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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.