas Exploration and Production Properties and
           Reserves                                                  13

Item 3.  Legal Proceedings                                           16

Item 4.  Submission of Matters to a Vote of Security Holders         16

                                PART II

Item 5.  Market for Registrant's Common Equity and Related
          Shareholder Matters                                        16

Item 6.  Selected Financial Data                                     17

Item 7.  Management's Discussion and Analysis of Financial
          Condition and Results of Operations                        18

Item 7A. Quantitative and Qualitative Disclosures About Market Risk  19

Item 8.  Financial Statements and Supplementary Data                 19

Item 9.  Changes in and Disagreements with Accountants on
          Accounting and Financial Disclosure                        19

Item 9A. Controls and Procedures                                     19

                               PART III

Item 10. Directors and Executive Officers of the Registrant          19

Item 11. Executive Compensation                                      19

Item 12. Security Ownership of Certain Beneficial Owners and
          Management                                                 20

Item 13. Certain Relationships and Related Transactions              20

Item 14. Principal Accounting Fees and Services                      20

                                PART IV

Item 15. Financial Statements and Financial Statement Schedule,
          Exhibits and Reports on Form 8-K                           20

                              SIGNATURES



                             PART I

ITEM 1.  Business

General

     EOG Resources, Inc. (EOG), a Delaware corporation organized
in 1985, together with its subsidiaries, explores for, develops,
produces and markets natural gas and crude oil primarily in major
producing basins in the United States of America, as well as in
Canada and Trinidad and, to a lesser extent, selected other
international areas, including the United Kingdom North Sea.
EOG's principal producing areas are further described under
"Exploration and Production" below.  EOG's website address is
http://www.eogresources.com.  EOG's Annual Report on Form 10-K,
Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and
all amendments to those reports are made available, free of
charge, through its website as soon as reasonably practicable
after such reports have been filed with or furnished to the
Securities and Exchange Commission (SEC).

     At December 31, 2003, EOG's total estimated net proved
reserves were 5,216 billion cubic feet equivalent (Bcfe), of
which estimated net proved natural gas reserves were 4,645
billion cubic feet (Bcf) and estimated net proved crude oil,
condensate and natural gas liquids reserves were 95 million
barrels (MMBbl) (see "Supplemental Information to Consolidated
Financial Statements" beginning on page 42 of EOG's Current
Report on Form 8-K filed with the SEC on February 24, 2004,
which included financial statements of EOG for the fiscal year
ended December 31, 2003 and is attached hereto as Exhibit 99.1
(Form 8-K filed on February 24, 2004)). At such date,
approximately 49% of EOG's reserves (on a natural gas equivalent
basis) were located in the United States, 27% in Trinidad, 23%
in Canada and 1% in the United Kingdom North Sea.  As of December
31, 2003, EOG employed approximately 1,100 persons, including
foreign national employees.

     EOG's business strategy is to maximize the rate of return on
investment of capital by controlling all operating and capital
costs.  This strategy is intended to enhance the generation of
cash flow and earnings from each unit of production on a cost-
effective basis.  EOG focuses its drilling activity toward
natural gas deliverability in addition to natural gas reserve
replacement and to a lesser extent crude oil exploitation and
exploration.  EOG focuses on the cost-effective utilization of
advances in technology associated with the gathering, processing
and interpretation of three-dimensional seismic data, the
development of reservoir simulation models, the use of new and/or
improved drill bits, mud motors and mud additives, and formation
logging techniques and reservoir fracturing methods. These
advanced technologies are used, as appropriate, throughout EOG to
reduce the risks associated with all aspects of oil and gas
reserve exploration, exploitation and development.  EOG
implements its strategy by emphasizing the drilling of internally
generated prospects in order to find and develop low cost
reserves.  EOG also makes select tactical acquisitions that
result in additional economies of scale or land positions with
significant additional prospects.  Maintaining the lowest
possible operating cost structure that is consistent with prudent
and safe operations is also an important goal in the
implementation of EOG's strategy.

     With respect to information on EOG's working interest in
wells or acreage, "net" oil and gas wells or acreage are
determined by multiplying "gross" oil and gas wells or acreage by
EOG's working interest in the wells or acreage.

Business Segments

     EOG's operations are all natural gas and crude oil
exploration and production related.

Exploration and Production

  North American Operations

     EOG's North American operations are focused on most of the
productive basins in the United States and Canada, utilizing
personnel who have developed experience and expertise unique to
the geology of that region, thereby leveraging EOG's knowledge
and cost structure into enhanced returns on invested capital.

     At December 31, 2003, 87% of EOG's net proved North American
reserves (on a natural gas equivalent basis) were natural gas and
13% were crude oil, condensate and natural gas liquids.  A
substantial portion of EOG's North American natural gas reserves
are in long-lived fields with well-established production
histories. EOG believes that opportunities exist to increase
production in and around many of these fields through continued
development and application of new technology.  EOG will also
continue an active exploration program, designed to extend fields
and add new trends to its broad portfolio of North American
plays.  The following is a summary of significant developments
during 2003 and certain 2004 plans for EOG's North American
operations.

     United States.  During 2003, EOG continued its successful
Permian Basin horizontal drilling programs in the Devonian play
of West Texas and the Bone Spring play of Southeast New Mexico.
Improved horizontal technology continues to lower drilling and
completion costs along with increasing the production rates and
reserves of new wells.  In 2003, EOG initiated horizontal
drilling operations in the Barnett Shale play of the Fort Worth
Basin.  EOG drilled approximately 58 net wells in the Permian
and Fort Worth basins during 2003 and increased net average daily
production to approximately 100 million cubic feet per day (MMcfd)
of natural gas and 7.8 thousand barrels per day (MBbld) of crude oil,
condensate and natural gas liquids.  This represents a 7%
increase in natural gas and a 21% increase in liquids production
from 2002 levels.  EOG plans an active year of drilling and
continued production growth in 2004.

     EOG increased drilling activity in the Rocky Mountains area
during 2003, drilling approximately 77 net wells.  The majority
of the activity continues to be located in its key producing
areas of Big Piney, Wyoming - LaBarge Platform and Vernal, Utah -
Uintah/Chapita/Natural Buttes, and a new area in Richland County,
Montana.  EOG is developing a new Bakken Horizontal play in
Richland County, Montana, and expects to drill approximately 13
net wells in 2004.  During 2003, the net average daily production
for the Rocky Mountains area was approximately 117 MMcfd of
natural gas and 5.5 MBbld of crude oil, condensate and natural
gas liquids.  EOG expects to increase drilling in the Uintah
Basin, in both the Deep Mesaverde and Wasatch, and in the
Williston Basin, Bakken horizontal oil play.

     The Mid-Continent net average daily production during 2003 was
approximately 79 MMcfd of natural gas and 1.5 MBbld of crude oil
and condensate.  Natural gas production for 2003 increased 12%
over 2002.  In 2003, EOG drilled 133 net wells in two core
areas:  the Hugoton-Deep play in the Oklahoma Panhandle and the
Cleveland Horizontal play in the Texas Panhandle.  The Hugoton
Deep program will continue at a level comparable to 2003, while
an increase in the Cleveland Horizontal play program is expected.
EOG has expanded its Cleveland position over the last year to
more than 64,000 net acres and expects to drill over 50 Cleveland
Horizontal wells in 2004.  The average Cleveland gross well has
an initial rate of 1.5 MMcfd and an estimated ultimate recovery
of 1.25 Bcfe.  In addition to these two core areas, EOG will
remain active in the exploration of other plays throughout
Oklahoma, Kansas, and the Texas Panhandle.

    The Upper Gulf Coast continues to be a significant producing
and exploration area for EOG.  New operating areas were added in
East Texas and North Louisiana through exploration and property
trades during 2003. EOG drilled approximately 68 net wells in the
Upper Gulf Coast area during 2003.  Net average production for
the year was 96 MMcfd of natural gas and 3.1 MBbld of crude oil,
condensate and natural gas liquids.  In 2004, EOG will continue
to develop growth opportunities in East Texas, North Louisiana,
and Mississippi, and will test several high potential prospects
in the Lower Gulf Coast areas of Texas and South Louisiana.

    EOG had another active year in South Texas during 2003,
drilling or participating in approximately 74 net wells.  The
area averaged net production of approximately 169 MMcfd of
natural gas, a 5% increase over 2002, and 2.2 MBbld of crude oil,
condensate and natural gas liquids.  Several second half 2003
discoveries in Lavaca and San Patricio Counties resulted in
additional natural gas and liquids production of approximately
30 MMcfd and 3.5 MBbld, net, respectively.  There was also
continued success and growth in the Roleta and Lobo trends with
key discoveries in Webb and Zapata Counties. EOG had successful
drilling programs in the Wilcox in Duval and Lavaca Counties,
the Frio in Nueces, San Patricio and Matagorda Counties, and the
Olmos in Webb County.  EOG was successful in adding to its current
leasehold position in 2003, and this will provide additional
opportunities for its Roleta, Lobo, Frio, Wilcox and Olmos
programs in 2004.

     In 2003, EOG drilled over 200 net shallow Devonian natural
gas wells in the Appalachian Basins.  Net production increased
throughout the year from 20 MMcfd in January to over 25 MMcfd of
natural gas in December, averaging approximately 22 MMcfd for
the year.  While shallow drilling will continue to play an
important role in these areas in 2004, EOG will continue to
pursue higher impact plays such as the Oriskany and Trenton Black
River.

     In the Gulf of Mexico, EOG focuses on offshore Texas and
Louisiana.  Three fields, South Timbalier 156, Eugene Island 135
and Matagorda Island 623, account for over sixty percent of EOG's
Gulf of Mexico net production.  During 2003, total net production
averaged approximately 55 MMcfd of natural gas and 1.3 MBbld of
crude oil, condensate and natural gas liquids.  In 2003, EOG
drilled or participated in seven gross wells, including a
significant exploration discovery at Matagorda Island 685.  EOG
operates and has a 60% working interest in this estimated 27 Bcfe
discovery, which is expected to commence sales in the second
quarter of 2004.  The South Timbalier 156 field, a 2002
discovery, commenced first sales in October 2003 with initial
gross production of 13 MMcfd of natural gas and 4.4 MBbld of
condensate.  In 2004, EOG plans a similar level of drilling
concentrated primarily on the Gulf of Mexico shelf, with limited
deepwater activity possible.

     At December 31, 2003, EOG held approximately 2,424,900 net
undeveloped acres in the United States.

     Canada.  EOG conducts operations through its Canadian
subsidiary, EOG Resources Canada Inc. (EOGRC), from offices in
Calgary, Alberta.  During 2003, EOGRC was again successful with
its shallow natural gas strategy in Western Canada, drilling a
record 1,034 net wells and increasing its reserve base and
production potential.  Strategic property acquisitions were also
utilized to expand the shallow gas platform area in Southeast
Alberta.  On October 1, 2003, EOGRC closed the largest asset
purchase of primarily natural gas properties in EOG's history for
approximately US $320 million.  These properties are essentially
adjacent to existing EOGRC operations or are properties in which
EOGRC already has a working interest.  In late December 2003, EOGRC
closed another property acquisition for US $46 million.  EOGRC's
net production during 2003 averaged approximately 165 MMcfd of
natural gas, as compared to 154 MMcfd during 2002.  Crude oil,
condensate and natural gas liquids averaged approximately 3.0
MBbld, net, in 2003.  Additions from strategic property
acquisitions and new wells coming on stream late in the year
increased fourth quarter 2003 net production to 196 MMcfd of
natural gas and 3.4 MBbld of crude oil, condensate and natural
gas liquids. Key producing areas in the Western Canadian
Sedimentary Basin were the Southeast Alberta/Southwest
Saskatchewan shallow natural gas trend and Grande Prairie -
Wapiti.  EOGRC expects to increase its shallow natural gas drilling
on its expanded Southeast Alberta platform, to initiate coalbed
methane development at Twining, and to participate in several
higher impact exploratory and unconventional tests during 2004.

     At December 31, 2003, EOG held approximately 1,082,700 net
undeveloped acres in Canada.

  Outside North America Operations

     EOG has operations in offshore Trinidad and the United
Kingdom North Sea, and is evaluating additional exploration,
exploitation and development opportunities in the United Kingdom
and other international areas.

     Trinidad.  In November 1992, EOG, through its subsidiary,
EOG Resources Trinidad Limited (EOGRT) was awarded a 95% working
interest concession in the South East Coast Consortium (SECC)
Block offshore Trinidad, encompassing three undeveloped fields -
the Kiskadee, Ibis and Oilbird fields.  The Kiskadee and Ibis
fields have since been developed and are being produced.  The
Oilbird field was successfully appraised by the drilling of two
wells in the fourth quarter of 2001 and one well in the fourth
quarter of 2003.  The Oilbird 2 well encountered 380 feet of net
pay and the Oilbird 3 well encountered 290 feet of net pay.  The
Oilbird 3X well, which was drilled during 2003, encountered 64
feet of net pay in the targeted sand.  EOGRT expects to develop
the Oilbird field over the next few years and place it on
production in early 2007.  EOGRT discovered a new field with the
drilling of the Parula #1 wildcat well in 2002, which encountered
370 feet of net pay.  This field was brought on stream in
February 2004.  The term of the license covering the SECC Block
expires in December 2029.

     In July 1996, EOG, through its subsidiary, EOG Resources
Trinidad-U(a) Block Limited (EOGUA), signed a production sharing
contract with the Government of Trinidad and Tobago for the
Modified U(a) Block where EOG holds a 100% working interest. EOG
drilled its first commitment well, OA-1, on this block in 1998.
This well encountered over 500 feet of net pay. In the first
quarter of 2001, EOG drilled the OA-2 well which encountered 305
feet of net pay and increased gross proved reserves to a field
total of 870 Bcfe.  In September 2001, EOGUA set a platform and
jacket and first production began in the second quarter of 2002.

       Existing surplus processing and transportation capacity at the
Pelican field facilities owned and operated by a subsidiary of
EOGRT's partners in the SECC Block is being used to process and
transport much of EOGRT's natural gas production and all of its
condensate and crude oil production from the SECC and U(a) Blocks.


     In April 2002, EOG, through its subsidiary, EOG Resources
Trinidad LRL Unlimited, signed a production sharing contract with
the Government of Trinidad and Tobago for the Lower Reverse "L"
Block which is adjacent to the SECC Block.  EOG holds a 100%
working interest in the Lower Reverse "L" Block.  In the fourth
quarter of 2003, EOG drilled the first exploration well on this
block.  The well was determined to be uneconomical.

     In October 2002, EOG, through its subsidiary, EOG Resources
Trinidad-U(b) Block Unlimited, signed a production sharing
contract with the Government of Trinidad and Tobago for the
Modified U(b) Block which is also adjacent to the SECC Block.
EOG holds a 55% working interest in and operates the Modified
U(b) Block.  Primera Oil & Gas Ltd, a Trinidadian company, holds
the remaining 45% interest.

     At December 31, 2003, EOG held approximately 194,500 net
undeveloped acres in Trinidad.

     Natural gas from EOG's Trinidad operations is being sold to
the National Gas Company of Trinidad and Tobago (NGC) under the
following arrangements:

     . Under the first take-or-pay contract, which expires in 2009,
       natural gas is delivered to NGC for resale to Trinidad local
       markets.  During 2003, EOG delivered net average production of
       104 MMcfd of natural gas under this agreement.

     . Under the second take-or-pay contract, which expires in
       2017, EOG delivers to NGC approximately 60 MMcfd, gross,
       of natural gas which is resold to an anhydrous ammonia
       plant owned by Caribbean Nitrogen Company Limited (CNCL).
       Based on average 2003 prices, approximately 48 MMcfd of
       natural gas delivered to NGC was net to EOG in 2003.
       EOGRT owns an approximate 12% equity interest in CNCL, a
       Trinidadian company, which has constructed an ammonia plant in
       Pt. Lisas, Trinidad.  The other shareholders in CNCL are
       subsidiaries of Ferrostaal AG, Halliburton, Koch Industries, Inc.
       and CL Financial Ltd.  At December 31, 2003, EOGRT's investment
       in CNCL was approximately $14 million. CNCL commenced production
       in June 2002 and currently produces approximately 1,950 metric
       tons of ammonia daily.  At December 31, 2003, CNCL had a long-
       term debt balance of approximately $218 million, which is non-
       recourse to CNCL's shareholders.  As part of the financing for
       CNCL, the shareholders agreed to enter into a post-completion
       deficiency loan agreement with CNCL to fund the costs of
       operations, payment of principal and interest to the principal
       creditor and other cash deficiencies of CNCL up to $30 million,
       up to $4 million of which is to be provided by EOGRT.  The
       Shareholders' Agreement requires the consent of the holders of
       90% or more of the shares to take certain material actions.
       Accordingly, given its current level of equity ownership, EOGRT
       is able to exercise significant influence over the operating and
       financial policies of CNCL and therefore, EOG accounts for the
       investment using the equity method.  During 2003, EOG recognized
       equity income of $3.7 million from CNCL.

     . Under a fifteen-year take-or-pay contract, EOG is to supply
       approximately 60 MMcfd gross of natural gas to NGC.  This gas
       will be resold by NGC to an anhydrous ammonia plant that is
       currently under construction and is owned by Nitrogen 2000
       Unlimited (N2000).  EOG's subsidiary, EOG Resources NITRO2000
       Ltd. (EOGNitro2000), owns an approximate 23% equity interest
       in N2000 at February 29, 2004.  The other shareholders
       in N2000 are subsidiaries of Ferrostaal AG, Halliburton, Koch
       Industries, Inc. and CL Financial Ltd.  At December 31, 2003,
       EOGNitro2000's equity interest and investment in N2000 was
       approximately 27% and $20 million, respectively.  In February
       2004, a portion of EOGNitro2000's shareholdings was sold to one
       of the other shareholders.  The sale did not result in any gain
       or loss.  N2000 is constructing an ammonia plant in Trinidad, at
       an expected total cost of approximately $320 million, and is expected
       to commence production in the third quarter 2004.  At December
       31, 2003, N2000 had a long-term debt balance of approximately
       $172 million, which is non-recourse to N2000's shareholders.  As
       part of the loan agreement for the N2000 financing, affiliates of
       the shareholders have entered into a pre-completion deficiency
       loan agreement with N2000 to fund plant cost overruns up to $15
       million, up to $3 million of which is to be provided by the
       immediate parent company of EOGNitro2000.  Affiliates of the
       shareholders have also entered into a post-completion deficiency
       loan agreement with N2000 to fund the costs of operations, payment
       of principal and interest to the principal creditor and other
       cash deficiencies of N2000 up to $30 million, up to $7 million of
       which is to be provided by the immediate parent company of
       EOGNitro2000.  The Shareholders' Agreement requires the consent
       of the holders of 90% or more of the shares to take certain
       material actions.  Accordingly, given its current level of equity
       ownership, EOGNitro2000 is able to exercise significant influence
       over the operating and financial policies of N2000 and therefore,
       EOG accounts for the investment using the equity method.

     . Lastly, under a fifteen-year requirements natural gas contract,
       which was also recently signed, EOG will ultimately supply 87
       MMcfd, net, of natural gas to a methanol plant, based on current
       price and operating assumptions.  The plant is presently under
       construction and is expected to start up in mid-2005 with EOG
       supplying 67 MMcfd, net for the first four years of the contract.
       EOG has no equity investment in this plant.

     United Kingdom.  In 2003, EOG's subsidiary, EOG Resources
United Kingdom Limited (EOGUK), participated with other North Sea
partners in the drilling of three exploration wells, two of which
were commercial successes.  In 2002, EOGUK acquired a 25% non-
operating working interest in a portion of Block 49/16, located
in the Southern Gas Basin of the North Sea.  The first commercial
well, the 49/16-14Z, was drilled in the Southern Gas Basin
and temporarily abandoned in February 2003.  It encountered
approximately 106 Bcf gross of natural gas reserves in the
Rotliegendes formation, 26 Bcf net to EOGUK.  EOGUK and its
partners are, as of this date, drilling a development well 49/16-
VB from the Vampire platform.  In 2003, EOGUK acquired a 30% non-
operating working interest in a portion of Blocks 53/1 and 53/2.
These Blocks are also located in the Southern Gas Basin of the North
Sea.  EOGUK drilled and completed as a natural gas producer Well
53/2-11 in November 2003. The well encountered approximately 198
feet of net pay sands in the Rotliegendes formation, with gross
estimated natural gas reserves of 109 Bcf, or 33 Bcf, net to
EOGUK.

     At December 31, 2003, EOG held approximately 78,200 net
undeveloped acres in the United Kingdom.

     Other International.  EOG continues to evaluate other select
natural gas and crude oil opportunities outside North America
primarily by pursuing exploitation opportunities in countries
where indigenous natural gas and crude oil reserves have been
identified.

Marketing

     Wellhead Marketing.  EOG's North America wellhead natural
gas production is currently being sold on the spot market and
under long-term natural gas contracts at market-responsive
prices.  In many instances, the long-term contract prices closely
approximate the prices received for natural gas being sold on the
spot market.  Wellhead natural gas volumes from Trinidad are sold
under either a contract with a fixed price schedule with annual
escalations, or a contract that is price dependent on Caribbean
ammonia index prices.

     Substantially all of EOG's wellhead crude oil and condensate
is sold under various terms and arrangements at market-responsive
prices.

     During 2003, sales to subsidiaries of a major utility
company and subsidiaries of a major integrated oil and gas
company accounted for 12% and 10%, respectively, of EOG's oil and
gas revenues.  No other individual purchaser accounted for 10% or
more of EOG's oil and gas revenues for the same period. EOG does
not believe that the loss of any single purchaser will have a
material adverse effect on the financial condition or results of
operations of EOG.

     Other Marketing.  EOG Resources Marketing, Inc., a wholly
owned subsidiary of EOG, has purchased and constructed several
small gas gathering systems in order to facilitate its entry into
the gas gathering business on a limited basis.

Wellhead Volumes and Prices, and Lease and Well Expenses

     The following table sets forth certain information regarding
EOG's wellhead volumes of and average prices for natural gas per
thousand cubic feet (Mcf), wellhead volume of and average prices
for crude oil and condensate, and natural gas liquids per barrel
(Bbl), and average lease and well expenses per thousand cubic
feet equivalent (Mcfe - natural gas equivalents are determined
using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude
oil, condensate or natural gas liquids) delivered during each of
the three years in the period ended December 31, 2003.




                                                   Year Ended December 31,
                                                   2003     2002     2001
                                                          
 Natural Gas Volumes (MMcf per day)
  United States                                     638      635      680
  Canada                                            165      154      126
  Trinidad                                          152      135      115
    Total                                           955      924      921
 Crude Oil and Condensate Volumes (MBbl per day)
  United States                                    18.5     18.8     22.0
  Canada                                            2.3      2.1      1.7
  Trinidad                                          2.4      2.4      2.1
    Total                                          23.2     23.3     25.8
 Natural Gas Liquids Volumes (MBbl per day)
  United States                                     3.2      2.9      3.5
  Canada                                            0.6      0.8      0.5
    Total                                           3.8      3.7      4.0
 Average Natural Gas Prices ($/Mcf)
  United States                                  $ 5.06   $ 2.89   $ 4.26
  Canada                                           4.66     2.67     3.78
  Trinidad                                         1.35     1.20     1.22
    Composite                                      4.40     2.60     3.81
 Average Crude Oil and Condensate Prices ($/Bbl)
  United States                                  $30.24   $24.79   $25.06
  Canada                                          28.54    23.62    22.70
  Trinidad                                        28.88    23.58    24.14
    Composite                                     29.92    24.56    24.83
 Average Natural Gas Liquids Prices ($/Bbl)
  United States                                  $21.53   $14.76   $17.17
  Canada                                          19.13    11.17    15.05
    Composite                                     21.13    14.05    16.89
 Lease and Well Expenses ($/Mcfe)
  United States                                  $ 0.53   $ 0.45   $ 0.45
  Canada                                           0.82     0.72     0.62
  Trinidad                                         0.18     0.17     0.15
    Composite                                      0.52     0.45     0.44


Competition

     EOG competes for reserve acquisitions and exploration/exploitation
leases, licenses and concessions, frequently against companies with
substantially larger financial and other resources.  To the extent EOG's
exploration budget is lower than that of certain of its competitors,
EOG may be disadvantaged in effectively competing for certain reserves,
leases, licenses and concessions.  Competitive factors include
price, contract terms and quality of service, including pipeline
connection times and distribution efficiencies.  In addition, EOG
faces competition from other worldwide energy supplies, such as
liquefied natural gas imported into the United States from other
countries.

Regulation

     United States Regulation of Natural Gas and Crude Oil
Production.  Natural gas and crude oil production operations are
subject to various types of regulation, including regulation in
the United States by state and federal agencies.

     United States legislation affecting the oil and gas industry
is under constant review for amendment or expansion.  Also,
numerous departments and agencies, both federal and state, are
authorized by statute to issue and have issued rules and
regulations which, among other things, require permits for the
drilling of wells, regulate the spacing of wells, prevent the
waste of natural gas and liquid hydrocarbon resources through
proration and restrictions on flaring, require drilling bonds and
regulate environmental and safety matters.  The regulatory burden
on the oil and gas industry increases its cost of doing business
and, consequently, affects its profitability.

     A substantial portion of EOG's oil and gas leases in the Big
Piney area and in the Gulf of Mexico, as well as some in other
areas, are granted by the federal government and administered by
the Bureau of Land Management (BLM) and the Minerals Management
Service (MMS), both federal agencies.  Operations conducted by
EOG on federal oil and gas leases must comply with numerous
statutory and regulatory restrictions concerning the above and
other matters.  Certain operations must be conducted pursuant to
appropriate permits issued by the BLM and the MMS.

     BLM and MMS leases contain relatively standardized terms
requiring compliance with detailed regulations and, in the case
of offshore leases, orders pursuant to the Outer Continental
Shelf Lands Act (which are subject to change by the MMS). Such
offshore operations are subject to numerous regulatory
requirements, including the need for prior MMS approval for
exploration, development, and production plans, stringent
engineering and construction specifications applicable to
offshore production facilities, regulations restricting the
flaring or venting of production, and regulations governing the
plugging and abandonment of offshore wells and the removal of all
production facilities.  Under certain circumstances, the MMS may
require operations on federal leases to be suspended or
terminated. Any such suspension or termination could adversely
affect EOG's interests.

     The MMS amended the regulations governing the calculation of
royalties and the valuation of crude oil produced from federal
leases, effective June 1, 2000.  The new rules modified the
valuation procedures for both arm's-length and non-arm's-length
crude oil transactions.  For non-arm's length transactions, the
revised rules replace a familiar set of benchmarks (e.g., posted
prices, comparable sales) with an indexing system based on spot
prices at nearby market centers.  In addition, the revised rules
limit deductions on post-production transportation costs and
disallow altogether deductions for post-production marketing costs.
Together, these changes are expected to somewhat increase EOG's
royalty obligation.  Two industry trade association have sought
judicial review of the revised regulations but the MMS has
already proposed additional changes to the regulations, some of
which are beneficial to the industry.  EOG cannot predict what
effect the outcome of the pending litigation or the pending
rulemaking will be or what net effect, if any, it will have on
EOG's operations.  The revised regulations are expected to be
promulgated in April 2004 and effective in June 2004.

     In March 2000, a federal district court vacated MMS
regulations which sought to clarify the types of costs that are
deductible transportation costs for purposes of royalty valuation
of production sold off the lease.  In particular, MMS disallowed
deduction of costs associated with marketer fees, cash out and
other pipeline imbalance penalties, or long-term storage fees.
However, on appeal by the government, a federal court of appeals
in 2002 reversed a 2000 district court decision, reinstating MMS's
categorical disallowance of deductions for post-production marketing
costs, except for firm demand charges.  While this litigation was
directed at a gas transportation rule, the disallowance of marketing
costs applies to crude oil as well.  As in the still pending oil
valuation litigation, two trade associations brought the legal
challenge of the gas transportation rules; the trade associations'
petition seeking Supreme Court review of the court of appeals
decision was denied.

     Sales of crude oil, condensate and natural gas liquids by
EOG are made at unregulated market prices.

     The transportation and sale for resale of natural gas in
interstate commerce are regulated pursuant to the Natural Gas Act
of 1938 (NGA) and the Natural Gas Policy Act of 1978 (NGPA).
These statutes are administered by the Federal Energy Regulatory
Commission (FERC).  Effective January 1, 1993, the Natural Gas
Wellhead Decontrol Act of 1989 deregulated natural gas prices for
all "first sales" of natural gas, which includes all sales by EOG
of its own production.  All other sales of natural gas by EOG,
such as those of natural gas purchased from third parties, remain
jurisdictional sales subject to a blanket sales certificate under
the NGA, which has flexible terms and conditions.  Consequently,
all of EOG's sales of natural gas currently may be made at market
prices, subject to applicable contract provisions.  EOG's
jurisdictional sales, however, are subject to the future
possibility of greater federal oversight, including the
possibility that the FERC might prospectively impose more
restrictive conditions on such sales.

     Since 1985, the FERC has endeavored to enhance competition
in natural gas markets by making natural gas transportation more
accessible to natural gas buyers and sellers on an open and
nondiscriminatory basis.  These efforts culminated in Order No.
636 and various rehearing orders (Order No. 636), which mandated
a fundamental restructuring of interstate natural gas pipeline
sales and transportation services, including the "unbundling" by
interstate natural gas pipelines of the sales, transportation,
storage, and other components of their service, and to separately
state the rates for each unbundled service.  Order No. 636 does
not directly regulate EOG's activities, but has an indirect
effect because of its broad scope.  Order No. 636 has ended
interstate pipelines' traditional role as wholesalers of natural
gas, and substantially increased competition in natural gas
markets.  In spite of this uncertainty, Order No. 636 may enhance
EOG's ability to market and transport its natural gas production,
although it may also subject EOG to more restrictive pipeline
imbalance tolerances and greater penalties for violation of such
tolerances.  Order No. 636 led directly to the MMS gas transportation
regulations addressed above, which limit deductions for post-
production marketing costs and result in a somewhat expanded
royalty obligation.

     EOG owns, directly or indirectly, certain natural gas
pipelines that it believes meet the traditional tests the FERC
has used to establish a pipeline's status as a gatherer not
subject to FERC jurisdiction under the NGA.  State regulation of
gathering facilities generally includes various safety,
environmental, and in some circumstances, nondiscriminatory take
requirements, but does not generally entail rate regulation.
Natural gas gathering may receive greater regulatory scrutiny at
both the state and federal levels as a result of pipeline
restructuring under Order No. 636.  For example, the Texas
Railroad Commission has approved changes to its regulations
governing transportation and gathering services performed by
intrastate pipelines and gatherers, which prohibit such entities
from unduly discriminating in favor of their affiliates.  EOG's
gathering operations could be adversely affected should they be
subject in the future to the application of state or federal
regulation of rates and services.

     EOG's natural gas gathering operations also may be or become
subject to safety and operational regulations relating to the
design, installation, testing, construction, operation,
replacement, and management of facilities.  Additional rules and
legislation pertaining to these matters are considered or adopted
from time to time.  EOG cannot predict what effect, if any, such
legislation might have on its operations, but the industry could
be required to incur additional capital expenditures and
increased costs depending on future legislative and regulatory
changes.

     The FERC conducted a broad review of its transportation
regulations, including how they operate in conjunction with state
proposals for retail natural gas marketing restructuring, whether
to eliminate cost-of-service rates for short-term transportation,
whether to allocate all short-term capacity on the basis of
competitive auctions, and whether changes to its long-term
transportation policies may also be appropriate to alleviate a
market bias toward short-term contracts.  This review culminated
in part with the FERC's issuance of Order No. 637 on February 9,
2000.

     Order No. 637 revises the FERC's current regulatory
framework for purposes of improving the efficiency of the market
and providing captive pipeline customers with the opportunity to
reduce their cost of holding long-term pipeline capacity while
continuing to protect against the exercise of market power.
Order No. 637 revises FERC pricing policy by waiving price
ceilings for short-term released capacity for a two-year period
and permitting pipelines to file for peak/off-peak and term
differentiated rate structures.  Order No. 637 does not, however,
require the allocation of all short-term capacity on the basis of
competitive auctions - as had been proposed by the FERC.  Order
No. 637 adopts changes in regulations relating to scheduling
procedures, capacity segmentation and pipeline penalties to
improve the competitiveness and efficiency of the interstate
pipeline grid.  It also narrows pipeline customers' right of
first refusal to remove economic biases in the current rule,
while still protecting captive customers' ability to resubscribe
to long-term capacity.  Finally, it improves the FERC's reporting
requirements to provide more transparent pricing information and
permit more effective monitoring of the market.  Appeals of Order
No. 637 are pending court review.  EOG cannot predict what the
outcome of that review will be or what effect it will have on
EOG's operations.

     While Order No. 637, and any subsequent FERC action will
affect EOG only indirectly, the Order and related inquiries are
intended to further enhance competition in natural gas markets,
while maintaining adequate consumer protections.

     EOG cannot predict the effect that any of the aforementioned
orders or the challenges to such orders will ultimately have on
EOG's operations.  Additional proposals and proceedings that
might affect the natural gas industry are considered from time to
time by Congress, the FERC and the courts. EOG cannot predict
when or whether any such proposals or proceedings may become
effective.  It should also be noted that the natural gas industry
historically has been very heavily regulated; therefore, there is
no assurance that the less regulated approach currently being
pursued by the FERC will continue indefinitely.

     Environmental Regulation - United States.  Various federal,
state and local laws and regulations covering the discharge of
materials into the environment, or otherwise relating to the
protection of the environment, affect EOG's operations and costs
as a result of their effect on natural gas and crude oil
exploration, development and production operations and could
cause EOG to incur remediation or other corrective action costs
in connection with a release of regulated substances, including
crude oil, into the environment.  In addition, EOG has acquired
certain oil and gas properties from third parties whose actions
with respect to the management and disposal or release of
hydrocarbons or other wastes were not under EOG's control.  Under
environmental laws and regulations, EOG could be required to
remove or remediate wastes disposed of or released by prior
owners or operators.  In addition, EOG could be responsible under
environmental laws and regulations for oil and gas properties in
which EOG owns an interest but is not the operator.  Compliance
with such laws and regulations increases EOG's overall cost of
business, but has not had a material adverse effect on EOG's
operations or financial condition. It is not anticipated, based
on current laws and regulations, that EOG will be required in the
near future to expend amounts that are material in relation to
its total exploration and development expenditure program in
order to comply with environmental laws and regulations, but
inasmuch as such laws and regulations are frequently changed, EOG
is unable to predict the ultimate cost of compliance.  EOG also
could incur costs related to the clean up of sites to which it
sent regulated substances for disposal or to which it sent
equipment for cleaning, and for damages to natural resources or
other claims related to releases of regulated substances at such
sites.  In this regard, EOG has been named as a potentially
responsible party in certain proceedings initiated pursuant to
the Comprehensive Environmental Response, Compensation, and
Liability Act and may be named as a potentially responsible party
in other similar proceedings in the future.  It is not
anticipated that the costs incurred by EOG in connection with the
presently pending proceedings will, individually or in the
aggregate, have a materially adverse effect on the financial
condition or results of operations of EOG.

     Canadian Regulation.  The crude oil and natural gas industry
in Canada is subject to extensive controls and regulations
imposed by various levels of government.  It is not expected that
any of these controls or regulations will affect EOG operations
in a manner materially different than they would affect other oil
and gas companies of similar size. EOG is unable to predict what
additional legislation or amendments may be enacted.

     In addition, each province has regulations that govern land
tenure, royalties, production rates and other matters.  The
royalty regime is a significant factor in the profitability of
crude oil and natural gas production.  Royalties payable on
production from private lands are determined by negotiations
between the mineral owner and the lessee, although production
from such lands is also subject to certain provincial taxes and
royalties.  Crown royalties are determined by government
regulation and are generally calculated as a percentage of the
value of the gross production, and the rate of royalties payable
generally depends in part on prescribed reference prices, well
productivity, geographical location, field discovery date and the
type or quality of the petroleum product produced.

     Environmental Matters - Canada.  In Canada, the crude oil
and natural gas industry is currently subject to environmental
regulation pursuant to provincial and federal legislation that
provides for restrictions and prohibitions on releases or
emissions of various substances produced or utilized with oil and
gas industry operations.  In addition, wells and facility sites
must be abandoned and reclaimed to the satisfaction of provincial
authorities.  Compliance with such legislation can require
significant expenditures.  A breach of such legislation may
result in the imposition of fines and penalties, the revocation
of licenses and authorizations or civil liability for pollution
damage.

     Other International Regulation.  EOG's exploration and
production operations outside North America are subject to
various types of regulations imposed by the respective
governments of the countries in which EOG's operations are
conducted, and may affect EOG's operations and costs within that
country.  EOG currently has operations in offshore Trinidad and
the United Kingdom North Sea.

Enron Corp. Bankruptcy

     In December 2001, Enron Corp. and certain of its affiliates,
including Enron North America Corp., filed voluntary petitions
for reorganization under Chapter 11 of the United States
Bankruptcy Code.  EOG recorded $19.2 million in charges
associated with the Enron bankruptcies in the fourth quarter of
2001 related to certain contracts with Enron affiliates,
including 2001 and 2002 natural gas and crude oil derivative
contracts.  Based on EOG's review of all matters related to Enron
Corp. and its affiliates, EOG believes that Enron Corp.'s Chapter
11 proceedings will not have a material adverse effect on EOG's
financial position.

Other Matters

     Energy Prices.  Since EOG is primarily a natural gas
company, it is more significantly impacted by changes in natural
gas prices than in the prices for crude oil, condensate or
natural gas liquids.  Average North America wellhead natural gas
prices have fluctuated, at times rather dramatically, during the
last three years.  These fluctuations resulted in a 9% increase
in the average wellhead natural gas price for North America
received by EOG from 2000 to 2001, a decrease of 32% from 2001 to
2002, and an increase of 75% from 2002 to 2003.  Wellhead natural
gas volumes from Trinidad are sold under either a contract with a
fixed price schedule with annual escalations, or a contract that
is price dependent on Caribbean ammonia index prices.
Substantially all of EOG's wellhead crude oil and condensate is
sold under various terms and arrangements at market responsive
prices. Crude oil and condensate prices also have fluctuated
during the last three years.  Due to the many uncertainties
associated with the world political environment, the
availabilities of other world wide energy supplies and the
relative competitive relationships of the various energy sources
in the view of consumers, EOG is unable to predict what changes
may occur in natural gas, crude oil and condensate, and ammonia
prices in the future.

     Risk Management.  EOG engages in price risk management
activities from time to time.  These activities are intended to
manage EOG's exposure to fluctuations in commodity prices for
natural gas and crude oil.  EOG utilizes derivative financial
instruments, primarily price swaps and collars, as the means to
manage this price risk.  In addition to these financial
transactions, EOG is a party to various physical commodity
contracts for the sale of hydrocarbons that cover varying periods
of time and have varying pricing provisions.  Under SFAS No. 133
- - "Accounting for Derivative Instruments and Hedging Activities,"
as amended by SFAS Nos. 137, 138 and 149, these various physical
commodity contracts qualify for the normal purchases and normal
sales exception and therefore, are not subject to hedge
accounting or mark-to-market accounting.  The financial impact of
these various physical commodity contracts is included in
revenues at the time of settlement, which in turn affects average
realized hydrocarbon prices.

     Presented below is a summary of EOG's natural gas financial
collar contracts and natural gas and crude oil financial price
swap contracts as of March 11, 2004 with prices expressed in
dollars per million British thermal units ($/MMBtu) and in
dollars per barrel ($/Bbl), as applicable, and notional volumes
in million British thermal units per day (MMBtud) and in barrels
per day (Bbld), as applicable.  As indicated, EOG does not have
any financial collar or swap contracts that cover periods beyond
October 2004.  Moreover, EOG has not entered into any additional
natural gas financial collar contracts or natural gas or crude
oil financial price swap contracts since December 31, 2003.  EOG
accounts for these collar and swap contracts using mark-to-market
accounting.



              Natural Gas Financial Collar Contracts                   Financial Price Swap Contracts
                         Floor Price            Ceiling Price          Natural Gas          Crude Oil
                                                                              Weighted           Weighted
                       Floor    Weighted      Ceiling    Weighted              Average            Average
          Volume       Range     Average       Range      Average    Volume     Price    Volume    Price
2004(1)  (MMBtud)    ($/MMBtu)  ($/MMBtu)    ($/MMBtu)   ($/MMBtu)  (MMBtud)  ($/MMBtu)  (Bbld)   ($/Bbl)

                                                                 
Jan       330,000  $5.06 - 5.88   $5.38    $5.86 - 6.69    $6.29     30,000     $5.57     4,000   $30.61
Feb       330,000   5.02 - 5.78    5.31     5.82 - 6.62     6.24     30,000      5.50     4,000    30.12
Mar       330,000   4.93 - 5.53    5.16     5.73 - 6.40     6.10     30,000      5.37     4,000    29.58
Apr       375,000   4.47 - 4.71    4.59     4.93 - 5.30     5.13     30,000      4.89     4,000    29.08
May       375,000   4.47 - 4.75    4.58     4.93 - 5.19     5.09     30,000      4.80     4,000    28.66
Jun       375,000   4.47 - 4.75    4.58     4.93 - 5.19     5.09     30,000      4.80     4,000    28.27
Jul       375,000   4.47 - 4.75    4.58     4.93 - 5.19     5.09     30,000      4.80     3,000    27.91
Aug       375,000   4.47 - 4.75    4.58     4.93 - 5.19     5.09     30,000      4.80     2,000    28.11
Sep       375,000   4.47 - 4.75    4.58     4.93 - 5.19     5.09     30,000      4.78        --       --
Oct       375,000   4.47 - 4.75    4.58     4.93 - 5.19     5.09     30,000      4.80        --       --


(1) The collar contracts for January 2004 to March 2004 were
    purchased at a total premium of $3 million or $0.10 per
    MMBtu.  The collar contracts for April 2004 to October 2004
    were purchased without a premium.


     Severance Tax Exemption.  Natural gas production from wells
spudded or completed after May 24, 1989 and before September 1,
1996 in tight formations in Texas qualified for a ten-year
exemption from severance taxes, subject to certain limitations.
This ten-year exemption began September 1, 1991 and ended August
31, 2001.  Natural gas production from qualifying wells spudded
or completed after August 31, 1996, is entitled to use a reduced
severance tax rate for the first 120 consecutive months.
However, the cumulative value of the tax reduction cannot exceed
50 percent of the drilling and completion costs incurred on a
well-by-well basis.

     Preferred Stock.  On December 10, 1999, EOG issued 100,000
shares of Fixed Rate Cumulative Perpetual Senior Preferred Stock,
Series A, with a $1,000 Liquidation Preference per share, in a
private transaction.  Dividends will be payable on the shares
only if declared by EOG's Board of Directors and will be
cumulative.  If declared, dividends will be payable at a rate of
$71.95 per share, per year on March 15, June 15, September 15 and
December 15 or each year beginning March 15, 2000.  EOG may
redeem all or part of the Series A preferred stock at any time
beginning on December 15, 2009 at $1,000 per share, plus accrued
and unpaid dividends.  The Series A preferred shares are not
convertible into, or exchangeable for, common stock of EOG.

     On December 22, 1999, EOG issued 500 shares of Flexible
Money Market Cumulative Preferred Stock, Series C, with a
liquidation preference of $100,000 per share, in a private
transaction.  Dividends will be payable on the shares only if
declared by EOG's Board of Directors and will be cumulative.  The
initial dividend rate on the shares will be 6.84% until December
15, 2004 (Initial Period-End Dividend Payment Date).  Through the
Initial Period-End Dividend Payment Date, dividends will be
payable, if declared, on March 15, June 15, September 15 and
December 15 of each year beginning March 15, 2000.  The cash
dividend rate for each subsequent dividend period will be
determined pursuant to periodic auctions conducted in accordance
with certain auction procedures.  The first auction date will be
December 14, 2004.  After December 15, 2004 (unless EOG has
elected a "Non-Call Period" for a subsequent dividend period),
EOG may redeem the shares, in whole or in part, on any dividend
payment date at $100,000 per share plus accumulated and unpaid
dividends.  The Series C preferred shares are not convertible
into, or exchangeable for, common stock of EOG.

     During the third quarter of 2000, EOG completed two exchange
offers for its preferred stock whereby shares of EOG's Series A
preferred stock were exchanged for shares of EOG's Series B
preferred stock, and shares of EOG's Series C preferred stock
were exchanged for shares of EOG's Series D preferred stock.  All
preferred shares were validly tendered and not withdrawn prior to
expiration of the offers.  EOG accepted all of the tendered
shares and issued the respective series in exchange.  Both
exchange offers were registered under the Securities Act of 1933.
The Series B preferred stock has substantially the same terms as
Series A and the Series D preferred stock has substantially the
same terms as Series C.

     Other.  All of EOG's natural gas and crude oil activities
are subject to the risks normally incident to the exploration for
and development and production of natural gas and crude oil,
including blowouts, cratering and fires, each of which could
result in damage to life and/or property.  Offshore operations
are subject to usual marine perils, including hurricanes and
other adverse weather conditions.  EOG's activities are also
subject to governmental regulations as well as interruption or
termination by governmental authorities based on environmental
and other considerations.  In accordance with customary industry
practices, insurance is maintained by EOG against some, but not
all, of the risks.  Losses and liabilities arising from such
events could reduce revenues and increase costs to EOG to the
extent not covered by insurance.

     EOG's operations outside of North America are subject to
certain risks, including expropriation of assets, risks of
increases in taxes and government royalties, renegotiation of
contracts with foreign governments, political instability,
payment delays, limits on allowable levels of production and
currency exchange and repatriation losses, as well as changes in
laws, regulations and policies governing operations of foreign
companies.

Current Executive Officers of the Registrant

     The current executive officers of EOG and their names and
ages are as follows:

Name                   Age            Position

Mark G. Papa            57     Chairman of the Board and Chief
                                Executive Officer; Director

Edmund P. Segner, III   50     President and Chief of Staff;
                                Director

Loren M. Leiker         50     Executive Vice President, Exploration
                                and Development

Gary L. Thomas          54     Executive Vice President, Operations

Barry Hunsaker, Jr.     53     Senior Vice President and General
                                Counsel

Timothy K. Driggers     42     Vice President and Chief Accounting
                                Officer

     Mark G. Papa was elected Chairman of the Board and Chief
Executive Officer of EOG in August 1999, President and Chief
Executive Officer and Director in September 1998, President and
Chief Operating Officer in September 1997, President in December
1996 and was President-North America Operations from February
1994 to September 1998.  Mr. Papa joined Belco Petroleum
Corporation, a predecessor of EOG, in 1981.

     Edmund P. Segner, III became President and Chief of Staff
and Director of EOG in August 1999.  He became Vice Chairman and
Chief of Staff of EOG in September 1997.  He was a director of
EOG from January 1997 to October 1997.  Mr. Segner is EOG's
principal financial officer.

     Loren M. Leiker was elected Executive Vice President,
Exploration in May 1998 and was subsequently named Executive Vice
President, Exploration and Development.  He was previously Senior
Vice President, Exploration.  Mr. Leiker joined EOG in April 1989
as International Exploration Manager.

     Gary L. Thomas was elected Executive Vice President, North
America Operations in May 1998 and was subsequently named
Executive Vice President, Operations.  He was previously Senior
Vice President and General Manager of EOG in Midland.  Mr. Thomas
joined a predecessor of EOG in July 1978.

     Barry Hunsaker, Jr. has been Senior Vice President and
General Counsel since he joined EOG in May 1996.

     Timothy K. Driggers was elected Vice President and
Controller of EOG in October 1999 and was subsequently named Vice
President and Chief Accounting Officer in August 2003.  He was
previously Vice President, Accounting and Land Administration.
Mr. Driggers held management positions in EOG's former majority
shareholder company from October 1998 through September 1999.
Mr. Driggers is EOG's principal accounting officer.

     There are no family relationships among the officers listed,
and there are no arrangements or understandings pursuant to which
any of them were elected as officers.  Officers are appointed or
elected annually by the Board of Directors at its meeting
immediately prior to the Annual Meeting of Shareholders, each to
hold office until the corresponding meeting of the Board in the
next year or until a successor shall have been elected, appointed
or shall have qualified.


ITEM 2.  Properties

Oil and Gas Exploration and Production Properties and Reserves

     Reserve Information.  For estimates of EOG's net proved and
proved developed reserves of natural gas and liquids, including
crude oil, condensate and natural gas liquids, see "Supplemental
Information to Consolidated Financial Statements" in the Form 8-K
filed on February 24, 2004 and attached hereto as Exhibit 99.1.

     There are numerous uncertainties inherent in estimating
quantities of proved reserves and in projecting future rates of
production and timing of development expenditures, including many
factors beyond the control of the producer. The reserve data set
forth in Supplemental Information to Consolidated Financial
Statements represent only estimates.  Reserve engineering is a
subjective process of estimating underground accumulations of
natural gas and liquids, including crude oil, condensate and
natural gas liquids, that cannot be measured in an exact manner.
The accuracy of any reserve estimate is a function of the amount
and quality of available data and of engineering and geological
interpretation and judgment.  As a result, estimates of different
engineers normally vary. In addition, results of drilling,
testing and production subsequent to the date of an estimate may
justify revision of such estimate (upward or downward).
Accordingly, reserve estimates are often different from the
quantities ultimately recovered.  The meaningfulness of such
estimates is highly dependent upon the accuracy of the
assumptions upon which they were based.

     In general, the volume of production from EOG's oil and gas
properties declines as reserves are depleted. Except to the
extent EOG acquires additional properties containing proved
reserves or conducts successful exploration, exploitation and
development activities, the proved reserves of EOG will decline
as reserves are produced.  Volumes generated from future
activities of EOG are therefore highly dependent upon the level
of success in finding or acquiring additional reserves and the
costs incurred in so doing. EOG's estimates of reserves filed
with other federal agencies agree with the information set forth
in Supplemental Information to Consolidated Financial Statements.

     Acreage.  The following table summarizes EOG's developed and
undeveloped acreage at December 31, 2003. Excluded is acreage in
which EOG's interest is limited to owned royalty, overriding
royalty and other similar interests.



                                  Developed              Undeveloped               Total
                              Gross        Net        Gross        Net       Gross        Net
                                                                     
United States
 Texas                       526,306     329,543     870,711     765,670   1,397,017   1,095,213
 Wyoming                     312,540     188,844     625,945     375,986     938,485     564,830
 Utah                        223,675      81,269     362,683     214,758     586,358     296,027
 Oklahoma                    221,291     141,423     183,696     140,998     404,987     282,421
 New Mexico                  163,723      92,801     302,864     176,136     466,587     268,937
 Pennsylvania                 82,450      69,642     163,012     154,246     245,462     223,888
 West Virginia                96,428      96,188      87,858      60,784     184,286     156,972
 Offshore Gulf of Mexico     279,717      81,988     147,880      73,516     427,597     155,504
 Montana                     119,566         758     120,977     101,978     240,543     102,736
 New York                          -           -     109,445      92,781     109,445      92,781
 Ohio                         61,497      58,888      28,406      28,386      89,903      87,274
 California                    4,154       1,414      71,605      69,782      75,759      71,196
 Colorado                     24,884       1,414     129,760      52,589     154,644      54,003
 Louisiana                    16,972      11,887      27,825      21,672      44,797      33,559
 Kansas                       10,086       8,705      34,711      24,854      44,797      33,559
 Mississippi                  13,281      12,645      20,337      18,615      33,618      31,260
 Nevada                            -           -      23,805      23,805      23,805      23,805
 Michigan                          -           -      43,035      23,405      43,035      23,405
 North Dakota                  3,784       1,590       4,680       4,499       8,464       6,089
 Arkansas                      3,042       1,143       1,105         230       4,147       1,373
 Alabama                           -           -         212         193         212         193
  Total United States      2,163,396   1,180,142   3,360,552   2,424,883   5,523,948   3,605,025

Canada
 Alberta                   1,278,478     995,779     650,758     588,888   1,929,236   1,584,667
 Saskatchewan                375,316     344,933     234,316     208,178     609,632     553,111
 Northwest Territories             -           -     706,706     209,863     706,706     209,863
 Manitoba                     17,660      16,558      36,858      36,858      54,518      53,416
 British Columbia              9,176       2,733      45,920      38,897      55,096      41,630
 New Brunswick                   219          33           -           -         219          33
  Total Canada             1,680,849   1,360,036   1,674,558   1,082,684   3,355,407   2,442,720

Trinidad                      41,492      40,325     240,540     194,532     282,032     234,857

United Kingdom                     -           -     190,837      78,150     190,837      78,150

  Total                    3,885,737   2,580,503   5,466,487   3,780,249   9,352,224   6,360,752


     Producing Well Summary.  The following table reflects EOG's
ownership in gas and oil wells located in Texas, the Gulf of
Mexico, Oklahoma, New Mexico, Utah, Pennsylvania, Wyoming, and
various other states in the United States, Canada and Trinidad at
December 31, 2003. Gross gas and oil wells include 546 with
multiple completions.



                                             Productive Wells
                                              Gross      Net

                                                 
     Gas                                      15,356   11,712
     Oil                                       1,722    1,373
       Total                                  17,078   13,085



     Drilling and Acquisition Activities.  During the years ended
December 31, 2003, 2002 and 2001, EOG expended approximately
$1,333 million, $836 million and $1,163 million, respectively,
for exploratory and development drilling and acquisition of
leases and producing properties.  EOG drilled, participated in
the drilling of or acquired wells as set out in the table below
for the periods indicated:



                                             Year Ended December 31,
                                   2003               2002               2001
                              Gross     Net      Gross     Net      Gross     Net
                                                          
Development Wells Completed
 North America
  Gas                         1,586   1,439.99   1,465   1,204.93   1,550   1,311.86
  Oil                            89      78.98      88      64.27     124     107.06
  Dry                            89      78.02      84      74.88      95      81.68
    Total                     1,764   1,596.99   1,637   1,344.08   1,769   1,500.60
 Outside North America
  Gas                             -          -       -          -       3       2.90
  Oil                             -          -       -          -       -          -
  Dry                             -          -       -          -       -          -
    Total                         -          -       -          -       3       2.90
  Total Development           1,764   1,596.99   1,637   1,344.08   1,772   1,503.50
Exploratory Wells Completed
 North America
  Gas                            46      28.91      22      17.97      24      18.38
  Oil                             5       4.22       4       3.00      10       7.10
  Dry                            39      29.22      22      17.87      29      23.05
    Total                        90      62.35      48      38.84      63      48.53
 Outside North America
  Gas                             2       0.55       1       0.95       -          -
  Oil                             -          -       -          -       -          -
  Dry                             2       1.50       -          -       1       0.25
    Total                         4       2.05       1       0.95       1       0.25
 Total Exploratory               94      64.40      49      39.79      64      48.78
    Total                     1,858   1,661.39   1,686   1,383.87   1,836   1,552.28
Wells in Progress at end
 of period                       90      79.49      50      42.93      71      59.04
    Total                     1,948   1,740.88   1,736   1,426.80   1,907   1,611.32
Wells Acquired*
  Gas                         1,274   1,079.02     664     374.06   1,089     981.53
  Oil                           108      68.03       7       4.21      53      51.04
    Total                     1,382   1,147.05     671     378.27   1,142   1,032.57


__________________
*Includes the acquisition of additional interests in certain
 wells in which EOG previously owned an interest.


     All of EOG's drilling activities are conducted on a contract
basis with independent drilling contractors. EOG owns no drilling
equipment.


ITEM 3.  Legal Proceedings

     The information required by this Item is incorporated by
reference from the Contingencies section in Note 8 of Notes to
Consolidated Financial Statements included in the Form 8-K filed
on February 24, 2004 and attached hereto as Exhibit 99.1.


ITEM 4.  Submission of Matters to a Vote of Security Holders

     There were no matters submitted to a vote of security
holders during the fourth quarter of 2003.


                               PART II

ITEM 5.  Market for Registrant's Common Equity and Related
Shareholder Matters

     The following table sets forth, for the periods indicated,
the high and low sales prices per share for the common stock of
EOG, as reported on the New York Stock Exchange Composite Tape,
and the amount of cash dividends declared per share.



                       Price Range       Cash
                      High      Low    Dividend
                               
2003
     First Quarter   $42.83   $35.70    $ 0.04
     Second Quarter   45.56    36.56      0.04
     Third Quarter    42.87    37.70      0.05
     Fourth Quarter   47.52    40.85      0.05

2002
     First Quarter   $41.32   $30.50    $ 0.04
     Second Quarter   44.15    37.11      0.04
     Third Quarter    39.68    30.02      0.04
     Fourth Quarter   42.00    32.40      0.04


     As of March 8, 2004, there were approximately 285 record
holders of EOG's common stock, including individual participants
in security position listings.  There are an estimated 75,000
beneficial owners of EOG's common stock, including shares held in
street name.

     EOG currently intends to continue to pay quarterly cash
dividends on its outstanding shares of common stock.  However,
the determination of the amount of future cash dividends, if any,
to be declared and paid will depend upon, among other things, the
financial condition, funds from operations, level of exploration,
exploitation and development expenditure opportunities and future
business prospects of EOG.


ITEM 6.  Selected Financial Data



                                                                 Year Ended December 31,
(In Thousands, Except Per Share Amounts)        2003         2002         2001         2000        1999

                                                                                 
Statement of Income Data:
Net Operating Revenues                      $1,744,675   $1,094,682   $1,655,722   $1,484,356   $ 847,701
Operating Income                               697,314      180,977      675,387      691,324      23,790
Net Income Before Cumulative Effect of
   Change in Accounting Principle              437,276       87,173      398,616      396,931     569,094
Cumulative Effect of Change in Accounting
   Principle, Net of Income Tax (1)             (7,131)           -            -            -           -
Net Income                                     430,145       87,173      398,616      396,931     569,094(2)
Preferred Stock Dividends                       11,032       11,032       10,994       11,028         535
Net Income Available to Common              $  419,113   $   76,141   $  387,622   $  385,903   $ 568,559
Net Income Per Share Available to Common
  Basic
   Net Income Available to Common
      Before Cumulative Effect of Change
      in Accounting Principle               $     3.72   $     0.66   $     3.35   $     3.30   $    4.04
   Cumulative Effect of Change in
      Accounting Principle, Net of
      Income Tax (1)                             (0.06)           -            -            -           -
   Net Income Per Share Available to
      Common                                $     3.66   $     0.66   $     3.35   $     3.30   $    4.04
  Diluted
   Net Income Available to Common
      Before Cumulative Effect of Change
      in Accounting Principle               $     3.66   $     0.65   $     3.30   $     3.24   $    4.01
   Cumulative Effect of Change in
      Accounting Principle, Net of
      Income Tax (1)                             (0.06)           -            -            -           -
   Net Income Per Share Available to
      Common                                $     3.60   $     0.65   $     3.30   $     3.24   $    4.01
Average Number of Common Shares
  Basic                                        114,597      115,335      115,765      116,934     140,648
  Diluted                                      116,519      117,245      117,488      119,102     141,627


(1) EOG adopted Statement of Financial Accounting Standards (SFAS) No. 143 - "Accounting for Asset
    Retirement Obligations" on January 1, 2003.  Pro forma net income for 2002 through 1999 is not
    presented since the pro forma application of SFAS No. 143 to the prior periods would
    not result in pro forma net income materially different from the actual amount reported.
(2) Included a $575 million tax-free gain on the share exchange transactions with a former majority
    shareholder, recorded in Other Income (Expense), Net.




                                                      At December 31,
(In Thousands)                   2003         2002         2001         2000         1999
                                                                  
Balance Sheet Data:
Net Oil and Gas Properties   $4,248,917   $3,321,548   $3,055,910   $2,525,007   $2,334,928
Total Assets                  4,749,015    3,813,568    3,414,044    3,001,253    2,610,793
Long-Term Debt                1,108,872    1,145,132      855,969      859,000      990,306
Shareholders' Equity          2,223,381    1,672,395    1,642,686    1,380,925    1,129,611


     Off-Balance Sheet Arrangements.  EOG does not participate in
financial transactions that generate relationships with
unconsolidated entities or financial partnerships.  Such
entities, often referred to as variable interest entities (VIE)
or special purpose entities (SPE), are generally established for
the purpose of facilitating off-balance sheet arrangements or
other contractually narrow or limited purposes.  EOG was not
involved in any unconsolidated VIE or SPE financial transactions
during any of the reporting periods in this document and has no
intention to participate in such transactions in the foreseeable
future.

     Long-Term Debt, Lease Obligations and Other Commitments.
The following table summarizes EOG's long-term debt, lease
obligations and other commitments at December 31, 2003 (in
thousands):



                                                                                       2010 &
                                     Total       2004    2005 - 2007   2008 - 2009     beyond

                                                                       
Long-Term Debt                    $1,108,872   $198,050    $376,870      $173,952     $360,000
Non-cancelable Operating Leases       54,650     18,187      25,954         3,898        6,611
Drilling Rig Commitments               2,364      1,033         998           333           --
Pipeline Transportation Service
 Commitments (1)                      45,702     13,615      25,811         3,666        2,610
   Total                          $1,211,588   $230,885    $429,633      $181,849     $369,221


(1) Amounts shown are based on current pipeline transportation rates and the Canadian
    foreign currency exchange rate at December 31, 2003.  Management does not
    believe that any future changes in these rates before the expiration dates of
    these commitments will have a materially adverse effect on the financial condition
    or results of operations of EOG.


ITEM 7.  Management's Discussion and Analysis of Financial
Condition and Results of Operations

     Information required by this Item is incorporated by
reference from pages 4 through 16 of the Form 8-K filed on
February 24, 2004 and attached hereto as Exhibit 99.1.

Information Regarding Forward-Looking Statements

     This Annual Report on Form 10-K includes forward-looking
statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of
1934.  All statements other than statements of historical facts,
including, among others, statements regarding EOG's future
financial position, business strategy, budgets, reserve
information, projected levels of production, projected costs and
plans and objectives of management for future operations, are
forward-looking statements.  EOG typically uses words such as
"expect," "anticipate," "estimate," "strategy," "intend," "plan,"
"target" and "believe" or the negative of those terms or other
variations of them or by comparable terminology to identify its
forward-looking statements. In particular, statements, express or
implied, concerning future operating results, the ability to
replace or increase reserves or to increase production, or the
ability to generate income or cash flows are forward-looking
statements.  Forward-looking statements are not guarantees of
performance.  Although EOG believes its expectations reflected in
forward-looking statements are based on reasonable assumptions,
no assurance can be given that these expectations will be
achieved.  Important factors that could cause actual results to
differ materially from the expectations reflected in the forward-
looking statements include, among others:  the timing and extent
of changes in commodity prices for crude oil, natural gas and
related products, foreign currency exchange rates and interest
rates; the timing and impact of liquefied natural gas imports and
changes in demand or prices for ammonia or methanol; the extent
and effect of any hedging activities engaged in by EOG; the
extent of EOG's success in discovering, developing, marketing and
producing reserves and in acquiring oil and gas properties; the
accuracy of reserve estimates, which by their nature involve the
exercise of professional judgment and may therefore be imprecise;
political developments around the world, acts of war and
terrorism and responses to these acts; and financial market
conditions.  In light of these risks, uncertainties and
assumptions, the events anticipated by EOG's forward-looking
statements might not occur.  EOG undertakes no obligations to
update or revise its forward-looking statements, whether as a
result of new information, future events or otherwise.

ITEM 7A.  Quantitative and Qualitative Disclosures About Market Risk

     EOG's exposure to interest rate risk and commodity price
risk is discussed respectively in the Financing and Outlook
sections of the "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Capital Resources
and Liquidity," which is incorporated by reference from pages 10
through 14 of the Form 8-K filed on February 24, 2004 and attached
hereto as Exhibit 99.1.

ITEM 8.  Financial Statements and Supplementary Data

     Information required by this Item is incorporated by
reference from portions of the Form 8-K filed on February 24,
2004 and attached hereto as Exhibit 99.1 as indicated:

     Cross Reference to Applicable Sections     Beginning
     of Form 8-K filed on February 24, 2004      on Page

     Reports of Independent Public Accountants      18
     Consolidated Financial Statements              20
     Notes to Consolidated Financial Statements     24
     Supplemental Information to Consolidated
      Financial Statements                          42
     Unaudited Quarterly Financial Information      50

ITEM 9.  Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure

     None.

ITEM 9A.  Controls and Procedures

     EOG's management, with the participation of EOG's principal
executive officer (CEO) and principal financial officer (CFO),
evaluated the effectiveness of EOG's disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d-15(e)
promulgated under the Securities Exchange Act of 1934, as amended
(Exchange Act)) as of the end of the fiscal quarter ended
December 31, 2003.  Based on this evaluation, the CEO and CFO
have concluded that EOG's disclosure controls and procedures were
effective as of the end of the fiscal quarter ended December 31,
2003 to ensure that information that is required to be disclosed
by EOG in the reports it files or submits under the Exchange Act
is recorded, processed, summarized and reported, within the time
periods specified in the SEC's rules and forms.  There were no
changes in EOG's internal control over financial reporting that
occurred during the fiscal quarter ended December 31, 2003 that
has materially affected, or is reasonably likely to materially
affect, EOG's internal control over financial reporting.

                               PART III

ITEM 10.  Directors and Executive Officers of the Registrant

     Directors and Executive Officers of the Registrant.  The
information required by this Item regarding directors is
incorporated by reference from the Proxy Statement to be filed
within 120 days after December 31, 2003, under the caption
entitled "Election of Directors" of Item 1.

     Audit Committee Related Matters and Code of Ethics for the
CEO and CFO.  The information required by this Item regarding
audit committee related matters is incorporated by reference from
the Proxy Statement to be filed within 120 days after December
31, 2003, under the caption entitled "Board of Directors and
Committees" of Item 1.

ITEM 11.  Executive Compensation

     The information required by this Item is incorporated by
reference from the Proxy Statement to be filed within 120 days
after December 31, 2003, under the caption "Compensation of
Directors and Executive Officers" of Item 1.

ITEM 12.  Security Ownership of Certain Beneficial Owners and
Management


     Information required by this Item is incorporated by
reference from the Proxy Statement to be filed within 120 days
after December 31, 2003, under the captions "Election of
Directors" and "Compensation of Directors and Executive Officers"
of Item 1.

ITEM 13.  Certain Relationships and Related Transactions

     None.

ITEM 14.  Principal Accounting Fees and Services

     Information regarding auditor fees, audit-related fees, tax
fees and all other fees and services billed by the principal
accountant is incorporated by reference from the Proxy Statement
to be filed within 120 days after December 31, 2003, under the
caption "Ratification of Appointment of Auditors - General" of
Item 2.


                               PART IV

ITEM 15.  Financial Statements and Financial Statement Schedule,
Exhibits and Reports on Form 8-K

     Information required by this Item is incorporated by
reference from portions of the Form 8-K filed on February 24,
2004 and attached hereto as Exhibit 99.1 as indicated:

(a)(1) Financial Statements and Supplemental Data

       Cross Reference to Applicable Sections       Beginning
       of Form 8-K filed on February 24, 2004        on Page

       Consolidated Financial Statements                20
       Notes to Consolidated Financial Statements       24
       Supplemental Information to Consolidated
        Financial Statements                            42
       Unaudited Quarterly Financial Information        50

(a)(2) Financial Statement Schedules

       Schedule II - Valuation and Qualifying Accounts and
Reserves for the Years Ended December 31, 2003, 2002 and 2001
(see page 24 for Schedule II).

       Other financial statement schedules have been omitted because
they are inapplicable or the information required therein is
included elsewhere in the consolidated financial statements or
notes thereto.



            REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS


To the Board of Directors and Stockholders of
EOG Resources, Inc.
Houston, Texas


     We have audited the consolidated financial statements of EOG
Resources, Inc. as of December 31, 2003 and 2002, and for the two
years in the period ended December 31, 2003, and have issued our
report thereon dated February 23, 2004; such consolidated
financial statements and report are included in your Current
Report on Form 8-K dated February 24, 2004, and are incorporated
herein by reference.  Our audits also included the financial
statement schedule of EOG Resources, Inc., listed in Item 15.
This financial statement schedule is the responsibility of the
Corporation's management.  Our responsibility is to express an
opinion based on our audits.  In our opinion, such financial
statement schedule, when considered in relation to the basic
financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.




DELOITTE & TOUCHE LLP

Houston, Texas
February 23, 2004



      REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS (Continued)


     EOG dismissed Arthur Andersen LLP on February 27, 2002 and
subsequently engaged Deloitte & Touche LLP as its independent
auditors.  The predecessor auditor's report appearing below is a
copy of Arthur Andersen's previously issued report dated February
21, 2002.  Since EOG is unable to obtain a current manually
signed audit report, a copy of Arthur Andersen's most recent
signed and dated report has been included to satisfy filing
requirements, as permitted under Rule 2-02(e) of Regulation S-X.
The only information in the financial statements and the related
footnotes included in EOG's Current Report on Form 8-K dated
February 24, 2004, incorporated by reference in this Annual
Report on Form 10-K that is referred to in the report of Arthur
Andersen LLP is the information included in the Consolidated
Statements of Income and Comprehensive Income, Consolidated
Statements of Shareholders' Equity, Consolidated Statements
of Cash Flows and the related footnotes for the year ended
December 31, 2001.


To EOG Resources, Inc.:

     We have audited in accordance with auditing standards
generally accepted in the United States the financial statements
included in EOG Resources, Inc.'s Current Report on Form 8-K
dated February 27, 2002, incorporated by reference in this Form
10-K, and have issued our report thereon dated February 21, 2002.
Our audit was made for the purpose of forming an opinion on those
statements taken as a whole.  The schedule included in this item
is the responsibility of the Company's management and is
presented for purposes of complying with the Securities and
Exchange Commission's rules and is not part of the basic
financial statements.  This schedule has been subjected to the
auditing procedures applied in the audit of the basic financial
statements and, in our opinion, fairly states in all material
respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.


                                  ARTHUR ANDERSEN LLP

Houston, Texas
February 21, 2002





  (a)(3) Exhibits

     See pages 25 through 30 for a listing of the exhibits.

  (b)  Reports on Form 8-K

     Current Report on Form 8-K filed on October 1, 2003 to
report Canadian Acquisition and to provide updated summaries of
natural gas and crude oil financial swap and natural gas
financial collar contracts for the third quarter and to report
anticipated results of the price risk management activities for
2003 fourth quarter and 2004 in Item 9 - Regulation FD
Disclosure.

     Current Report on Form 8-K filed on October 16, 2003 to
provide updated summaries of natural gas and crude oil financial
swap and natural gas financial collar contracts for the third
quarter and to report anticipated results of the price risk
management activities for 2003 fourth quarter and 2004 in Item 9 -
Regulation FD Disclosure.

     Current Report on Form 8-K filed on November 3, 2003 to
provide estimates for the fourth quarter and full year 2003 and
updated summaries of natural gas and crude oil financial swap and
natural gas financial collar contracts for 2003 fourth quarter
and 2004 in Item 9 - Regulation FD Disclosure.

     Current Report on Form 8-K filed on November 3, 2003 to
furnish the press release issued November 3, 2003 for the third
quarter 2003 financial and operational results in Item 7 -
Financial Statement and Exhibits and Item 12 - Results of
Operations and Financial Condition.


       Schedule II


                       EOG RESOURCES, INC.

         VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
      For the Years Ended December 31, 2003, 2002 and 2001
                         (In Thousands)


Column A                             Column B     Column C       Column D       Column E
                                                  Additions   Deductions for
                                    Balance at   Charged to    Purpose for     Balance at
                                   Beginning of   Costs and   Which Reserves     End of
Description                            Year       Expenses     Were Created       Year

                                                                    
2003
 Reserves deducted from assets
  to which they apply--
  Allowance for Doubtful Accounts    $20,287      $   506         $ 45          $20,748

2002
 Reserves deducted from assets
  to which they apply--
  Allowance for Doubtful Accounts    $20,114      $   182         $  9          $20,287

2001
 Reserves deducted from assets
  to which they apply--
  Allowance for Doubtful Accounts    $ 1,558      $19,211         $ 655         $20,114




                               EXHIBITS

     Exhibits not incorporated herein by reference to a prior filing are
designated by an asterisk (*) and are filed herewith; all exhibits not so
designated are incorporated herein by reference to EOG's Form S-1
Registration Statement, Registration No. 33-30678, filed on August 24,
1989 (Form S-1), or as otherwise indicated.

Exhibit
Number                          Description

3.1(a)     --   Restated Certificate of Incorporation (Exhibit 3.1 to
                Form S-1).

3.1(b)     --   Certificate of Amendment of Restated Certificate of
                Incorporation (Exhibit 4.1(b) to Form S-8 Registration
                Statement No. 33-52201, filed February 8, 1994).

3.1(c)     --   Certificate of Amendment of Restated Certificate of
                Incorporation (Exhibit 4.1(c) to Form S-8 Registration
                Statement No. 33-58103, filed March 15, 1995).

3.1(d)     --   Certificate of Amendment of Restated Certificate of
                Incorporation, dated June 11, 1996 (Exhibit 3(d) to Form S-3
                Registration Statement No. 333-09919, filed August 9, 1996).

3.1(e)     --   Certificate of Amendment of Restated Certificate of
                Incorporation, dated May 7, 1997 (Exhibit 3(e) to Form S-3
                Registration Statement No. 333-44785, filed January 23,
                1998).

3.1(f)     --   Certificate of Ownership and Merger, dated August 26,
                1999 (Exhibit 3.1(f) to EOG's Annual Report on Form 10-K for
                the year ended December 31, 1999).

3.1(g)     --   Certificate of Designations of Series E Junior
                Participating Preferred Stock, dated February 14, 2000
                (Exhibit 2 to Form 8-A Registration Statement, filed
                February 18, 2000).

3.1(h)     --   Certificate of Designation, Preferences and Rights of
                Fixed Rate Cumulative Perpetual Senior Preferred Stock,
                Series B, dated July 19, 2000 (Exhibit 3.1(h) to EOG's
                Registration Statement on Form S-3 Registration Statement No.
                333-46858, filed September 28, 2000).

3.1(i)     --   Certificate of Designation, Preferences and Rights of
                the Flexible Money Market Cumulative Preferred Stock, Series
                D, dated July 25, 2000 (Exhibit 3.1(i) to EOG's Registration
                Statement on Form S-3 Registration Statement No. 333-46858,
                filed September 28, 2000).

3.1(j)     --   Certificate of Elimination of the Fixed Rate Cumulative
                Perpetual Senior Preferred Stock, Series A, dated September
                15, 2000 (Exhibit 3.1(j) to EOG's Registration Statement on
                Form S-3 Registration Statement No. 333-46858, filed
                September 28, 2000).

3.1(k)     --   Certificate of Elimination of the Flexible Money Market
                Cumulative Preferred Stock, Series C, dated September 15,
                2000 (Exhibit 3.1(k) to EOG's Registration Statement on Form
                S-3 Registration Statement No. 333-46858, filed September 28,
                2000).

3.2*       --   By-laws, dated August 23, 1989, as amended and
                restated effective as of February 24, 2004.

4.1(a)     --   Specimen of Certificate evidencing the Common Stock
                (Exhibit 3.3 to EOG's Annual Report on Form 10-K for the year
                ended December 31, 1999).

4.1(b)     --   Specimen of Certificate Evidencing Fixed Rate Cumulative
                Perpetual Senior Preferred Stock, Series B (Exhibit 4.3(g) to
                EOG's Registration Statement on Form S-4 Registration
                Statement No. 333-36056, filed June 7, 2000).

4.1(c)     --   Specimen of Certificate Evidencing Flexible Money Market
                Cumulative Preferred Stock, Series D (Exhibit 4.3(g) to EOG's
                Registration Statement on Form S-4 Registration Statement No.
                333-36416, filed June 12, 2000).

4.2        --   Rights Agreement, dated as of February 14, 2000, between
                EOG and First Chicago Trust Company of New York, which
                includes the form of Rights Certificate as Exhibit B and the
                Summary of Rights to Purchase Preferred Shares as Exhibit C
                (Exhibit 1 to EOG's Registration Statement on Form 8-A, filed
                February 18, 2000).

4.3        --   Form of Rights Certificate (Exhibit 3 to EOG's
                Registration Statement on Form 8-A, filed February 18, 2000).

4.4        --   Indenture dated as of September 1, 1991, between EOG and
                Chase Bank of Texas National Association (formerly, Texas
                Commerce Bank National Association) (Exhibit 4(a) to EOG's
                Registration Statement on Form S-3 Registration Statement No.
                33-42640, filed September 6, 1991).

4.5        --   Indenture dated as of _________, 2000, between EOG and
                The Bank of New York (Exhibit 4.6 to EOG's Registration
                Statement on Form S-3 Registration Statement No. 333-46858,
                filed September 28, 2000).

4.6        --   Amendment, dated as of December 13, 2001, to the Rights
                Agreement, dated as of February 14, 2000, between EOG and
                First Chicago Trust Company of New York, as rights agent
                (Exhibit 2 to Amendment No. 1 to EOG's Registration Statement
                on Form 8-A/A filed December 14, 2001).

4.7        --   Letter dated December 13, 2001, from First Chicago Trust
                Company of New York to EOG resigning as rights agent
                effective January 12, 2002 (Exhibit 3 to Amendment No. 2 to
                EOG's Registration Statement on Form 8-A/A filed February 7,
                2002).

4.8        --   Amendment, dated as of December 20, 2001, to the Rights
                Agreement, dated as of February 14, 2000, as amended, between
                EOG and First Chicago Trust Company of New York, as rights
                agent (Exhibit 4 to Amendment No. 2 to EOG's Registration
                Statement on Form 8-A/A filed February 7, 2002).

4.9        --   Letter dated December 20, 2001, from EOG Resources, Inc.
                to EquiServe Trust Company, N.A. appointing EquiServe Trust
                Company, N.A. as successor rights agent (Exhibit 5 to
                Amendment No. 2 to EOG's Registration Statement on Form 8-A/A
                filed February 7, 2002).

4.10       --   Amendment, dated as of April 11, 2002, to the Rights
                Agreement, dated as of February 14, 2000, as amended, between
                EOG and EquiServe Trust Company, N.A., as rights agent
                (Exhibit 4.1 to EOG's Current Report on Form 8-K, filed April
                12, 2002).

4.11       --   Amendment, dated as of December 10, 2002, to the Rights
                Agreement, dated as of February 14, 2000, as amended, between
                EOG and EquiServe Trust Company, N.A., as rights agent
                (Exhibit 4.1 to EOG's Current Report on Form 8-K, filed
                December 11, 2002).

10.1(a)    --   Amended and Restated 1994 Stock Plan (Exhibit 4.3 to
                Form S-8 Registration Statement No. 33-58103, filed March 15,
                1995).

10.1(b)    --   Amendment to Amended and Restated 1994 Stock Plan, dated
                effective as of December 12, 1995 (Exhibit 4.3(a) to EOG's
                Annual Report on Form 10-K for the year ended December 31,
                1995).

10.1(c)    --   Amendment to Amended and Restated 1994 Stock Plan, dated
                effective as of December 10, 1996 (Exhibit 4.3(a) to Form S-8
                Registration Statement No. 333-20841, filed January 31,
                1997).

10.1(d)    --   Third Amendment to Amended and Restated 1994 Stock Plan,
                dated effective as of December 9, 1997 (Exhibit 4.3(d) to
                EOG's Annual Report on Form 10-K for the year ended
                December 31, 1997).

10.1(e)    --   Fourth Amendment to Amended and Restated 1994 Stock
                Plan, dated effective as of May 5, 1998 (Exhibit 4.3(e) to
                EOG's Annual Report on Form 10-K for the year ended
                December 31, 1998).

10.1(f)    --   Fifth Amendment to Amended and Restated 1994 Stock Plan,
                dated effective as of December 8, 1998 (Exhibit 4.3(f) to
                EOG's Annual Report on Form 10-K for the year ended
                December 31, 1998).

10.1(g)    --   Sixth Amendment to Amended and Restated 1994 Stock Plan,
                dated effective as of May 8, 2001 (Exhibit 10.1(g) to EOG's
                Annual Report on Form 10-K for the year ended December 31,
                2001).

10.2       --   Amended and Restated 1993 Nonemployee Directors Stock
                Option Plan (Exhibit A to EOG's Proxy Statement, dated March
                28, 2002, with respect to EOG's Annual Meeting of
                Shareholders).

10.3(a)    --   1992 Stock Plan (As Amended and Restated Effective
                June 28, 1999) (Exhibit A to EOG's Proxy Statement, dated
                June 4, 1999, with respect to EOG's Annual Meeting of
                Shareholders).

10.3(b)    --   First Amendment to 1992 Stock Plan (As Amended and
                Restated Effective June 28, 1999) dated effective as of May
                8, 2001 (Exhibit 10.7(b) to EOG's Annual Report on Form 10-K
                for the year ended December 31, 2001).

10.4(a)    --   1996 Deferral Plan (Exhibit 10.63(a) to EOG's Annual
                Report on Form 10-K for the year ended December 31, 1997).

10.4(b)    --   First Amendment to 1996 Deferral Plan, dated effective
                as of December 9, 1997 (Exhibit 10.63(b) to EOG's Annual
                Report on Form 10-K for the year ended December 31, 1997).

10.4(c)    --   Second Amendment to 1996 Deferral Plan, dated effective
                as of December 8, 1998 (Exhibit 10.63(c) to EOG's Annual
                Report on Form 10-K for the year ended December 31, 1998).

10.4(d)    --   1996 Deferral Plan, as amended and restated effective
                May 8, 2001 (Exhibit 4.4 to Form S-8 Registration Statement
                No. 333-84014, filed March 8, 2002).

10.4(e)    --   First Amendment to 1996 Deferral Plan, as amended and
                restated effective May 8, 2001, effective as of
                September 10, 2002 (Exhibit 10.9(e) to EOG's Annual Report
                on Form 10-K for the year ended December 31, 2002).

10.5(a)    --   Executive Employment Agreement between EOG and Mark G.
                Papa, effective as of November 1, 1997 (Exhibit 10.64 to
                EOG's Annual Report on Form 10-K for the year ended
                December 31, 1997).

10.5(b)    --   First Amendment to Executive Employment Agreement
                between EOG and Mark G. Papa, effective as of February 1,
                1999 (Exhibit 10.64(b) to EOG's Annual Report on Form 10-K
                for the year ended December 31, 1998).

10.5(c)    --   Second Amendment to Executive Agreement between EOG and
                Mark G. Papa, effective as of June 28, 1999 (Exhibit 10.64(c)
                to EOG's Annual Report on Form 10-K for the year ended
                December 31, 1999).

10.5(d)    --   Third Amendment to Executive Employment Agreement between
                EOG and Mark G. Papa, entered into on June 20, 2001, and made
                effective as of June 1, 2001 (Exhibit 10.10(d) to EOG's
                Annual Report on Form 10-K for the year ended December 31,
                2001).

10.5(e)    --   Change of Control Agreement between EOG and Mark G. Papa,
                effective as of June 20, 2001 (Exhibit 10.10(e) to EOG's
                Annual Report on Form 10-K for the year ended December 31,
                2001).

10.6(a)    --   Executive Employment Agreement between EOG and Edmund P.
                Segner, III, effective as of September 1, 1998
                (Exhibit 10.65(a) to EOG's Annual Report on Form 10-K for the
                year ended December 31, 1998).

10.6(b)    --   First Amendment to Executive Employment Agreement
                between EOG and Edmund P. Segner, III, effective as of
                February 1, 1999 (Exhibit 10.65(b) to EOG's Annual Report on
                Form 10-K for the year ended December 31, 1998).

10.6(c)    --   Second Amendment to Executive Employment Agreement
                between EOG and Edmund P. Segner, III, effective as of
                June 28, 1999 (Exhibit 10.65(c) to EOG's Annual Report on
                Form 10-K for the year ended December 31, 1999).

10.6(d)    --   Third Amendment to Executive Employment Agreement
                between EOG and Edmund P. Segner, III, entered into on June
                22, 2001, and made effective as of June 1, 2001 (Exhibit
                10.11(d) to EOG's Annual Report on Form 10-K for the year
                ended December 31, 2001).

10.6(e)    --   Change of Control Agreement between EOG and Edmund P.
                Segner, III, effective as of June 22, 2001 (Exhibit 10.11(e)
                to EOG's Annual Report on Form 10-K for the year ended
                December 31, 2001).

10.7(a)    --   Executive Employment Agreement between EOG and Barry
                Hunsaker, Jr., effective as of September 1, 1998 (Exhibit
                10.66(a) to EOG's Annual Report on Form 10-K for the year
                ended December 31, 1999).

10.7(b)    --   First Amendment to Executive Employment Agreement
                between EOG and Barry Hunsaker, Jr., effective as of
                December 21, 1998 (Exhibit 10.66(b) to EOG's Annual Report on
                Form 10-K for the year ended December 31, 1999).

10.7(c)    --   Second Amendment to Executive Employment Agreement
                between EOG and Barry Hunsaker, Jr., effective as of
                February 1, 1999 (Exhibit 10.66(c) to EOG's Annual Report on
                Form 10-K for the year ended December 31, 1999).

10.7(d)    --   Third Amendment to Executive Employment Agreement
                between EOG and Barry Hunsaker, Jr., entered into on June 29,
                2001, and made effective as of June 1, 2001 (Exhibit 10.12(d)
                to EOG's Annual Report on Form 10-K for the year ended
                December 31, 2001).

10.7(e)    --   Change of Control Agreement between EOG and Barry
                Hunsaker, Jr., effective as of June 29, 2001 (Exhibit
                10.12(e) to EOG's Annual Report on Form 10-K for the year
                ended December 31, 2001).

10.8(a)    --   Executive Employment Agreement between EOG and Loren M
                Leiker, effective as of March 1, 1998 (Exhibit 10.67(a) to
                EOG's Annual Report on Form 10-K for the year ended December
                31, 1999).

10.8(b)    --   First Amendment to Executive Employment Agreement
                between EOG and Loren M. Leiker, effective as of February 1,
                1999 (Exhibit 10.67(b) to EOG's Annual Report on Form 10-K
                for the year ended December 31, 1999).

10.8(c)    --   Second Amendment to Executive Employment Agreement
                between EOG and Loren M. Leiker, entered into on July 1,
                2001, and made effective as of June 1, 2001 (Exhibit 10.13(c)
                to EOG's Annual Report on Form 10-K for the year ended
                December 31, 2001).

10.8(d)    --   Change of Control Agreement between EOG and Loren M.
                Leiker, effective as of July 1, 2001 (Exhibit 10.13(d) to
                EOG's Annual Report on Form 10-K for the year ended December
                31, 2001).

10.9(a)    --   Executive Employment Agreement between EOG and Gary L.
                Thomas, effective as of September 1, 1998 (Exhibit 10.68(a)
                to EOG's Annual Report on Form 10-K for the year ended
                December 31, 1999).

10.9(b)    --   First Amendment to Executive Employment Agreement
                between EOG and Gary L. Thomas, effective as of February 1,
                1999 (Exhibit 10.68(b) to EOG's Annual Report on Form 10-K
                for the year ended December 31, 1999).

10.9(c)    --   Second Amendment to Executive Employment Agreement
                between EOG and Gary L. Thomas, entered into on July 1, 2001,
                and made effective as of June 1, 2001 (Exhibit 10.14(c) to
                EOG's Annual Report on Form 10-K for the year ended December
                31, 2001).

10.9(d)    --   Change of Control Agreement between EOG and Gary L.
                Thomas, effective as of July 1, 2001 (Exhibit 10.14(d) to
                EOG's Annual Report on Form 10-K for the year ended December
                31, 2001).

10.10(a)   --   Change of Control Severance Plan (As Amended and
                Restated Effective May 8, 2001) (Exhibit 10.15 to EOG's
                Annual Report on Form 10-K for the year ended December 31,
                2001).

10.10(b)   --   First Amendment to Change of Control Severance
                Plan (As Amended and Restated Effective May 8, 2001),
                effective as of September 10, 2002 (Exhibit 10.15(b) to
                EOG's Annual Report on Form 10-K for the year ended
                December 31, 2002).

10.11      --   Employee Stock Purchase Plan (Exhibit 4.4 to Form S-8
                Registration Statement No. 333-62256, filed June 4, 2001).

10.12(a)   --   Amended and Restated Savings Plan (Exhibit 10.17 to EOG's
                Annual Report on Form 10-K for the year ended December 31,
                2002).

*10.12(b)  --   First Amendment to Amended and Restated Savings Plan,
                dated effective as of December 15, 2003.

10.13      --   Executive Officer Annual Bonus Plan (Exhibit C to EOG's
                Proxy Statement, dated March 30, 2001, with respect to EOG's
                Annual Meeting of Shareholders).

10.14      --   Form of Grant Agreement to Non-Employee Directors of EOG
                (Exhibit 10.21 to EOG's Annual Report on Form 10-K for
                the year ended December 31, 2002).

*12        --   Computation of Ratio of Earnings to Fixed Charges and
                Combined Fixed Charges and Preferred Dividends.

*21        --   List of subsidiaries.

*23.1      --   Consent of DeGolyer and MacNaughton.

*23.2      --   Opinion of DeGolyer and MacNaughton dated March 1, 2004.

*23.3      --   Consent of Deloitte & Touche LLP.

*24        --   Powers of Attorney.

*31.1      --   Section 302 Certification of Annual Report of Chief
                Executive Officer.

*31.2      --   Section 302 Certification of Annual Report of Principal
                Financial Officer.

*32.1      --   Section 906 Certification of Annual Report of Chief
                Executive Officer.

*32.2      --   Section 906 Certification of Annual Report of Principal
                Financial Officer.

*99.1      --   Current Report on Form 8-K, filed on February 24, 2004.



                              SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized, on the 11th day of March, 2004.

                              EOG RESOURCES, INC.
                              (Registrant)

                              By   /s/TIMOTHY K. DRIGGERS
                                Timothy K. Driggers
                    Vice President and Chief Accounting Officer
                           (Principal Accounting Officer)

     Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed by the following persons on behalf
of registrant and in the capacities with EOG Resources, Inc. indicated
and on the 11th day of March, 2004.

           Signature                             Title

        /s/ MARK G. PAPA           Chairman and Chief Executive Officer and
         (Mark G. Papa)             Director (Principal Executive Officer)

      /s/ EDMUND P. SEGNER, III     President and Chief of Staff and Director
      (Edmund P. Segner, III)            (Principal Financial Officer)

     /s/ TIMOTHY K. DRIGGERS        Vice President and Chief Accounting Officer
      (Timothy K. Driggers)              (Principal Accounting Officer)

       *GEORGE A. ALCORN                        Director
       (George A. Alcorn)

       *CHARLES R. CRISP                        Director
       (Charles R. Crisp)

      *EDWARD RANDALL, III                      Director
     (Edward Randall, III)

       *DONALD F. TEXTOR                        Director
       (Donald F. Textor)

        *FRANK G. WISNER                        Director
       (Frank G. Wisner)


*By  /s/ PATRICIA L. EDWARDS
     (Patricia L. Edwards)
     (Attorney-in-fact for persons indicated)



                 EOG RESOURCES, INC. AND SUBSIDIARIES
                         EXHIBITS TO FORM 10-K
              FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003
                           INDEX OF EXHIBITS


Exhibit
Number                       Description

*3.2       --   By-laws, dated August 23, 1989, as amended and
                restated effective as of February 24, 2004.

*10.12(b)  --   First Amendment to Amended and Restated Savings
                Plan, dated effective as of Decembr 15, 2003.

*12        --   Computation of Ratio of Earnings to Fixed Charges and
                Combined Fixed Charges and Preferred Dividends.

*21        --   List of subsidiaries.

*23.1      --   Consent of DeGolyer and MacNaughton.

*23.2      --   Opinion of DeGolyer and MacNaughton dated March 1, 2004.

*23.3      --   Consent of Deloitte & Touche LLP.

*24        --   Powers of Attorney.

*31.1      --   Section 302 Certification of Annual Report of Chief
                Executive Officer.

*31.2      --   Section 302 Certification of Annual Report of
                Principal Financial Officer.

*32.1      --   Section 906 Certification of Annual Report of Chief
                Executive Officer.

*32.2      --   Section 906 Certification of Annual Report of
                Principal Financial Officer.

*99.1      --   Current Report on Form 8-K, filed on February 24, 2004.


*Exhibits filed herewith.

EX-3

                                                 EXHIBIT 3.2


                           BYLAWS

                             OF

                     EOG RESOURCES, INC.

                   A Delaware Corporation
























                         Date of Adoption:   August 23, 1989

                         As Amended:    December 12, 1990,
                                        February 8, 1994,
                                        January 19, 1996,
                                        February 13, 1997,
                                        May 5, 1998,
                                        September 7, 1999,
                                        February 14, 2000,
                                        May 8, 2001,
                                        February 20, 2003,
                                        February 24, 2004.


                              BYLAWS

                         Table of Contents

                                                         Page

Article I.          Offices

  Section        1. Registered Office                      1
  Section        2. Offices                                1
  Section        3. Books and Records                      1

Article II.    Stockholders

  Section        1. Place of Meetings                      1
  Section        2. Quorum; Adjournment of Meetings        1
  Section        3. Annual Meetings                        2
  Section        4. Special Meeting                        2
  Section        5. Record Date                            2
  Section        6. Notice of Meetings                     3
  Section        7. Stockholder List                       3
  Section        8. Proxies                                3
  Section        9. Voting; Elections; Inspectors          4
  Section       10. Conduct of Meetings                    4
  Section       11. Treasury Stock                         5
  Section       12. Business to Be Brought Before
                     the Annual Meeting                    5
  Section       13. Record Date for Action by Written
                     Consent                               6
  Section       14. Inspectors of Written Consent          6
  Section       15. Effectiveness of Written Consent       7

Article III.   Board of Directors

  Section        1. Power; Number; Term of Office          7
  Section        2. Quorum; Voting                         7
  Section        3. Place of Meetings; Order of Business   7
  Section        4. First Meeting                          8
  Section        5. Regular Meetings                       8
  Section        6. Special Meetings                       8
  Section        7. Nomination of Directors                8
  Section        8. Removal                                9
  Section        9. Vacancies; Increases in the Number
                     of Directors                          9
  Section       10. Compensation                           9
  Section       11. Action Without a Meeting; Telephone
                     Conference Meeting                   10
  Section       12. Approval or Ratification of Acts or
                     Contracts by Stockholders            10
  Section       13. Retirement                            10
  Section       14. Independent Directors                 10

Article IV.    Committees

  Section        1. Executive Committee                   12
  Section        2. Audit Committee                       12
  Section        3. Other Committees                      12
  Section        4. Procedure; Meetings; Quorum           13
  Section        5. Substitution and Removal of Members;
                     Vacancies                            13

Article V.     Officers

  Section        1. Number, Titles and Term of Office     13
  Section        2. Powers and Duties of the Chairman
                     of the Board                         13
  Section        3. Powers and Duties of the President,
                     President-North American Operations,
                     and President-International
                     Operations                           14
  Section        4. Powers and Duties of the Vice
                     Chairman of the Board                14
  Section        5. Vice Presidents                       15
  Section        6. General Counsel                       15
  Section        7. Secretary                             15
  Section        8. Deputy Corporate Secretary and
                     Assistant Secretaries                15
  Section        9. Treasurer                             15
  Section       10. Assistant Treasurers                  16
  Section       11. Action with Respect to Securities
                     of Other Corporations                16
  Section       12. Delegation                            16

Article VI.    Capital Stock

  Section        1. Certificates of Stock                 16
  Section        2. Transfer of Shares                    17
  Section        3. Ownership of Shares                   17
  Section        4. Regulations Regarding Certificates    17
  Section        5. Lost or Destroyed Certificates        17

Article VII.   Miscellaneous Provisions

  Section        1. Fiscal Year                           18
  Section        2. Corporate Seal                        18
  Section        3. Notice and Waiver of Notice           18
  Section        4. Facsimile Signatures                  18
  Section        5. Reliance upon Books, Reports and
                     Records                              18
  Section        6. Application of Bylaws                 19

Article VIII.  Amendments                                 19


                              BYLAWS

                                OF

                        EOG RESOURCES, INC.


                             Article I

                              Offices

     Section 1.  Registered Office.  The registered office of the
Corporation required by the General Corporation Law of the State
of Delaware to be maintained in the State of Delaware shall be the
registered office named in the original Certificate of
Incorporation of the Corporation, or such other office as may be
designated from time to time by the Board of Directors in the
manner provided by law.

     Section 2.  Offices.  The Corporation may also have offices
at such other places both within and without the state of
incorporation of the Corporation as the Board of Directors may
from time to time determine or the business of the Corporation may
require.

     Section 3.  Books and Records.  The books and records of the
Corporation may be kept outside the State of Delaware at such
place or places as may from time to time be designated by the
Board of Directors.

                            Article II

                           Stockholders

     Section 1.  Place of Meetings.  All meetings of the
stockholders shall be held at the principal office of the
Corporation, or at such other place within or without the state of
incorporation of the Corporation as shall be specified or fixed in
the notices or waivers of notice thereof.

     Section 2  Quorum; Adjournment of Meetings.  Unless otherwise
required by law or provided in the Certificate of Incorporation or
these Bylaws, (i) the holders of a majority of the stock issued
and outstanding and entitled to vote thereat, present in person or
represented by proxy, shall constitute a quorum at any meeting of
stockholders for the transaction of business, (ii) the affirmative
vote of the holders of a majority of such stock so present or
represented at any meeting of stockholders at which a quorum is
present shall constitute the act of the stockholders, and (iii)
where a separate vote by a class or classes is required, a
majority of the outstanding shares of such class or classes,
present in person or represented by proxy shall constitute a
quorum entitled to take action with respect to that vote on that
matter and the affirmative vote of the majority of the shares of
such class or classes present in person or represented by proxy at
the meeting shall be the act of such class.  The stockholders
present at a duly organized meeting may continue to transact
business until adjournment, notwithstanding the withdrawal of
enough stockholders to leave less than a quorum, subject to the
provisions of clauses (ii) and (iii) above.

     Directors shall be elected by a majority of the votes of the
shares present in person or represented by proxy at the meeting
and entitled to vote on the election of directors.

     Notwithstanding the other provisions of the Certificate of
Incorporation or these Bylaws, the chairman of the meeting or the
holders of a majority of the issued and outstanding stock, present
in person or represented by proxy and entitled to vote thereat, at
any meeting of stockholders, whether or not a quorum is present,
shall have the power to adjourn such meeting from time to time,
without any notice other than announcement at the meeting of the
time and place of the holding of the adjourned meeting.  If the
adjournment is for more than thirty (30) days, or if after the
adjournment a new record date is fixed for the adjourned meeting,
a notice of the adjourned meeting shall be given to each
stockholder of record entitled to vote at such meeting.  At such
adjourned meeting at which a quorum shall be present or
represented any business may be transacted which might have been
transacted at the meeting as originally called.

     Section 3.  Annual Meetings.  An annual meeting of the
stockholders, for the election of directors to succeed those whose
terms expire and for the transaction of such other business as may
properly come before the meeting, shall be held at such place
(within or without the state of incorporation of the Corporation),
on such date, and at such time as the Board of Directors shall fix
and set forth in the notice of the meeting.

     Section 4.  Special Meeting.  Subject to the rights of the
holders of any series of stock having a preference over the Common
Stock of the Corporation as to dividends or upon liquidation with
respect to such series of preferred stock, special meetings of the
stockholders may be called only by the Chairman of the Board or by
the Board of Directors pursuant to a resolution adopted by a
majority of the total number of directors which the Corporation
would have if there were no vacancies.

     Section 5.  Record Date.  For the purpose of determining
stockholders entitled to notice of or to vote at any meeting of
stockholders, or any adjournment thereof, or entitled to receive
payment of any dividend or other distribution or allotment of any
rights, or entitled to exercise any rights in respect of any
change, conversion or exchange of stock or for the purpose of any
other lawful action, the Board of Directors of the Corporation may
fix a date as the record date for any such determination of
stockholders, which record date shall not precede the date on
which the resolutions fixing the record date are adopted and which
record date shall not be more than sixty (60) days nor less than
ten (10) days before the date of such meeting of stockholders, nor
more than sixty (60) days prior to any other action.

     If the Board of Directors does not fix a record date for any
meeting of the stockholders, the record date for determining
stockholders entitled to notice of or to vote at such meeting
shall be at the close of business on the day next preceding the
day on which notice is given, or, if in accordance with Article
VII, Section 3 of these Bylaws notice is waived, at the close of
business on the day next preceding the day on which the meeting is
held. The record date for determining stockholders for any other
purpose shall be at the close of business on the day on which the
Board of Directors adopts the resolution relating thereto. A
determination of stockholders of record entitled to notice of or
to vote at a meeting of stockholders shall apply to any adjournment
of the meeting; provided, however, that the Board of Directors may
fix a new record date for the adjourned meeting.

     Section 6.  Notice of Meetings.  Written notice of the place,
date and hour of all meetings, and, in case of a special meeting,
the purpose or purposes for which the meeting is called, shall be
given by or at the direction of the Chairman of the Board, the
President, the Vice Chairman of the Board, the Secretary or the
other person(s) calling the meeting to each stockholder entitled
to vote thereat not less than ten (10) nor more than sixty (60)
days before the date of the meeting. Such notice may be delivered
either personally or by mail. If mailed, notice is given when
deposited in the United States mail, postage prepaid, directed to
the stockholder at such stockholder's address as it appears on the
records of the Corporation.

     Section 7.  Stockholder List.  A complete list of
stockholders entitled to vote at any meeting of stockholders,
arranged in alphabetical order for each class of stock and showing
the address of each such stockholder and the number of shares
registered in the name of such stockholder, shall be open to the
examination of any stockholder, for any purpose germane to the
meeting, during ordinary business hours, for a period of at least
ten (10) days prior to the meeting, either at a place within the
city where the meeting is to be held, which place shall be
specified in the notice of the meeting, or if not so specified, at
the place where the meeting is to be held. The stockholder list
shall also be produced and kept at the time and place of the
meeting during the whole time thereof, and may be inspected by any
stockholder who is present.

     Section 8.  Proxies.  Each stockholder entitled to vote at a
meeting of stockholders may authorize another person or persons to
act for him by proxy. Proxies for use at any meeting of
stockholders shall be filed with the Secretary, or such other
officer as the Board of Directors may from time to time determine
by resolution, before or at the time of the meeting. All proxies
shall be received and taken charge of and all ballots shall be
received and canvassed by the secretary of the meeting, who shall
decide all questions touching upon the qualification of voters,
the validity of the proxies, and the acceptance or rejection of
votes, unless an inspector or inspectors shall have been appointed
by the chairman of the meeting, in which event such inspector or
inspectors shall decide all such questions.

     No proxy shall be valid after three (3) years from its date,
unless the proxy provides for a longer period. Each proxy shall be
revocable unless expressly provided therein to be irrevocable and
coupled with an interest sufficient in law to support an
irrevocable power.

     Should a proxy designate two or more persons to act as
proxies, unless such instrument shall provide the contrary, a
majority of such persons present at any meeting at which their
powers thereunder are to be exercised shall have and may exercise
all the powers of voting or giving consents thereby conferred, or
if only one be present, then such powers may be exercised by that
one; or, if an even number attend and a majority do not agree on
any particular issue, each proxy so attending shall be entitled to
exercise such powers in respect of such portion of the shares as
is equal to the reciprocal of the fraction equal to the number of
proxies representing such shares divided by the total number of
shares represented by such proxies.

     Section 9.  Voting; Elections; Inspectors.  Unless otherwise
required by law or provided in the Certificate of Incorporation,
each stockholder shall on each matter submitted to a vote at a
meeting of stockholders have one vote for each share of stock
entitled to vote which is registered in his name on the record
date for the meeting. For the purposes hereof, each election to
fill a directorship shall constitute a separate matter. Shares
registered in the name of another corporation, domestic or
foreign, may be voted by such officer, agent or proxy as the
bylaws (or comparable instrument) of such corporation may
prescribe, or in the absence of such provision, as the Board of
Directors (or comparable body) of such corporation may determine.
Shares registered in the name of a deceased person may be voted by
the executor or administrator of such person's estate, either in
person or by proxy.

     All voting, except as required by the Certificate of
Incorporation or where otherwise required by law, may be by a
voice vote; provided, however, upon request of the chairman of the
meeting or upon demand therefor by stockholders holding a majority
of the issued and outstanding stock present in person or by proxy
at any meeting a stock vote shall be taken. Every stock vote shall
be taken by written ballots, each of which shall state the name of
the stockholder or proxy voting and such other information as may
be required under the procedure established for the meeting. All
elections of directors shall be by written ballots, unless
otherwise provided in the Certificate of Incorporation.

     At any meeting at which a vote is taken by written ballots,
the chairman of the meeting may appoint one or more inspectors,
each of whom shall subscribe an oath or affirmation to execute
faithfully the duties of inspector at such meeting with strict
impartiality and according to the best of such inspector's
ability. Such inspector shall receive the written ballots, count
the votes and make and sign a certificate of the result thereof.
The chairman of the meeting may appoint any person to serve as
inspector, except no candidate for the office of director shall be
appointed as an inspector.

     Unless otherwise provided in the Certificate of
Incorporation, cumulative voting for the election of directors
shall be prohibited.

     Section 10.  Conduct of Meetings. The meetings of the
stockholders shall be presided over by the Chairman of the Board,
or if the Chairman of the Board is not present, by the President,
or if the President is not present, by the Vice Chairman of the
Board, or if neither the Chairman of the Board, the President nor
the Vice Chairman of the Board is present, by a chairman elected
at the meeting. The Secretary of the Corporation, if present,
shall act as secretary of such meetings, or if the Secretary is
not present, the Deputy Corporate Secretary or an Assistant
Secretary shall so act; if neither the Secretary or the Deputy
Corporate Secretary or an Assistant Secretary is present, then a
secretary shall be appointed by the chairman of the meeting. The
chairman of any meeting of stockholders shall determine the order
of business and the procedure at the meeting, including such
regulation of the manner of voting and the conduct of discussion
as seem to the chairman in order.

     Section 11.  Treasury Stock.  The Corporation shall not vote,
directly or indirectly, shares of its own stock owned by it and
such shares shall not be counted for quorum purposes. Nothing in
this Section 11 shall be construed as limiting the right of the
Corporation to vote stock, including but not limited to its own
stock, held by it in a fiduciary capacity.

     Section 12.  Business to Be Brought Before the Annual
Meeting.  To be properly brought before the annual meeting of
stockholders, business must be either (a) specified in the notice
of meeting (or any supplement thereto) given by or at the
direction of the Board of Directors, (b) otherwise brought before
the meeting by or at the direction of the Board of Directors, or
(c) otherwise properly brought before the meeting by a stockholder
of the Corporation who is a stockholder of record at the time of
giving of notice provided for in this Section 12 of Article II,
who shall be entitled to vote at such meeting and who complies
with the notice procedures set forth in this Section 12 of Article
II.  In addition to any other applicable requirements, for
business to be brought before an annual meeting by a stockholder
of the Corporation, the stockholder must have given timely notice
thereof in writing to the Secretary of the Corporation. To be
timely, a stockholder's notice must be delivered to or mailed and
received at the principal executive offices of the Corporation not
less than 120 days prior to the anniversary date of the proxy
statement for the preceding annual meeting of stockholders of the
Corporation. A stockholder's notice to the Secretary shall set
forth as to each matter the stockholder proposes to bring before
the annual meeting (i) a brief description of the business desired
to be brought before the annual meeting and the reasons for
conducting such business at the annual meeting, (ii) the name and
address, as they appear on the Corporation's books, of the
stockholder proposing such business, (iii) the acquisition date,
the class and the number of shares of voting stock of the
Corporation which are owned beneficially by the stockholder, (iv)
any material interest of the stockholder in such business, and (v)
a representation that the stockholder intends to appear in person
or by proxy at the meeting to bring the proposed business before
the meeting.

     Notwithstanding anything in these Bylaws to the contrary, no
business shall be conducted at the annual meeting except in
accordance with the procedures set forth in this Section 12.

     The chairman of the annual meeting shall, if the facts
warrant, determine and declare to the meeting that business was
not properly brought before the meeting in accordance with the
provisions of this Section 12 of Article II, and if the chairman
should so determine, the chairman shall so declare to the meeting
and any such business not properly brought before the meeting
shall not be transacted.

     Notwithstanding the foregoing provisions of this Section 12
of Article II, a stockholder shall also comply with all applicable
requirements of the Securities Exchange Act of 1934, as amended,
and the rules and regulations thereunder with respect to the
matters set forth in this Section 12.

     Section 13.  Record Date for Action by Written Consent.  In
order that the Corporation may determine the stockholders entitled
to consent to corporate action in writing without a meeting, the
Board of Directors may fix a record date, which record date shall
not precede the date upon which the resolution fixing the record
date is adopted by the Board of Directors, and which date shall
not be more than ten (10) days after the date upon which the
resolution fixing the record date is adopted by the Board of
Directors. Any stockholder of record seeking to have the
stockholders authorize or take corporate action by written consent
shall, by written notice to the Secretary, request the Board of
Directors to fix a record date. The Board of Directors shall
promptly, but in all events within ten (10) days after the date on
which such a request is received, adopt a resolution fixing the
record date (unless a record date has previously been fixed by the
Board of Directors pursuant to the first sentence of this Section
13). If no record date has been fixed by the Board of Directors
pursuant to the first sentence of this Section 13 or otherwise
within ten (10) days of the date on which such a request is
received, the record date for determining stockholders entitled to
consent to corporate action in writing without a meeting, when no
prior action by the Board of Directors is required by applicable
law, shall be the first date on which a signed written consent
setting forth the action taken or proposed to be taken is
delivered to the Corporation by delivery to its registered office
in Delaware, its principal place of business, or to any officer or
agent of the Corporation having custody of the books in which
proceedings of meetings of stockholders are recorded. Delivery
shall be by hand or by certified or registered mail, return
receipt requested. If no record date has been fixed by the Board
of Directors and prior action by the Board of Directors is
required by applicable law, the record date for determining
stockholders entitled to consent to corporate action in writing
without a meeting shall be at the close of business on the date on
which the Board of Directors adopts the resolution taking such
prior action.

     Section 14.  Inspectors of Written Consent. In the event of
the delivery, in the manner provided by Section 13, to the
Corporation of the requisite written consent or consents to take
corporate action and/or any related revocation or revocations, the
Corporation shall engage independent inspectors of elections for
the purpose of promptly performing a ministerial review of the
validity of the consents and revocations. For the purpose of
permitting the inspectors to perform such review, no action by
written consent without a meeting shall be effective until such
date as the independent inspectors certify to the Corporation that
the consents delivered to the Corporation in accordance with
Section 13 represent at least the minimum number of votes that
would be necessary to take the corporate action. Nothing contained
in this Section 14 shall in any way be construed to suggest or
imply that the Board of Directors or any stockholder shall not be
entitled to contest the validity of any consent or revocation
thereof, whether before or after such certification by the
independent inspectors, or to take any other action (including,
without limitation, the commencement, prosecution, or defense of
any litigation with respect thereto, and the seeking of injunctive
relief in such litigation).

     Section 15.  Effectiveness of Written Consent.  Every written
consent shall bear the date of signature of each stockholder who
signs the consent and no written consent shall be effective to
take the corporate action referred to therein unless, within sixty
(60) days of the earliest dated written consent received in
accordance with Section 13, a written consent or consents signed
by a sufficient number of holders to take such action are
delivered to the Corporation in the manner prescribed in Section
13.

                            Article III

                        Board of Directors

     Section 1.  Power; Number; Term of Office. The business and
affairs of the Corporation shall be managed by or under the
direction of the Board of Directors, and subject to the
restrictions imposed by law or the Certificate of Incorporation,
the Board of Directors may exercise all the powers of the
Corporation.

     The number of directors which shall constitute the whole
Board of Directors shall be determined from time to time by the
Board of Directors (provided that no decrease in the number of
directors which would have the effect of shortening the term of an
incumbent director may be made by the Board of Directors). If the
Board of Directors makes no such determination, the number of
directors shall be three. Each director shall hold office for the
term for which such director is elected, and until such Director's
successor shall have been elected and qualified or until such
Director's earlier death, resignation or removal.

     Unless otherwise provided in the Certificate of
Incorporation, directors need not be stockholders nor residents of
the state of incorporation of the Corporation.

     Section 2.  Quorum; Voting.  Unless otherwise provided in the
Certificate of Incorporation, a majority of the total number of
directors, at least half of whom are Independent Directors as
defined in Section 14 below, shall constitute a quorum for the
transaction of business of the Board of Directors and the vote of
a majority of the directors present at a meeting at which a quorum
is present shall be the act of the Board of Directors.

     Section 3.  Place of Meetings; Order of Business.  The
directors may hold their meetings and may have an office and keep
the books of the Corporation, except as otherwise provided by law,
in such place or places, within or without the state of
incorporation of the Corporation, as the Board of Directors may
from time to time determine. At all meetings of the Board of
Directors business shall be transacted in such order as shall from
time to time be determined by the Chairman of the Board, or in the
Chairman of the Board's absence by the President (should the
President be a director), or in the President's absence by the
Vice Chairman of the Board, or by the Board of Directors.

     Section 4.  First Meeting.  Each newly elected Board of
Directors may hold its first meeting for the purpose of
organization and the transaction of business, if a quorum is
present, immediately after and at the same place as the annual
meeting of the stockholders. Notice of such meeting shall not be
required. At the first meeting of the Board of Directors in each
year at which a quorum shall be present, held next after the
annual meeting of stockholders, the Board of Directors shall elect
the officers of the Corporation.

     Section 5.  Regular Meetings.  Regular meetings of the Board
of Directors shall be held at such times and places as shall be
designated from time to time by the Chairman of the Board or, in
the absence of the Chairman of the Board, by the President (should
the President be a director), or in the President's absence, by
the Vice Chairman of the Board. Notice of such regular meetings
shall not be required.

     Section 6.  Special Meetings.  Special meetings of the Board
of Directors may be called by the Chairman of the Board, the
President (should the President be a director) or the Vice
Chairman of the Board or, on the written request of any two
directors, by the Secretary, in each case on at least twenty-four
(24) hours personal, written, telegraphic, cable or wireless
notice to each director. Such notice, or any waiver thereof
pursuant to Article VII, Section 3 hereof, need not state the
purpose or purposes of such meeting, except as may otherwise be
required by law or provided for in the Certificate of
Incorporation or these Bylaws. Meetings may be held at any time
without notice if all the directors are present or if those not
present waive notice of the meeting in writing.

     Section 7.  Nomination of Directors.  Only persons who are
nominated in accordance with the following procedures shall be
eligible for election as directors. Nominations of persons for
election to the Board of Directors of the Corporation may be made
at a meeting of stockholders (a) by or at the direction of the
Board of Directors or (b) by any stockholder of the Corporation
who is a stockholder of record at the time of giving of notice
provided for in this Section 7 of Article III, who shall be
entitled to vote for the election of directors at the meeting and
who complies with the notice procedures set forth in this Section
7 of Article III. Such nominations, other than those made by or at
the direction of the Board of Directors, shall be made pursuant to
timely notice in writing to the Secretary of the Corporation. To
be timely, a stockholder's notice shall be delivered to or mailed
and received at the principal executive offices of the Corporation
(i) with respect to an election to be held at the annual meeting
of the stockholders of the Corporation, not less than 120 days
prior to the anniversary date of the proxy statement for the
immediately preceding annual meeting of stockholders of the
Corporation, and (ii) with respect to an election to be held at a
special meeting of stockholders of the Corporation for the
election of directors, not later than the close of business on the
10th day following the day on which such notice of the date of the
meeting was mailed or public disclosure of the date of the meeting
was made, whichever first occurs. Such stockholder's notice to the
Secretary shall set forth (a) as to each person whom the
stockholder proposes to nominate for election or re-election as a
director, all information relating to the person that is required
to be disclosed in solicitations for proxies for election of
directors, or is otherwise required, pursuant to Regulation 14A
under the Securities Exchange Act of 1934, as amended (including
the written consent of such person to be named in the proxy
statement as a nominee and to serve as a director if elected); and
(b) as to the stockholder giving the notice (i) the name and
address, as they appear on the Corporation's books, of such
stockholder, and (ii) the class and number of shares of capital
stock of the Corporation which are beneficially owned by the
stockholder. At the request of the Board of Directors, any person
nominated by the Board of Directors for election as a director
shall furnish to the Secretary of the Corporation that information
required to be set forth in a stockholder's notice of nomination
which pertains to the nominee.

     In the event that a person is validly designated as nominee
to the Board and shall thereafter become unable or unwilling to
stand for election to the Board of Directors, the Board of
Directors or the stockholder who proposed such nominee, as the
case may be, may designate a substitute nominee.

     No person shall be eligible to serve as a director of the
Corporation unless nominated in accordance with the procedures set
forth in this Section 7 of Article III and in compliance with
Section 14 of Article III.  The chairman of the meeting of
stockholders shall, if the facts warrant, determine and declare to
the meeting that a nomination was not made in accordance with the
procedures and requirements prescribed by the Bylaws, and if the
chairman should so determine, the chairman shall so declare to the
meeting and the defective nomination shall be disregarded.

     Notwithstanding the foregoing provisions of this Section 7 of
Article III, a stockholder shall also comply with all applicable
requirements of the Securities Exchange Act of 1934, as amended,
and the rules and regulations thereunder with respect to the
matters set forth in this Section 7 of Article III.

     Section 8.  Removal.  Any director or the entire Board of
Directors may be removed, with or without cause, by the holders of
a majority of the shares then entitled to vote at an election of
directors.

     Section 9.  Vacancies; Increases in the Number of Directors.
Unless otherwise provided in the Certificate of Incorporation,
subject to the requirements set forth in Section 14 of this
Article III, vacancies existing on the Board of Directors for any
reason and newly created directorships resulting from any increase
in the authorized number of directors may be filled by the
affirmative vote of a majority of the directors then in office,
although less than a quorum, or by a sole remaining director; and
any director so chosen shall hold office until the next annual
election and until such Director's successor shall have been
elected and qualified, or until such Director's earlier death,
resignation or removal.

     Section 10.  Compensation.  Directors and members of standing
committees may receive such compensation as the Board of Directors
from time to time shall determine to be appropriate, and shall be
reimbursed for all reasonable expenses incurred in attending and
returning from meetings of the Board of Directors.

     Section 11.  Action Without a Meeting; Telephone Conference
Meeting.  Unless otherwise restricted by the Certificate of
Incorporation, any action required or permitted to be taken at any
meeting of the Board of Directors, or any committee designated by
the Board of Directors, may be taken without a meeting if all
members of the Board of Directors or committee, as the case may
be, consent thereto in writing, and the writing or writings are
filed with the minutes of proceedings of the Board of Directors or
committee. Such consent shall have the same force and effect as a
unanimous vote at a meeting, and may be stated as such in any
document or instrument filed with the Secretary of State of the
state of incorporation of the Corporation.

     Unless otherwise restricted by the Certificate of
Incorporation, subject to the requirement for notice of meetings,
members of the Board of Directors, or members of any committee
designated by the Board of Directors, may participate in a meeting
of such Board of Directors or committee, as the case may be, by
means of a conference telephone connection or similar
communications equipment by means of which all persons
participating in the meeting can hear each other, and
participation in such a meeting shall constitute presence in
person at such meeting, except where a person participates in the
meeting for the express purpose of objecting to the transaction of
any business on the ground that the meeting is not lawfully called
or convened.

     Section 12.  Approval or Ratification of Acts or Contracts by
Stockholders.  The Board of Directors in its discretion may submit
any act or contract for approval or ratification at any annual
meeting of the stockholders, or at any special meeting of the
stockholders called for the purpose of considering any such act or
contract, and any act or contract that shall be approved or be
ratified by the vote of the stockholders holding a majority of the
issued and outstanding shares of stock of the Corporation entitled
to vote and present in person or by proxy at such meeting
(provided that a quorum is present) shall be as valid and as
binding upon the Corporation and upon all the stockholders as if
it has been approved or ratified by every stockholder of the
Corporation.

     Section 13.    Retirement.  No incumbent Director shall be
eligible to stand for re-election as a Director of the Corporation
after having attained the age of 74 years, unless otherwise
approved by the Board of Directors.

     Section 14.    Independent Directors.

     The Board of Directors has determined that the following
requirements in respect of the qualifications of the Corporation's
directors and the composition of the Board of Directors are
desirable for and in the best interests of the Corporation and it
stockholders:

     (a)  At least three-fifths of the individuals elected to the
Board of Directors at the Corporation's annual meeting of
stockholders shall consist of individuals who, upon election,
would be Independent Directors.

     (b)  In the event one or more directors are elected or
appointed other than by action of the stockholders at an annual
meeting of stockholders, at least three-fifths of all directors
holding office immediately thereafter shall be Independent
Directors.

     (c)  For purposes of this Section 14, the term "Independent
Director" shall mean a director who:

          (i)  is not, and has not been within the prior three
     years, an officer or employee of the Corporation or any of
     its subsidiaries;

          (ii)  is not, and has not been within the prior three
     years, affiliated with or employed by a present internal or
     external auditor of the Corporation, by an auditor that
     within the prior three years was an internal or external
     auditor of the Corporation, or by an affiliate of any such
     auditor;

          (iii)  is not the direct or indirect beneficial owner of
     more than 5% of the outstanding shares of stock of the
     Corporation entitled to vote in the election of directors
     ("Voting Stock"), or an affiliate or representative of, or a
     party to a contract, arrangement or understanding with, such
     beneficial owner or an affiliate thereof, excluding any
     direct or indirect beneficial owner which has beneficially
     owned more than 5% of the outstanding Voting Stock
     continuously during the two years immediately prior to the
     relevant election or appointment to the Board of Directors;

          (iv) is not (and is not affiliated with) a significant
     advisor or consultant to the Corporation or any of its
     subsidiaries;

          (v) is not (and is not affiliated with) a significant
     customer, contractor, vendor or supplier of the Corporation
     or any of its subsidiaries;

          (vi) does not have a personal services contract or
     arrangement with the Corporation or any of its subsidiaries;

          (vii) is not affiliated with a charitable organization
     that receives significant contributions from the Corporation
     or any of its subsidiaries;

          (viii) is not an immediate family member of any person
     described by (i) through (vii); and

          (ix) does not have any other relationship with the
     Corporation or any of its subsidiaries that would materially
     impair his or her independence.

     (d)  The Board of Directors shall have the exclusive right
and power to interpret and apply the provisions of this Section
14, including, without limitation, the adoption of written
definitions of terms used in and guidelines for the application of
this Section 14 (any such definitions and guidelines shall be
filed with the Secretary of the Corporation, and such definitions
and guidelines as may prevail shall be made available to any
stockholder upon written request), and any such definitions or
guidelines and any other interpretation or application of the
provisions of this Section 14 made in good faith shall be binding
and conclusive upon all holders of equity securities of the
Corporation.

     (e)  Information regarding a nominee for director provided by
a stockholder pursuant to Section 7 of this Article III shall
include such information as may be necessary to enable the Board
of Directors to make an informed determination as to whether such
nominee, if elected, would be an Independent Director as defined
in this Section 14.

                            Article IV

                            Committees

     Section 1.  Executive Committee.  The Board of Directors may,
by resolution passed by a majority of the whole Board of
Directors, designate an Executive Committee consisting of one or
more of the directors of the Corporation, one of whom shall be
designated chairman of the Executive Committee. During the
intervals between the meetings of the Board of Directors, the
Executive Committee shall possess and may exercise all the powers
of the Board of Directors, including the power to authorize the
seal of the Corporation to be affixed to all papers which may
require it; provided, however, that the Executive Committee shall
not have the power or authority of the Board of Directors in
reference to amending the Certificate of Incorporation, adopting
an agreement of merger or consolidation, recommending to the
stockholders the sale, lease or exchange of all or substantially
all of the Corporation's property and assets, recommending to the
stockholders a dissolution of the Corporation or a revocation of a
dissolution of the Corporation, amending, altering or repealing
these Bylaws or adopting new bylaws for the Corporation or
otherwise acting where action by the Board of Directors is
specified by the Delaware General Corporation Law. The Executive
Committee shall also have, and may exercise, all the powers of the
Board of Directors, except as aforesaid, whenever a quorum of the
Board of Directors shall fail to be present at any meeting of the
Board.

     Section 2.  Audit Committee.  The Board of Directors may, by
resolution passed by a majority of the whole Board of Directors,
designate an Audit Committee consisting of one or more of the
directors of the Corporation, one of whom shall be designated
chairman of the Audit Committee. The Audit Committee shall have
and may exercise such powers and authority as provided in the
resolution creating it and as determined from time to time by the
Board of Directors.

     Section 3.  Other Committees.  The Board of Directors may, by
resolution passed from time to time by a majority of the whole
Board of Directors, designate such other committees as it shall
see fit consisting of one or more of the directors of the
Corporation, one of whom shall be designated chairman of each such
committee. Any such committee shall have and may exercise such
powers and authority as provided in the resolution creating it and
as determined from time to time by the Board of Directors.

     Section 4.  Procedure; Meetings; Quorum.  Any committee
designated pursuant to this Article IV shall keep regular minutes
of its actions and proceedings in a book provided for that purpose
and report the same to the Board of Directors at its meeting next
succeeding such action, shall fix its own rules or procedures, and
shall meet at such times and at such place or places as may be
provided by such rules, or by such committee or the Board of
Directors. Should a committee fail to fix its own rules, the
provisions of these Bylaws, pertaining to the calling of meetings
and conduct of business by the Board of Directors, shall apply as
nearly as may be. At every meeting of any such committee, the
presence of a majority of all the members thereof shall constitute
a quorum, except as provided in Section 5 of this Article IV, and
the affirmative vote of a majority of the members present shall be
necessary for the adoption by it of any resolution.

     Section 5.  Substitution and Removal of Members; Vacancies.
The Board of Directors may designate one or more directors as
alternate members of any committee, who may replace any absent or
disqualified member at any meeting of such committee. In the
absence or disqualification of a member of a committee, the member
or members present at any meeting and not disqualified from
voting, whether or not constituting a quorum, may unanimously
appoint another member of the Board of Directors to act at the
meeting in the place of the absent or disqualified member. The
Board of Directors shall have the power at any time to remove any
member(s) of a committee and to appoint other directors in lieu of
the person(s) so removed and shall also have the power to fill
vacancies in a committee.

                             Article V

                             Officers

     Section 1.  Number, Titles and Term of Office.  The officers
of the Corporation shall be a Chairman of the Board, a President,
a President-North American Operations, one or more Presidents-
International Operations, one or more Vice Presidents (any one or
more of whom may be designated Executive Vice President or Senior
Vice President), a General Counsel, a Treasurer, a Secretary and
such other officers as the Board of Directors may from time to
time elect or appoint (including, but not limited to, a Vice
Chairman of the Board, a Deputy Corporate Secretary, one or more
Assistant Secretaries and one or more Assistant Treasurers). Each
officer shall hold office until such officer's successor shall be
duly elected and shall qualify or until such officer's death or
until such officer shall resign or shall have been removed. Any
number of offices may be held by the same person, unless the
Certificate of Incorporation provides otherwise. Except for the
Chairman of the Board and the Vice Chairman of the Board, no
officer need be a director.

     Section 2.  Powers and Duties of the Chairman of the Board.
The Chairman of the Board shall be the chief executive officer of
the Corporation. Subject to the control of the Board of Directors
and the Executive Committee (if any), the Chairman of the Board
shall have general executive charge, management and control of the
properties, business and operations of the Corporation with all
such powers as may be reasonably incident to such
responsibilities; may agree upon and execute all leases,
contracts, evidences of indebtedness and other obligations in the
name of the Corporation and may sign all certificates for shares
of capital stock of the Corporation; and shall have such other
powers and duties as designated in accordance with these Bylaws
and as from time to time may be assigned to the Chairman of the
Board by the Board of Directors. The Chairman of the Board shall
preside at all meetings of the stockholders and of the Board of
Directors.

     Section 3.  Powers and Duties of the President, President-
North American Operations, and President-International Operations.

     (a)  Unless the Board of Directors otherwise determines, the
President shall have the authority to agree upon and execute all
leases, contracts, evidences of indebtedness and other obligations
in the name of the Corporation; and, unless the Board of Directors
otherwise determines, the President shall, in the absence of the
Chairman of the Board or if there be no Chairman of the Board,
preside at all meetings of the stockholders and (should the
President be a director) of the Board of Directors; and the
President shall have such other powers and duties as designated in
accordance with these Bylaws and as from time to time may be
assigned to the President by the Board of Directors or the
Chairman of the Board.

     (b)  Unless the Board of Directors otherwise determines, the
President-North American Operations shall have the authority to
agree upon and execute all leases, contracts, evidences of
indebtedness and other obligations in the name of the Corporation
pertaining to the Corporation's North American operations; and the
President-North American Operations shall have such other powers
and duties as designated in accordance with these Bylaws and as
from time to time may be assigned to the President-North American
Operations by the Board of Directors or the Chairman of the Board.

     (c)  Unless the Board of Directors otherwise determines, each
President-International Operations shall have the authority to
agree upon and execute all leases, contracts, evidences of
indebtedness and other obligations in the name of the Corporation
pertaining to the Corporation's international operations; and each
President-International Operations shall have such other powers
and duties as designated in accordance with these Bylaws and as
from time to time may be assigned to each President-International
Operations by the Board of Directors or the Chairman of the Board.

     Section 4.  Powers and Duties of the Vice Chairman of the
Board.  The Board of Directors may assign areas of responsibility
to the Vice Chairman of the Board, and, in such event, and subject
to the overall direction of the Chairman of the Board and Board of
Directors, the Vice Chairman of the Board shall be responsible for
supervising the management of the affairs of the Corporation and
its subsidiaries within the area or areas assigned and shall
monitor and review on behalf of the Board of Directors all
functions within the corresponding area or areas of the
Corporation and each such subsidiary of the Corporation. In the
absence of the President, or in the event of the President's
inability or refusal to act, the Vice Chairman of the Board shall
perform the duties of the President, and when so acting shall have
all the powers of and be subject to all the restrictions upon the
President. Further, the Vice Chairman of the Board shall have such
other powers and duties as designated in accordance with these
Bylaws and as from time to time may be assigned to the Vice
Chairman of the Board by the Board of Directors or the Chairman of
the Board.

     Section 5.  Vice Presidents.  Each Vice President shall at
all times possess power to sign all certificates, contracts and
other instruments of the Corporation, except as otherwise limited
in writing by the Chairman of the Board, the President or the Vice
Chairman of the Board or of the Corporation. Each Vice President
shall have such other powers and duties as from time to time may
be assigned to such Vice President by the Board of Directors, the
Chairman of the Board, the President or the Vice Chairman of the
Board.

     Section 6.  General Counsel.  The General Counsel shall act
as chief legal advisor to the Corporation. The General Counsel may
have one or more staff attorneys and assistants, and may retain
other attorneys to conduct the legal affairs and litigation of the
Corporation under the General Counsel's supervision.

     Section 7.  Secretary.  The Secretary shall keep the minutes
of all meetings of the Board of Directors, committees of the Board
of Directors and the stockholders, in books provided for that
purpose; shall attend to the giving and serving of all notices;
may in the name of the Corporation affix the seal of the
Corporation to all contracts of the Corporation and attest the
affixation of the seal of the Corporation thereto; may sign with
the other appointed officers all certificates for shares of
capital stock of the Corporation; shall have charge of the
certificate books, transfer books and stock ledgers, and such
other books and papers as the Board of Directors may direct, all
of which shall at all reasonable times be open to inspection of
any director upon application at the office of the Corporation
during business hours; shall have such other powers and duties as
designated in these Bylaws and as from time to time may be
assigned to the Secretary by the Board of Directors, the Chairman
of the Board, the President or the Vice Chairman of the Board; and
shall in general perform all acts incident to the office of
Secretary, subject to the control of the Board of Directors, the
Chairman of the Board, the President or the Vice Chairman of the
Board.

     Section 8. Deputy Corporate Secretary and Assistant
Secretaries.  The Deputy Corporate Secretary and each Assistant
Secretary shall have the usual powers and duties pertaining to
such offices, together with such other powers and duties as
designated in these Bylaws and as from time to time may be
assigned to the Deputy Corporate Secretary or an Assistant
Secretary by the Board of Directors, the Chairman of the Board,
the President, the Vice Chairman of the Board, or the Secretary.
The Deputy Corporate Secretary shall exercise the powers of the
Secretary during that officer's absence or inability or refusal to
act.

     Section 9.  Treasurer.  The Treasurer shall have
responsibility for the custody and control of all the funds and
securities of the Corporation, and shall have such other powers
and duties as designated in these Bylaws and as from time to time
may be assigned to the Treasurer by the Board of Directors, the
Chairman of the Board, the President or the Vice Chairman of the
Board. The Treasurer shall perform all acts incident to the
position of Treasurer, subject to the control of the Board of
Directors, the Chairman of the Board, the President and the Vice
Chairman of the Board; and the Treasurer shall, if required by the
Board of Directors, give such bond for the faithful discharge of
the Treasurer's duties in such form as the Board of Directors may
require.

     Section 10.  Assistant Treasurers.  Each Assistant Treasurer
shall have the usual powers and duties pertaining to such office,
together with such other powers and duties as designated in these
Bylaws and as from time to time may be assigned to each Assistant
Treasurer by the Board of Directors, the Chairman of the Board,
the President, the Vice Chairman of the Board, or the Treasurer.
The Assistant Treasurers shall exercise the powers of the
Treasurer during that officer's absence or inability or refusal to
act.

     Section 11.  Action with Respect to Securities of Other
Corporations.  Unless otherwise directed by the Board of
Directors, the Chairman of the Board, the President or the Vice
Chairman of the Board, together with the Secretary, the Deputy
Corporate Secretary or any Assistant Secretary shall have power to
vote and otherwise act on behalf of the Corporation, in person or
by proxy, at any meeting of security holders of or with respect to
any action of security holders of any other corporation in which
this Corporation may hold securities and otherwise to exercise any
and all rights and powers which this Corporation may possess by
reason of its ownership of securities in such other corporation.

     Section 12.  Delegation.  For any reason that the Board of
Directors may deem sufficient, the Board of Directors may, except
where otherwise provided by statute, delegate the powers or duties
of any officer to any other person, and may authorize any officer
to delegate specified duties of such officer to any other person.
Any such delegation or authorization by the Board shall be
effected from time to time by resolution of the Board of
Directors.

                            Article VI

                           Capital Stock

     Section 1.  Certificates of Stock.  The certificates for
shares of the capital stock of the Corporation shall be in such
form, not inconsistent with that required by law and the
Certificate of Incorporation, as shall be approved by the Board of
Directors. Every holder of stock represented by certificates shall
be entitled to have a certificate signed by or in the name of the
Corporation by the Chairman of the Board, President, Vice Chairman
of the Board or a Vice President and the Secretary, Deputy
Corporate Secretary or an Assistant Secretary or the Treasurer or
an Assistant Treasurer of the Corporation  representing the number
of shares (and, if the stock of the Corporation shall be divided
into classes or series, certifying the class and series of such
shares) owned by such stockholder which are registered in
certified form; provided, however, that any of or all the
signatures on the certificate may be facsimile. The stock record
books and the blank stock certificate books shall be kept by the
Secretary, or at the office of such transfer agent or transfer
agents as the Board of Directors may from time to time determine.
In case any officer, transfer agent or registrar who shall have
signed or whose facsimile signature or signatures shall have been
placed upon any such certificate or certificates shall have ceased
to be such officer, transfer agent or registrar before such
certificate is issued by the Corporation, such certificate may
nevertheless be issued by the Corporation with the same effect as
if such person were such officer, transfer agent or registrar at
the date of issue. The stock certificates shall be consecutively
numbered and shall be entered in the books of the Corporation as
they are issued and shall exhibit the holder's name and number of
shares.

     Section 2.  Transfer of Shares.  The shares of stock of the
Corporation shall be transferable only on the books of the
Corporation by the holders thereof in person or by their duly
authorized attorneys or legal representatives upon surrender and
cancellation of certificates for a like number of shares. Upon
surrender to the Corporation or a transfer agent of the
Corporation of a certificate for shares duly endorsed or
accompanied by proper evidence of succession, assignment or
authority to transfer, it shall be the duty of the Corporation to
issue a new certificate to the person entitled thereto, cancel the
old certificate and record the transaction upon its books.

     Section 3.  Ownership of Shares.   The Corporation shall be
entitled to treat the holder of record of any share or shares of
capital stock of the Corporation as the holder in fact thereof
and, accordingly, shall not be bound to recognize any equitable or
other claim to or interest in such share or shares on the part of
any other person, whether or not it shall have express or other
notice thereof, except as otherwise provided by the laws of the
state of incorporation of the Corporation.

     Section 4.  Regulations Regarding Certificates.  The Board of
Directors shall have the power and authority to make all such
rules and regulations as they may deem expedient concerning the
issue, transfer and registration or the replacement of
certificates for shares of capital stock of the Corporation.

     Section 5.  Lost or Destroyed Certificates.  The Board of
Directors may determine the conditions upon which the Corporation
may issue a new certificate of stock in place of a certificate
theretofore issued by it which is alleged to have been lost,
stolen or destroyed and may require the owner of such certificate
or such owner's legal representative to give bond, with surety
sufficient to indemnify the Corporation and each transfer agent
and registrar against any and all losses or claims which may arise
by reason of the alleged loss, theft or destruction of any such
certificate or the issuance of such new certificate in the place
of the one so lost, stolen or destroyed.

                            Article VII

                     Miscellaneous Provisions

     Section 1.  Fiscal Year.  The fiscal year of the Corporation
shall begin on the first day of January of each year.

     Section 2.  Corporate Seal.  The corporate seal shall be
circular in form and shall have inscribed thereon the name of the
Corporation and the state of its incorporation, which seal shall
be in the charge of the Secretary and shall be affixed to
certificates of stock, debentures, bonds, and other documents, in
accordance with the direction of the Board of Directors or a
committee thereof, and as may be required by law; however, the
Secretary may, if the Secretary deems it expedient, have a
facsimile of the corporate seal inscribed on any such certificates
of stock, debentures, bonds, contracts or other documents.
Duplicates of the seal may be kept for use by the Deputy Corporate
Secretary or any Assistant Secretary.

     Section 3.  Notice and Waiver of Notice.  Whenever any notice
is required to be given by law, the Certificate of Incorporation
or under the provisions of these Bylaws, said notice shall be
deemed to be sufficient if given (i) by telegraphic, cable or
wireless transmission (including by telecopy or facsimile
transmission) or (ii) by deposit of the same in a post office box
or by delivery to an overnight courier service company in a sealed
prepaid wrapper addressed to the person entitled thereto at such
person's post office address, as it appears on the records of the
Corporation, and such notice shall be deemed to have been given on
the day of such transmission or mailing or delivery to courier, as
the case may be.

     Whenever notice is required to be given by law, the
Certificate of Incorporation or under any of the provisions of
these Bylaws, a written waiver thereof, signed by the person
entitled to notice, whether before or after the time stated
therein, shall be deemed equivalent to notice. Attendance of a
person, including without limitation a director, at a meeting
shall constitute a waiver of notice of such meeting, except when
the person attends a meeting for the express purpose of objecting,
at the beginning of the meeting, to the transaction of any
business because the meeting is not lawfully called or convened.
Neither the business to be transacted at, nor the purpose of, any
regular or special meeting of the stockholders, directors, or
members of a committee of directors need be specified in any
written waiver of notice unless so required by the Certificate of
Incorporation or these Bylaws.

     Section 4.  Facsimile Signatures.  In addition to the
provisions for the use of facsimile signatures elsewhere
specifically authorized in these Bylaws, facsimile signatures of
any officer or officers of the Corporation may be used whenever
and as authorized by the Board of Directors.

     Section 5.  Reliance upon Books, Reports and Records.  A
member of the Board of Directors, or a member of any committee
designated by the Board of Directors, shall, in the performance of
such person's duties, be fully protected in relying in good faith
upon the records of the Corporation and upon such information,
opinion, reports or statements presented to the Corporation by any
of the Corporation's officers or employees, or committees of the
Board of Directors, or by any other person as to matters the
member reasonably believes are within such other person's
professional or expert competence and who has been selected with
reasonable care by or on behalf of the Corporation.

     Section 6.  Application of Bylaws.  In the event that any
provisions of these Bylaws is or may be in conflict with any law
of the United States, of the state of incorporation of the
Corporation or of any other governmental body or power having
jurisdiction over this Corporation, or over the subject matter to
which such provision of these Bylaws applies, or may apply, such
provision of these Bylaws shall be inoperative to the extent only
that the operation thereof unavoidably conflicts with such law,
and shall in all other respects be in full force and effect.

                           Article VIII

                            Amendments

     The Board of Directors shall have the power to adopt, amend
and repeal from time to time Bylaws of the Corporation, subject to
the right of the stockholders entitled to vote with respect
thereto to amend or repeal such Bylaws as adopted or amended by
the Board of Directors.

EX-10

                                                 EXHIBIT 10.12(b)



                       FIRST AMENDMENT TO
                EOG RESOURCES, INC. SAVINGS PLAN

     THIS AGREEMENT, by EOG Resources, Inc. (the "Sponsor"),

                           WITNESSETH:

     WHEREAS, the Sponsor maintains the EOG Resources, Inc.
Savings Plan (the "Plan");

     WHEREAS, the Sponsor retained the right in Section 13.1 of
the Plan to amend the Plan from time to time;

     WHEREAS, the Plan is required to be amended to comply with
final and temporary regulations promulgated under
section 401(a)(9) of the Internal Revenue Code of 1986, as
amended (the "Code"), on April 17, 2002; and

     WHEREAS, the Board of Directors of the Sponsor approved
resolutions authorizing the proper officers of the Sponsor to
amend the Plan to comply with the requirements of the Code;

     NOW, THEREFORE, the Plan is hereby amended, effective
January 1, 2003, except as otherwise required by applicable law
or as provided in the applicable provisions of the Plan, as
follows:

          A new Article XVII is hereby added to the Plan to
     provide as set forth in the substitute pages attached
     hereto which shall be inserted into the Plan
     immediately following Article XVI of the Plan.

     IN WITNESS WHEREOF, the Sponsor has executed this Agreement
this 15th day of December 2003.

                              EOG RESOURCES, INC.



                              By:   /s/ PATRICIA EDWARDS
                                        Patricia Edwards

                              Title: V.P. Human Resources,
                                      Administration and
                                      Corporate Secretary


                          ARTICLE XVII

                MINIMUM DISTRIBUTION REQUIREMENTS

          17.1 General Rules

          (a)  Effective Date.  The provisions of this Article will apply
     for purposes of determining required minimum distributions for
     calendar years beginning with the 2003 calendar year.

          (b)  Precedence.  The requirements of this Article will take
     precedence over any inconsistent provisions of the Plan.

          (c)  Requirements of Treasury Regulations Incorporated.  All
     distributions required under this Article will be determined and
     made in accordance with the Treasury regulations under
     section 401(a)(9) of the Code.

          (d)  TEFRA Section 242(b)(2) Elections.  Notwithstanding the
     other provisions of this Article, distributions may be made under
     a designation made before January 1, 1984, in accordance with
     section 242(b)(2) of the Tax Equity and Fiscal Responsibility Act
     ("TEFRA") and the provisions of the Plan that relate to
     section 242(b)(2) of TEFRA.

          17.2 Time and Manner of Distribution.

          (a)  Required Beginning Date.  The Member's entire interest will
     be distributed, or begin to be distributed, to the Member no
     later than the Member's Required Beginning Date.

          (b)  Death of Participant Before Distributions Begin.  If the
     Member dies before distributions begin, the Member's entire
     interest will be distributed, or begin to be distributed, no
     later than as follows:

               (i) If the Member's surviving spouse is the Member's sole
          Designated Beneficiary, then distributions to the surviving
          spouse will begin by December 31 of the calendar year immediately
          following the calendar year in which the Member died, or by
          December 31 of the calendar year in which the Member would have
          attained age 70 1/2, if later.

               (ii) If the Member's surviving spouse is not the Member's sole
          Designated Beneficiary, then distributions to the Designated
          Beneficiary will begin by December 31 of the calendar year
          immediately following the calendar year in which the Member died.

               (iii) If there is no Designated Beneficiary as of
          September 30 of the year following the year of the Member's
          death, the Member's entire interest will be distributed by
          December 31 of the calendar year containing the fifth anniversary
          of the Member's death.

               (iv) If the Member's surviving spouse is the Member's sole
          Designated Beneficiary and the surviving spouse dies after the
          Member but before distributions to the surviving spouse begin,
          this Section 17.2(b)(iv), other than Section 17.2(b)(i), will
          apply as if the surviving spouse were the Member.

               For purposes of this Section 17.2(b) and
          Section 17.4, unless Section 17.2(b)(iv) applies,
          distributions are considered to begin on the Member's
          Required Beginning Date.  If Section 17.2(b)(iv)
          applies, distributions are considered to begin on the
          date distributions are required to begin to the
          surviving spouse under Section 17.2(b)(i).  If
          distributions under an annuity purchased from an
          insurance company irrevocably commence to the Member
          before the Member's Required Beginning Date (or to the
          Member's surviving spouse before the date distributions
          are required to begin to the surviving spouse under
          Section 17.2(b)(i)), the date distributions are
          considered to begin is the date distributions actually
          commence.

          (c)  Forms of Distribution.  Unless the Member's interest is
     distributed in the form of an annuity purchased from an insurance
     company or in a single sum on or before the Required Beginning
     Date, as of the first Distribution Calendar Year distributions
     will be made in accordance with Sections 17.3 and 17.4.  If the
     Member's interest is distributed in the form of an annuity
     purchased from an insurance company, distributions thereunder
     will be made in accordance with the requirements of
     section 401(a)(9) of the Code and the Treasury regulations.

          17.3 Required Minimum Distributions During Participant's Lifetime.

          (a)  Amount of Required Minimum Distribution For Each
     Distribution Calendar Year.  During the Member's lifetime, the
     minimum amount that will be distributed for each Distribution
     Calendar Year is the lesser of:

               (i)  the quotient obtained by dividing the Participant's Account
          Balance by the distribution period in the Uniform Lifetime Table
          set forth in section 1.401(a)(9)-9 of the Treasury regulations,
          using the Member's age as of the Member's birthday in the
          Distribution Calendar Year; or

               (ii) if the Member's sole Designated Beneficiary for the
          Distribution Calendar Year is the Member's spouse, the quotient
          obtained by dividing the Participant's Account Balance by the
          number in the Joint and Last Survivor Table set forth in
          section 1.401(a)(9)-9 of the Treasury regulations, using the
          Member's and spouse's attained ages as of the Member's and
          spouse's birthdays in the Distribution Calendar Year.

          (b)  Lifetime Required Minimum Distributions Continue Through
     Year of Participant's Death.  Required minimum distributions will
     be determined under this Section 17.3 beginning with the first
     Distribution Calendar Year and up to and including the
     Distribution Calendar Year that includes the Member's date of
     death.


          17.4 Required Minimum Distributions After Participant's Death.

          (a)  Death On or After Date Distributions Begin.

               (i)  Participant Survived by Designated Beneficiary.  If the
          Member dies on or after the date distributions begin and there is
          a Designated Beneficiary, the minimum amount that will be
          distributed for each Distribution Calendar Year after the year of
          the Member's death is the quotient obtained by dividing the
          Participant's Account Balance by the longer of the remaining Life
          Expectancy of the Member or the remaining Life Expectancy of the
          Member's Designated Beneficiary, determined as follows:

                    (1)  The Member's remaining Life Expectancy is calculated
                    using the age of the Member in the year of death, reduced
                    by one for each subsequent year.

                    (2)  If the Member's surviving spouse is the Member's sole
               Designated Beneficiary, the remaining Life Expectancy of the
               surviving spouse is calculated for each Distribution Calendar
               Year after the year of the Member's death using the surviving
               spouse's age as of the spouse's birthday in that year.  For
               Distribution Calendar Years after the year of the surviving
               spouse's death, the remaining Life Expectancy of the surviving
               spouse is calculated using the age of the surviving spouse as
               of the spouse's birthday in the calendar year of the spouse's
               death, reduced by one for each subsequent calendar year.

                    (3)  If the Member's surviving spouse is not the Member's
                    sole Designated Beneficiary, the Designated Beneficiary's
                    remaining Life Expectancy is calculated using the age of
                    the beneficiary in the year following the year of the
                    Member's death, reduced by one for each subsequent year.

               (ii) No Designated Beneficiary.  If the Member dies on or after
          the date distributions begin and there is no Designated
          Beneficiary as of September 30 of the year after the year of the
          Member's death, the minimum amount that will be distributed for
          each Distribution Calendar Year after the year of the Member's
          death is the quotient obtained by dividing the Participant's
          Account Balance by the Member's remaining Life Expectancy
          calculated using the age of the Member in the year of death,
          reduced by one for each subsequent year.

          (b)  Death Before Date Distributions Begin.

               (i)  Five-Year Default Rule.  If the Member dies before the date
          distributions begin, distribution of the Member's entire interest
          will be completed by December 31 of the calendar year containing
          the fifth anniversary of the Member's death.

               (ii) Death of Surviving Spouse Before Distributions to Surviving
          Spouse Are Required to Begin.  If the Member dies before the date
          distributions begin, the Member's surviving spouse is the
          Member's sole Designated Beneficiary, and the surviving spouse
          dies before distributions are required to begin to the surviving
          spouse under Section 17.2(b)(i), this Section 17.4(b) will apply
          as if the surviving spouse were the Member.

          17.5 Definitions.

          (a)  Designated Beneficiary.  The individual who is designated as
     the beneficiary under Section 6.2 and is the designated
     beneficiary under section 401(a)(9) of the Code and
     section 1.401(a)(9)-1, Q&A-4, of the Treasury regulations.

          (b)  Distribution Calendar Year.  A calendar year for which a
     minimum distribution is required.   For distributions beginning
     before the Member's death, the first Distribution Calendar Year
     is the calendar year immediately preceding the calendar year
     which contains the Member's Required Beginning Date.  For
     distributions beginning after the Member's death, the first
     Distribution Calendar Year is the calendar year in which
     distributions are required to begin under Section 17.2(b).  The
     required minimum distribution for the Member's first Distribution
     Calendar Year will be made on or before the Member's Required
     Beginning Date.  The required minimum distribution for other
     Distribution Calendar Years, including the required minimum
     distribution for the Distribution Calendar Year in which the
     Member's Required Beginning Date occurs, will be made on or
     before December 31 of that Distribution Calendar Year.

          (c)  Life Expectancy.  Life expectancy as computed by use of the
     Single Life Table in section 1.401(a)(9)-9 of the Treasury
     regulations.

          (d)  Participant's Account Balance.  The account balance as of
     the last valuation date in the calendar year immediately
     preceding the Distribution Calendar Year (valuation calendar
     year) increased by the amount of any contributions made and
     allocated or forfeitures allocated to the account balance as of
     dates in the valuation calendar year after the valuation date and
     decreased by distributions made in the valuation calendar year
     after the valuation date.  The account balance for the valuation
     calendar year includes any amounts rolled over or transferred to
     the Plan either in the valuation calendar year or in the
     Distribution Calendar Year if distributed or transferred in the
     valuation calendar year.

          (e)  Required Beginning Date.  The date specified in
     Section 6.13.

EX-12

                                                            EXHIBIT 12



                          EOG RESOURCES, INC.
 Computation of Ratio of Earnings to Fixed Charges and Combined Fixed
                    Charges and Preferred Dividends
                            (In Thousands)
                              (Unaudited)




                                                        Year Ended December 31,
                                           2003        2002      2001       2000       1999

                                                                      
EARNINGS AVAILABLE FOR
FIXED CHARGES:
Net Income Before Cumulative Effect of
 Change in Accounting Principle (1)      $437,276   $ 87,173   $398,616   $396,931   $569,094
Less:  Capitalized Interest Expense        (8,541)    (8,987)    (8,646)    (6,708)   (10,594)
Add:  Fixed Charges                        74,661     75,497     60,468     72,833     77,837
Income Tax Provision (Benefit)            216,600     32,499    232,829    236,626     (1,382)
EARNINGS AVAILABLE                       $719,996   $186,182   $683,267   $699,682   $634,955


FIXED CHARGES:
Interest Expense                         $ 58,711   $ 59,654   $ 45,110   $ 61,006   $ 61,819
Capitalized Interest Expense                8,541      8,987      8,646      6,708     10,594
Rental Expense Representative of
 Interest Factor                            7,409      6,856      6,712      5,119      5,424
TOTAL FIXED CHARGES                        74,661     75,497     60,468     72,833     77,837
Preferred Dividends on a Pre-tax Basis     16,497     15,145     17,416     17,602        660
COMBINED TOTAL FIXED CHARGES AND
 PREFERRED DIVIDENDS                     $ 91,158   $ 90,642   $ 77,884   $ 90,435   $ 78,497

RATIO OF EARNINGS TO
FIXED CHARGES                                9.64       2.47      11.30       9.61       8.16

RATIO OF EARNINGS TO
COMBINED FIXED CHARGES
AND PREFERRED DIVIDENDS                      7.90       2.05       8.77       7.74       8.09


(1) EOG adopted Statement of Financial Accounting Standards (SFAS)
    No. 143 - "Accounting for Asset Retirement Obligations" on January
    1, 2003.  Pro forma net income for 2002 through 1999 is not
    presented since the pro forma application of SFAS No. 143 to the
    prior periods would not result in pro forma net income materially
    different from the actual amount reported.

EX-21

                                                       EXHIBIT 21

         EOG Resources, Inc. and Subsidiaries

                 As of March 10, 2004



     Company Name                           Place Of Incorporation

EOG Resources, Inc.                                 Delaware
EOG Resources - Carthage, Inc.                      Delaware
EOG Resources Investments, Inc.                     Delaware
EOG Resources Property Management, Inc.             Delaware
EOG Resources Acquisitions L.P.                     Delaware
ERSO, Inc.                                          Texas
EOG Expat Services, Inc.                            Delaware
EOG Resources Marketing, Inc.                       Delaware
EOG - Canada, Inc.                                  Delaware
EOG Company of Canada                               Nova Scotia
EOG Canada Company Ltd.                             Alberta
EOG Canada Holdings I Inc.                          Alberta
EOG Canada Holdings II Inc.                         Alberta
EOG Finance Canada Company                          Nova Scotia
EOG Resources Canada Company                        Nova Scotia
EOG Resources Canada Inc.                           Alberta
EOG Resources Canada (a partnership between
 EOG Resources Canada Inc., Managing Partner
 and EOG Resources Canada Company)                  Alberta
Nilo Operating Company                              Delaware
EOG Resources - Callaghan, Inc.                     Delaware
Online Energy Solutions, Inc.                       Delaware
EOG Resources Holdings LLC                          Delaware
EOG Resources Properties LLC                        Delaware
Belring Company (a Texas Limited Partnership)       Texas
Big Sky Ranches, Inc.                               Delaware
EOG Resources Appalachian LLC                       Delaware
EOG Resources East Texas L.P.                       Delaware
Energy Search, Incorporated                         Tennessee
O P Operating Company                               Delaware
EOG Resources International, Inc.                   Delaware
EOG Resources Trinidad - LRL Limited                Nevis
EOG Resources Trinidad - LRL Unlimited              Trinidad
EOG Resources Abu Dhabi Ltd.                        Cayman Islands
EOG Resources Bangladesh Ltd.                       Cayman Islands
EOGI - Mozambique, Inc.                             Delaware
EOG Resources Mozambique, Ltd.                      Cayman Islands
EOG Resources Nitro2000 Ltd.                        Nevis
EOGI - Trinidad, Inc.                               Delaware
EOGI Trinidad Company                               Cayman Islands
EOG Resources Trinidad Limited                      Trinidad
EOG Resources Capital Management I, Ltd.            Cayman Islands
Wilsyx International Finance B.V.                   The Netherlands
EOGI Company of Trinidad                            Cayman Islands
Harfin Capital and Finance Ltd.                     Cayman Islands
OCC Investment Company Ltd.                         Cayman Islands
Murrott Capital Ltd.                                Nevis
EOGI Trinidad - U(a) Block Company                  Cayman Islands
EOG Resources Trinidad - U(a) Block Limited         Cayman Islands
EOG Resources United Kingdom Limited                UK
EOGI - Venezuela, Inc.                              Delaware
EOGI - Venezuela (Guarico), Inc.                    Delaware
EOG Resources Nevis U(b) Block Limited              Nevis
EOG Resources Trinidad U(b) Block Unlimited         Trinidad
EOG Resources Egypt GHZ Ltd.                        Cayman Islands
EOGI Egypt GHZ Ltd.                                 Cayman Islands
EOG Resources Egypt WS Ltd.                         Cayman Islands
EOGI Egypt WS Ltd.                                  Cayman Islands
EOG Resources (Nevis) Block 4 (a) Limited           Nevis

EX-23

                                                Exhibit 23.1

                  DeGolyer and MacNaughton
              4925 Greenville Avenue, Suite 400
                      One Energy Square
                     Dallas, Texas 75206

                       March 11, 2004





EOG Resources, Inc.
333 Clay Street, Suite 4200
Houston, Texas 77002


Gentlemen:

     We hereby consent to the inclusion of references to our
firm and to the opinions as mentioned below delivered to EOG
Resources, Inc. (EOG) regarding our comparison of estimates
prepared by us with those furnished to us by EOG of the
proved oil, condensate, natural gas liquids, and natural gas
reserves of certain selected properties owned by EOG in the
section "Supplemental Information to Consolidated Financial
Statements - Oil and Gas Producing Activities" in EOG's
current Report on Form 8-K filed with the United States
Securities and Exchange Commission (SEC) on February 24,
2004 (the Form 8-K filed on February 24, 2004). The opinions
are contained in our letter reports dated January 25, 2002,
January 31, 2003, and March 1, 2004, for estimates as of
December 31, 2001, December 31, 2002, and December 31, 2003,
respectively. That section of the Form 8-K filed on February
24, 2004, is in turn incorporated by reference in Item 14 of
EOG's Annual Report on Form 10-K for the year ended December
31, 2003, to be filed with the SEC. Additionally, we hereby
consent to the incorporation by reference of such references
to our firm and to our opinions in EOG's previously filed
Registration Statement Nos. 33-48358, 33-52201, 33-58103,
33-62005, 333-09919, 333-20841, 333-18511, 333-31715,
333-44785, 333-69483, 333-46858, 333-62256, 333-63184,
333-84014, and 333-88924.

                              Very truly yours,



                              DeGOLYER and MacNAUGHTON

EX-23

                                                Exhibit 23.2

                  DeGolyer and MacNaughton
              4925 Greenville Avenue, Suite 400
                      One Energy Square
                     Dallas, Texas 75206

                        March 1, 2004





EOG Resources, Inc.
333 Clay Street, Suite 4200
Houston, Texas 77002


Gentlemen:

     Pursuant to your request, we have prepared estimates of
the proved crude oil, condensate, natural gas liquids, and
natural gas reserves, as of December 31, 2003, of certain
selected properties in the United States, Canada, Trinidad,
and the United Kingdom owned by EOG Resources, Inc. (EOG).
The properties consist of working and royalty interests
located in California, New Mexico, Texas, Utah, and Wyoming
and offshore from Texas, Louisiana, and Alabama; in Alberta
and Saskatchewan, Canada; offshore from Trinidad; and
offshore from the United Kingdom. The estimates are reported
in detail in our "Report as of December 31, 2003 on Proved
Reserves of Certain Properties in the United States owned by
EOG Resources, Inc. Selected Properties," our "Report as of
December 31, 2003 on Proved Reserves of Certain Properties
in Canada owned by EOG Resources, Inc. Selected Properties,"
our "Report as of December 31, 2003 of the U(A) Block
Offshore Trinidad owned by EOG Resources, Inc.," our "Report
as of December 31, 2003 of the SECC and U(B) Blocks Offshore
Trinidad owned by EOG Resources, Inc.," and our "Report as
of December 31, 2003 on Reserves of the Valkyrie and East
Camelot Fields Offshore United Kingdom owned by EOG
Resources, Inc.," hereinafter collectively referred to as
the "Reports." We also have reviewed information provided to
us by EOG that it represents to be EOG's estimates of the
reserves, as of December 31, 2003, for the same properties
as those included in the Reports.

     Proved reserves estimated by us and referred to herein
are judged to be economically producible in future years
from known reservoirs under existing economic and operating
conditions and assuming continuation of current regulatory
practices using conventional production methods and
equipment. Proved reserves are defined as those that have
been proved to a high degree of certainty by reason of
actual completion, successful testing, or in certain
cases by adequate core analyses and electrical-log
interpretation when the producing characteristics of the
formation are known from nearby fields. These reserves are
defined areally by reasonable geological interpretation of
structure and known continuity of oil- or gas-saturated
material. This definition is in agreement with the
definition of proved reserves prescribed by the Securities
and Exchange Commission (SEC).

     EOG represents that its estimates of the proved
reserves, as of December 31, 2003, net to its interests in
the properties included in the Reports are as follows,
expressed in thousands of barrels (Mbbl) or millions of
cubic feet (MMcf):

     Oil, Condensate, and    Natural        Net
     Natural Gas Liquids       Gas       Equivalent
           (Mbbl)            (MMcf)        (MMcf)


           59,228           3,392,292     3,747,663

     Note: Net equivalent million cubic feet is based
           on 1 barrel of oil, condensate, or natural
           gas liquids being equivalent to 6,000
           cubic feet of gas (affected by rounding).

     EOG has advised us, and we have assumed, that its
estimates of proved oil, condensate, natural gas liquids,
and natural gas reserves are in accordance with the rules
and regulations of the SEC. The reserves estimated above are
amended by EOG to correct a typographical error shown in our
letter dated January 30, 2004.

     Proved reserves net to EOG's interests estimated by us
for the properties included in the Reports, as of December
31, 2003, are as follows, expressed in thousands of barrels
(Mbbl) or millions of cubic feet (MMcf):

     Oil, Condensate, and    Natural       Net
     Natural Gas Liquids       Gas      Equivalent
           (Mbbl)            (MMcf)       (MMcf)

           55,793           3,279,785    3,614,543

     Note: Net equivalent million cubic feet is based on
           1 barrel of oil, condensate, or natural gas
           liquids being equivalent to 6,000 cubic feet
           of gas.

     In making a comparison of the detailed reserves
estimates prepared by us and by EOG of the properties
involved, we have found differences, both positive and
negative, in  reserves  estimates for individual properties.
These  differences  appear to be compensating to a great
extent when considering the reserves of EOG in the properties
included in the Reports, resulting in overall differences not
being substantial. It is our opinion that the reserves estimates
prepared by EOG on the properties reviewed by us and
referred to above, when compared on the basis of net
equivalent million cubic feet of gas, do not differ
materially from those prepared by us.

                              Submitted,




                              DeGOLYER and MacNAUGHTON

EX-23

                                                EXHIBIT 23.3


          CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS


We consent to the incorporation by reference in Registration
Statements No. 33-48358, 33-52201, 33-58103, 33-62005, 333-
09919, 333-20841, 333-18511, 333-31715, 333-46858, 333-
44785, 333-69483, 333-62256, 333-63184, 333-84014, and 333-
88924 of EOG Resources, Inc. on Form S-3 and Form S-8 of our
report dated February 23, 2004, appearing in this Annual
Report on Form 10-K of EOG Resources, Inc. for the year
ended December 31, 2003.


                                  DELOITTE & TOUCHE LLP

Houston, Texas
March 11, 2004

EX-24

                                                  EXHIBIT 24

                      POWER OF ATTORNEY



     KNOW ALL MEN BY THESE PRESENTS, that in connection with
the filing by EOG Resources, Inc., a Delaware corporation
(the "Company") of its Annual Report on Form 10-K for the
year ended December 31, 2003 with the Securities and
Exchange Commission, the undersigned director of the Company
hereby constitutes and appoints Barry Hunsaker, Jr. and
Patricia L. Edwards, and each of them (with full power to
each of them to act alone), his true and lawful attorney-in-
fact and agent, for him and on his behalf and in his name,
place and stead, in any and all capacities, to sign, execute
and file such Annual Report on Form 10-K, together with any
amendments or supplements thereto, with all exhibits and any
and all documents required to be filed with respect thereto
with any regulatory authority, granting unto said attorneys,
and each of them, full power and authority to do and perform
each and every act and action requisite and necessary to be
done in and about the premises in order to effectuate the
same as fully to all intents and purposes as the undersigned
might or could do if personally present, hereby ratifying
and confirming all the said attorneys-in-fact and agents, or
any of them, may lawfully do or cause to be done by virtue
hereof.

     IN WITNESS WHEREOF, the undersigned has hereto set his
hand this 7th day of March, 2004.



                              /s/ GEORGE A. ALCORN
                                  George A. Alcorn



                      POWER OF ATTORNEY



     KNOW ALL MEN BY THESE PRESENTS, that in connection with
the filing by EOG Resources, Inc., a Delaware corporation
(the "Company") of its Annual Report on Form 10-K for the
year ended December 31, 2003 with the Securities and
Exchange Commission, the undersigned director of the Company
hereby constitutes and appoints Barry Hunsaker, Jr. and
Patricia L. Edwards, and each of them (with full power to
each of them to act alone), his true and lawful attorney-in-
fact and agent, for him and on his behalf and in his name,
place and stead, in any and all capacities, to sign, execute
and file such Annual Report on Form 10-K, together with any
amendments or supplements thereto, with all exhibits and any
and all documents required to be filed with respect thereto
with any regulatory authority, granting unto said attorneys,
and each of them, full power and authority to do and perform
each and every act and action requisite and necessary to be
done in and about the premises in order to effectuate the
same as fully to all intents and purposes as the undersigned
might or could do if personally present, hereby ratifying
and confirming all the said attorneys-in-fact and agents, or
any of them, may lawfully do or cause to be done by virtue
hereof.

     IN WITNESS WHEREOF, the undersigned has hereto set his
hand this 3rd day of March, 2004.



                              /s/ CHARLES R. CRISP
                                  Charles R. Crisp



                      POWER OF ATTORNEY



     KNOW ALL MEN BY THESE PRESENTS, that in connection with
the filing by EOG Resources, Inc., a Delaware corporation
(the "Company") of its Annual Report on Form 10-K for the
year ended December 31, 2003 with the Securities and
Exchange Commission, the undersigned director of the Company
hereby constitutes and appoints Barry Hunsaker, Jr. and
Patricia L. Edwards, and each of them (with full power to
each of them to act alone), his true and lawful attorney-in-
fact and agent, for him and on his behalf and in his name,
place and stead, in any and all capacities, to sign, execute
and file such Annual Report on Form 10-K, together with any
amendments or supplements thereto, with all exhibits and any
and all documents required to be filed with respect thereto
with any regulatory authority, granting unto said attorneys,
and each of them, full power and authority to do and perform
each and every act and action requisite and necessary to be
done in and about the premises in order to effectuate the
same as fully to all intents and purposes as the undersigned
might or could do if personally present, hereby ratifying
and confirming all the said attorneys-in-fact and agents, or
any of them, may lawfully do or cause to be done by virtue
hereof.

     IN WITNESS WHEREOF, the undersigned has hereto set his
hand this 5th day of March, 2004.



                              /s/ EDWARD RANDALL, III
                                  Edward Randall, III



                      POWER OF ATTORNEY



     KNOW ALL MEN BY THESE PRESENTS, that in connection with
the filing by EOG Resources, Inc., a Delaware corporation
(the "Company") of its Annual Report on Form 10-K for the
year ended December 31, 2003 with the Securities and
Exchange Commission, the undersigned director of the Company
hereby constitutes and appoints Barry Hunsaker, Jr. and
Patricia L. Edwards, and each of them (with full power to
each of them to act alone), his true and lawful attorney-in-
fact and agent, for him and on his behalf and in his name,
place and stead, in any and all capacities, to sign, execute
and file such Annual Report on Form 10-K, together with any
amendments or supplements thereto, with all exhibits and any
and all documents required to be filed with respect thereto
with any regulatory authority, granting unto said attorneys,
and each of them, full power and authority to do and perform
each and every act and action requisite and necessary to be
done in and about the premises in order to effectuate the
same as fully to all intents and purposes as the undersigned
might or could do if personally present, hereby ratifying
and confirming all the said attorneys-in-fact and agents, or
any of them, may lawfully do or cause to be done by virtue
hereof.

     IN WITNESS WHEREOF, the undersigned has hereto set his
hand this 4th day of March, 2004.



                              /s/ DONALD F. TEXTOR
                                  Donald F. Textor



                      POWER OF ATTORNEY



     KNOW ALL MEN BY THESE PRESENTS, that in connection with
the filing by EOG Resources, Inc., a Delaware corporation
(the "Company") of its Annual Report on Form 10-K for the
year ended December 31, 2003 with the Securities and
Exchange Commission, the undersigned director of the Company
hereby constitutes and appoints Barry Hunsaker, Jr. and
Patricia L. Edwards, and each of them (with full power to
each of them to act alone), his true and lawful attorney-in-
fact and agent, for him and on his behalf and in his name,
place and stead, in any and all capacities, to sign, execute
and file such Annual Report on Form 10-K, together with any
amendments or supplements thereto, with all exhibits and any
and all documents required to be filed with respect thereto
with any regulatory authority, granting unto said attorneys,
and each of them, full power and authority to do and perform
each and every act and action requisite and necessary to be
done in and about the premises in order to effectuate the
same as fully to all intents and purposes as the undersigned
might or could do if personally present, hereby ratifying
and confirming all the said attorneys-in-fact and agents, or
any of them, may lawfully do or cause to be done by virtue
hereof.

     IN WITNESS WHEREOF, the undersigned has hereto set his
hand this 5th day of March, 2004.



                              /s/ FRANK G. WISNER
                                  Frank G. Wisner

EX-31

                                                     Exhibit 31.1

                         CERTIFICATIONS


I, Mark G. Papa, the Principal Executive Officer of EOG
Resources, Inc., a Delaware corporation, certify that:

1.   I have reviewed this annual report on Form 10-K of EOG
Resources, Inc.;

2.   Based on my knowledge, this report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other
financial information included in this report, fairly present in
all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the
periods presented in this report;

4.   The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) for the registrant and have:

     a) designed such disclosure controls and procedures, or
     caused such disclosure controls and procedures to be
     designed under our supervision, to ensure that material
     information relating to the registrant, including its
     consolidated subsidiaries, is made known to us by
     others within those entities, particularly during the
     period in which this report is being prepared;

     b) [Paragraph omitted in accordance with SEC transition
     instructions contained in SEC Release 34-47986]

     c) evaluated the effectiveness of the registrant's
     disclosure controls and procedures and presented in
     this report our conclusions about the effectiveness of
     the disclosure controls and procedures, as of the end
     of the period covered by this report based on such
     evaluation; and

     d) disclosed in this report any change in the
     registrant's internal control over financial reporting
     that occurred during the registrant's most recent
     fiscal quarter (the registrant's fourth fiscal quarter
     in the case of an annual report) that has materially
     affected, or is reasonably likely to materially affect,
     the registrant's internal control over financial
     reporting.

5.   The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors
and the audit committee of registrant's board of directors (or
persons performing the equivalent functions):

     a) all significant deficiencies and material weaknesses
     in the design or operation of internal control over
     financial reporting which are reasonably likely to
     adversely affect the registrant's ability to record,
     process, summarize and report financial information;
     and

     b) any fraud, whether or not material, that involves
     management or other employees who have a significant
     role in the registrant's internal control over
     financial reporting.

Date:  March 11, 2004

/s/ MARK G. PAPA
    Mark G. Papa
    Chairman of the Board and Chief Executive Officer
    (Principal Executive Officer)

EX-31

                                                     Exhibit 31.2

                         CERTIFICATIONS


I, Edmund P. Segner, III, the Principal Financial Officer of EOG
Resources, Inc., a Delaware corporation, certify that:

1.   I have reviewed this annual report on Form 10-K of EOG
Resources, Inc.;

2.   Based on my knowledge, this report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other
financial information included in this report, fairly present in
all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the
periods presented in this report;

4.   The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) for the registrant and have:

     a) designed such disclosure controls and procedures, or
     caused such disclosure controls and procedures to be
     designed under our supervision, to ensure that material
     information relating to the registrant, including its
     consolidated subsidiaries, is made known to us by
     others within those entities, particularly during the
     period in which this report is being prepared;

     b) [Paragraph omitted in accordance with SEC transition
     instructions contained in SEC Release 34-47986]

     c) evaluated the effectiveness of the registrant's
     disclosure controls and procedures and presented in
     this report our conclusions about the effectiveness of
     the disclosure controls and procedures, as of the end
     of the period covered by this report based on such
     evaluation; and

     d) disclosed in this report any change in the
     registrant's internal control over financial reporting
     that occurred during the registrant's most recent
     fiscal quarter (the registrant's fourth fiscal quarter
     in the case of an annual report) that has materially
     affected, or is reasonably likely to materially affect,
     the registrant's internal control over financial
     reporting.

5.   The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors
and the audit committee of registrant's board of directors (or
persons performing the equivalent functions):

     a) all significant deficiencies and material weaknesses
     in the design or operation of internal control over
     financial reporting which are reasonably likely to
     adversely affect the registrant's ability to record,
     process, summarize and report financial information;
     and

     b) any fraud, whether or not material, that involves
     management or other employees who have a significant
     role in the registrant's internal control over
     financial reporting.

Date: March 11, 2004

/s/ EDMUND P. SEGNER, III
    Edmund P. Segner, III
    President and Chief of Staff
    (Principal Financial Officer)

EX-32

                                                     Exhibit 32.1

                CERTIFICATION OF PERIODIC REPORT


I, Mark G. Papa, Chairman of the Board and Chief Executive
Officer of EOG Resources, Inc., a Delaware Corporation (the
"Company"), certify, pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002, 18 U.S.C. Section 1350, that:

     (1)  the Annual Report on Form 10-K of the Company for the
     year ended December 31, 2003 (the "Report") fully complies
     with the requirements of Section 13(a) or 15(d) of the
     Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d));
     and

     (2)  the information contained in the Report fairly
     presents, in all material respects, the financial condition
     and results of operations of the Company.

A signed original of this written statement required by Section
906 has been provided to the Company and will be retained by the
Company and furnished to the Securities and Exchange Commission
or its staff upon request.

Dated: March 11, 2004



                                   /s/ MARK G. PAPA
                                       Mark G. Papa
                                   Chairman of the Board and
                                   Chief Executive Officer

EX-32

                                                     Exhibit 32.2

                CERTIFICATION OF PERIODIC REPORT


I, Edmund P. Segner, III, President and Chief of Staff, and
Principal Financial Officer of EOG Resources, Inc., a Delaware
Corporation (the "Company"), certify, pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that:

     (1)  the Annual Report on Form 10-K of the Company for the
     year ended December 31, 2003 (the "Report") fully complies
     with the requirements of Section 13(a) or 15(d) of the
     Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d));
     and

     (2)  the information contained in the Report fairly
     presents, in all material respects, the financial condition
     and results of operations of the Company.

A signed original of this written statement required by Section
906 has been provided to the Company and will be retained by the
Company and furnished to the Securities and Exchange Commission
or its staff upon request.

Dated: March 11, 2004



                                   /s/ EDMUND P. SEGNER, III
                                       Edmund P. Segner, III
                                   President and Chief of Staff
                                   (Principal Financial Officer)

EX-99

                                                         EXHIBIT 99.1


                          UNITED STATES
               SECURITIES AND EXCHANGE COMMISSION
                     WASHINGTON, D.C. 20549


                            FORM 8-K


                         CURRENT REPORT


Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934


               Date of Report:  February 24, 2004




                       EOG RESOURCES, INC.

     (Exact name of registrant as specified in its charter)


          Delaware             1-9743             47-0684736
      (State or other      (Commission File    (I.R.S. Employer
      jurisdiction of          Number)        Identification No.)
      incorporation or
        organization)


            333 Clay Street
              Suite 4200
             Houston, Texas                          77002
 (Address of principal executive offices)         (Zip code)


                          713/651-7000
      (Registrant's telephone number, including area code)








                       EOG RESOURCES, INC.



Item 7.  Financial Statements and Exhibits.

  (a) Financial Statements of EOG Resources, Inc.

      Financial Statements of EOG Resources, Inc. and its
      Consolidated Subsidiaries for the fiscal year ended December
      31, 2003, including Reports of Independent Public
      Accountants.

  (b) Exhibits.

      23.1 Consent of DeGolyer and MacNaughton.

      23.2 Opinion of DeGolyer and MacNaughton dated January 30, 2004.

      23.3 Consent of Deloitte & Touche LLP.



                           SIGNATURES


     Pursuant to the requirements of the Securities Exchange Act
of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned hereunto duly authorized.

                              EOG RESOURCES, INC.
                              (Registrant)




Date: February 24, 2004       By:  /s/ TIMOTHY K. DRIGGERS
                                    Timothy K. Driggers
                                 Vice President and Chief
                                    Accounting Officer
                             (Principal Accounting Officer)





                       EOG RESOURCES, INC.

                        TABLE OF CONTENTS



                                                              Page No.

Management's Discussion and Analysis of Financial Condition
  and Results of Operations                                       4

Management's Responsibility for Financial Reporting              17

Reports of Independent Public Accountants                        18

Consolidated Statements of Income and Comprehensive Income
  for the years ended December 31, 2003, 2002 and 2001           20

Consolidated Balance Sheets, December 31, 2003 and 2002          21

Consolidated Statements of Shareholders' Equity
  for the years ended December 31, 2003, 2002 and 2001           22

Consolidated Statements of Cash Flows
  for the years ended December 31, 2003, 2002 and 2001           23

Notes to Consolidated Financial Statements                       24

Supplemental Information to Consolidated Financial Statements    42

Exhibits

  Exhibit 23.1 - Consent of DeGolyer and MacNaughton             52

  Exhibit 23.2 - Opinion of DeGolyer and MacNaughton
     dated January 30, 2004                                      53

  Exhibit 23.3 - Consent of Deloitte & Touche LLP                55







                       EOG RESOURCES, INC.

              MANAGEMENT'S DISCUSSION AND ANALYSIS
        OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management's Discussion and Analysis of Financial Condition and
 Results of Operations

Overview

     EOG Resources, Inc. (EOG) is one of the largest independent
(non-integrated) oil and gas companies in the United States and
has substantial proved reserves in the U.S., Canada, and offshore
Trinidad, and to a lesser extent, the United Kingdom North Sea.
EOG operates under a business strategy that focuses predominantly
on three factors:  achieving a strong reinvestment rate of return
on its capital program, drilling internally generated prospects
in order to find and develop low cost reserves, and maintaining a
strong balance sheet, with a below average debt-to-total
capitalization ratio.

     EOG had record operating earnings in 2003.  Net income
available to common for 2003 of $419.1 million, or $3.60 per
share, was up 450% over 2002, attributable primarily to higher
commodity prices.  In addition, EOG substantially added to its
reserve base by replacing 249% of production at an all-in finding
cost of $1.28 per thousand cubic feet equivalent (Mcfe).  From
drilling alone, EOG replaced 183% of production at a rate of
$1.21 per Mcfe.

  Operations

     Several important developments have occurred since January 1,
2003.

     North America.  EOG closed the largest property acquisition
in its history on October 1, 2003, with the purchase of natural
gas properties in the Wintering Hills, Drumheller East and
Twining areas of southeast Alberta, Canada, from a subsidiary of
Husky Energy Inc. for approximately US $320 million.  This
transaction increases EOG's  drilling inventory in Canada,
primarily in the footprint of its very successful shallow natural
gas program in southern Alberta.  It also complements EOG's
existing Canadian assets by providing incremental reserve
potential and significantly increasing EOG's coal bed methane
acreage position in the Twining Field.

     EOG's effort to identify plays with larger reserve potential
has proven a successful supplement to its base development and
exploitation program in North America.  EOG plans to continue to
drill smaller wells in large acreage plays, which in the
aggregate, will contribute substantially to EOG's crude oil and
natural gas production.  EOG has several larger potential plays
underway in Wyoming, Utah and Texas, including the Barnett Shale,
from which more information will become known during 2004.

     International.  In 2003, Trinidad had its first full year of
sales to the Caribbean Nitrogen Company Limited (CNCL) ammonia
plant versus only six months of sales in 2002.  Also in Trinidad
in 2003, construction progressed on the Nitro 2000 ammonia plant,
which is scheduled to start up in the second half of 2004.  EOG
will supply 60 million cubic feet per day (MMcfd), gross, and
based on current price assumptions, expects to supply 47 MMcfd,
net, of natural gas to this facility under a fifteen-year
contract.  Additionally in Trinidad, EOG signed a fifteen-year
contract to supply a portion of the natural gas requirements of
the M5000 methanol plant.  Currently under construction, start-up
of the M5000 facility is planned for mid-2005.  When the plant is
running at its design capacity, EOG anticipates supplying
approximately 95 MMcfd, gross, of natural gas during the first
four years and approximately 125 MMcfd, gross, during the
remaining eleven years of the contract.  Based on current price
assumptions, the company expects to supply an average 67 MMcfd,
net, during the first four years and 87 MMcfd, net, during the
remaining eleven years.  The wellhead price will be linked to
Caribbean methanol prices but with a floor price.  With this new
contract, EOG anticipates another significant increase in its
Trinidad production next year.  In addition, EOG believes that
there are additional exploration opportunities in its existing
acreage position in Trinidad and continues to pursue additional
acreage.

     Although EOG continues to focus on North American natural
gas, EOG sees an increasing linkage between North American
natural gas demand and Trinidadian natural gas supply.  For
example, liquefied natural gas (LNG) imports from existing and
planned facilities in Trinidad are serious contenders to meet
increasing U.S. demand.  In addition, ammonia, methanol and
chemical production has been relocating from North America to
Trinidad, driven by attractive natural gas feedstock prices in
the island nation.  EOG anticipates that its existing position
with the supply contracts to the two ammonia plants and the new
methanol plant, discussed above, will continue to give its
portfolio an even broader exposure to North American natural gas
fundamentals.

     Also in 2003, EOG established a new venue outside of North
America with two natural gas discoveries in the Southern Gas
Basin of the United Kingdom North Sea.  The wells were farm-in
opportunities from major oil companies.  Production of
approximately 40 MMcfd, net, is expected by year-end 2004.  EOG
is reviewing additional farm-in opportunities in this area and
expects to participate in several exploration wells in 2004.

  Capital Structure

     As noted, one of management's key strategies is to keep a
strong balance sheet with a consistently below average debt-to-
total capitalization ratio.  At December 31, 2003, its debt-to-
total capitalization ratio was 33.3%, down from 40.6% at year-end
2002.  With the net cash provided from operating activities, EOG
funded its entire $917 million capital program, paid down $36
million of debt, closed $405 million of acquisitions and, in May
2003, increased the dividend paid to common shareholders by 25%.
As management currently assesses price forecast and demand trends
for 2004, EOG believes that operations and capital expenditure
activity can essentially be funded by cash from operations.

     For 2004, EOG's estimated capital expenditure budget is
approximately $1.1 billion, excluding acquisitions.  EOG plans to
spend about 5% of this estimated capital expenditure budget to
drill new, internally generated, bigger target ideas.  North
American natural gas continues to be a key component of this
effort.  When it fits EOG's strategy, EOG will make acquisitions
that bolster existing drilling programs or offer EOG incremental
exploration and/or production opportunities.  Management believes
EOG has one of the strongest prospect inventories in EOG's
history.

  Finding Costs and Reserve Replacement

     During 2003, EOG replaced 249% of its production at an all-
in $1.28 per Mcfe finding cost.  In North America, EOG had 259%
reserve replacement at $1.36 per Mcfe.  EOG replaced 189% of
production at a $0.63 per Mcfe finding costs in its Trinidad and
United Kingdom activities.  An external review of approximately
70% of EOG's reserves was conducted by the independent reserve
engineering firm of DeGolyer and MacNaughton (D&M).  For the
sixteenth consecutive year, D&M reported no material differences
overall between their independent estimates and EOG's internal
estimates.



     The following review of operations for each of the three
years in the period ended December 31, 2003 should be read in
conjunction with the consolidated financial statements of EOG and
notes thereto beginning with page 20.

Results of Operations

  Net Operating Revenue

     During 2003, net operating revenues increased $650 million
to $1,745 million.  Total wellhead revenues increased 65% to
$1,818 million as compared to 2002.  Wellhead volume and price
statistics for the specified years were as follows:



                                                        Year Ended December 31,
                                                        2003     2002     2001
                                                               
Natural Gas Volumes (MMcf per day) (1)
 United States                                           638      635      680
 Canada                                                  165      154      126
 Trinidad                                                152      135      115
     Total                                               955      924      921

Average Natural Gas Prices ($/Mcf) (2)
 United States                                         $5.06    $2.89    $4.26
 Canada                                                 4.66     2.67     3.78
 Trinidad                                               1.35     1.20     1.22
     Composite                                          4.40     2.60     3.81

Crude Oil and Condensate Volumes (MBbl per day) (1)
 United States                                          18.5     18.8     22.0
 Canada                                                  2.3      2.1      1.7
 Trinidad                                                2.4      2.4      2.1
     Total                                              23.2     23.3     25.8

Average Crude Oil and Condensate Prices ($/Bbl) (2)
 United States                                        $30.24   $24.79   $25.06
 Canada                                                28.54    23.62    22.70
 Trinidad                                              28.88    23.58    24.14
     Composite                                         29.92    24.56    24.83

Natural Gas Liquids Volumes (MBbl per day) (1)
 United States                                           3.2      2.9      3.5
 Canada                                                  0.6      0.8      0.5
     Total                                               3.8      3.7      4.0

Average Natural Gas Liquids Prices ($/Bbl) (2)
 United States                                        $21.53   $14.76   $17.17
 Canada                                                19.13    11.17    15.05
     Composite                                         21.13    14.05    16.89

Natural Gas Equivalent Volumes (MMcfe per day) (3)
 United States                                           768      765      833
 Canada                                                  183      171      139
 Trinidad                                                166      150      128
     Total                                             1,117    1,086    1,100

Total Bcfe (3) Deliveries                                408      396      401


(1) Million cubic feet per day or thousand barrels per day,
    as applicable.
(2) Dollars per thousand cubic feet or per barrel, as
    applicable.
(3) Million cubic feet equivalent per day or billion cubic
    feet equivalent, as applicable; includes natural gas, crude
    oil, condensate and natural gas liquids.


     2003 compared to 2002.  Wellhead natural gas revenues for
2003 increased $657 million, or 75%, due to increases in the
composite average wellhead natural gas price and natural gas
deliveries.  The composite average wellhead price for natural gas
increased 69% to $4.40 per Mcf for 2003 from $2.60 per Mcf in
2002.

     Natural gas deliveries increased to 955 MMcf per day for
2003 from 924 MMcf per day for the comparable period a year ago.
The overall increase in natural gas deliveries was primarily due
to an increase in Canada of 7% to 165 MMcf per day and an
increase in Trinidad of 13% to 152 MMcf per day in 2003.  The 7%
or 11 MMcf per day increase in Canada was primarily attributable
to a major property acquisition in the fourth quarter.  The 13%
or 17 MMcf per day increase in Trinidad was attributable to a
full year of sales to the CNCL ammonia plant versus only six
months of sales in 2002.

     Wellhead crude oil and condensate revenues increased $45
million, or 22%, due to increases in the composite average
wellhead crude oil and condensate price. The composite average
wellhead crude oil and condensate price for 2003 was $29.92 per
barrel compared to $24.56 per barrel for 2002.

     Natural gas liquids revenues were $11 million higher than a
year ago primarily due to a 50% increase in the composite average
price and a 3% increase in deliveries.

     During 2003, EOG recognized losses on mark-to-market
commodity derivative contracts of $80 million, which included
realized losses of $45 million and collar premium payments of $3
million.  During 2002, EOG recognized losses on mark-to-market
commodity derivative contracts of $49 million, which included
realized losses of $21 million and a $2 million collar premium
payment.

     2002 compared to 2001.  During 2002, net operating revenues
decreased $560 million to $1,095 million.  Total wellhead
revenues of $1,105 million decreased by $435 million, or 28%, as
compared to 2001.

     Wellhead natural gas revenues for 2002 decreased
approximately $405 million primarily due to a general decline in
the composite average wellhead natural gas price, partially
offset by an increase in natural gas deliveries in Canada and
Trinidad.  The composite average wellhead price for natural gas
decreased 32% to $2.60 per Mcf for 2002 compared to $3.81 per Mcf
in 2001.

     Natural gas deliveries increased slightly to 924 MMcf per
day for 2002 compared to 921 MMcf per day for 2001.  The overall
increase in natural gas deliveries was due to an increase in
Canada of 22% to 154 MMcf per day in 2002 and an increase in
Trinidad of 17% to 135 MMcf per day in 2002.  The higher
production in 2002 was attributable to drilling activities and
strategic property acquisitions in Canada, and the commencement
of production from the U(a) Block in Trinidad.  This increase was
partially offset by the overall decrease in production in the
United States of 7% or 45 MMcf per day.

     Wellhead crude oil and condensate revenues decreased
approximately $25 million, due primarily to a decline in domestic
crude oil and condensate deliveries with essentially flat
wellhead crude oil and condensate prices.  The composite average
wellhead crude oil and condensate price for 2002 was $24.56 per
barrel compared to $24.83 per barrel for 2001.

     Crude oil and condensate deliveries decreased 10% to 23.3
MBbl per day for 2002 compared to 25.8 MBbl per day in 2001.  The
decrease in volumes was primarily due to decreased crude oil and
condensate production in certain areas in the United States as a
result of a natural decline in production.  This natural decline
in production was partially offset by increased production in
Trinidad due to the commencement of production from the U(a)
Block, and drilling activities and strategic property
acquisitions in Canada.

     Natural gas liquids revenues were $6 million lower in 2002
than in 2001 primarily due to a decrease in prices of 17% and a
decrease in deliveries of 8%.

     During 2002, EOG recognized losses on mark-to-market
commodity derivative contracts of $49 million, which included
realized losses of $21 million and a $2 million collar premium
payment.  During 2001, EOG recognized gains on mark-to-market
commodity derivative contracts of $98 million, of which $67
million were realized gains which were netted against a $5
million collar premium payment.

     Other marketing activities associated with sales and
purchases of natural gas increased net operating revenues by $37
million and $16 million in 2002 and 2001, respectively.

  Operating and Other Expenses

     2003 compared to 2002.  During 2003, operating expenses of
$1,047 million were $133 million higher than the $914 million
incurred in 2002.  The following table presents the costs per
Mcfe for the years ended December 31, 2003 and 2002:



                                  Year Ended December 31,
                                       2003      2002

                                          
          Lease and Well              $0.52     $0.45
          DD&A                         1.08      1.00
          G&A                          0.25      0.22
          Taxes Other than Income      0.21      0.18
          Interest Expense, Net        0.14      0.15
            Total Per-Unit Costs      $2.20     $2.00


     The higher per-unit rates of lease and well, DD&A, G&A and
taxes other than income for 2003 compared to 2002 were due
primarily to the reasons set forth below.

     Lease and well expenses of $213 million were $33 million
higher than 2002 due primarily to a general increase in service
costs related to operating activities in the United States ($15
million) and Canada ($4 million), increased lease and well
administrative expenses in the United States ($7 million) and
changes in the Canadian exchange rate ($6 million).

     Depreciation, depletion and amortization (DD&A) expenses of
$442 million increased $44 million from the prior year due
primarily to more relative production from higher cost properties
in the United States ($20 million) and Canada ($5 million),
increased production in Canada ($3 million) and Trinidad ($2
million), and changes in the Canadian exchange rate ($8 million).
Also, included in DD&A expenses for 2003 was $5 million of
accretion expense related to Statement of Financial Accounting
Standards (SFAS) No. 143 - "Accounting for Asset Retirement
Obligations."

     General and administrative (G&A) expenses of $100 million
were $11 million higher than the period a year ago due primarily
to expanded operations ($9 million) and increased insurance
expense ($5 million), partially offset by decreases in legal
costs ($3 million).

     Taxes other than income of $86 million were $14 million
higher than the prior year period primarily due to an increase of
approximately $35 million as a result of increased wellhead
revenue as previously discussed, partially offset by $24 million
of severance tax credits from the qualification of wells for a
Texas high cost gas severance tax exemption.

     Exploration costs of $76 million were $16 million higher
than a year ago due primarily to an increase in technical staff
costs across EOG ($7 million) and increased geological and
geoscience expenditures in the United States ($5 million) and
Trinidad ($3 million).

     Impairments increased $21 million to $89 million compared to
a year ago due to higher amortization of unproved leases in the
United States ($25 million).  Total impairments under SFAS No.
144 - "Accounting for the Impairment or Disposal of Long-Lived
Assets" for 2003 and 2002 were $25 million and $30 million,
respectively.

     Other Income (Expense), Net for 2003 included foreign
currency transaction gains of $9 million as a result of applying
the changes in the Canadian exchange rate to certain intercompany
short-term loans that eliminate in consolidation.

     Income tax provision increased $184 million to $217 million
for 2003 as compared to 2002 primarily resulting from higher
income before income taxes for federal ($187 million) and state
($4 million), expiration of the tight gas sands federal income
tax credit as of December 31, 2002 ($4 million), higher effective
foreign income tax rates ($4 million), offset by net tax benefit
associated with the Canadian tax law change ($14 million).

     In November 2003, Canada enacted legislation reducing the
Canadian federal income tax rate for companies in the resource
sector from 28% to 27% for 2003, with further reductions to 21%
phased in over the next four years.  This legislation also made
changes to the tax treatment of crown royalties and the resource
allowance.  Beginning in 2003, Canadian taxpayers are allowed to
deduct 10% of actual provincial and other crown royalties.  This
percentage increases each year through 2007, at which time 100%
of crown royalties will be deductible.  The resource allowance, a
statutory deduction calculated as 25% of adjusted resource
profits, will be phased out through 2007, when the deduction will
be completely eliminated.

     2002 compared to 2001.  During 2002, operating expenses of
$914 million were approximately $66 million lower than the $980
million incurred in 2001.  The following table presents the costs
per Mcfe for the years ended December 31, 2002 and 2001:



                                  Year Ended December 31,
                                       2002      2001

                                          
          Lease and Well              $0.45     $0.44
          DD&A                         1.00      0.98
          G&A                          0.22      0.20
          Taxes Other than Income      0.18      0.24
          Interest Expense, Net        0.15      0.11
            Total Per-Unit Costs      $2.00     $1.97


     The changes in per-unit lease and well, DD&A, G&A, taxes
other than income and net interest expense rates for 2002
compared to 2001 are due primarily to the reasons set forth
below.

     Lease and well expenses increased $4 million to $179 million
compared to a year ago primarily due to continually expanding
operations and increases in production activity in Canada,
partially offset by fewer workovers in the Gulf of Mexico.

     DD&A expenses increased $6 million to $398 million primarily
due to increased activity in Canada and higher per unit costs
related to certain fields in the United States.

     G&A expenses increased $9 million to $89 million primarily
due to the settlement of litigation in the second quarter,
increased insurance expense and expanded operations.

     Taxes other than income decreased $23 million to $72 million
as compared to 2001 due to decreased wellhead revenue in North
America resulting in lower production taxes and decreased ad
valorem taxes.

     The increase in net interest expense of $15 million for 2002
as compared to 2001 is primarily due to higher average debt
balance for the year of 2002 and the one-time close-out fees
associated with the completion of the Section 29 (Tight Gas Sands
Federal Income Tax Credits) financing begun in 1999.

     Exploration costs of $60 million were $7 million lower than
a year ago primarily due to decreased geological and geoscience
expenditures.

     Dry hole costs of $47 million decreased $25 million from
2001.

     Impairments decreased $11 million to $68 million primarily
as a result of improved value-to-cost relationship on a field by
field basis and decreased amortization of unproved leases in
2002.

     Income tax provision decreased approximately $200 million
for 2002 as compared to 2001 primarily as a result of a lower pre-
tax income in 2002 and a reduction in the overall foreign
effective tax rate.

Capital Resources and Liquidity

  Cash Flow

     The primary sources of cash for EOG during the three-year
period ended December 31, 2003 included funds generated from
operations and funds from new borrowings.  Primary cash outflows
included funds used in operations, exploration and development
expenditures, oil and gas property acquisitions, repayment of
debt, common stock repurchases and dividends.

     2003 compared to 2002.  Net operating cash inflows of $1,320
million in 2003 increased approximately $652 million as compared
to 2002 primarily reflecting an increase in operating revenues of
$650 million and favorable changes in working capital and other
liabilities of $115 million, partially offset by an increase in
cash operating expenses of $132 million.

     Net investing cash outflows of approximately $1,269 million
in 2003 increased by $396 million as compared to 2002 due
primarily to increased exploration and development expenditures
of $501 million, which includes $366 million related to two
Canadian asset purchases as mentioned below in the Capital
Expenditures discussion, partially offset by favorable changes in
working capital of $81 million related to investing activities
and a decrease in equity investment of $15 million.  Changes in
Components of Working Capital Associated with Investing
Activities included changes in accounts payable associated with
the accrual of exploration and development expenditures and
changes in inventories which represent material and equipment
used in drilling and related activities.

     Cash used by financing activities was $57 million in 2003
versus cash provided of $211 million in 2002.  Financing
activities for 2003 included repayment of the outstanding
balances of commercial paper borrowings and the uncommitted line
of credit of $22 million and $14 million, respectively,
repurchases of EOG's common stock of $21 million, cash dividend
payments of $31 million and proceeds of $35 million from sales of
treasury stock attributable to employee stock option exercises
and the employee stock purchase plan.

     2002 compared to 2001.  Net operating cash flows of $669
million in 2002 decreased approximately $529 million as compared
to 2001 primarily due to lower average natural gas and liquids
prices partially offset by lower cash operating expenses and
lower current income taxes.  Changes in working capital and other
liabilities decreased operating cash flows by $145 million as
compared to 2001 primarily due to changes in accounts receivable,
accrued royalties payable and accrued production taxes caused by
fluctuation of commodity prices at each yearend.

     Net investing cash outflows of $873 million in 2002
decreased by $216 million as compared to 2001 due primarily to
decreased exploration and development expenditures of $292
million (including producing property acquisitions), partially
offset by increased uses of working capital related to investing
activities and increased equity investments.

     Cash provided by financing activities in 2002 was $211
million as compared to cash used of $127 million in 2001.
Financing activities in 2002 included funds from new borrowings
of $289 million, common stock repurchases of $63 million,
dividend payments of $29 million and proceeds from stock options
exercised of $17 million. New borrowings included $120 million of
commercial paper borrowings and  $250 million of promissory note
issuances, partially offset by a decrease in uncommitted line of
credit borrowings of $81 million.

  Exploration and Development Expenditures

     The table below sets out components of exploration and
development expenditures for the years ended December 31, 2003,
2002 and 2001, along with the total budgeted for 2004, excluding
acquisitions (in millions):



                                            Actual                  Budgeted 2004
                                    2003     2002     2001    (excluding acquisitions)
                                                   
Expenditure Category
Capital
 Drilling and Facilities           $  731   $  595   $  722
 Leasehold Acquisitions                59       39       76
 Producing Property Acquisitions      405       71      168
 Capitalized Interest                   9        9        9
  Subtotal                          1,204      714      975
Exploration Costs                      76       60       67
Dry Hole Costs                         41       47       71
  Subtotal                          1,321      821    1,113     Approximately $1,100
Asset Retirement Costs (1)             12       --       --
Deferred Income Tax Gross Up           --       15       50
  Total (2)                        $1,333   $  836   $1,163


(1) 2003 Asset Retirement Costs does not include the cumulative
    effect of adoption and is netted with gains recognized upon
    settlement of asset retirement obligations of $1 million.
(2) Pro forma total expenditures for 2002 and 2001 are not
    presented since the pro forma application of SFAS No. 143 to
    the prior periods would not result in pro forma total
    expenditures materially different from the actual amounts
    reported.


     Total exploration and development expenditures of $1,333
million increased $497 million in 2003 as compared to 2002 due
primarily to the two property acquisitions by a Canadian
subsidiary of EOG, as described below, and increased exploration
and development activities across EOG.  Included in 2003
expenditures are $652 million in development, $405 million in
property acquisitions and $266 million in exploration.

     On October 1, 2003, a Canadian subsidiary of EOG closed an
asset purchase of natural gas properties in the Wintering Hills,
Drumheller East and Twining areas of southeast Alberta from a
subsidiary of Husky Energy Inc. for approximately US $320
million.  These properties are essentially adjacent to existing
EOG operations or are properties in which EOG already had a
working interest.  The transaction was partially funded by
commercial paper borrowings of US $140.5 million on October 1,
2003.  The remainder of the purchase price, US $179.5 million,
was funded by EOG's available cash balance.  Subsequent to the
closing, the purchase price was reduced by exercised preferential
rights on the properties which totaled approximately US $5
million.  In late December 2003, a Canadian subsidiary of EOG
closed another property acquisition for US $46 million.

  Derivative Transactions

     During 2003, EOG recognized losses on mark-to-market
commodity derivative contracts of $80 million, which included
realized losses of $45 million and collar premium payments of $3
million.  During 2002, EOG recognized losses on mark-to-market
commodity derivative contracts of $49 million, which included
realized losses of $21 million and a $2 million collar premium
payment.  (See Note 12 to the Consolidated Financial Statements.)

     Presented below is a summary of EOG's 2004 natural gas
financial collar contracts and natural gas and crude oil
financial price swap contracts as of February 24, 2004, with
prices expressed in dollars per million British thermal units
($/MMBtu) and in dollars per barrel ($/Bbl), as applicable, and
notional volumes in million British thermal units per day
(MMBtud) and in barrels per day (Bbld), as applicable.  EOG has
not entered into any additional natural gas financial collar
contracts or natural gas or crude oil financial price swap
contracts since December 31, 2003.  EOG accounts for these collar
and swap contracts using mark-to-market accounting.



                 Natural Gas Financial Collar Contracts               Financial Price Swap Contracts
                          Floor Price            Ceiling Price         Natural Gas         Crude Oil
                        Floor    Weighted      Ceiling   Weighted            Weighted           Weighted
           Volume       Range     Average       Range     Average    Volume   Average   Volume   Average
Month(1)  (MMBtud)    ($/MMBtu)  ($/MMBtu)    ($/MMBtu)  ($/MMBtu)  (MMBtud) ($/MMBtu)  (Bbld)   ($/Bbl)

                                                                
Jan       330,000   $5.06 - 5.88   $5.38    $5.86 - 6.69   $6.29     30,000    $5.57     4,000   $30.61
Feb       330,000    5.02 - 5.78    5.31     5.82 - 6.62    6.24     30,000     5.50     4,000    30.12
Mar       330,000    4.93 - 5.53    5.16     5.73 - 6.40    6.10     30,000     5.37     4,000    29.58
Apr       375,000    4.47 - 4.71    4.59     4.93 - 5.30    5.13     30,000     4.89     4,000    29.08
May       375,000    4.47 - 4.75    4.58     4.93 - 5.19    5.09     30,000     4.80     4,000    28.66
Jun       375,000    4.47 - 4.75    4.58     4.93 - 5.19    5.09     30,000     4.80     4,000    28.27
Jul       375,000    4.47 - 4.75    4.58     4.93 - 5.19    5.09     30,000     4.80     3,000    27.91
Aug       375,000    4.47 - 4.75    4.58     4.93 - 5.19    5.09     30,000     4.80     2,000    28.11
Sep       375,000    4.47 - 4.75    4.58     4.93 - 5.19    5.09     30,000     4.78        --       --
Oct       375,000    4.47 - 4.75    4.58     4.93 - 5.19    5.09     30,000     4.80        --       --


(1) The collar contracts for January 2004 to March 2004 were
    purchased at a total premium of $3 million or $0.10 per MMBtu.
    The collar contracts for April 2004 to October 2004 were
    purchased without a premium.


  Financing

     EOG's long-term debt-to-total capitalization ratio was 33.3%
as of December 31, 2003 compared to 40.6% as of December 31, 2002.

     During 2003, total long-term debt decreased $36 million to
$1,109 million (see Note 2 to the Consolidated Financial
Statements).  The estimated fair value of EOG's long-term debt at
December 31, 2003 and 2002 was $1,175 million and $1,225 million,
respectively, based upon quoted market prices and, where such
prices were not available, upon interest rates currently
available to EOG at yearend.  EOG's debt is primarily at fixed
interest rates.  At December 31, 2003, a 1% decline in interest
rates would result in a $51 million increase in the estimated
fair value of the fixed rate obligations (see Note 12 to the
Consolidated Financial Statements).

     During 2003 and 2002, EOG utilized primarily commercial
paper and committed bank loans to fund its operations.  These
loans are more fully described in Note 2 to the Consolidated
Financial Statements.  While EOG maintains a $600 million
commercial paper program, the maximum outstanding at any time
during 2003 was $244 million, and the amount outstanding at
yearend was $98 million.  EOG considers this excess availability,
which is contractually backed by the $600 million Revolving
Credit Agreement with domestic and foreign lenders described in
Note 2, combined with the $688 million of availability under its
shelf registration described below, to be ample to meet its
ongoing operating needs.

  Contractual Obligations

     The following table summarizes EOG's contractual obligations
at December 31, 2003 (in thousands):



                                                                                       2010 &
Contractual Obligations (1)          Total       2004     2005 - 2007   2008 - 2009    beyond

                                                                       
Long-Term Debt (2)                $1,108,872   $198,050     $376,870      $173,952    $360,000
Non-cancelable Operating Leases       54,650     18,187       25,954         3,898       6,611
Drilling Rig Commitments               2,364      1,033          998           333          --
Pipeline Transportation Service
   Commitments (3)                    45,702     13,615       25,811         3,666       2,610
  Total Contractual Obligations   $1,211,588   $230,885     $429,633      $181,849    $369,221


(1) See Notes 2 and 8 to Consolidated Financial Statements.
(2) Commercial paper and the 6.50% Notes due 2004 are
    classified as long-term debt on the Consolidated Balance
    Sheets based on EOG's intent and ability to ultimately replace
    such amounts with other long-term debt.  See Note 2 to the
    Consolidated Financial Statements.
(3) Amounts shown are based on current pipeline
    transportation rates and the Canadian foreign currency
    exchange rate at December 31, 2003.  Management does not
    believe that any future changes in these rates before the
    expiration dates of these commitments will have a materially
    adverse effect on the financial condition or results of
    operations of EOG.


  Shelf Registration

     As of February 24, 2004, the amount available under various
filed registration statements with the Securities and Exchange
Commission for the offer and sale from time to time of EOG debt
securities, preferred stock and/or common stock totaled $688
million.

  Off-Balance Sheet Arrangements

     EOG does not participate in financial transactions that generate
relationships with unconsolidated entities or financial
partnerships.  Such entities, often referred to as variable
interest entities (VIE) or special purpose entities (SPE), are
generally established for the purpose of facilitating off-balance
sheet arrangements or other contractually narrow or limited
purposes.  EOG was not involved in any unconsolidated VIE or SPE
financial transactions during any of the reporting periods in this
document and has no intention to participate in such transactions
in the foreseeable future.

  Foreign Currency Exchange Rate Risk

     During 2003, EOG was exposed to foreign currency exchange
rate risk inherent in its operations in foreign countries,
including Canada, Trinidad and the United Kingdom.  The foreign
currency most significant to EOG's operations during 2003 was the
Canadian Dollar.  While the strengthening of the Canadian Dollar
in 2003 impacted both the revenues and expenses recorded on the
income statements of EOG's Canadian subsidiaries, its impacts on
these items were not to the same extent.  Since the Canadian
natural gas prices are largely correlated to United States
prices, the changes in the Canadian currency exchange rate have
less of an impact on the Canadian revenues than the Canadian
expenses.  EOG continues to monitor the foreign currency exchange
rates of countries in which it is currently conducting business
and will implement measures to protect against the foreign
currency exchange rate risk if needed.

  Outlook

     Natural gas prices historically have been volatile, and this
volatility is expected to continue.  Uncertainty continues to
exist as to the direction of future North America natural gas and
crude oil price trends, and there remains a rather wide
divergence in the opinions held by some in the industry.  This
divergence in opinion is caused by various factors including
current economic conditions, improvements in the technology used
in drilling and completing crude oil and natural gas wells,
fluctuations in the availability and utilization of natural gas
storage capacity and ever-changing weather patterns.  However,
the increasing recognition of natural gas as a more
environmentally friendly source of energy could result in
increases in demand. Being primarily a natural gas producer, EOG
is more significantly impacted by changes in natural gas prices
than by changes in crude oil and condensate prices.  Longer term
natural gas prices will be determined by the natural rate of
production decline in North America, the level of North American
rig activity and the level of LNG imports as well as prices of
competing fuels, including oil.

     Marketing companies have played an important role in the
North American natural gas market.  These companies aggregate
natural gas supplies through purchases from producers like EOG
and then resell the gas to end users, local distribution
companies or other buyers.  In recent years, several of the
largest natural gas marketing companies have filed for bankruptcy
or are having financial difficulty, and others are exiting this
business.  EOG does not believe that this will have a material
effect on its ability to market its natural gas production.  EOG
continues to assess and monitor the credit worthiness of partners
to whom it sells its production and where appropriate, to seek
new markets.

     EOG plans to continue to focus a substantial portion of its
exploration and development expenditures in its major producing
areas in North America.  However, in order to diversify its
overall asset portfolio and as a result of its overall success
realized in Trinidad, EOG anticipates expending a portion of its
available funds in the further development of opportunities
outside North America.  In addition, EOG expects to conduct
exploratory activity in other areas outside of North America,
including the United Kingdom North Sea, and will continue to
evaluate the potential for involvement in other exploitation type
opportunities.  Budgeted 2004 exploration and development
expenditures, excluding acquisitions, are approximately $1.1
billion, addressing the continuing uncertainty with regard to the
future of the North America natural gas and crude oil and
condensate price environment.  Budgeted expenditures for 2004 are
structured to maintain the flexibility necessary under EOG's
strategy of funding North America exploration, exploitation,
development and acquisition activities primarily from available
internally generated cash flow.

     The level of exploration and development expenditures may
vary in 2004 and will vary in future periods depending on energy
market conditions and other related economic factors.  Based upon
existing economic and market conditions, EOG believes net
operating cash flow and available financing alternatives in 2004
will be sufficient to fund its net investing cash requirements
for the year.  However, EOG has significant flexibility with
respect to its financing alternatives and adjustment of its
exploration, exploitation, development and acquisition
expenditure plans if circumstances warrant.  While EOG has
certain continuing commitments associated with expenditure plans
related to operations in the United States, Canada, Trinidad and
the United Kingdom, such commitments are not expected to be
material when considered in relation to the total financial
capacity of EOG.

  Environmental Regulations

     Various federal, state and local laws and regulations
covering the discharge of materials into the environment, or
otherwise relating to protection of the environment, may affect
EOG's operations and costs as a result of their effect on natural
gas and crude oil exploration, exploitation, development and
production operations.  In addition, EOG has acquired certain oil
and gas properties from third parties whose actions with respect
to the management and disposal or release of hydrocarbons or
other wastes were not under EOG's control.  Under environmental
laws and regulations, EOG could be required to remove or
remediate wastes disposed of or released by prior owners or
operators.  EOG also has acquired or merged with companies that
own and operate oil and gas properties.  Any obligations or
liabilities of these companies under environmental laws would
continue as liabilities of the acquired company, or of EOG in the
event of a merger, even if the obligations or liabilities
resulted from actions that took place before the acquisition or
merger.  Compliance with such laws and regulations has not had a
material adverse effect on EOG's operations or financial
condition.  It is not anticipated, based on current laws and
regulations, that EOG will be required in the near future to
expend amounts that are material in relation to its total
exploration and development expenditure program by reason of
environmental laws and regulations.  However, inasmuch as such
laws and regulations are frequently changed, EOG is unable to
predict the ultimate cost of compliance.

     EOG also could incur costs related to the clean up of sites
to which it sent regulated substances for disposal or to which it
sent equipment for cleaning, and for damages to natural resources
or other claims related to releases of regulated substances at
such sites.  In this regard, EOG has been named as a potentially
responsible party in certain proceedings initiated pursuant to
the Comprehensive Environmental Response, Compensation, and
Liability Act and may be named as a potentially responsible party
in other similar proceedings in the future.  It is not
anticipated that the costs incurred by EOG in connection with the
presently pending proceedings will, individually or in the
aggregate, have a materially adverse effect on the financial
condition or results of operations of EOG.

Summary of Critical Accounting Policies

    EOG prepares its financial statements and the accompanying
notes in conformity with accounting principles generally accepted
in the United States of America, which requires management to
make estimates and assumptions about future events that affect
the reported amounts in the financial statements and the
accompanying notes.  EOG identifies certain accounting policies
as critical based on, among other things, their impact on the
portrayal of EOG's financial condition, results of operations or
liquidity, and the degree of difficulty, subjectivity and
complexity in their deployment.  Critical accounting policies
cover accounting matters that are inherently uncertain because
the future resolution of such matters is unknown.  Management
routinely discusses the development, selection and disclosure of
each of the critical accounting policies.  Following is a
discussion of EOG's most critical accounting policies:

  Proved Oil and Gas Reserves

     EOG's engineers, with secondary verification from third-
party experts (D&M), estimate proved oil and gas reserves, which
directly impact financial accounting estimates, including
depreciation, depletion and amortization.  Proved reserves
represent estimated quantities of natural gas, crude oil,
condensate, and natural gas liquids that geological and
engineering data demonstrate, with reasonable certainty, to be
recoverable in future years from known reservoirs under economic
and operating conditions existing at the time the estimates were
made.  The process of estimating quantities of proved oil and gas
reserves is very complex, requiring significant subjective
decisions in the evaluation of all available geological,
engineering and economic data for each reservoir.  The data for a
given reservoir may also change substantially over time as a
result of numerous factors including, but not limited to,
additional development activity, evolving production history and
continual reassessment of the viability of production under
varying economic conditions.  Consequently, material revisions
(upward or downward) to existing reserve estimates may occur from
time to time.

  Impairments

     Oil and gas lease acquisition costs are capitalized when
incurred.  Unproved properties with individually significant
acquisition costs are assessed quarterly on a
property-by-property basis, and any impairment in value is
recognized.  Unproved properties with acquisition costs that are
not individually significant are aggregated, and the portion of
such costs estimated to be nonproductive, based on historical
experience, is amortized over the average holding period.  If the
unproved properties are determined to be productive, the
appropriate related costs are transferred to proved oil and gas
properties. Lease rentals are expensed as incurred.

     Periodically, or when circumstances indicate that an asset
may be impaired, EOG compares expected undiscounted future cash
flows at a producing field level to the unamortized capitalized
cost of the asset. If the future undiscounted cash flows, based
on EOG's estimate of future crude oil and natural gas prices,
operating costs, anticipated production from proved reserves and
other relevant data, are lower than the unamortized capitalized
cost, the capitalized cost is reduced to fair value.  Fair value
is calculated by discounting the future cash flows at an
appropriate risk-adjusted discount rate.

  Depreciation, Depletion and Amortization for Oil and Gas Properties

     The quantities of estimated proved oil and gas reserves are
a significant component of our calculation of depletion expense
and revisions in such estimates may alter the rate of future
expense.  Holding all other factors constant, if reserves were
revised upward or downward, earnings would increase or decrease
respectively.

  Stock Options

     EOG accounts for stock options under the provisions and
related interpretations of Accounting Principles Board (APB)
Opinion No. 25 - "Accounting for Stock Issued to Employees."  No
compensation expense is recognized for such options.  As allowed
by SFAS No. 123 - "Accounting for Stock-Based Compensation"
issued in 1995, EOG has continued to apply APB Opinion No. 25 for
purposes of determining net income and to present the pro forma
disclosures required by SFAS No. 123.


Information Regarding Forward-Looking Statements

  This Current Report on Form 8-K includes forward-looking
statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of
1934.  All statements other than statements of historical facts,
including, among others, statements regarding EOG's future
financial position, business strategy, budgets, reserve
information, projected levels of production, projected costs and
plans and objectives of management for future operations, are
forward-looking statements.  EOG typically uses words such as
"expect," "anticipate," "estimate," "strategy," "intend," "plan,"
"target" and "believe" or the negative of those terms or other
variations of them or by comparable terminology to identify its
forward-looking statements.  In particular, statements, express
or implied, concerning future operating results, the ability to
replace or increase reserves or to increase production, or the
ability to generate income or cash flows are forward-looking
statements.  Forward-looking statements are not guarantees of
performance.  Although EOG believes its expectations reflected in
forward-looking statements are based on reasonable assumptions,
no assurance can be given that these expectations will be
achieved.  Important factors that could cause actual results to
differ materially from the expectations reflected in the forward-
looking statements include, among others:  the timing and extent
of changes in commodity prices for crude oil, natural gas and
related products, foreign currency exchange rates and interest
rates; the timing and impact of liquefied natural gas imports and
changes in demand or prices for ammonia or methanol; the extent
and effect of any hedging activities engaged in by EOG; the
extent of EOG's success in discovering, developing, marketing and
producing reserves and in acquiring oil and gas properties; the
accuracy of reserve estimates, which by their nature involve the
exercise of professional judgment and may therefore be imprecise;
political developments around the world; acts of war and
terrorism and responses to these acts; and financial market
conditions.  In light of these risks, uncertainties and
assumptions, the events anticipated by EOG's forward-looking
statements might not occur.  EOG undertakes no obligations to
update or revise its forward-looking statements, whether as a
result of new information, future events or otherwise.



         MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING

     The following consolidated financial statements of EOG
Resources, Inc. and its subsidiaries (EOG) were prepared by
management, which is responsible for their integrity, objectivity
and fair presentation.  The statements have been prepared in
conformity with accounting principles generally accepted in the
United States and, accordingly, include some amounts that are
based on the best estimates and judgments of management.

     Deloitte & Touche LLP, independent public accountants, was
engaged to audit the consolidated financial statements of EOG and
issue a report thereon. In the conduct of the audit, Deloitte &
Touche LLP was given unrestricted access to all financial records
and related data including minutes of all meetings of
shareholders, the Board of Directors and committees of the Board.
Their audit was made in accordance with auditing standards
generally accepted in the United States of America and included a
review of the system of internal controls to the extent
considered necessary to determine the audit procedures required
to support their opinion on the consolidated financial
statements.  Management believes that all representations made to
Deloitte & Touche LLP during the audit were valid and
appropriate.

     The system of internal controls of EOG is designed to
provide reasonable assurance as to the reliability of financial
statements and the protection of assets from unauthorized
acquisition, use or disposition.  This system includes, but is
not limited to, written policies and guidelines including a
published code for the conduct of business affairs, conflicts of
interest and compliance with laws regarding antitrust,
antiboycott and foreign corrupt practices policies, the careful
selection and training of qualified personnel, and a documented
organizational structure outlining the separation of
responsibilities among management representatives and staff
groups.

     The adequacy of financial controls of EOG and the accounting
principles employed in financial reporting by EOG are under the
general oversight of the Audit Committee of the Board of
Directors.  No member of this committee is an officer or employee
of EOG.  The independent public accountants and internal auditors
have full, free, separate and direct access to the Audit
Committee and meet with the committee from time to time to
discuss accounting, auditing and financial reporting matters.  It
should be recognized that there are inherent limitations to the
effectiveness of any system of internal control, including the
possibility of human error and circumvention or override.
Accordingly, even an effective system can provide only reasonable
assurance with respect to the preparation of reliable financial
statements and safeguarding of assets.  Furthermore, the
effectiveness of an internal control system can change with
circumstances.

     It is management's opinion that, considering the criteria
for effective internal control over financial reporting and
safeguarding of assets which consists of interrelated components
including the control environment, risk assessment process,
control activities, information and communication systems, and
monitoring, EOG maintained an effective system of internal
control as to the reliability of financial statements and the
protection of assets against unauthorized acquisition, use or
disposition during the year ended December 31, 2003.


     MARK G. PAPA       EDMUND P. SEGNER, III      TIMOTHY K. DRIGGERS
Chairman of the Board    President and Chief    Vice President and Chief
and Chief Executive           of Staff             Accounting Officer
       Officer


Houston, Texas
February 23, 2004




              REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS



To the Board of Directors and Stockholders of
EOG Resources, Inc.
Houston, Texas

   We have audited the accompanying consolidated balance sheets
of EOG Resources, Inc. (the "Company") as of December 31, 2003
and 2002, and the related consolidated statements of income,
stockholders' equity, and cash flows for the years then ended.
These consolidated financial statements are the responsibility of
the Company's management.  Our responsibility is to express an
opinion on these consolidated financial statements based on our
audits.  The consolidated financial statements of EOG Resources,
Inc. for the year ended December 31, 2001, were audited by other
auditors who have ceased operations.  Those auditors expressed
an unqualified opinion on those consolidated financial statements
in their report dated February 21, 2002.

   We conducted our audits in accordance with auditing standards
generally accepted in the United States of America.  Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement.  An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements.  An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation.  We believe that our audits provide a reasonable
basis for our opinion.

   In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of the
Company as of December 31, 2003 and 2002, and the results of its
operations and its cash flows for the years then ended in
conformity with accounting principles generally accepted in the
United States of America.

   As discussed in Note 14 to the consolidated financial
statements, the Company adopted Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations,"
on January 1, 2003.


Deloitte & Touche LLP
February 23, 2004




      REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS (Concluded)


     EOG dismissed Arthur Andersen LLP on February 27, 2002 and
subsequently engaged Deloitte & Touche LLP as its independent
auditors.  The predecessor auditor's report appearing below is a
copy of Arthur Andersen's previously issued report dated February
21, 2002.  Since EOG is unable to obtain a current manually
signed audit report, a copy of Arthur Andersen's most recent
signed and dated report has been included to satisfy filing
requirements, as permitted under Rule 2-02(e) of Regulation S-X.
The only information in the financial statements and the related
footnotes included in this Current Report on Form 8-K that is
referred to in the report of Arthur Andersen LLP is the
information included in the accompanying Consolidated Statements
of Income and Consolidated Statements of Cash Flows and the
related footnotes for the year ended December 31, 2001.



To EOG Resources, Inc.:

     We have audited the accompanying consolidated balance sheets
of EOG Resources, Inc. (a Delaware corporation) and subsidiaries
as of December 31, 2001 and 2000, and the related consolidated
statements of income and comprehensive income, shareholders'
equity and cash flows for each of the three years in the period
ended December 31, 2001.  These financial statements are the
responsibility of the Company's management.  Our responsibility
is to express an opinion on these financial statements based on
our audits.

     We conducted our audits in accordance with auditing
standards generally accepted in the United States.  Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement.  An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements.  An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation.  We believe that our audits provide a reasonable
basis for our opinion.

     In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of EOG Resources, Inc. and subsidiaries as of December 31, 2001
and 2000, and the results of their operations and their cash
flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles
generally accepted in the United States.


                                  ARTHUR ANDERSEN LLP

Houston, Texas
February 21, 2002




                           EOG RESOURCES, INC.
       CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
                (In Thousands, Except Per Share Amounts)


                                                         Year Ended December 31,
                                                      2003         2002         2001
                                                                     
  NET OPERATING REVENUES
    Natural Gas                                     $1,537,352   $  915,129   $1,298,102
    Crude Oil, Condensate and Natural Gas Liquids      283,042      227,309      258,101
    Gains (Losses) on Mark-to-Market Commodity
     Derivative Contracts                              (80,414)     (48,508)      97,750
    Other, Net                                           4,695          752        1,769
      TOTAL                                          1,744,675    1,094,682    1,655,722
  OPERATING EXPENSES
    Lease and Well                                     212,601      179,429      175,446
    Exploration Costs                                   76,358       60,228       67,467
    Dry Hole Costs                                      41,156       46,749       71,360
    Impairments                                         89,133       68,430       79,156
    Depreciation, Depletion and Amortization           441,843      398,036      392,399
    General and Administrative                         100,403       88,952       79,963
    Taxes Other Than Income                             85,867       71,881       95,333
    Charges Associated with Enron Bankruptcy                 -            -       19,211
      TOTAL                                          1,047,361      913,705      980,335
  OPERATING INCOME                                     697,314      180,977      675,387
  OTHER INCOME (EXPENSE), NET                           15,273       (1,651)       1,168
  INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES      712,587      179,326      676,555
  INTEREST EXPENSE
    Incurred                                            67,252       68,641       53,756
    Capitalized                                        (8,541)      (8,987)      (8,646)
      Net Interest Expense                              58,711       59,654       45,110
  INCOME BEFORE INCOME TAXES                           653,876      119,672      631,445
  INCOME TAX PROVISION                                 216,600       32,499      232,829
  NET INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
   IN ACCOUNTING PRINCIPLE                             437,276       87,173      398,616
  CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
   PRINCIPLE, NET OF INCOME TAX                         (7,131)           -            -
  NET INCOME                                           430,145       87,173      398,616
  PREFERRED STOCK DIVIDENDS                             11,032       11,032       10,994
  NET INCOME AVAILABLE TO COMMON                    $  419,113   $   76,141   $  387,622

  NET INCOME PER SHARE AVAILABLE TO COMMON
    Basic
      Net Income Available to Common Before
       Cumulative Effect of Change in Accounting
       Principle                                    $     3.72   $     0.66   $     3.35
      Cumulative Effect of Change in Accounting
       Principle, Net of Income Tax                      (0.06)           -            -
      Net Income Available to Common                $     3.66   $     0.66   $     3.35
    Diluted
      Net Income Available to Common Before
       Cumulative Effect of Change in Accounting
       Principle                                    $     3.66   $     0.65   $     3.30
      Cumulative Effect of Change in Accounting
       Principle, Net of Income Tax                      (0.06)           -            -
      Net Income Available to Common                $     3.60   $     0.65   $     3.30
  AVERAGE NUMBER OF COMMON SHARES
      Basic                                            114,597      115,335      115,765
      Diluted                                          116,519      117,245      117,488

  COMPREHENSIVE INCOME
  NET INCOME                                        $  430,145   $   87,173   $  398,616
  OTHER COMPREHENSIVE INCOME (LOSS)
      Foreign Currency Translation Adjustment          123,811        4,315      (22,044)
      Available-for-Sale Security Transactions               -          926       (1,318)
  COMPREHENSIVE INCOME                              $  553,956   $   92,414   $  375,254


The accompanying notes are an integral part of these consolidated financial statements.





                           EOG RESOURCES, INC.
                       CONSOLIDATED BALANCE SHEETS
                    (In Thousands, Except Share Data)



                                                             At December 31,
                                                           2003          2002
                               ASSETS
                                                               
  CURRENT ASSETS
   Cash and Cash Equivalents                           $     4,443   $     9,848
   Accounts Receivable, net                                295,118       259,308
   Inventories                                              21,922        18,928
   Income Taxes Receivable                                   7,976        67,090
   Deferred Income Taxes                                    31,548        12,925
   Other                                                    35,007        26,255
    TOTAL                                                  396,014       394,354
  OIL AND GAS PROPERTIES (SUCCESSFUL EFFORTS METHOD)     8,189,062     6,750,095
   Less:  Accumulated Depreciation, Depletion
    and Amortization                                    (3,940,145)   (3,428,547)
     Net Oil and Gas Properties                          4,248,917     3,321,548
  OTHER ASSETS                                             104,084        97,666
  TOTAL ASSETS                                         $ 4,749,015   $ 3,813,568


                  LIABILITIES AND SHAREHOLDERS' EQUITY
  CURRENT LIABILITIES
   Accounts Payable                                    $   282,379   $   201,931
   Accrued Taxes Payable                                    33,276        22,732
   Dividends Payable                                         6,175         5,007
   Liabilities from Price Risk Management Activities        37,779         5,939
   Deferred Income Taxes                                    73,611        39,634
   Other                                                    43,299        40,304
    TOTAL                                                  476,519       315,547

  LONG-TERM DEBT                                         1,108,872     1,145,132
  OTHER LIABILITIES                                        171,115        59,180
  DEFERRED INCOME TAXES                                    769,128       621,314

  SHAREHOLDERS' EQUITY
  Preferred Stock, $.01 Par, 10,000,000 Shares
   Authorized:
    Series B, 100,000 Shares Issued, Cumulative,
     $100,000,000 Liquidation Preference                    98,589        98,352
    Series D, 500 Shares Issued, Cumulative,
     $50,000,000 Liquidation Preference                     49,827        49,647
  Common Stock, $.01 Par, 320,000,000 Shares
   Authorized and 124,730,000 Shares Issued                201,247       201,247
  Additional Paid in Capital                                 1,625             -
  Unearned Compensation                                    (23,473)      (15,033)
  Accumulated Other Comprehensive Income (Loss)             73,934       (49,877)
  Retained Earnings                                      2,121,214     1,723,948
  Common Stock Held in Treasury, 8,819,600
   shares at December 31, 2003 and 10,009,740
   shares at December 31, 2002                            (299,582)     (335,889)
    TOTAL SHAREHOLDERS' EQUITY                           2,223,381     1,672,395

  TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY           $ 4,749,015   $ 3,813,568



The accompanying notes are an integral part of these consolidated financial statements.







                               EOG RESOURCES, INC.
                 CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
                    (In Thousands, Except Per Share Amounts)

                                                                                Accumulated                Common

                                                      Additional                   Other                    Stock        Total
                                   Preferred  Common    Paid In    Unearned    Comprehensive   Retained    Held In   Shareholders'
                                     Stock     Stock    Capital  Compensation  Income (Loss)   Earnings    Treasury      Equity

                                                                                              
 Balance at December 31, 2000      $147,164  $201,247  $  4,221   $ (3,756)      $(31,756)    $1,301,067  $(237,262)  $1,380,925
   Net Income                            --        --        --         --             --        398,616         --      398,616
   Amortization of Preferred
    Stock Discount                      418        --        --         --             --           (418)        --           --
   Preferred Stock Dividends
    Paid/Declared                        --        --        --         --             --        (10,576)        --      (10,576)
   Common Stock Dividends
    Declared, $.16 Per Share             --        --        --         --             --        (18,523)        --      (18,523)
   Translation Adjustment                --        --        --         --        (22,044)            --         --      (22,044)
   Unrealized Loss on Available-
    for-Sale Security                    --        --        --         --         (1,318)            --         --       (1,318)
   Treasury Stock Purchased              --        --        --         --             --             --   (126,769)    (126,769)
   Treasury Stock Issued Under
    Stock Option Plans                   --        --   (19,097)        --             --         (1,458)    50,403       29,848
   Treasury Stock Issued Under
    Employee Stock Purchase Plan         --        --      (104)        --             --             --      1,061          957
   Tax Benefits from Stock
    Options Exercised                    --        --     7,332         --             --             --         --        7,332
   Restricted Stock and Units            --        --     6,583    (14,467)            --             --      7,884           --
   Amortization of Unearned
    Compensation                         --        --        --      3,270             --             --         --        3,270
   Equity Derivative Transactions        --        --     1,201         --             --             --         --        1,201
   Other                                 --        --      (136)        --             --             --        (97)        (233)
 Balance at December 31, 2001       147,582   201,247        --    (14,953)       (55,118)     1,668,708   (304,780)   1,642,686
   Net Income                            --        --        --         --             --         87,173         --       87,173
   Amortization of Preferred
    Stock Discount                      417        --        --         --             --           (417)        --           --
   Preferred Stock Dividends
    Paid/Declared                        --        --        --         --             --        (10,615)        --      (10,615)
   Common Stock Dividends
    Declared, $.16 Per Share             --        --        --         --             --        (18,499)        --      (18,499)
   Translation Adjustment                --        --        --         --          4,315             --         --        4,315
   Available-for-Sale Security
    Transactions                         --        --        --         --            926             --         --          926
   Treasury Stock Purchased              --        --        --         --             --             --    (63,038)     (63,038)
   Treasury Stock Issued Under
    Stock Option Plans                   --        --    (9,457)        --             --         (2,402)    28,565       16,706
   Treasury Stock Issued Under
    Employee Stock Purchase Plan         --        --       (39)        --             --             --      2,301        2,262
   Tax Benefits from Stock
    Options Exercised                    --        --     5,167         --             --             --         --        5,167
   Restricted Stock and Units            --        --     4,329     (4,951)            --             --        622           --
   Amortization of Unearned
    Compensation                         --        --        --      4,871             --             --         --        4,871
   Other                                 --        --        --         --             --             --        441          441
 Balance at December 31, 2002       147,999   201,247        --    (15,033)       (49,877)     1,723,948   (335,889)   1,672,395
   Net Income                            --        --        --         --             --        430,145         --      430,145
   Amortization of Preferred
    Stock Discount                      417        --        --         --             --           (417)        --           --
   Preferred Stock Dividends
    Paid/Declared                        --        --        --         --             --        (10,615)        --      (10,615)
   Common Stock Dividends
    Declared, $.20 Per Share             --        --        --         --             --        (21,847)        --      (21,847)
   Translation Adjustment                --        --        --         --        123,811             --         --      123,811
   Treasury Stock Purchased              --        --        --         --             --             --    (21,295)     (21,295)
   Treasury Stock Issued Under
    Stock Option Plans                   --        --   (16,522)        --             --             --     46,379       29,857
   Treasury Stock Issued Under
    Employee Stock Purchase Plan         --        --        84         --             --             --      2,515        2,599
   Tax Benefits from Stock
    Options Exercised                    --        --    11,926         --             --             --         --       11,926
   Restricted Stock and Units            --        --     6,084    (14,467)            --             --      8,383           --
   Amortization of Unearned
    Compensation                         --        --        --      6,027             --             --         --        6,027
   Other                                 --        --        53         --             --             --        325          378
 Balance at December 31, 2003      $148,416  $201,247  $  1,625   $(23,473)      $ 73,934     $2,121,214  $(299,582)  $2,223,381



 The accompanying notes are an integral part of these consolidated financial statements.






                            EOG RESOURCES, INC.
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                              (In Thousands)


                                                           Year Ended December 31,
                                                       2003        2002          2001
                                                                   
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of Net Income to Net
 Operating Cash Inflows:
  Net Income                                      $   430,145   $  87,173   $   398,616
  Items Not Requiring Cash
    Depreciation, Depletion and Amortization          441,843     398,036       392,399
    Impairments                                        89,133      68,430        79,156
    Deferred Income Taxes                             191,726      82,179       164,945
    Charges Associated with Enron Bankruptcy                -           -        19,211
    Cumulative Effect of Change in Accounting
     Principle, Net of Income Tax                       7,131           -             -
    Other, Net                                          1,033      17,333        10,423
  Exploration Costs                                    76,358      60,228        67,467
  Dry Hole Costs                                       41,156      46,749        71,360
  Mark-to-Market Commodity Derivative Contracts
    Total (Gains) Losses                               80,414      48,508       (97,750)
    Realized Gains (Losses)                           (44,870)    (21,136)       66,731
    Collar Premium                                     (3,003)     (1,825)       (4,621)
  Tax Benefits from Stock Options Exercised            11,926       5,168         7,332
  Other, Net                                            2,141      (1,978)       (2,292)
  Changes in Components of Working Capital
   and Other Liabilities
    Accounts Receivable                               (36,156)    (61,580)      146,235
    Inventories                                        (2,994)        (57)       (2,248)
    Accounts Payable                                   79,748     (19,012)      (26,949)
    Accrued Taxes Payable                               8,285     (84,666)      (38,619)
    Other Liabilities                                  (3,387)      7,816        (3,422)
    Other, Net                                        (14,400)     (5,578)      (16,442)
  Changes in Components of Working Capital
   Associated with Investing and Financing
   Activities                                         (35,928)     42,782       (34,105)
NET OPERATING CASH INFLOWS                          1,320,301     668,570     1,197,427

INVESTING CASH FLOWS
 Additions to Oil and Gas Properties               (1,204,383)   (714,127)     (974,016)
 Exploration Costs                                    (76,358)    (60,228)      (67,467)
 Dry Hole Costs                                       (41,156)    (46,749)      (71,360)
 Proceeds from Sales of Assets                         13,480       8,089         8,032
 Changes in Components of Working Capital
  Associated with Investing Activities                 37,475     (43,246)       32,405
 Other, Net                                             2,432     (16,277)      (15,649)
NET INVESTING CASH OUTFLOWS                        (1,268,510)   (872,538)   (1,088,055)

FINANCING CASH FLOWS
 Long-Term Debt Borrowings (Repayments)               (36,260)    289,163        (4,155)
 Dividends Paid                                       (31,294)    (29,152)      (28,580)
 Treasury Stock Purchased                             (21,295)    (63,038)     (126,769)
 Proceeds from Stock Options Exercised                 35,138      17,339        30,805
 Other, Net                                            (3,485)     (3,008)        1,687
NET FINANCING CASH INFLOWS (OUTFLOWS)                 (57,196)    211,304      (127,012)

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS       (5,405)      7,336       (17,640)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR          9,848       2,512        20,152
CASH AND CASH EQUIVALENTS AT END OF YEAR           $    4,443   $   9,848   $     2,512



The accompanying notes are an integral part of these consolidated financial statements.





                       EOG RESOURCES, INC.

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  Summary of Significant Accounting Policies

     Principles of Consolidation.  The consolidated financial
statements of EOG Resources, Inc. (EOG) include the accounts of
all domestic and foreign subsidiaries.  Investments in
unconsolidated affiliates, in which EOG is able to exercise
significant influence, are accounted for using the equity method.
All material intercompany accounts and transactions have been
eliminated.

     The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenue and
expenses during the reporting period.  Actual results could
differ from those estimates.

     Certain reclassifications have been made to prior period
financial statements to conform with the current presentation.

     Financial Instruments.  EOG's financial instruments consist
of cash and cash equivalents, marketable securities, commodity
derivative contracts, accounts receivable, accounts payable and
long-term debt.  The carrying values of cash and cash
equivalents, marketable securities, commodity derivative
contracts, accounts receivable and accounts payable approximate
fair value (see Note 2 for fair value of long-term debt).

     Cash and Cash Equivalents.  EOG records as cash equivalents
all highly liquid short-term investments with original maturities
of three months or less.

     Oil and Gas Operations.  EOG accounts for its natural gas
and crude oil exploration and production activities under the
successful efforts method of accounting.

     Oil and gas lease acquisition costs are capitalized when
incurred.  Unproved properties with individually significant
acquisition costs are assessed quarterly on a
property-by-property basis, and any impairment in value is
recognized.  Unproved properties with acquisition costs that are
not individually significant are aggregated, and the portion of
such costs estimated to be nonproductive, based on historical
experience, is amortized over the average holding period.  If the
unproved properties are determined to be productive, the
appropriate related costs are transferred to proved oil and gas
properties. Lease rentals are expensed as incurred.

     Oil and gas exploration costs, other than the costs of
drilling exploratory wells, are charged to expense as incurred.
The costs of drilling exploratory wells are capitalized pending
determination of whether they have discovered proved commercial
reserves.  If proved commercial reserves are not discovered, such
drilling costs are expensed.  Costs to develop proved reserves,
including the costs of all development wells and related
equipment used in the production of natural gas and crude oil,
are capitalized.

     Depreciation, depletion and amortization of the cost of
proved oil and gas properties is calculated using the
unit-of-production method.  Estimated future dismantlement,
restoration and abandonment costs, net of salvage values, are
taken into account. Certain other assets are depreciated on a
straight-line basis.

     EOG accounts for impairments under the provisions of
Statement of Financial Accounting Standards (SFAS) No. 144 -
"Accounting for the Impairment or Disposal of Long-Lived Assets."
Periodically, or when circumstances indicate that an asset may be
impaired, EOG compares expected undiscounted future cash flows at
a producing field level to the unamortized capitalized cost of
the asset.  If the future undiscounted cash flows, based on EOG's
estimate of future crude oil and natural gas prices, operating
costs, anticipated production from proved reserves and other
relevant data, are lower than the unamortized capitalized cost,
the capitalized cost is reduced to fair value.  Fair value is
calculated by discounting the future cash flows at an appropriate
risk-adjusted discount rate.

     Inventories, consisting primarily of tubular goods and well
equipment held for use in the exploration for, and development
and production of natural gas and crude oil reserves, are carried
at cost with adjustments made from time to time to recognize any
reductions in value.

     Natural gas and liquids revenues are recorded when
production is delivered.  Revenues are recorded on the
entitlement method based on EOG's percentage ownership of current
production.  Each working interest owner in a well generally has
the right to a specific percentage of production, although actual
production sold on that owner's behalf may differ from that
owner's ownership percentage.  Under entitlement accounting, a
receivable is recorded when underproduction occurs and a payable
is recorded when overproduction occurs.

     Capitalized Interest Costs.  Interest capitalization is
required for those properties if its effect, compared with the
effect of expensing interest, is material.  Accordingly, certain
interest costs have been capitalized as a part of the historical
cost of unproved oil and gas properties.  The amount capitalized
is an allocation of the interest cost incurred during the
reporting period.  The interest rate used for capitalization
purposes is based on the interest rates on EOG's outstanding
borrowings.

     Accounting for Price Risk Management Activities.  EOG
accounts for its price risk management activities under the
provisions of SFAS No. 133 - "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS Nos. 137,
138 and 149.  The statement establishes accounting and reporting
standards requiring that every derivative instrument be recorded
in the balance sheet as either an asset or liability measured at
its fair value.  The statement requires that changes in the
derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met.  During 2001,
2002 and 2003, EOG elected not to designate any of its price risk
management activities as accounting hedges under SFAS No. 133,
and accordingly, accounted for them using the mark-to-market
accounting method.  Under this accounting method, the changes in
the market value of outstanding financial instruments are
recognized as gains or losses in the period of change.  The gains
or losses are recorded in Gains (Losses) on Mark-to-Market
Commodity Derivative Contracts.  The related cash flow impact is
reflected as cash flows from operating activities (see Note 12).

     Income Taxes.  EOG accounts for income taxes under the
provisions of SFAS No. 109 - "Accounting for Income Taxes." SFAS
No. 109 requires the asset and liability approach for accounting
for income taxes.  Under this approach, deferred tax assets and
liabilities are recognized based on anticipated future tax
consequences attributable to differences between financial
statement carrying amounts of assets and liabilities and their
respective tax bases (see Note 6).

     Foreign Currency Translation.  For subsidiaries whose
functional currency is deemed to be other than the United States
dollar, asset and liability accounts are translated at year-end
exchange rates and revenue and expenses are translated at average
exchange rates prevailing during the year.  Translation
adjustments are included in Accumulated Other Comprehensive
Income (Loss).  Any gains or losses on transactions or monetary
assets or liabilities in currencies other than the functional
currency are included in net income in the current period.

     Net Income Per Share.  In accordance with the provisions of
SFAS No. 128 - "Earnings per Share," basic net income per share
is computed on the basis of the weighted-average number of common
shares outstanding during the periods.  Diluted net income per
share is computed based upon the weighted-average number of
common shares plus the assumed issuance of common shares for all
potentially dilutive securities (see Note 9 for additional
information to reconcile the difference between the Average
Number of Common Shares outstanding for basic and diluted net
income per share).

     Stock Options.  EOG accounts for stock options under the
provisions and related interpretations of Accounting Principles
Board (APB) Opinion No. 25 - "Accounting for Stock Issued to
Employees."  No compensation expense is recognized for such
options.  As allowed by SFAS No. 123 - "Accounting for Stock-
Based Compensation" issued in 1995, EOG has continued to apply
APB Opinion No. 25 for purposes of determining net income and to
present the pro forma disclosures required by SFAS No. 123 (see
Note 7).

     New Accounting Pronouncements. In June 2001, the Financial
Accounting Standards Board (FASB) issued SFAS No. 143 -
"Accounting for Asset Retirement Obligations" effective for
fiscal years beginning after June 15, 2002.  SFAS No. 143
essentially requires entities to record the fair value of a
liability for legal obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement
costs.  EOG adopted the statement on January 1, 2003.  The impact
of adopting the statement results in an after-tax charge of $7.1
million, which was reported in the first quarter of 2003 as
cumulative effect of change in accounting principle.

     In November 2002, the FASB released its Interpretation No.
45 - "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Others"  (FIN 45).  FIN 45 requires a company, when serving as a
guarantor, to disclose its obligations and/or recognize the
liability associated with the guarantee.  The initial recognition
and measurement provisions of this Interpretation are applicable
to guarantees issued or modified after December 31, 2002 on a
prospective basis.  Disclosure is effective for financial
statements of interim or annual periods ending after December 15,
2002.  EOG has identified one instance where it acts as a co-
guarantor in a loan agreement between a bank and a school in
Trinidad.  The maximum exposure for EOG is US $1 million.  EOG
deems the amount immaterial.  The guarantee does not require
measurement and recognition under FIN 45.

     In December 2002, the FASB issued SFAS No. 148 - "Accounting
for Stock-Based Compensation - Transition and Disclosure - an
amendment of FASB Statement No. 123."  This statement provides
alternative methods of transition for a voluntary change to the
fair value based method of accounting for stock-based employee
compensation, along with the requirement of disclosure in both
annual and interim financial statements about the method used and
effect on reported results (see Note 7).  Subsequently, at the
April 22, 2003 FASB meeting, the FASB decided to require all
companies to expense the value of employee stock options.
Companies will be required to measure the cost according to the
fair value of the options under a method yet to be determined.
On October 1, 2003, the FASB set a goal of completing its
deliberations and issuing a final statement in the second half of
2004.  EOG continues to monitor the developments in this area as
details of the implementation of the decision emerge.

     In January 2003, the FASB released its Interpretation No. 46 -
"Consolidation of Variable Interest Entities, an Interpretation
of Accounting Research Bulletin no. 51" (FIN 46).  FIN 46
requires a company to consolidate a variable interest entity
(VIE) if the company has a variable interest (or combination of
variable interests) that will absorb a majority of the entity's
expected losses if they occur, receive a majority of the entity's
expected residual returns if they occur, or both.  Since EOG does
not own any interest in a VIE, the release of FIN 46 does not
have any effect on its financial position or results of
operations.

     During the third quarter of 2003, the Securities and
Exchange Commission (SEC) has made comments to other registrants
that oil and gas mineral rights acquired should be classified as
an intangible asset pursuant to SFAS No. 141 - "Business
Combinations," and SFAS No. 142 - "Goodwill and Other Intangible
Assets."  However, the SEC is not requiring all oil and gas
producing companies to apply this classification or the
disclosure requirements of intangible assets.  Currently, EOG
classifies the cost of oil and gas mineral rights as oil and gas
properties and believes that this is consistent with oil and gas
accounting and industry practice.  The FASB has been asked to
address this issue.  If the FASB determines that the
reclassification is required, EOG would reclassify these costs
from oil and gas properties to intangible assets on the balance
sheet.  There would be no effect on the statement of income or
cash flows.

     In December 2003, the FASB issued a revision to SFAS No. 132 -
"Employers' Disclosures about Pensions and Other Postretirement
Benefits."  The revised SFAS No. 132 retains the disclosures
required by the original SFAS No. 132 and requires additional
disclosures on the types of plan assets, investment strategy,
measurement dates, plan obligations, cash flows and components of
net periodic benefit cost recognized during interim periods.
This revision to SFAS No. 132 does not have any effect on EOG's
financial position or results of operations.  EOG has modified
its existing disclosure on benefit plans to incorporate this
revision (see Note 7).

     In January 2004, the FASB released its FASB Staff Position
No. 106-1 - "Accounting and Disclosure Requirements related to
the Medicare Prescription Drug, Improvement and Modernization Act
of 2003" (FSP 106-1), which allows a company to make a one-time
election to defer accounting for the effects of the Medicare
Prescription Drug Improvement Act of 2003 (Act).  While EOG is
aware of the Act, any measures of the Accounting for
Postretirement Benefits Other than Pensions or net periodic
postretirement benefit cost in the financial statements and
accompanying Footnote 7 below, do not reflect the effects of the
Act on the plan.  Specific authoritative guidance on the
accounting for the federal subsidy is pending and that guidance,
when issued, could require the company to change previously
reported information.

2.  Long-Term Debt

     Long-Term Debt at December 31 consisted of the following (in
thousands):



                                                   2003         2002

                                                      
Commercial Paper                               $   98,050   $  120,000
Uncommitted Credit Facilities                          --       14,310
Senior Unsecured Term Loan Facility due 2005      150,000      150,000
6.50% Notes due 2004                              100,000      100,000
6.70% Notes due 2006                              126,870      126,870
6.50% Notes due 2007                              100,000      100,000
6.00% Notes due 2008                              173,952      173,952
6.65% Notes due 2028                              140,000      140,000
7.00% Subsidiary Debt due 2011                    220,000      220,000
     Total                                     $1,108,872   $1,145,132



     During 2003 and 2002, EOG utilized commercial paper and
short-term funding from uncommitted credit facilities, bearing
market interest rates, for various corporate financing purposes.
Commercial paper and uncommitted credit borrowings are classified
as long-term debt based on EOG's intent and ability to ultimately
replace such amounts with other long-term debt.

     On July 23, 2003, EOG entered into a new three-year
Revolving Credit Agreement (Agreement) with domestic and foreign
lenders which provides for $600 million in long-term committed
credit, and concurrently cancelled the existing $300 million 364-
day credit facility and $300 million five-year credit facility
scheduled to expire in July 2003 and July 2004, respectively.
Advances under the Agreement bear interest based upon a base rate
or a Eurodollar rate at the option of EOG.  The Agreement also
provides for the allocation, at the option of EOG, of up to $75
million of the $600 million to its Canadian subsidiary. Advances
to the Canadian subsidiary, should they occur, would be
guaranteed by EOG and would bear interest at the option of the
Canadian subsidiary based upon a Canadian prime rate or a
Canadian banker's acceptance rate.  EOG also has the option to
issue up to $100 million in letters of credit as part of this
Agreement.  No amounts were borrowed under this Agreement at
December 31, 2003.

     EOG maintains a three-year Senior Unsecured Term Loan
Facility (Facility) with a group of banks whereby the banks lent
EOG $150 million with a maturity date of October 30, 2005.  This
Facility calls for interest to be charged at a spread over LIBOR
(London InterBank Offering Rate) or the base rate at EOG's
option, and contains substantially the same covenants as those in
EOG's $600 million Long-Term Revolving Credit Agreement.  The
applicable interest rate for this Facility was 1.88% at December
31, 2003.

     The 6.00% to 6.70% Notes due 2004 to 2028 were issued
through public offerings and have effective interest rates of
6.14% to 6.83%.  The Subsidiary Debt due 2011 bears interest at a
fixed rate of 7.00% and is guaranteed by EOG.  The weighted
average interest rate for the commercial paper was 1.28% for
2003.

     At December 31, 2003, the aggregate annual maturities of
long-term debt were $100 million for 2004, $150 million for 2005,
$127 million in 2006, $100 million for 2007 and $174 million for
2008.  The 6.50% Notes due 2004 are classified as long-term debt
based on EOG's intent and ability to ultimately refinance such
amounts with other long-term debt.

     Both EOG's credit Agreement and Facility contain certain
restrictive covenants, including a maximum debt-to-total
capitalization ratio of 65% and a minimum ratio of EBITDAX
(earnings before interest, taxes, DD&A, and exploration expense)
to interest expense of at least three times.  Other than these
covenants, EOG does not have any other financial covenants in its
financing agreements.  EOG continues to comply with these two
covenants and does not view them as materially restrictive.

     Shelf Registration.  As of February 24, 2004, the amount
available under various filed registration statements with the
SEC for the offer and sale from time to time of EOG debt
securities, preferred stock and/or common stock totaled $688
million.

     Fair Value Of Long-Term Debt.  At December 31, 2003 and
2002, EOG had $1,109 million and $1,145 million, respectively, of
long-term debt, which had fair values of approximately
$1,175 million and $1,225 million, respectively. The fair value
of long-term debt is the value EOG would have to pay to retire
the debt, including any premium or discount to the debt-holder
for the differential between the stated interest rate and the
year-end market rate.  The fair value of long-term debt is based
upon quoted market prices and, where such quotes were not
available, upon interest rates available to EOG at yearend.

3.  Shareholders' Equity

     EOG purchases its common stock from time to time in the open
market to be held in treasury for the purpose of, but not limited
to, fulfilling any obligations arising under EOG's stock plans
and any other approved transactions or activities for which such
common stock shall be required.  In September 2001, the Board of
Directors authorized the purchase of an aggregate maximum of 10
million shares of common stock of EOG which superseded all
previous authorizations.  At December 31, 2003, 6,386,200 shares
remain available for repurchases under this authorization.

     During the second quarter of 2001, EOG sold put options for
$1.2 million obligating EOG to purchase up to 0.6 million shares
of its common stock at an average price of $33.42 per share.
These options expired unexercised in December 2001.  EOG had one
million put options which it had written which were outstanding
at December 31, 2000.  The strike price of these options was
$18.00 per share, and they expired unexercised in April 2001.

     The following summarizes shares of common stock outstanding
(in thousands):



                                           Common Shares
                                      2003      2002      2001

                                               
Outstanding at January 1            114,720   115,452   116,904
Repurchased                            (531)   (1,700)   (3,281)
Issued Pursuant to Stock Options
 and Stock Plans                      1,721       968     1,829
   Outstanding at December 31       115,910   114,720   115,452



     On February 14, 2000, EOG's Board of Directors declared a
dividend of one preferred share purchase right (a "Right," and
the agreement governing the terms of such Rights, the "Rights
Agreement") for each outstanding share of common stock, par value
$.01 per share.  The Board of Directors has adopted this Rights
Agreement to protect stockholders from coercive or otherwise
unfair takeover tactics.  The dividend was distributed to the
stockholders of record on February 24, 2000. Each Right, expiring
February 24, 2010, represents a right to buy from EOG one
hundredth (1/100) of a share of Series E Junior Participating
Preferred Stock (Preferred Share) for $90, once the Rights become
exercisable.  This portion of a Preferred Share will give the
stockholder approximately the same dividend, voting, and
liquidation rights as would one share of common stock.  Prior to
exercise, the Right does not give its holder any dividend,
voting, or liquidation rights.  If issued, each one hundredth
(1/100) of a Preferred Share (i) will not be redeemable;
(ii) will entitle holders to quarterly dividend payments of $.01
per share, or an amount equal to the dividend paid on one share
of common stock, whichever is greater; (iii) will entitle holders
upon liquidation either to receive $1 per share or an amount
equal to the payment made on one share of common stock, whichever
is greater; (iv) will have the same voting power as one share of
common stock; and (v) if shares of EOG's common stock are
exchanged via merger, consolidation, or a similar transaction,
will entitle holders to a per share payment equal to the payment
made on one share of common stock.

     The Rights will not be exercisable until ten days after the
public announcement that a person or group has become an
acquiring person (Acquiring Person) by obtaining beneficial
ownership of 10% or more of EOG's common stock, or if earlier,
ten business days (or a later date determined by EOG's Board of
Directors before any person or group becomes an Acquiring Person)
after a person or group begins a tender or exchange offer which,
if consummated, would result in that person or group becoming an
Acquiring Person.  On December 10, 2002, the Rights Agreement was
amended to create an exception to the definition of Acquiring
Person to permit a qualified institutional investor to
beneficially own 10% or more but less than 15% of EOG's common
stock without being deemed an Acquiring Person if the
institutional investor meets the following requirements: (i) the
institutional investor is described in Rule 13d-1(b)(1)
promulgated under the Securities Exchange Act of 1934 and is
eligible to report (and does in fact report) beneficial ownership
of common stock on Schedule 13G; (ii) the institutional investor
is not required to file a Schedule 13D (or any successor or
comparable report) with respect to its beneficial ownership of
EOG's common stock; and (iii) the institutional investor does not
beneficially own 15% or more of EOG's common stock then
outstanding.

     If a person or group becomes an Acquiring Person, all
holders of Rights, except the Acquiring Person, may for $90,
purchase shares of EOG's common stock with a market value of
$180, based on the market price of the common stock prior to such
acquisition.  If EOG is later acquired in a merger or similar
transaction after the Rights become exercisable, all holders of
Rights except the Acquiring Person may, for $90, purchase shares
of the acquiring corporation with a market value of $180 based on
the market price of the acquiring corporation's stock, prior to
such merger.

     EOG's Board of Directors may redeem the Rights for $.01 per
Right at any time before any person or group becomes an Acquiring
Person. If the Board of Directors redeems any Rights, it must
redeem all of the Rights.  Once the Rights are redeemed, the only
right of the holders of Rights will be to receive the redemption
price of $.01 per Right.  The redemption price will be adjusted
if EOG has a stock split or stock dividends of EOG's common
stock.  After a person or group becomes an Acquiring Person, but
before an Acquiring Person owns 50% or more of EOG's outstanding
common stock, the Board of Directors may exchange the Rights for
common stock or equivalent security at an exchange ratio of one
share of common stock or an equivalent security for each such
Right, other than Rights held by the Acquiring Person.

4.  Enron Corp. Bankruptcy

     In December 2001, Enron Corp. and certain of its affiliates,
including Enron North America Corp., filed voluntary petitions
for reorganization under Chapter 11 of the United States
Bankruptcy Code.  EOG recorded $19 million in charges associated
with the Enron bankruptcies in the fourth quarter of 2001 related
to certain contracts with Enron affiliates, including 2001 and
2002 natural gas and crude oil derivative contracts.  Based on
EOG's review of all matters related to Enron Corp. and its
affiliates, EOG believes that Enron Corp.'s Chapter 11
proceedings will not have a material adverse effect on EOG's
financial position.

5.  Other Income (Expense), Net

     Other Income (Expense), Net for 2003 included foreign
currency transaction gains of $9 million as a result of applying
the changes in the Canadian exchange rate to certain intercompany
short-term loans that eliminate in consolidation.

6.  Income Taxes

     The principal components of EOG's net deferred income tax
liability at December 31, 2003 and 2002 were as follows (in
thousands):



                                                             2003       2002
                                                               
Current Deferred Income Tax Assets
  Commodity Hedging Contracts                             $  9,739   $ (1,688)
  Deferred Compensation Plans                                4,994      3,801
  Net Operating Loss                                         5,225         --
  Other                                                     11,590     10,812
     Total Current Deferred Income Tax Assets               31,548     12,925

Current Deferred Income Tax Liabilities
  Timing Differences Associated With Different
   Yearends In Foreign Jurisdictions                        73,611     39,634

     Total Net Current Deferred Income Tax Liability      $ 42,063   $ 26,709

Noncurrent Deferred Income Tax Assets
 (included in Other Assets)
     Foreign Net Operating Loss Carryforward              $  3,688   $     --

Noncurrent Deferred Income Tax Assets
  Non-Producing Leasehold Costs                           $ 36,154   $ 29,574
  Seismic Costs Capitalized for Tax                         21,365     18,657
  Alternative Minimum Tax Credit Carryforward                3,869     20,200
  Other                                                     20,124     12,589
     Total Noncurrent Deferred Income Tax Assets            81,512     81,020

Noncurrent Deferred Income Tax Liabilities
  Oil and Gas Exploration and Development Costs
   Deducted for Tax Over Book Depreciation,
   Depletion and Amortization                              837,189    691,555
  Capitalized Interest                                      13,451     10,779
     Total Noncurrent Deferred Income Tax Liabilities      850,640    702,334
     Total Net Noncurrent Deferred Income Tax Liability   $769,128   $621,314

Total Net Deferred Income Tax Liability                   $807,503   $648,023



     The components of income before income taxes were as follows
(in thousands):



                                      2003       2002       2001

                                                 
United States                       $442,109   $ 37,354   $488,741
Foreign                              211,767     82,318    142,704
   Total                            $653,876   $119,672   $631,445



     Total income tax provision was as follows (in thousands):



                                       2003       2002        2001
                                                  
Current:
  Federal                           $  3,844   $(61,013)   $ 36,737
  State                                  880     (5,130)      5,475
  Foreign                             20,150     16,463      25,672
   Total                              24,874    (49,680)     67,884
Deferred:
  Federal                            151,389     57,232     131,127
  State                                4,052       (358)     10,411
  Foreign                             36,285     25,305      23,407
   Total                             191,726     82,179     164,945
Income Tax Provision                $216,600   $ 32,499    $232,829



     The differences between taxes computed at the U.S. federal
statutory tax rate and EOG's effective rate were as follows:



                                              2003     2002     2001

                                                      
Statutory Federal Income Tax Rate            35.00%   35.00%   35.00%
State Income Tax, Net of Federal Benefit      0.73     0.22     1.64
Income Tax Provision Related to Foreign
 Operations                                  (0.05)   (3.54)    0.36
Change in Canadian Federal Tax Rate          (2.16)      --       --
Tight Gas Sands Federal Income Tax Credits      --    (3.57)   (0.83)
Other                                        (0.40)   (0.95)    0.70
   Effective Income Tax Rate                 33.12%   27.16%   36.87%



     EOG's foreign subsidiaries' undistributed earnings of
approximately $722 million at December 31, 2003 are considered to
be indefinitely invested outside the U.S. and, accordingly, no
U.S. federal or state income taxes have been provided thereon.
Upon distribution of those earnings in the form of dividends, EOG
may be subject to both foreign withholding taxes and U.S. income
taxes, net of allowable foreign tax credits.  Determination of
any potential amount of unrecognized deferred income tax
liabilities is not practicable.

     EOG incurred a tax net operating loss of $191 million in
2002.  During 2003, EOG utilized $176 million of the 2002 net
operating loss.  The remaining net operating loss of $15 million
will not expire until 2022.  EOG expects the entire remaining net
operating loss to be utilized in 2004.

     A foreign net operating loss of $9 million was incurred
during 2003.  These losses will be carried forward indefinitely
until they are utilized.

     EOG has an alternative minimum tax (AMT) credit carryforward
of $4 million which can be used to offset regular income taxes
payable in future years.  The AMT credit carryforward has an
indefinite carryforward period.

7.  Employee Benefit Plans

Pension Plans

     EOG has defined contribution pension and savings plans in
place for most of its employees in the United States.  EOG's
contributions to these plans are based on various percentages of
compensation, and in some instances, are based upon the amount of
the employees' contributions to the plan.  For 2003, 2002 and
2001, the contributions to these plans amounted to approximately
$8.2 million, $8.0 million and $6.5 million, respectively.

     In addition, EOG's Canadian subsidiary maintains a non-
contributory defined contribution pension plan and a matched
savings plan and EOG's Trinidadian subsidiary maintains a
contributory defined benefit pension plan and a matched savings
plan.  These plans are available to most employees of the
Canadian and Trinidadian subsidiaries and activity related to
these plans was less than $1 million combined for 2003, which is
deemed immaterial relative to EOG's operations.

Postretirement Plan

     During 2000, EOG adopted postretirement medical and dental
benefits for eligible employees and their eligible dependents.
Benefits are provided under the provisions of a contributory
defined dollar benefit plan.  EOG accrues these postretirement
benefit costs over the service lives of the employees expected to
be eligible to receive such benefits.  The following table
summarizes EOG's postretirement benefit plan (in thousands):



                                                        As of December 31,
                                                     2003      2002      2001
                                                              
Change in Benefit Obligation
Benefit Obligation at Beginning of Year            $ 1,875   $ 2,021   $ 1,526
Service Cost                                           175       139       192
Interest Cost                                          131       115       134
Plan Participants' Contributions                        64        58        34
Amendments                                             773        --        --
Benefits Paid                                         (102)      (95)      (63)
Actuarial (Gain) Loss                                   95      (363)      198
     Benefit Obligation at Yearend                 $ 3,011   $ 1,875   $ 2,021

Change in Plan Asset
Fair Value of Plan Asset at Beginning of Year      $    --   $    --   $    --
Employer Contributions                                  38        37        29
Plan Participants Contributions                         64        58        34
Benefits Paid                                         (102)      (95)      (63)
     Fair Value of Plan Asset at End of Year       $    --   $    --   $    --

Reconciliation of Funded Status to Balance Sheet
Funded Status                                      $ 3,011   $ 1,875   $ 2,021
Unrecognized Net Actuarial Gain (Loss)                 (64)       35      (327)
Unrecognized Prior Service (Cost) Benefit           (1,647)     (948)   (1,024)
     Accrued Benefit Cost at Yearend               $ 1,300   $   962   $   670

Components of Net Periodic Benefit Cost
Service Cost                                       $   175   $   139   $   192
Interest Cost                                          131       115       134
Amortization of Prior Service Cost                      75        75        75
Recognized Net Actuarial Loss (Gain)                    --        (1)        8
     Net Periodic Benefit Cost                     $   381   $   328   $   409



     Weighted-average discount rate assumptions used in the
determination of benefit obligations at December 31, 2003, 2002
and 2001 were 6.15%, 6.40% and 7.00%, respectively.  Weighted-
average discount rate assumptions used in the determination of
net periodic benefit cost for years ended December 31, 2003, 2002
and 2001 were 6.40%, 7.00% and 7.25%, respectively.

     Estimated Future Employer-Paid Benefits.  The following
benefits, which reflect expected future service, as appropriate,
are expected to be paid by EOG in the next 10 years (in
thousands):



                                    Postretirement
                                Employer-Paid Benefits

                                      
          2004                           $ 57
          2005                             68
          2006                             81
          2007                             92
          2008                            104
          2009 - 2013                     855



     Postretirement health care trend rates have zero effect on
the amounts reported for the postretirement health care plan for
both 2003 and 2002.  A one-percentage point increase or decrease
in EOG's healthcare cost trend rates would have zero impact on
the postretirement benefit obligation, as any increase or
decrease in healthcare costs would be borne by the employee.

Stock Plans

     EOG has various stock plans (Plans) under which employees
and non-employee members of the Board of Directors of EOG and its
subsidiaries have been or may be granted certain equity
compensation.  At December 31, 2003, the total number of shares
authorized for grant from the Plans was 27,445,000 shares.

     Stock Options.  Under the Plans, participants have been or
may be granted rights to purchase shares of common stock of EOG
at a price not less than the market price of the stock at the
date of grant.  Stock options granted under the Plans vest either
immediately at the date of grant or up to four years from the
date of grant based on the nature of the grants and as defined in
individual grant agreements.  Terms for stock options granted
under the Plans have not exceeded a maximum term of 10 years.

     The following table sets forth the option transactions for
the years ended December 31 (options in thousands):



                                           2003               2002               2001
                                               Average            Average            Average
                                                Grant              Grant              Grant
                                     Options    Price   Options    Price   Options    Price

                                                                   
Outstanding at January 1              7,842    $27.31    7,013    $24.69    7,056    $20.70
Granted                               1,515     39.13    1,809     33.82    1,631     36.63
Exercised                            (1,485)    22.73     (868)    19.90   (1,563)    19.18
Forfeited                              (121)    34.74     (112)    27.64     (111)    23.84
Outstanding at December 31            7,751     30.38    7,842     27.31    7,013     24.69

Options Exercisable at December 31    4,933     27.03    5,041     23.96    4,034     22.04

Available for Future Grant            1,178              2,932              4,531

Average Fair Value of Options
 Granted During Year                 $16.55             $14.79             $16.76



     The fair value of each option grant is estimated using the
Black-Scholes option-pricing model with the following
weighted-average assumptions used for grants in 2003, 2002 and
2001, respectively: (1) dividend yield of 0.4%, 0.4% and 0.5%,
(2) expected volatility of 43%, 45% and 43%, (3) risk-free
interest rate of 3.4%, 3.7% and 4.6% and (4) expected life of 5.2
years, 5.3 years and 6.0 years.

     The following table summarizes certain information for the
options outstanding at December 31, 2003 (options in thousands):



                               Options Outstanding           Options Exercisable
                                    Weighted      Weighted             Weighted
                                     Average       Average              Average
                                    Remaining       Grant                Grant
Range of Grant Prices    Options   Life (Years)     Price    Options     Price

                                                         
  $13.00 to $17.99          892         4          $14.59       887     $14.58
   18.00 to  22.99        1,370         4           20.06     1,369      20.06
   23.00 to  28.99          198         3           24.33       195      24.27
   29.00 to  33.99        2,351         8           33.25     1,276      33.04
   34.00 to  39.99        2,568         9           37.27       929      36.37
   40.00 to  54.99          372         7           43.86       277      44.19
                          7,751         7           30.38     4,933      27.03



     EOG's pro forma net income and net income per share of
common stock for 2003, 2002 and 2001, had compensation costs been
recorded in accordance with SFAS No. 123, are presented below (in
millions, except per share data):
                                               Year Ended December 31,


                                                2003     2002     2001

                                                        
Net Income Available to Common - As Reported   $419.1   $ 76.1   $387.6
Deduct: Total stock-based employee
 compensation expense                           (13.9)   (13.7)   (11.9)
Net Income Available to Common - Pro Forma     $405.2   $ 62.4   $375.7

Net Income per Share Available to Common
  Basic - As Reported                          $ 3.66   $ 0.66   $ 3.35
  Basic - Pro Forma                            $ 3.54   $ 0.54   $ 3.25

  Diluted - As Reported                        $ 3.60   $ 0.65   $ 3.30
  Diluted - Pro Forma                          $ 3.48   $ 0.53   $ 3.20



     The effects of applying SFAS No. 123 in this pro forma
disclosure should not be interpreted as being indicative of
future effects.  SFAS No. 123 does not apply to awards prior to
1995, and the extent and timing of additional future awards
cannot be predicted.

     Restricted Stock and Units.  Under the Plans, employees may
be granted restricted stock and/or units without cost to them.
The shares and units granted vest to the employee at various
times ranging from one to five years from the date of grant based
on the nature of the grants and as defined in individual grant
agreements.  Upon vesting, restricted shares are released to the
employee.  Upon vesting, restricted units are converted into one
share of common stock and released to the employee.  The
following summarizes shares of restricted stock and units granted
(shares and units in thousands):



                                                  Restricted Shares and Units
                                                    2003     2002     2001

                                                            
Outstanding at January 1                              775      632      309
Granted                                               372      158      353
Released                                             (103)     (10)     (15)
Forfeited or Expired                                  (18)      (5)     (15)
Outstanding at December 31                          1,026      775      632
Average Fair Value of Shares Granted During Year   $40.43   $32.56   $42.08



     The fair value of the restricted shares and units at date of
grant has been recorded in shareholders' equity as unearned
compensation and is being amortized over the vesting period as
compensation expense.  Related compensation expense for 2003,
2002 and 2001 was $6.0 million, $4.9 million and $3.3 million,
respectively.

     Employee Stock Purchase Plan.  During 2001, EOG implemented
an Employee Stock Purchase Plan (ESPP) that allows eligible
employees to semi-annually purchase, through payroll deductions,
shares of EOG common stock at 85 percent of the fair market value
at specified dates.  Contributions to the ESPP are limited to 10
percent of the employees' pay (subject to certain ESPP limits)
during each of the two six-month offering periods.  As of
December 31, 2003, 324,362 common shares remained available for
issuance under the plan.  During 2003, approximately 410
employees participated in the plan and 74,094 common shares were
purchased at an aggregate price of $2.6 million.  During 2002,
approximately 350 employees participated in the plan and 69,243
common shares were purchased at an aggregate price of $2.3
million.  During 2001, approximately 300 employees participated
in the plan and 32,301 common shares were purchased at an
aggregate price of $1.0 million.

     Treasury Shares.  During 2003, 2002 and 2001, EOG
repurchased 531,000, 1,700,000 and 3,281,000 of its common
shares, respectively.  Approximately 531,000, 968,000 and
1,829,000 of these common shares were repurchased during 2003,
2002 and 2001, respectively, to offset the dilution resulting
from shares issued under the EOG employee stock plans.  The
difference between the cost of the treasury shares and the
exercise price of the options, net of federal income tax benefit
of $11.9 million, $5.2 million and $7.3 million, for the years
2003, 2002 and 2001, respectively, is reflected as an adjustment
to additional paid in capital to the extent EOG has accumulated
additional paid in capital relating to treasury stock and
retained earnings thereafter.

8.  Commitments and Contingencies

     Letters Of Credit.  At December 31, 2003 and 2002, EOG had
standby letters of credit and guarantees outstanding totaling
approximately $266 million and $234 million, respectively;
however, of these amounts, $220 million represents guarantees of
subsidiary indebtedness included under Note 2 "Long-Term Debt."

     Minimum Commitments.  At December 31, 2003, total minimum
commitments from long-term non-cancelable operating leases,
drilling rig commitments and pipeline transportation service
commitments, based on current transportation rates and the
Canadian currency exchange rate at December 31, 2003, are as
follows (in thousands):



                                  Total Minimum
                                   Commitments

                                  
               2004                  $ 32,835
               2005 - 2007             52,763
               2008 - 2009              7,897
               2010 and beyond          9,221
                                     $102,716



     Included in the table above are leases for buildings,
facilities and equipment with varying expiration dates through
2012.  Rental expenses associated with these leases amounted to
$22 million, $21 million and $20 million for 2003, 2002 and 2001,
respectively.

     Contingencies.  EOG and numerous other companies in the
natural gas industry are named as defendants in various lawsuits
alleging violations of the Civil False Claims Act.  These
lawsuits have been consolidated for pre-trial proceedings in the
United States District Court for the District of Wyoming.  The
plaintiffs contend that defendants have underpaid royalties on
natural gas and natural gas liquids produced on federal and
Indian lands through the use of below-market prices, improper
deductions, improper measurement techniques and transactions with
affiliated companies.  Plaintiffs allege that the royalties paid
by defendants were lower than the royalties required to be paid
under federal regulations and that the forms filed by defendants
with the Minerals Management Service reporting these royalty
payments were false, thereby violating the Civil False Claims
Act.  The United States has intervened in certain of the cases as
to some of the defendants, but has not intervened as to EOG.  The
plaintiffs in one of the two lawsuits in which EOG is involved
dismissed EOG from that case without prejudice.  Based on EOG's
present understanding of the remaining case in which it is a
defendant, EOG believes that it has substantial defenses to the
plaintiff's claims and intends to vigorously assert these
defenses.  However, if EOG is found to have violated the Civil
False Claims Act, EOG could be subject to a variety of sanctions,
including treble damages and substantial monetary fines.

     There are various other suits and claims against EOG that
have arisen in the ordinary course of business.  However,
management does not believe these suits and claims will
individually or in the aggregate have a material adverse effect
on the financial condition or results of operations of EOG.  EOG
has been named as a potentially responsible party in certain
Comprehensive Environmental Response Compensation and Liability
Act proceedings.  However, management does not believe that any
potential assessments resulting from such proceedings will,
individually or in the aggregate, have a material adverse effect
on the financial condition of EOG.

9.  Net Income Per Share Available to Common

     The following table sets forth the computation of net income
per share available to common for the years ended December 31 (in
thousands, except per share amounts):



                                                 2003       2002       2001

                                                            
Numerator for basic and diluted earnings
 per share -
   Net income available to common              $419,113   $ 76,141   $387,622
Denominator for basic earnings per share -
   Weighted average shares                      114,597    115,335    115,765
Potential dilutive common shares -
   Stock options                                  1,584      1,633      1,453
   Restricted stock and units                       338        277        270
Denominator for diluted earnings per share -
   Adjusted weighted average shares             116,519    117,245    117,488
Net income per share of common stock
   Basic                                       $   3.66   $   0.66   $   3.35
   Diluted                                     $   3.60   $   0.65   $   3.30



10.  Supplemental Cash Flow Information

     Cash paid for interest and income taxes was as follows for
the years ended December 31 (in thousands):



                                                  2003       2002       2001

                                                            
Interest (net of amount capitalized)           $ 62,472   $ 54,432   $ 45,715
Income taxes                                     26,330     15,946    106,312



11.  Business Segment Information

     EOG's operations are all natural gas and crude oil
exploration and production related. SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information,"
establishes standards for reporting information about operating
segments in annual financial statements and requires selected
information about operating segments in interim financial
reports.  Operating segments are defined as components of an
enterprise about which separate financial information is
available and evaluated regularly by the chief operating decision
maker, or decision making group, in deciding how to allocate
resources and in assessing performance.  EOG's chief operating
decision making process is informal and involves the Chairman and
Chief Executive Officer and other key officers.  This group
routinely reviews and makes operating decisions related to
significant issues associated with each of EOG's major producing
areas in the United States and each significant international
location.  For segment reporting purposes, the major United
States producing areas have been aggregated as one reportable
segment due to similarities in their operations as allowed by
SFAS No. 131.  Financial information by reportable segment is
presented below for the years ended December 31, or at
December 31 (in thousands):



                                               United                                  United
                                               States         Canada        Trinidad   Kingdom    Other       Total
                                                                                         
2003
 Net Operating Revenues                     $1,335,145(1)   $  309,418(1)   $100,112   $    --   $    --   $1,744,675(1)
 Depreciation, Depletion and Amortization      359,439          66,334        16,070        --        --      441,843
 Operating Income (Loss)                       487,133         163,783        55,433    (9,195)      160      697,314
 Interest Income                                 1,385             950           454        --        --        2,789
 Other Income (Expense)                          2,777           6,354         3,418       (71)        6       12,484
 Interest Expense                               43,421          14,618           670        --         2       58,711
 Income (Loss) Before Income Taxes             447,874         156,469        58,635    (9,266)      164      653,876
 Income Tax Provision (Benefit)                163,359          36,190        20,671    (3,486)     (134)     216,600
 Additions to Oil and Gas Properties           605,667         552,164        31,942    14,610        --    1,204,383
 Total Assets                                3,119,474       1,302,753       309,727    17,061        --    4,749,015
2002
 Net Operating Revenues                     $  846,007(2)   $  169,106(2)   $ 79,551   $    --   $    18   $1,094,682(2)
 Depreciation, Depletion and Amortization      334,318          49,622        14,085        --        11      398,036
 Operating Income (Loss)                        93,600          40,587        49,450      (250)   (2,410)     180,977
 Interest Income                                   765             229           348        --        --        1,342
 Other Income (Expense)                         (3,652)            261           394        --         4       (2,993)
 Interest Expense                               45,907          13,534           211        --         2       59,654
 Income (Loss) Before Income Taxes              44,806          27,543        49,981      (250)   (2,408)     119,672
 Income Tax Provision (Benefit)                 (7,684)         20,359        20,974       300    (1,450)      32,499
 Additions to Oil and Gas Properties           517,598         160,840        35,689        --        --      714,127
 Total Assets                                2,864,862         665,202       283,395        66        43    3,813,568
2001
 Net Operating Revenues                     $1,395,349(2)   $  191,213(2)   $ 69,140   $    --   $    20   $1,655,722(2)
 Depreciation, Depletion and Amortization      348,539          31,821        12,031        --         8      392,399
 Operating Income (Loss)                       537,549         107,518        36,761       (40)   (6,401)     675,387
 Interest Income                                 1,117           2,244         1,699        --        --        5,060
 Other Income (Expense)                         (4,123)             77           154        --        --       (3,892)
 Interest Expense                               45,064            (280)          326        --        --       45,110
 Income (Loss) Before Income Taxes             489,479         110,119        38,288       (40)   (6,401)     631,445
 Income Tax Provision (Benefit)                187,265          28,438        20,166       432    (3,472)     232,829
 Additions to Oil and Gas Properties           729,655         176,101        68,260        --        --      974,016
 Total Assets                                2,676,182         510,476       227,229        36       121    3,414,044


(1) EOG had sales activity with two significant purchasers, one
    totaled $222 million and the other totaled $182 million, of
    Consolidated Net Operating Revenues in the United States and Canada
    segments in 2003.
(2) EOG had sales activity with a single significant purchaser in the
    United States and Canada segments in 2002 and 2001 that totaled $163
    million and $225 million, respectively, of the Consolidated Net
    Operating Revenues.



12.  Price, Interest Rate and Credit Risk Management Activities

     Price and Interest Rate Risks.  EOG engages in price risk
management activities from time to time.  These activities are
intended to manage EOG's exposure to fluctuations in commodity
prices for natural gas and crude oil.  EOG utilizes derivative
financial instruments, primarily price swaps and collars, as the
means to manage this price risk.  In addition to these financial
transactions, EOG is a party to various physical commodity
contracts for the sale of hydrocarbons that cover varying periods
of time and have varying pricing provisions.  Under SFAS No. 133 -
"Accounting for Derivative Instruments and Hedging Activities,"
as amended by SFAS Nos. 137, 138 and 149, these various physical
commodity contracts qualify for the normal purchases and normal
sales exception and therefore, are not subject to hedge
accounting or mark-to-market accounting.  The financial impact of
these various physical commodity contracts is included in
revenues at the time of settlement, which in turn affects average
realized hydrocarbon prices.

     During 2003, 2002 and 2001, EOG elected not to designate any
of its derivative financial contracts as accounting hedges and
accordingly, accounted for these derivative financial contracts
using mark-to-market accounting.  During 2003, EOG recognized
losses on mark-to-market commodity derivative contracts of $80
million, which included realized losses of $45 million and collar
premium payments of $3 million.  During 2002, EOG recognized
losses on mark-to-market commodity derivative contracts of $49
million, which included realized losses of $21 million and a $2
million collar premium payment.  During 2001, EOG recognized
gains on mark-to-market commodity derivative contracts of $98
million, of which $67 million were realized gains which were
netted against a $5 million collar premium payment.

     Presented below is a summary of EOG's 2004 natural gas
financial collar contracts and natural gas and crude oil
financial price swap contracts as of December 31, 2003 with
prices expressed in dollars per million British thermal units
($/MMBtu) and in dollars per barrel ($/Bbl), as applicable, and
notional volumes in million British thermal units per day
(MMBtud) and in barrels per day (Bbld), as applicable.  EOG
accounts for these collar and swap contracts using mark-to-market
accounting.  The total fair value of the natural gas financial
collar contracts and natural gas and crude oil financial price
swap contracts at December 31, 2003 was a negative $38 million.



                Natural Gas Financial Collar Contracts                  Financial Price Swap Contracts
                            Floor Price           Ceiling Price          Natural Gas         Crude Oil
                         Floor    Weighted     Ceiling   Weighted              Weighted           Weighted
           Volume        Range     Average      Range     Average     Volume    Average   Volume   Average
Month(1)  (MMBtud)     ($/MMBtu)  ($/MMBtu)   ($/MMBtu)  ($/MMBtu)   (MMBtud)  ($/MMBtu)  (Bbld)   ($/Bbl)

                                                                  
Jan       330,000    $5.06 - 5.88   $5.38   $5.86 - 6.69   $6.29      30,000     $5.57     4,000   $30.61
Feb       330,000     5.02 - 5.78    5.31    5.82 - 6.62    6.24      30,000      5.50     4,000    30.12
Mar       330,000     4.93 - 5.53    5.16    5.73 - 6.40    6.10      30,000      5.37     4,000    29.58
Apr       375,000     4.47 - 4.71    4.59    4.93 - 5.30    5.13      30,000      4.89     4,000    29.08
May       375,000     4.47 - 4.75    4.58    4.93 - 5.19    5.09      30,000      4.80     4,000    28.66
Jun       375,000     4.47 - 4.75    4.58    4.93 - 5.19    5.09      30,000      4.80     4,000    28.27
Jul       375,000     4.47 - 4.75    4.58    4.93 - 5.19    5.09      30,000      4.80     3,000    27.91
Aug       375,000     4.47 - 4.75    4.58    4.93 - 5.19    5.09      30,000      4.80     2,000    28.11
Sep       375,000     4.47 - 4.75    4.58    4.93 - 5.19    5.09      30,000      4.78        --       --
Oct       375,000     4.47 - 4.75    4.58    4.93 - 5.19    5.09      30,000      4.80        --       --


(1) The collar contracts for January 2004 to March 2004 were
    purchased at a total premium of $3 million or $0.10 per
    MMBtu.  The collar contracts for April 2004 to October 2004
    were purchased without a premium.



     The following table summarizes the estimated fair value of
financial instruments and related transactions at December 31,
2003 and 2002 (in millions):



                                                  2003                       2002
                                          Carrying     Estimated     Carrying     Estimated
                                           Amount    Fair Value(1)    Amount    Fair Value(1)

                                                                       
Long-Term Debt(2)                          $1,109       $1,175        $1,145       $1,225
NYMEX-Related Commodity Market Positions      (38)         (38)           (6)          (6)


(1) Estimated fair values have been determined by using
    available market data and valuation methodologies. Judgment is
    necessarily required in interpreting market data and the use
    of different market assumptions or estimation methodologies
    may affect the estimated fair value amounts.
(2) See Note 2 "Long-Term Debt."



     Credit Risk.  While notional contract amounts are used to
express the magnitude of commodity price and interest rate swap
agreements, the amounts potentially subject to credit risk, in
the event of nonperformance by the other parties, are
substantially smaller.  EOG evaluates its exposure to all
counterparties on an ongoing basis, including those arising from
physical and financial transactions.  In some instances, EOG
requires collateral, parent guarantees or letters of credit to
minimize credit risk.  At December 31, 2003, EOG's net accounts
receivable balance related to North American natural gas, crude
oil and condensate sales included receivables from a major
integrated oil and gas company  and a major utility company,
which constituted 14% and 11%, respectively, of the total
balance.  The related amounts were collected during early 2004.
The amount due from the major utility company at December 31,
2002, which approximated 13% of the North American net accounts
receivable balance, was collected during early 2003.  No other
individual purchaser accounted for 10% or more of the North
American net accounts receivable balance at December 31, 2003 and
2002.  At December 31, 2003, EOG had an allowance for doubtful
accounts of $21 million, of which $19 million is associated with
the Enron bankruptcies recorded in December 2001.

     Substantially all of EOG's accounts receivable at
December 31, 2003 and 2002 result from crude oil and natural gas
sales and/or joint interest billings to third party companies
including foreign state-owned entities in the oil and gas
industry.  This concentration of customers and joint interest
owners may impact EOG's overall credit risk, either positively or
negatively, in that these entities may be similarly affected by
changes in economic or other conditions.  In determining whether
or not to require collateral or other credit enhancements from a
customer or joint interest owner, EOG analyzes the entity's net
worth, cash flows, earnings, and credit ratings.  Receivables are
generally not collateralized.  Historical credit losses incurred
on receivables by EOG have been immaterial except for those
associated with the Enron bankruptcies which were recorded in
December 2001.

13.  Accounting for Certain Long-Lived Assets

     Periodically, EOG reviews its oil and gas properties for
impairment purposes by comparing the expected undiscounted future
cash flows at a producing field level to the unamortized
capitalized cost of the asset.  During 2003, 2002 and 2001, such
reviews indicated that unamortized capitalized costs of certain
properties were higher than their expected undiscounted future
cash flows due primarily to downward reserve revisions for
certain producing fields.  As a result, during 2003, EOG recorded
in Impairments pre-tax charges of $21 million and $4 million in
the United States and Canada operating segments, respectively.
During 2002 and 2001, EOG recorded in Impairments pre-tax charges
of $30 million and $39 million, respectively, in the United
States operating segment.  The carrying values for assets
determined to be impaired were adjusted to estimated fair values
based on projected future net cash flows discounted using EOG's
risk-adjusted discount rate.  Amortization expenses of
acquisition costs of unproved properties, including amortization
of capitalized interest, were $64 million, $38 million and $40
million for 2003, 2002 and 2001, respectively.

14.  Accounting for Asset Retirement Obligations

     EOG adopted SFAS No. 143 - "Accounting for Asset Retirement
Obligations" on January 1, 2003.  The impact of adopting the
statement resulted in an after-tax charge of $7.1 million, which
was reported in the first quarter of 2003 as cumulative effect of
change in accounting principle.  The following table presents the
reconciliation of the beginning and ending aggregate carrying
amount of short-term and long-term legal obligations associated
with the retirement of oil and gas properties pursuant to SFAS
No. 143 for 2003 (in thousands):



                                       Asset Retirement Obligations
                                     Short-Term   Long-Term     Total

                                                     
      Balance at December 31, 2002     $    -      $      -   $      -
      Carrying Amount at Adoption       6,384        92,097     98,481
      Liabilities Incurred              1,364        11,295     12,659
      Liabilities Settled              (2,699)       (1,144)    (3,843)
      Accretion                           140         4,740      4,880
      Foreign Currency Translation        131         2,128      2,259
        Balance at December 31, 2003   $5,320      $109,116   $114,436



     Pro forma net income and earnings per share are not
presented for the comparable period in 2002 because the pro forma
application of SFAS No. 143 to the prior period would not result
in pro forma net income and earnings per share materially
different from the actual amounts reported for the period in the
accompanying Consolidated Statements of Income.

15.  Investment in Caribbean Nitrogen Company Limited and
      Nitrogen (2000) Unlimited

     EOG, through certain wholly-owned subsidiaries, owns equity
interests in two Trinidadian companies:  Caribbean Nitrogen
Company Limited (CNCL) and Nitrogen (2000) Unlimited (N2000).
During the first quarter of 2003, EOG completed separate share
sale agreements whereby a portion of the EOG subsidiaries'
shareholdings in CNCL and N2000 was sold to a third party energy
company.  The sale left EOG with equity interests of
approximately 12% in CNCL and 27% in N2000 and did not result in
any gain or loss.

     The other shareholders in CNCL are subsidiaries of
Ferrostaal AG, Duke Energy, Halliburton, Koch Industries, Inc.
and CL Financial Ltd.  At December 31, 2003, investment in CNCL
was approximately $14 million.  CNCL commenced production in June
2002, and at December 31, 2003, was producing approximately 1,950
metric tons of ammonia daily.  At December 31, 2003, CNCL had a
long-term debt balance of approximately $218 million, which is
non-recourse to CNCL's shareholders.  EOG will be liable for its
share of any post-completion deficiency funds loans to fund the
costs of operation, payment of principal and interest to the
principal creditor and other cash deficiencies of CNCL up to $30
million, approximately $4 million of which is net to EOG's
interest.  The Shareholders' Agreement requires the consent of
the holders of 90% or more of the shares to take certain material
actions.  Accordingly, given its current level of equity
ownership, EOG is able to exercise significant influence over the
operating and financial policies of CNCL and therefore, it
accounts for the investment using the equity method.  During
2003, EOG recognized equity income of $3.7 million.

     The other shareholders in N2000 are subsidiaries of
Ferrostaal AG, Halliburton, Koch Industries, Inc. and CL
Financial Ltd.  At December 31, 2003, investment in N2000 was
approximately $20 million.  N2000 is constructing an ammonia
plant in Trinidad, at an expected cost of approximately $320
million, and is expected to commence production in  the third
quarter 2004.  At December 31, 2003, N2000 had a long-term debt
balance of approximately $172 million, which is non-recourse to
N2000's shareholders. EOG will be liable for its share of any pre-
completion deficiency funds loans to fund plant cost overruns up
to $15 million, approximately $4 million of which is net to EOG's
interest.  EOG will also be liable for its share of any post-
completion deficiency funds loans to fund the costs of operation,
payment of principal and interest to the principal creditor and
other cash deficiencies of N2000 up to $30 million, approximately
$8 million of which is net to EOG's interest.  The Shareholders'
Agreement requires the consent of the holders of 90% or more of
the shares to take certain material actions.  Accordingly, given
its current level of equity ownership, EOG is able to exercise
significant influence over the operating and financial policies
of N2000 and therefore, it accounts for the investment using the
equity method.

16.  Property Acquisitions

     On October 1, 2003, a Canadian subsidiary of EOG closed an
asset purchase of natural gas properties in the Wintering Hills,
Drumheller East and Twining areas of southeast Alberta from a
subsidiary of Husky Energy Inc. for approximately US $320
million.  These properties are essentially adjacent to existing
EOG operations or are properties in which EOG already has a
working interest.  The transaction was partially funded by
commercial paper borrowings of US $140.5 million on October 1,
2003.  The remainder of the purchase price, US $179.5 million,
was funded by EOG's available cash balance.  Subsequent to the
closing, the purchase price was reduced by exercised preferential
rights on the properties which totaled approximately US $5
million.  In late December 2003, a Canadian subsidiary of EOG
closed another property acquisition for US $46 million.





                       EOG RESOURCES, INC.

  SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands Except Per Share Amounts Unless Otherwise Indicated)
   (Unaudited Except for Results of Operations for Oil and Gas
                      Producing Activities)


Oil and Gas Producing Activities

     The following disclosures are made in accordance with SFAS
No. 69 - "Disclosures about Oil and Gas Producing Activities":

     Oil and Gas Reserves.  Users of this information should be
aware that the process of estimating quantities of "proved,"
"proved developed" and "proved undeveloped" crude oil and natural
gas reserves is very complex, requiring significant subjective
decisions in the evaluation of all available geological,
engineering and economic data for each reservoir.  The data for a
given reservoir may also change substantially over time as a
result of numerous factors including, but not limited to,
additional development activity, evolving production history, and
continual reassessment of the viability of production under
varying economic conditions.  Consequently, material revisions
(upward or downward) to existing reserve estimates may occur from
time to time.  Although every reasonable effort is made to ensure
that reserve estimates reported represent the most accurate
assessments possible, the significance of the subjective
decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other
estimates presented in connection with financial statement
disclosures.

     Proved reserves represent estimated quantities of natural
gas, crude oil, condensate, and natural gas liquids that
geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known
reservoirs under economic and operating conditions existing at
the time the estimates were made.

     Proved developed reserves are proved reserves expected to be
recovered, through wells and equipment in place and under
operating methods being utilized at the time the estimates were
made.

     Proved undeveloped reserves are reserves that are expected
to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required
for completion. Reserves on undrilled acreage are limited to
those drilling units offsetting productive units that are
reasonably certain of production when drilled.  Proved reserves
for other undrilled units can be claimed only where it can be
demonstrated with certainty that there is continuity of
production from the existing productive formation.  Estimates for
proved undeveloped reserves are not attributed to any acreage for
which an application of fluid injection or other improved
recovery technique is contemplated, unless such techniques have
been proved effective by actual tests in the area and in the same
reservoir.

     Canadian provincial royalties are determined based on a
graduated percentage scale which varies with prices and
production volumes.  Canadian reserves, as presented on a net
basis, assume prices and royalty rates in existence at the time
the estimates were made, and EOG's estimate of future production
volumes.  Future fluctuations in prices, production rates, or
changes in political or regulatory environments could cause EOG's
share of future production from Canadian reserves to be
materially different from that presented.

     Estimates of proved and proved developed reserves at
December 31, 2003, 2002 and 2001 were based on studies performed
by the engineering staff of EOG for reserves in the United
States, Canada, Trinidad and the United Kingdom.  Opinions by
DeGolyer and MacNaughton (D&M), independent petroleum
consultants, for the years ended December 31, 2003, 2002 and 2001
covered producing areas containing 72%, 73% and 71%,
respectively, of proved reserves of EOG on a net-equivalent-cubic-
feet-of-gas basis.  D&M's opinions indicate that the estimates of
proved reserves prepared by EOG's engineering staff for the
properties reviewed by D&M, when compared in total on a net-
equivalent-cubic-feet-of-gas basis, do not differ materially from
the estimates prepared by D&M.  Such estimates by D&M in the
aggregate varied by not more than 5% from those prepared by the
engineering staff of EOG.  All reports by D&M were developed
utilizing geological and engineering data provided by EOG.

     No major discovery or other favorable or adverse event
subsequent to December 31, 2003 is believed to have caused a
material change in the estimates of proved or proved developed
reserves as of that date.

     The following table sets forth EOG's net proved and proved
developed reserves at December 31 for each of the four years in
the period ended December 31, 2003, and the changes in the net
proved reserves for each of the three years in the period then
ended as estimated by the engineering staff of EOG.


           NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY


                                               United                         United
                                               States     Canada   Trinidad   Kingdom    TOTAL
NET PROVED RESERVES

                                                                         
Natural Gas (Bcf)(1)
Net proved reserves at December 31, 2000       1,821.4     545.7    1,013.5       --    3,380.6
 Revisions of previous estimates                  15.0     (26.8)    (121.6)      --     (133.4)
 Purchases in place                               66.1     111.5         --       --      177.6
 Extensions, discoveries and other additions     358.3      59.7      295.2       --      713.2
 Sales in place                                   (1.0)       --         --       --       (1.0)
 Production                                     (252.5)    (46.0)     (42.0)      --     (340.5)
Net proved reserves at December 31, 2001       2,007.3     644.1    1,145.1       --    3,796.5
 Revisions of previous estimates                   9.4       4.7      (21.7)      --       (7.6)
 Purchases in place                                9.9     102.9         --       --      112.8
 Extensions, discoveries and other additions     217.0      83.9      232.4       --      533.3
 Sales in place                                   (0.8)     (1.5)        --       --       (2.3)
 Production                                     (236.6)    (56.2)     (49.3)      --     (342.1)
Net proved reserves at December 31, 2002       2,006.2     777.9    1,306.5       --    4,090.6
 Revisions of previous estimates                 (24.9)    (18.5)     (74.9)      --     (118.3)
 Purchases in place                               43.9     361.0         --       --      404.9
 Extensions, discoveries and other additions     345.5     118.3      129.3     59.2      652.3
 Sales in place                                  (30.8)       --         --       --      (30.8)
 Production                                     (238.3)    (60.2)     (55.4)      --     (353.9)
Net proved reserves at December 31, 2003       2,101.6   1,178.5    1,305.5     59.2    4,644.8





                                               United                       United
                                               States   Canada   Trinidad   Kingdom   TOTAL

                                                                       
Liquids (MBbl)(2)
Net proved reserves at December 31, 2000       52,013    5,817    15,572       --     73,402
 Revisions of previous estimates               (3,111)   1,294    (3,691)      --     (5,508)
 Purchases in place                               586       35        --       --        621
 Extensions, discoveries and other additions   12,380      361     1,967       --     14,708
 Sales in place                                  (192)     (35)       --       --       (227)
 Production                                    (9,293)    (820)     (749)      --    (10,862)
Net proved reserves at December 31, 2001       52,383    6,652    13,099       --     72,134
 Revisions of previous estimates                3,543      396      (572)      --      3,367
 Purchases in place                               624      865        --       --      1,489
 Extensions, discoveries and other additions   14,763      279     3,041       --     18,083
 Sales in place                                   (33)      --        --       --        (33)
 Production                                    (7,925)  (1,026)     (874)      --     (9,825)
Net proved reserves at December 31, 2002       63,355    7,166    14,694       --     85,215
 Revisions of previous estimates                1,487      214    (1,120)      --        581
 Purchases in place                               738    1,379        --       --      2,117
 Extensions, discoveries and other additions   15,669      598     1,212       84     17,563
 Sales in place                                  (344)      --        --       --       (344)
 Production                                    (7,897)  (1,091)     (881)      --     (9,869)
Net proved reserves at December 31, 2003       73,008    8,266    13,905       84     95,263

Bcf Equivalent (Bcfe)(1)
Net proved reserves at December 31, 2000        2,133.5    580.6   1,106.9     --      3,821.0
 Revisions of previous estimates                   (3.7)   (19.1)   (143.7)    --       (166.5)
 Purchases in place                                69.7    111.6      --       --        181.3
 Extensions, discoveries and other additions      432.5     62.0     307.0     --        801.5
 Sales in place                                    (2.2)    (0.2)     --       --         (2.4)
 Production                                      (308.2)   (50.9)    (46.5)    --       (405.6)
Net proved reserves at December 31, 2001        2,321.6    684.0   1,223.7     --      4,229.3
 Revisions of previous estimates                   30.7      7.1     (25.1)    --         12.7
 Purchases in place                                13.6    108.1      --       --        121.7
 Extensions, discoveries and other additions      305.6     85.6     250.6     --        641.8
 Sales in place                                    (1.0)    (1.5)     --       --         (2.5)
 Production                                      (284.2)   (62.4)    (54.5)    --       (401.1)
Net proved reserves at December 31, 2002        2,386.3    820.9   1,394.7     --      4,601.9
 Revisions of previous estimates                  (15.9)   (17.2)    (81.7)    --       (114.8)
 Purchases in place                                48.3    369.3      --       --        417.6
 Extensions, discoveries and other additions      439.6    121.8     136.5     59.7      757.6
 Sales in place                                   (32.9)      --      --       --        (32.9)
 Production                                      (285.7)   (66.7)    (60.7)    --       (413.1)
Net proved reserves at December 31, 2003        2,539.7  1,228.1   1,388.8     59.7    5,216.3




                               United
                               States   Canada   Trinidad    TOTAL

NET PROVED DEVELOPED RESERVES

                                                
 Natural Gas (Bcf) (1)
   December 31, 2000          1,498.6    479.4     207.0    2,185.0
   December 31, 2001          1,588.4    587.6     620.6    2,796.6
   December 31, 2002          1,658.7    683.3     555.2    2,897.2
   December 31, 2003          1,749.3    889.2     429.9    3,068.4
 Liquids (MBbl) (2)
   December 31, 2000           42,132    5,695     2,967     50,794
   December 31, 2001           41,205    6,532     8,435     56,172
   December 31, 2002           47,476    7,045     7,135     61,656
   December 31, 2003           56,321    7,995     5,229     69,545
 Bcf Equivalents (Bcfe) (1)
   December 31, 2000          1,751.4    513.6     224.8    2,489.8
   December 31, 2001          1,835.7    626.8     671.1    3,133.6
   December 31, 2002          1,943.6    725.5     598.0    3,267.1
   December 31, 2003          2,087.3    937.2     461.2    3,485.7


(1) Billion cubic feet or billion cubic feet equivalent, as
    applicable.
(2) Thousand barrels; includes crude oil, condensate and
    natural gas liquids.




     Capitalized Costs Relating to Oil and Gas Producing
Activities.  The following table sets forth the capitalized costs
relating to EOG's natural gas and crude oil producing activities
at December 31, 2003 and 2002:



                                                    2003          2002

                                                       
          Proved properties (1)                $ 7,990,675   $ 6,527,716
          Unproved properties                      198,387       222,379
            Total                                8,189,062     6,750,095
          Accumulated depreciation, depletion
           and amortization                     (3,940,145)   (3,428,547)
            Net capitalized costs              $ 4,248,917   $ 3,321,548


(1) The 2003 proved properties amount includes asset
    retirement obligations of $85 million as a result of the
    adoption of SFAS No. 143 - "Accounting for Asset Retirement
    Obligations" on January 1, 2003.



     Costs Incurred in Oil and Gas Property Acquisition,
Exploration and Development Activities. The acquisition,
exploration and development costs disclosed in the following
tables are in accordance with definitions in SFAS No. 19 -
"Financial Accounting and Reporting by Oil and Gas Producing
Companies."

     Acquisition costs include costs incurred to purchase, lease,
or otherwise acquire property.

     Exploration costs include additions to exploration wells
including those in progress and exploration expenses.

     Development costs include additions to production facilities and
equipment and additions to development wells including those in
progress.

     The following tables set forth costs incurred related to EOG's oil
and gas activities for the years ended December 31:



                                   United                          United
                                   States     Canada    Trinidad   Kingdom    Other     TOTAL
                                                                    
2003
Acquisition Costs of Properties
 Unproved                         $ 43,890   $ 14,536   $   172   $    --    $   --   $   58,598
 Proved                             18,347    386,532        --        --        --      404,879
    Subtotal                        62,237    401,068       172        --        --      463,477
Exploration Costs                  145,104     15,429    20,517    20,958     4,664      206,672
Development Costs                  480,257    145,539    23,140     2,812        --      651,748
    Subtotal                       687,598    562,036    43,829    23,770     4,664    1,321,897
Asset Retirement Costs (1)           8,167      3,552        --        --        --       11,719
    Total                         $695,765   $565,588   $43,829   $23,770    $4,664   $1,333,616
2002
Acquisition Costs of Properties
 Unproved                         $ 28,232   $  4,754   $ 5,629   $    --    $   --   $   38,615
 Proved                             22,589     48,487        --        --        --       71,076
    Subtotal                        50,821     53,241     5,629        --        --      109,691
Exploration Costs                  120,058     25,866    18,117        --     2,384      166,425
Development Costs                  423,436    107,952    13,600        --        --      544,988
    Subtotal                       594,315    187,059    37,346        --     2,384      821,104
Deferred Income Tax Gross Up            --     14,938        --        --        --       14,938
    Total (2)                     $594,315   $201,997   $37,346   $    --    $2,384   $  836,042
2001
Acquisition Costs of Properties
 Unproved                         $ 69,308   $  6,967   $    --   $    --    $   --   $   76,275
 Proved                             95,646     72,660        --        --        --      168,306
    Subtotal                       164,954     79,627        --        --        --      244,581
Exploration Costs                  163,602     16,708    13,695        --     8,739      202,744
Development Costs                  512,175     92,374    60,969        --        --      665,518
    Subtotal                       840,731    188,709    74,664        --     8,739    1,112,843
Deferred Income Tax Gross Up        19,411     30,845        --        --        --       50,256
    Total (2)                     $860,142   $219,554   $74,664   $    --    $8,739   $1,163,099


(1) Asset Retirement Costs do not include the cumulative effect of
    adoption.  The Asset Retirement Costs for the United States are netted
    with gains recognized upon settlement of asset retirement obligations
    of $1 million.
(2) Pro forma total expenditures for 2002 and 2001 are not presented as
    the pro forma application of SFAS No. 143 to the prior periods would
    not result in pro forma total expenditures materially different from
    the actual amounts reported.



     Results of Operations for Oil and Gas Producing Activities(1).  The
following tables set forth results of operations for oil and gas
producing activities for the years ended December 31:



                                             United                           United
                                             States      Canada    Trinidad   Kingdom   Other(2)    TOTAL
                                                                                
2003
Natural Gas, Crude Oil
 and Condensate Revenues                   $1,410,946   $309,336   $100,112   $    --   $    --   $1,820,394
Other, Net                                      4,613         82         --        --        --        4,695
  Total                                     1,415,559    309,418    100,112        --        --    1,825,089
Exploration Expenses                           65,885      5,726      3,997       739        11       76,358
Dry Hole Expenses                              20,706      4,139      7,890     8,421        --       41,156
Production Costs                              219,447     58,249     11,363        51         2      289,112
Impairments                                    81,661      7,473         --        --        (1)      89,133
Depreciation, Depletion and Amortization      359,439     66,334     16,070        --        --      441,843
Income (Loss) before Income Taxes             668,421    167,497     60,792    (9,211)      (12)     887,487
Income Tax Provision (Benefit)                239,534     61,928     24,661    (3,673)       (5)     322,445
Results of Operations                      $  428,887   $105,569   $ 36,131   $(5,538)  $    (7)  $  565,042

2002
Natural Gas, Crude Oil
 and Condensate Revenues                   $  891,991   $170,875   $  79,551  $    --   $    21   $1,142,438
Other, Net                                      2,521     (1,769)         --       --        --          752
  Total                                       894,512    169,106      79,551       --        21    1,143,190
Exploration Expenses                           52,830      5,529       1,656      152        61       60,228
Dry Hole Expenses                              26,107     20,642          --       --        --       46,749
Production Costs                              186,041     48,261       9,977       64         7      244,350
Impairments                                    65,813      2,619          --       --        (2)      68,430
Depreciation, Depletion and Amortization      334,318     49,622      14,085       --        11      398,036
Income (Loss) before Income Taxes             229,403     42,433      53,833     (216)      (56)     325,397
Income Tax Provision (Benefit)                 82,136     10,319      23,971      (70)      (20)     116,336
Results of Operations                      $  147,267   $ 32,114   $  29,862   $ (146)   $  (36)  $  209,061

2001
Natural Gas, Crude Oil
 and Condensate Revenues                   $1,295,945   $191,096   $  69,141   $   --    $   21   $1,556,203
Other, Net                                      1,652        117          --       --        --        1,769
  Total                                     1,297,597    191,213      69,141       --        21    1,557,972
Exploration Expenses                           57,602      6,101       3,577       --       187       67,467
Dry Hole Expenses                              55,817      6,495       2,828       --     6,220       71,360
Production Costs                              219,518     34,426      10,308       35        --      264,287
Impairments                                    76,801      2,355          --       --        --       79,156
Depreciation, Depletion and Amortization      348,397     31,821      12,031       --         9      392,258
Income (Loss) before Income Taxes             539,462    110,015      40,397      (35)   (6,395)     683,444
Income Tax Provision (Benefit)                198,243     32,663      22,218       --    (2,238)     250,886
Results of Operations                      $  341,219   $ 77,352   $  18,179   $  (35)  $(4,157)  $  432,558


(1) Excludes gains or losses on mark-to-market commodity derivative
    contracts, interest charges and general corporate expenses for each of
    the three years in the period ended December 31, 2003.
(2) Other includes other international operations.



     Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves.  The following information has been
developed utilizing procedures prescribed by SFAS No. 69 and based on
crude oil and natural gas reserve and production volumes estimated by
the engineering staff of EOG.  It may be useful for certain comparison
purposes, but should not be solely relied upon in evaluating EOG or its
performance.  Further, information contained in the following table
should not be considered as representative of realistic assessments of
future cash flows, nor should the Standardized Measure of Discounted
Future Net Cash Flows be viewed as representative of the current value
of EOG.

     The future cash flows presented below are based on sales prices,
cost rates, and statutory income tax rates in existence as of the date
of the projections.  It is expected that material revisions to some
estimates of crude oil and natural gas reserves may occur in the future,
development and production of the reserves may occur in periods other
than those assumed, and actual prices realized and costs incurred may
vary significantly from those used.

     Management does not rely upon the following information in making
investment and operating decisions.  Such decisions are based upon a
wide range of factors, including estimates of probable as well as proved
reserves, and varying price and cost assumptions considered more
representative of a range of possible economic conditions that may be
anticipated.

     The following table sets forth the standardized measure of
discounted future net cash flows from projected production of EOG's
crude oil and natural gas reserves for the years ended December 31:



                                                    United                                 United
                                                    States        Canada      Trinidad     Kingdom      TOTAL
                                                                                      
2003
  Future cash inflows                            $14,030,539   $ 6,221,171   $2,995,951   $320,427   $23,568,088
  Future production costs                         (3,026,650)   (1,289,592)    (449,200)   (47,524)   (4,812,966)
  Future development costs                          (524,401)     (200,324)    (228,504)   (21,289)     (974,518)
  Future net cash flows before income taxes       10,479,488     4,731,255    2,318,247    251,614    17,780,604
  Future income taxes                             (3,382,125)   (1,376,955)    (786,418)   (96,896)   (5,642,394)
  Future net cash flows                            7,097,363     3,354,300    1,531,829    154,718    12,138,210
  Discount to present value at 10% annual rate    (3,393,605)   (1,610,085)    (778,985)   (41,420)   (5,824,095)
  Standardized measure of discounted
   future net cash flows relating
   to proved oil and gas reserves                $ 3,703,758   $ 1,744,215   $  752,844   $113,298   $ 6,314,115

2002
  Future cash inflows                            $ 9,826,571   $ 2,989,000   $2,303,930   $     --   $15,119,501
  Future production costs                         (2,212,357)     (586,166)    (433,029)        --    (3,231,552)
  Future development costs                          (359,787)      (43,876)    (177,275)        --      (580,938)
  Future net cash flows before income taxes        7,254,427     2,358,958    1,693,626         --    11,307,011
  Future income taxes                             (2,214,072)     (653,425)    (558,788)        --    (3,426,285)
  Future net cash flows                            5,040,355     1,705,533    1,134,838         --     7,880,726
  Discount to present value at 10% annual rate    (2,265,700)     (766,567)    (629,024)        --    (3,661,291)
  Standardized measure of discounted
   future net cash flows relating
   to proved oil and gas reserves                $ 2,774,655   $   938,966   $  505,814   $     --   $ 4,219,435

2001
  Future cash inflows                            $ 5,677,824   $ 1,490,552   $1,472,197   $     --   $ 8,640,573
  Future production costs                         (1,528,474)     (371,124)    (335,395)        --    (2,234,993)
  Future development costs                          (387,048)      (31,232)    (110,331)        --      (528,611)
  Future net cash flows before income taxes        3,762,302     1,088,196    1,026,471         --     5,876,969
  Future income taxes                               (930,505)     (295,739)    (265,709)        --    (1,491,953)
  Future net cash flows                            2,831,797       792,457      760,762         --     4,385,016
  Discount to present value at 10% annual rate    (1,121,771)     (321,980)    (413,876)        --    (1,857,627)
  Standardized measure of discounted
   future net cash flows relating
   to proved oil and gas reserves                $ 1,710,026   $   470,477   $  346,886   $     --   $ 2,527,389



     Changes in Standardized Measure of Discounted Future Net Cash
Flows.  The following table sets forth the changes in the standardized
measure of discounted future net cash flows at December 31, for each of
the three years in the period ended December 31, 2003:



                                    United                             United
                                    States        Canada    Trinidad   Kingdom      TOTAL

                                                                  
December 31, 2000                 $6,011,133   $1,513,751   $388,553  $      --  $7,913,437
 Sales and transfers of oil
  and gas produced, net of
  production costs                (1,060,926)    (156,787)   (58,832)       --   (1,276,545)
 Net changes in prices and
  production costs                (6,400,910)  (1,822,229)  (194,995)       --   (8,418,134)
 Extensions, discoveries,
  additions and improved
  recovery net of related costs      347,088       48,271    114,871        --      510,230
 Development costs incurred          101,900       27,500     71,088        --      200,488
 Revisions of estimated
  development cost                    (5,296)       2,931     10,947        --        8,582
 Revisions of previous quantity
  estimates                           (3,563)     (12,536)    47,418        --       31,319
 Accretion of discount               862,118      223,154     54,297        --    1,139,569
 Net change in income taxes        2,313,068      592,322     15,087        --    2,920,477
 Purchases of reserves in place       35,686       78,790         --        --      114,476
 Sales of reserves in place           (6,165)        (303)        --        --       (6,468)
 Changes in timing and other        (484,107)     (24,387)  (101,548)       --     (610,042)
December 31, 2001                  1,710,026      470,477    346,886        --    2,527,389
 Sales and transfers of oil
  and gas produced, net of
  production costs                  (705,938)    (122,614)   (69,574)       --     (898,126)
 Net changes in prices and
  production costs                 1,561,946      460,977    223,614        --    2,246,537
 Extensions, discoveries,
  additions and improved
  recovery net of related costs      499,257      123,700    110,415        --      733,372
 Development costs incurred           84,300       18,100     13,600        --      116,000
 Revisions of estimated
  development cost                    35,255      (11,418)   (20,574)       --        3,263
 Revisions of previous quantity
  estimates                           51,227       11,470    (15,634)       --       47,063
 Accretion of discount               200,701       59,594     48,622        --      308,917
 Net change in income taxes         (692,670)    (135,888)   (87,229)       --     (915,787)
 Purchases of reserves in place       28,851      117,958         --        --      146,809
 Sales of reserves in place             (715)      (2,827)        --        --       (3,542)
 Changes in timing and other           2,415      (50,563)   (44,312)       --      (92,460)
December 31, 2002                  2,774,655      938,966    505,814        --    4,219,435
 Sales and transfers of oil
  and gas produced, net of
  production costs                (1,191,450)    (251,070)   (88,749)       --   (1,531,269)
 Net changes in prices and
  production costs                 1,334,817      422,754    294,570        --    2,052,141
 Extensions, discoveries,
  additions and improved
  recovery net of related costs      916,653      227,632     93,754   182,581    1,420,620
 Development costs incurred          103,200       22,600     23,100        --      148,900
 Revisions of estimated
  development cost                   (34,688)     (45,591)   (29,415)       --     (109,694)
 Revisions of previous quantity
  estimates                          (35,537)     (34,700)   (65,239)       --     (135,476)
 Accretion of discount               376,431      120,032     73,237        --      569,700
 Net change in income taxes         (520,575)    (240,253)  (145,698)  (69,283)    (975,809)
 Purchases of reserves in place       94,482      547,011         --        --      641,493
 Sales of reserves in place          (63,136)          --         --        --      (63,136)
 Changes in timing and other         (51,094)      36,834     91,470        --       77,210
December 31, 2003                 $3,703,758   $1,744,215   $752,844  $113,298   $6,314,115





Unaudited Quarterly Financial Information


                                                              Quarter Ended
                                                 Mar 31     Jun 30     Sep 30     Dec 31
                                                                     
2003
 Net Operating Revenues                         $464,669   $424,754   $458,724   $396,528
 Operating Income                               $226,129   $176,868   $193,312   $101,005

 Income Before Income Taxes                     $210,963   $165,741   $179,604   $ 97,568
 Income Tax Provision                             74,407     56,950     62,185     23,058
 Net Income Before Cumulative Effect
  of Change in Accounting Principle              136,556    108,791    117,419     74,510
 Cumulative Effect of Change in Accounting
  Principle, Net of Income Tax                    (7,131)         -          -          -
 Net Income                                      129,425    108,791    117,419     74,510
 Preferred Stock Dividends                         2,758      2,758      2,758      2,758
 Net Income Available to Common                 $126,667   $106,033   $114,661   $ 71,752
 Net Income per Share
   Basic (1)
     Net Income Available to Common Before
      Cumulative Effect of Change in
      Accounting Principle                      $   1.17   $   0.93   $   1.00   $   0.62
     Cumulative Effect of Change in
      Accounting Principle, Net of Income Tax      (0.06)         -          -          -
     Net Income Available to Common             $   1.11   $   0.93   $   1.00   $   0.62
   Diluted (1)
     Net Income Available to Common Before
      Cumulative Effect of Change in
      Accounting Principle                      $   1.15   $   0.91   $   0.99   $   0.61
     Cumulative Effect of Change in
      Accounting Principle, Net of Income Tax      (0.06)         -          -          -
     Net Income Available to Common             $   1.09   $   0.91   $   0.99   $   0.61
 Average Number of Common Shares
     Basic                                       114,441    114,382    114,616    114,893
     Diluted                                     116,224    116,131    116,370    117,209

2002
 Net Operating Revenues                         $186,563   $290,163   $279,879   $338,077
 Operating Income (Loss)                        $(20,646)  $ 69,300   $ 61,710   $ 70,613

 Income (Loss) Before Income Taxes              $(35,860)  $ 55,555   $ 42,866   $ 57,111
 Income Tax Provision (Benefit)                  (11,619)    17,447     13,979     12,692
 Net Income (Loss)                               (24,241)    38,108     28,887     44,419
 Preferred Stock Dividends                         2,758      2,758      2,758      2,758
 Net Income (Loss) Available to Common          $(26,999)  $ 35,350   $ 26,129   $ 41,661
 Net Income (Loss) per Share
  Available to Common
    Basic (1)                                   $  (0.23)  $   0.31   $   0.23   $   0.36
    Diluted (1)                                 $  (0.23)  $   0.30   $   0.22   $   0.36
 Average Number of Common Shares
    Basic                                        115,485    115,737    115,621    114,742
    Diluted                                      115,485    117,689    117,078    116,908


(1) The sum of quarterly net income (loss) per share available to
    common may not agree with total year net income per share available to
    common as each quarterly computation is based on the weighted average of
    common shares outstanding.




                          EXHIBIT INDEX


Exhibit No.         Description

 23.1          Consent of DeGolyer and MacNaughton

 23.2          Opinion of DeGolyer and MacNaughton dated January 30, 2004

 23.3          Consent of Deloitte & Touche LLP