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UNITED STATES
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, 2004
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, $0.01 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 x
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 February 15, 2005 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 February 15, 2005: $9,795,349,791 and as of June
30, 2004: $7,022,029,810.
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 February 15,
2005, Shares Outstanding: 119,208,346.
Documents incorporated by reference. Portions of the following
document are incorporated by reference into the indicated parts of
this report: Proxy Statement for the May 3, 2005 Annual Meeting of
Shareholders to be filed within 120 days after December 31, 2004
(Proxy Statement) - Part III.
TABLE OF CONTENTS
Page
PART I
Item 1. Business 1
General 1
Business Segments 1
Exploration and Production 1
Marketing 6
Wellhead Volumes and Prices 7
Competition 8
Regulation 8
Other Matters 11
Current Executive Officers of the Registrant 13
Item 2. Properties
Oil and Gas Exploration and Production Properties
and Reserves 14
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 17
Item 6. Selected Financial Data 18
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 19
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk 33
Item 8. Financial Statements and Supplementary Data 33
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 33
Item 9A. Controls and Procedures 33
Item 9B. Other Information 33
PART III
Item 10. Directors and Executive Officers of the Registrant 34
Item 11. Executive Compensation 34
Item 12. Security Ownership of Certain Beneficial Owners and
Management 34
Item 13. Certain Relationships and Related Transactions 35
Item 14. Principal Accounting Fees and Services 35
PART IV
Item 15. Financial Statements and Financial Statement
Schedule and Exhibits 35
SIGNATURES
(i)
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, Canada,
offshore Trinidad, the United Kingdom North Sea and, from time to
time, select other international areas. 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 Reports 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 the Securities and
Exchange Commission (SEC).
At December 31, 2004, EOG's total estimated net proved
reserves were 5,647 billion cubic feet equivalent (Bcfe), of
which 5,047 billion cubic feet (Bcf) were natural gas reserves
and 100 million barrels (MMBbl), or 600 Bcfe, were crude oil,
condensate and natural gas liquids reserves (see "Supplemental
Information to Consolidated Financial Statements"). At such
date, approximately 50% of EOG's reserves (on a natural gas
equivalent basis) were located in the United States, 25% in
Trinidad, 24% in Canada and 1% in the United Kingdom North Sea.
As of December 31, 2004, EOG employed approximately 1,250
persons, including foreign national employees.
EOG's business strategy is to maximize the rate of return on
investment of capital by controlling 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
United States and Canada Operations
EOG's operations are focused on most of the productive
basins in the United States and Canada.
At December 31, 2004, 88% of EOG's net proved United States
and Canada reserves (on a natural gas equivalent basis) were
natural gas and 12% were crude oil, condensate and natural gas
liquids. A substantial portion of EOG's United States and Canada
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 United
States and Canada plays. The following is a summary of
significant developments during 2004 and certain 2005 plans for
EOG's United States and Canada operations.
1
United States. During 2004, EOG opened a new office in Fort
Worth, Texas to expand EOG's drilling success in the Barnett
Shale play of the Fort Worth Basin. EOG made significant gas
discoveries in the non-core portion of the trend located south
and west of the city of Fort Worth, drilling 27 net horizontal
Barnett wells in 2004. As a result of this success, EOG rapidly
expanded its leasehold position and ended 2004 with approximately
400,000 net acres in the Barnett play. During December 2004, EOG
reached 30 million cubic feet equivalent per day (MMcfed) net
production from the Fort Worth Basin. EOG plans to drill 90
Barnett horizontal wells and will continue to add acreage in the
Barnett trend during 2005.
In the Permian Basin, EOG maintained successful horizontal
programs in the Devonian play of West Texas and in the Bone
Spring play of Southeast New Mexico. Improvements in technology
continued to yield increases in production rates and reserves,
when compared to completions of previous years. EOG drilled 46
net wells in the Permian Basin in 2004, and net production
averaged 97 million cubic feet per day (MMcfd) of natural gas and
8.3 thousand barrels per day (MBbld) of crude oil, condensate and
natural gas liquids. EOG has assembled a substantial acreage
position of over 130,000 net acres in a number of new plays in
this area, many of which will be tested during 2005.
EOG continued to intensify its activities in the Rocky
Mountain area during 2004. EOG has ramped up operations in its
traditional plays, drilling 48 net wells in the Chapita/Natural
Buttes area of the Uinta Basin, Utah, and 40 net wells in each
area of Wyoming's Green River Basin - the Big Piney area and the
LaBarge Platform/Moxa Arch area. EOG also drilled 16 net wells
in the Bakken horizontal play of the Williston Basin in Montana.
The net daily production from the Rocky Mountain area averaged
129 MMcfd of natural gas and 6.3 MBbld of crude oil, condensate
and natural gas liquids. EOG expects to further increase
drilling activity in 2005 in both the Uinta Basin of Utah and the
Green River Basin of Wyoming, and also continue exploration
drilling in other Rocky Mountain basins.
In the Mid-Continent area, EOG drilled 150 net wells in its
two core areas in 2004 - the Hugoton-Deep play in the Oklahoma
Panhandle and the Cleveland Horizontal play in the Texas
Panhandle. The net average daily production was 70 MMcfd of
natural gas and 1.9 MBbld of crude oil and condensate. EOG
expanded its Cleveland position over the last year to 110,000 net
acres. EOG has drilled 70 net Cleveland horizontal wells during
the past few years and expects to drill another 50 net wells in
2005. EOG has also obtained the rights on 40,000 of these
Cleveland acres to drill for high potential Morrow accumulations.
EOG expects its Hugoton Deep program to continue at a level
comparable to 2004. In addition to these two core areas, EOG
will continue active exploration programs throughout Oklahoma,
Kansas and the Texas Panhandle.
The Upper Gulf Coast continues to be a significant producing
and exploration area for EOG. New operating trends have been
added in East Texas and Louisiana through exploration and
property trades. Most notably, a significant Lower Cotton Valley
field discovery was made in North Louisiana at the Driscoll
Mountain field where a development of five net wells is planned
for 2005. EOG drilled 53 net wells in the Upper Gulf Coast area
during 2004 and averaged net production of 94 MMcfd of natural
gas and 2.9 MBbld of crude oil, condensate and natural gas
liquids. In the Sligo Field, EOG has drilled 4.5 net wells since
the completion of a property trade in mid-2003, increasing net
natural gas production from 2.5 MMcfd to 8.7 MMcfd. EOG is
anticipating running two to three rigs full time in the Sligo
Field throughout 2005. 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 Louisiana during 2005.
EOG continues to have success in South Texas where EOG
drilled or participated in 76 net wells in 2004. The area
averaged net production of 169 MMcfd of natural gas and 4.7 MBbld
of crude oil, condensate and natural gas liquids. The activity
was mainly focused in Webb, Zapata, Nueces, Lavaca and Duval
Counties. EOG executed successful drilling programs in the Lobo,
Roleta, Frio, Wilcox and Olmos plays. Significant activity in
these areas resulted from successful extensions of existing
plays, including the Frio trend in San Patricio and Nueces
Counties and the Lobo and Roleta trends in Webb and Zapata
Counties. EOG successfully added new lease positions in 2004 to
sustain drilling through 2005 and beyond.
In 2004, EOG drilled 70 net wells in the Appalachian area
and net production averaged 23 MMcfd of natural gas. EOG
continues to pursue the Trenton Black River play in New York, and
has begun to develop other intermediate depth plays in West
Virginia and New York in Mississippian and Ordovician age
reservoirs. EOG expects to drill over 100 net wells in 2005 in
this area.
2
In the Gulf of Mexico, four shelf fields (South Timbalier
156, Eugene Island 135, High Island 206 and Matagorda Island 623)
accounted for over 60% of EOG's 2004 net production. During
2004, total net production averaged 44 MMcfd of natural gas and
1.7 MBbld of crude oil, condensate and natural gas liquids. The
Matagorda Island 685 field, a 2003 discovery, commenced sales in
July 2004. EOG has a 67.5% working interest in the field, which
was producing 9 MMcfed, net, of natural gas and condensate at
year-end. In 2004, EOG drilled or participated in nine gross
wells; EOG plans a similar level of activity on the Gulf of
Mexico shelf in 2005.
At December 31, 2004, EOG held approximately 2,609,400 net
undeveloped acres in the United States.
Canada. In Canada, EOG conducts operations through its
subsidiary EOG Resources Canada Inc. (EOGRC) from offices in
Calgary, Alberta. During 2004, EOGRC was again successful with
its shallow natural gas strategy in Western Canada, drilling a
record of 1,254 net wells and increasing its production and
reserve base. EOGRC's net production during 2004 averaged 212
MMcfd of natural gas and 3.5 MBbld of crude oil, condensate and
natural gas liquids. Fourth quarter 2004 net production of 234
MMcfd of natural gas and 4.0 MBbld of crude oil, condensate and
natural gas liquids was a 20% increase over fourth quarter 2003
net production of 195 MMcfd of natural gas and 3.4 MBbld of crude
oil, condensate and natural gas liquids, which included
production from properties acquired in the fourth quarter of
2003. Key producing areas in the Western Canadian Sedimentary
Basin are the Southeast Alberta/Southwest Saskatchewan shallow
natural gas trend as well as the Drumheller, Twining and Grande
Prairie/Wapiti areas of central Alberta. EOGRC expects a similar
level of shallow natural gas drilling in 2005 on its expanded
Southeast Alberta platform, including the development of
Horseshoe Canyon dry coalbed methane at Twining. EOG also plans
to participate in several higher impact exploratory tests in
Alberta and the Northwest Territories during 2005.
At December 31, 2004, EOG held approximately 1,427,800 net
undeveloped acres in Canada.
Operations Outside the United States and Canada
EOG has operations offshore Trinidad and the United Kingdom
North Sea, and is evaluating additional exploration, exploitation
and development opportunities in the United Kingdom, Trinidad and
other international areas.
Trinidad. In November 1992, EOG, through its subsidiary,
EOG Resources Trinidad Limited (EOGRT) acquired a 95% working
interest, subject to a 5% overriding royalty interest, in the
South East Coast Consortium (SECC) Block offshore Trinidad,
encompassing three undeveloped fields - the Kiskadee, Ibis and
Oilbird fields. The Parula field was discovered in 2002 and
commenced production in 2004. The Kiskadee and Ibis fields have
been developed and are being produced. EOG is currently
developing the Oilbird field and expects first production in
early 2007. The term of the license covering the SECC Block
expires in December 2029. Effective February 3, 2005, EOG's
working interest was reduced to 80% due to conversion of the
overriding royalty interest. During 2004, average net production
from the SECC Block was 116 MMcfd of natural gas and 2.2 MBbld of
crude oil and condensate.
In the fourth quarter of 2004, EOG, through EOGRT and its
SECC partners, signed a farm in agreement with BP Trinidad and
Tobago LLC covering the Deep Ibis prospect on the SECC Block. BP
will pay the entire cost for drilling the well, which is
anticipated to spud in late 2005. EOG will retain a 50.6%
interest in the prospect and will develop the prospect, if
successful.
In July 1996, EOG, through its subsidiary, EOG Resources
Trinidad-U(a) Block Limited, 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. The Osprey field
was discovered in 1998 and commenced production in 2002. During
2004, average net production from the U(a) Block was 70 MMcfd of
natural gas and 1.4 MBbld of condensate.
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 EOG's natural gas production and all of its
condensate and crude oil production from the SECC and U(a)
Blocks. Condensate and crude oil from EOG's Trinidad operations
are being sold to the Petroleum Company of Trinidad and Tobago.
3
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, LRL #1,
on this block. The well was determined to be non-commercial. In
November 2004, EOG drilled the LRL #2 well which encountered
approximately 130 feet of net pay. In December 2004, the LRL #3
exploratory well was drilled and determined to be a dry hole.
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% working interest. In September 2004, EOG
drilled the first exploration well on this block, and the well
was determined to be non-commercial.
At December 31, 2004, EOG held approximately 191,600 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 was scheduled to
expire in 2008, natural gas was delivered to NGC for resale to
Trinidad local markets. During 2004, EOG delivered net average
production of 116 MMcfd of natural gas under this agreement. In
February 2005, the parties to the agreement executed an amended
and restated take-or-pay contract to replace the existing
agreement. The new agreement, among other things, provides for a
change in the pricing of wellhead natural gas volumes previously
sold under a fixed price schedule with annual escalations.
Prices are now partially dependent on Caribbean ammonia index
prices and methanol prices. The expiration date of the new
agreement is December 31, 2018.
. 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 in
Point Lisas, Trinidad, that is owned and operated by Caribbean
Nitrogen Company Limited (CNCL). During 2004, 48 MMcfd of
natural gas delivered to NGC was net to EOG. CNCL commenced
production in June 2002 and currently produces approximately
1,850 metric tons of ammonia daily. EOGRT owns a 12% equity
interest in CNCL. The other shareholders in CNCL are Ferrostaal
AG, Clico Energy Company Limited, KBRDC CNC (Cayman) Ltd. and
Koch CNC (Nevis) LLC. At December 31, 2004, EOGRT's investment
in CNCL was $15 million. At December 31, 2004, CNCL had a long-
term debt balance of $203 million, which is non-recourse to
CNCL's shareholders. As part of the financing for CNCL, the
shareholders have entered 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, approximately $4 million
of which is net to EOGRT's interest. The Shareholders' Agreement
requires the consent of the holders of 90% or more of the shares
to take certain material actions. Accordingly, given its current
level of equity ownership, 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 2004, EOG recognized equity income of $5 million
and received cash dividends of $5 million from CNCL.
4
. Under a fifteen-year take-or-pay contract, which expires in
2019, EOG supplies approximately 60 MMcfd, gross, of natural
gas to NGC. During 2004, production under the contract
averaged approximately 22 MMcfd of natural gas net to EOG.
This gas is being resold by NGC to an anhydrous ammonia
plant owned by Nitrogen (2000) Unlimited (N2000) and located
in Point Lisas, Trinidad. Construction of the plant was
completed in June 2004 at a total cost of $320 million and
ammonia production commenced in August 2004. N2000
currently produces approximately 1,950 metric tons of
ammonia daily. EOG's subsidiary, EOG Resources NITRO2000
Ltd. (EOGNitro2000), owned a 23% equity interest in N2000 at
December 31, 2004. The other shareholders in N2000 are FS
Petrochemicals (St. Kitts) Limited, CE Limited, KBRDC
Nitrogen 2000 (St. Lucia) Ltd. and Koch N2000 (Nevis) LLC.
At December 31, 2003, EOGNitro2000's equity interest and
investment in N2000 was 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. At December 31, 2004,
EOGNitro2000's investment in N2000 was $26 million. At
December 31, 2004, N2000 had a long-term debt balance of
$228 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 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, approximately $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 100% 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. During 2004, EOG recognized equity income of
$6 million from N2000.
In February 2005, a portion of EOGNitro2000's shareholdings
was sold to a subsidiary of one of the other shareholders.
The sale resulted in a pre-tax gain of approximately $2 million.
EOGNitro2000's equity interest is now 10%.
. Under a natural gas contract signed in January 2004, EOG
will ultimately supply 94 MMcfd (60 MMcfd, net, based on current
price and operating assumptions) of natural gas to NGC for the
initial four years of the contract term and 122 MMcfd (80 MMcfd,
net, based on current price and operating assumptions) for the
remaining term of the contract (11 years). This natural gas is
being resold by NGC to a methanol plant located in Point Lisas,
Trinidad. The plant is presently under construction and is
expected to start up in mid-2005. EOG has no equity investment
in this plant.
. Lastly, in February 2005, EOGRT executed a twenty-year take-
or-pay contract with NGC LNG (Train 4) Limited, a subsidiary of
NGC, for the supply of 30 MMcfd (20 MMcfd, net) of natural gas
for use in a LNG plant in Point Fortin, Trinidad. The plant is
presently under construction and is expected to start up in mid-
2006. EOG has no equity investment in this LNG plant.
United Kingdom. In 2002, EOG's subsidiary, EOG Resources
United Kingdom Limited (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, in the Valkyrie field, was drilled in the Southern
Gas Basin and temporarily suspended in February 2003. The well
encountered 300 feet of net pay sands in the Rotliegendes
formation, with gross estimated natural gas reserves of 106 Bcf,
or 26 Bcf, net to EOGUK. EOGUK and its partners drilled a
development well 49/16-VB from the Vampire platform in 2004 and
production commenced in the third quarter of 2004. EOG delivered
net average production of approximately 7 MMcfd from the Valkyrie
field in 2004.
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 the successful exploratory 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. This discovery,
named the Arthur field, commenced production in January 2005.
In the first quarter of 2004, EOGUK completed the drilling
of an exploration well, 49/2a-5Z. The well was determined to be
non-commercial.
In the second half of 2004, EOGUK drilled its first operated
well, 49/21-9Z, in the Viper prospect. The well was abandoned as
a dry hole.
5
At December 31, 2004, EOG held approximately 75,700 net
undeveloped acres in the United Kingdom.
Other International. EOG continues to evaluate other select
natural gas and crude oil opportunities outside the United States
and Canada primarily by pursuing exploitation opportunities in
countries where indigenous natural gas and crude oil reserves
have been identified.
Marketing
Wellhead Marketing. EOG's United States and Canada 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 in 2004
were 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. Beginning in 2005, wellhead
natural gas volumes from Trinidad will be sold under contracts
with prices which are either wholly or partially dependent on
Caribbean ammonia index prices and/or methanol prices. In the
United Kingdom, wellhead natural gas production is currently
being sold on the spot market.
Substantially all of EOG's wellhead crude oil and condensate
is sold under various terms and arrangements at market-responsive
prices.
During 2004, sales to an integrated oil and gas company with
investment grade credit ratings accounted for 12% 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.
6
Wellhead Volumes and Prices
The following table sets forth certain information regarding
EOG's wellhead volumes of and average prices for natural gas per
thousand cubic feet (Mcf), crude oil and condensate per barrel
(Bbl), and natural gas liquids per Bbl. The table also presents
natural gas equivalent volumes on a thousand cubic feet
equivalent basis (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, 2004.
2004 2003 2002
Natural Gas Volumes (MMcf per day)
United States 631 638 635
Canada 212 165 154
Trinidad 186 152 135
United Kingdom 7 - -
Total 1,036 955 924
Crude Oil and Condensate Volumes (MBbl per day)
United States 21.1 18.5 18.8
Canada 2.7 2.3 2.1
Trinidad 3.6 2.4 2.4
Total 27.4 23.2 23.3
Natural Gas Liquids Volumes (MBbl per day)
United States 4.8 3.2 2.9
Canada 0.8 0.6 0.8
Total 5.6 3.8 3.7
Natural Gas Equivalent Volumes (MMcfe per day)
United States 786 768 765
Canada 233 183 171
Trinidad 207 166 150
United Kingdom 7 - -
Total 1,233 1,117 1,086
Average Natural Gas Prices ($/Mcf)
United States $ 5.72 $ 5.06 $ 2.89
Canada 5.22 4.66 2.67
Trinidad 1.51 1.35 1.20
United Kingdom 5.14 - -
Composite 4.86 4.40 2.60
Average Crude Oil and Condensate Prices ($/Bbl)
United States $ 40.73 $30.24 $24.79
Canada 37.68 28.54 23.62
Trinidad 39.12 28.88 23.58
Composite 40.22 29.92 24.56
Average Natural Gas Liquids Prices ($/Bbl)
United States $ 27.79 $21.53 $14.76
Canada 23.23 19.13 11.17
Composite 27.13 21.13 14.05
7
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 Utah,
Wyoming and 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.
In 2002, the D.C. Circuit reversed a 2000 district court
decision and upheld a 1997 MMS gas valuation rule categorically
denying allowances for post-production marketing costs such as
long-term storage fees and marketer fees; however, the D.C.
Circuit decision expressly allows firm demand charges to be
deducted. Two trade associations had sought judicial review of
the 1997 gas valuation rule and procured a favorable district
court decision; however, the D.C. Circuit decision and denial of
certorari by the Supreme Court ended the litigation in early
2003. In early 2005, the MMS is expected to publish a further
revision to its gas valuation rule. The 2005 gas rule revision
will clarify the deductibility of transportation costs and adopt
the 2004 oil valuation rule's cost of capital approach described
below. The revisions are not expected to reflect any major
changes. EOG cannot predict what effect these changes will have
on EOG operations but nothing significant is anticipated.
In 2004, the MMS further amended its royalty regulations
governing the valuation of crude oil produced from federal
leases. The MMS's 2000 oil valuation rule had replaced a set of
valuation benchmarks based on posted prices and comparable sales
with an indexing system based on spot prices at nearby market
centers. Among other things, the 2000 oil valuation rule (like
the 1997 gas valuation rule) also categorically disallowed
deductions for post-production marketing costs. Two industry
trade associations sought judicial review of the 2000 oil rule,
but voluntarily dismissed their suit after late 2002 negotiations
led the MMS to amend its oil valuation rule further in 2004. The
amended rule retained indexing for valuation but replaced spot
prices with NYMEX future prices, except in the Rocky Mountain
Region and California. The 2004 oil valuation rule also
liberalized allowances for non-arm's length transportation
arrangements by increasing the multiplier used for calculating
the cost of capital. While the 2000 oil valuation rule was
likely to increase EOG's royalty obligation somewhat, the 2004
oil valuation rule is likely to attenuate that increase.
8
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.
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.
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 and/or
adopted from time to time. Although EOG cannot predict what
effect, if any, such legislation might have on its operations,
the industry could be required to incur additional capital
expenditures and increased costs depending on future legislative
and regulatory changes.
Proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the state
legislatures, the FERC, the state regulatory commissions and the
federal and state 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.
Canadian Regulation of Natural Gas and Crude Oil Production.
The crude oil and natural gas industry in Canada is subject to
extensive controls and regulations imposed by various levels of
government. These regulatory authorities may impose regulations
on or otherwise intervene in the oil and natural gas industry
with respect to prices, taxes, transportation rates, the
exportation of the commodity and, possibly, expropriation or
cancellation of contract rights. Such regulations may be changed
from time to time in response to complaints or economic or
political conditions. The implementation of new regulations or
the modification of existing regulations affecting the oil and
natural gas industry could reduce demand for these commodities,
increase EOG's costs and may have a material adverse impact on
its operations.
9
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 Regulation - Canada. All phases of the crude
oil and natural gas industry in Canada are subject to
environmental regulation pursuant to a variety of Canadian
federal, provincial, and municipal laws and regulations. Such
laws and regulations impose, among other things, restrictions,
liabilities and obligations in connection with the generation,
handling, use, storage, transportation, treatment and disposal of
hazardous substances and wastes and in connection with spills,
releases and emissions of various substances to the environment.
These laws and regulations also require that facility sites and
other properties associated with EOG's operations be operated,
maintained, abandoned and reclaimed to the satisfaction of
applicable regulatory authorities. In addition, new project or
changes to existing projects may require the submission and
approval of environmental assessments or permit applications.
These laws and regulations are subject to frequent change and the
clear trend is to place increasingly stringent limitations on
activities that may affect the environment. While compliance
with such legislation can require significant expenditures,
failure to comply with these environmental laws and regulations
could result in the assessment of administrative, civil or
criminal penalties, suspension or revocation of licenses and, in
some instances, the issuance of injunctions to limit or cease
operations.
Spills and releases from EOG's properties may have resulted
or result in soil and groundwater contamination in certain
locations. Such contamination is not unusual within the crude
oil and natural gas industries. Any contamination found on, under
or originating from the properties may be subject to remediation
requirements under Canadian laws. EOG could be required to
remove or remediate wastes disposed of or released by prior
owners or operators. In addition, EOG could be held responsible
for oil and gas properties in which EOG owns an interest but is
not the operator.
In December 2002, the Canadian federal government ratified
the Kyoto Protocol to the United Nations Framework Convention on
Climate Change, which requires Canada to reduce its greenhouse
gas emissions to 6% below 1990 levels over the 2008-2012 period.
Although the Canadian government has not yet provided significant
guidance on how it intends to meet these reduction targets, the
energy industry has been identified as one of the areas that will
be affected. The final rules, once known, could affect
operations and profitability.
Other International Regulation. EOG's exploration and
production operations outside the United States and Canada 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 Trinidad and the United
Kingdom.
10
Other Matters
Energy Prices. Since EOG is primarily a natural gas
producer, it is more significantly impacted by changes in prices
for natural gas than in prices for crude oil, condensate or
natural gas liquids. Average United States and Canada wellhead
natural gas prices have fluctuated, at times rather dramatically,
during the last three years. These fluctuations resulted in a
32% decrease in the average wellhead natural gas price for
production in the United States and Canada received by EOG from
2001 to 2002, an increase of 75% from 2002 to 2003, and an
increase of 12% from 2003 to 2004. Wellhead natural gas volumes
from Trinidad in 2004 were 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. Beginning
in 2005, wellhead natural gas volumes from Trinidad will be sold
under contracts with prices which are either wholly or partially
dependent on Caribbean ammonia index prices and/or methanol
prices. In the United Kingdom, wellhead natural gas production
is currently being sold on the spot market. 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.
Assuming a totally unhedged position for 2005, based on
EOG's tax position and the portion of EOG's anticipated natural
gas volumes for 2005 for which prices have not been determined
under long-term marketing contracts, EOG's price sensitivity for
each $0.10 per Mcf change in average wellhead natural gas price
is approximately $21 million for net income and operating cash
flow. EOG is not impacted as significantly by changing crude oil
prices. EOG's price sensitivity for each $1.00 per barrel change
in average wellhead crude oil price is approximately $6.5 million
for net income and operating cash flow. Summarized below and in
Note 11 to the Consolidated Financial Statements is information
regarding EOG's 2005 natural gas hedge position.
Risk Management. EOG engages in price risk management
activities from time to time. These activities are intended to
manage EOG's exposure to fluctuations in commodity prices for
natural gas and crude oil. EOG utilizes derivative financial
instruments, primarily price swaps and collars, as the means to
manage this price risk. In addition to these financial
transactions, EOG is a party to various physical commodity
contracts for the sale of hydrocarbons that cover varying periods
of time and have varying pricing provisions. Under Statement of
Financial Accounting Standards (SFAS) No. 133 - "Accounting for
Derivative Instruments and Hedging Activities," as amended by
SFAS Nos. 137, 138 and 149, these various physical commodity
contracts qualify for the normal purchases and normal sales
exception and therefore, are not subject to hedge accounting or
mark-to-market accounting. The financial impact of these various
physical commodity contracts is included in revenues at the time
of settlement, which in turn affects average realized hydrocarbon
prices.
Presented below is a summary of EOG's 2005 natural gas
financial collar contracts at February 25, 2005, with prices
expressed in dollars per million British thermal units ($/MMBtu)
and notional volumes in million British thermal units per day
(MMBtud). As indicated, EOG does not have any financial collar
or swap contracts that cover periods beyond March 2005.
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, 2004. EOG accounts for
these collar and swap contracts using mark-to-market accounting.
Natural Gas Financial Collar Contracts
Floor Price Ceiling Price
Weighted Weighted Settlement
Volume Floor Range Average Ceiling Range Average Price
2005 (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu)
Jan(1) 75,000 $7.65 - 8.00 $7.77 $8.90 - 9.50 $9.10 $6.35
Feb(2) 75,000 7.65 - 8.00 7.77 9.19 - 9.50 9.32 6.36
Mar(2) 75,000 7.65 - 8.00 7.77 9.19 - 9.50 9.32 6.24
(1) Notional volumes of 25,000 MMBtud of the January 2005 collar
contracts were purchased at a premium of $0.10 per MMBtu.
(2) The collar contracts for February 2005 and March 2005 were
purchased at a premium of $0.10 per MMBtu.
11
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 the United States and Canada 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.
Texas Severance Tax Exemption. Natural gas production from
qualifying Texas wells spudded or completed after August 31,
1996, is entitled to use a reduced severance tax rate for the
first 120 consecutive months of production. 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.
Common Stock Rights Agreement. On February 14, 2000, EOG's
Board of Directors declared a dividend of one preferred share
purchase right (a "Right," and the agreement governing the terms
of such Rights, the "Rights Agreement") for each outstanding
share of common stock, par value $.01 per share. The Board of
Directors has adopted this Rights Agreement to protect
stockholders from coercive or otherwise unfair takeover tactics.
The dividend was distributed to the stockholders of record on
February 24, 2000. On March 1, 2005, EOG will effect a two-for-
one stock split in the form of a stock dividend. In accordance
with the Rights Agreement, each share of common stock issued in
connection with the stock split will have one Right associated
with it. Each Right, expiring February 24, 2010, represents a
right to buy from EOG one hundredth (1/100) of a share of
Series E Junior Participating Preferred Stock (Preferred Share)
for $90, once the Rights become exercisable. This portion of a
Preferred Share will give the stockholder approximately the same
dividend, voting, and liquidation rights as would one share of
common stock. Prior to exercise, the Right does not give its
holder any dividend, voting, or liquidation rights. If issued,
each one hundredth (1/100) of a Preferred Share (i) will not be
redeemable; (ii) will entitle holders to quarterly dividend
payments of $.01 per share, or an amount equal to the dividend
paid on one share of common stock, whichever is greater;
(iii) will entitle holders upon liquidation either to receive
$1 per share or an amount equal to the payment made on one share
of common stock, whichever is greater; (iv) will have the same
voting power as one share of common stock; and (v) if shares of
EOG's common stock are exchanged via merger, consolidation, or a
similar transaction, will entitle holders to a per share payment
equal to the payment made on one share of common stock.
The Rights will not be exercisable until ten days after the
public announcement that a person or group has become an
acquiring person (Acquiring Person) by obtaining beneficial
ownership of 10% or more of EOG's common stock, or if earlier,
ten business days (or a later date determined by EOG's Board of
Directors before any person or group becomes an Acquiring Person)
after a person or group begins a tender or exchange offer which,
if consummated, would result in that person or group becoming an
Acquiring Person. On February 24, 2005, the Rights Agreement was
amended to create an exception to the definition of Acquiring
Person to permit a qualified institutional investor to hold 10%
or more but less than 20% of EOG's common stock without being
deemed an Acquiring Person if the institutional investor meets
the following requirements: (i) the institutional investor is
described in Rule 13d-1(b)(1) promulgated under the Securities
Exchange Act of 1934 and is eligible to report (and, if such
institutional investor is the beneficial owner of greater than 5%
of EOG's common stock, does in fact report) beneficial ownership
of common stock on Schedule 13G; (ii) the institutional investor
is not required to file a Schedule 13D (or any successor or
comparable report) with respect to its beneficial ownership of
EOG's common stock; (iii) the institutional investor does not
beneficially own 15% or more of EOG's common stock (including in
such calculation the holdings of all of the institutional
investor's affiliates and associates other than those which,
under published interpretations of the United States Securities
and Exchange Commission or its staff, are eligible to file
separate reports on Schedule 13G with respect to their beneficial
ownership of EOG's common stock); and (iv) the institutional
investor does not beneficially own 20% or more of EOG's common
stock (including in such calculation the holdings of all of the
institutional investor's affiliates and associates).
12
If a person or group becomes an Acquiring Person, all
holders of Rights, except the Acquiring Person, may for $90,
purchase shares of EOG's common stock with a market value of
$180, based on the market price of the common stock prior to such
acquisition. If EOG is later acquired in a merger or similar
transaction after the Rights become exercisable, all holders of
Rights except the Acquiring Person may, for $90, purchase shares
of the acquiring corporation with a market value of $180 based on
the market price of the acquiring corporation's stock, prior to
such merger.
EOG's Board of Directors may redeem the Rights for $.01 per
Right at any time before any person or group becomes an Acquiring
Person. If the Board of Directors redeems any Rights, it must
redeem all of the Rights. Once the Rights are redeemed, the only
right of the holders of Rights will be to receive the redemption
price of $.01 per Right. The redemption price will be adjusted
if EOG has a stock split or stock dividends of EOG's common
stock. After a person or group becomes an Acquiring Person, but
before an Acquiring Person owns 50% or more of EOG's outstanding
common stock, the Board of Directors may exchange the Rights for
common stock or equivalent security at an exchange ratio of one
share of common stock or an equivalent security for each such
Right, other than Rights held by the Acquiring Person.
Preferred Stock. EOG currently has two authorized series of
preferred stock. On February 14, 2000, EOG's Board of Directors,
in connection with the Rights Agreement described above,
authorized 1,500,000 shares of Series E Junior Participating
Preferred Stock with the rights and preferences described above.
On February 24, 2005, EOG's Board of Directors increased the
authorized shares of Series E Junior Participating Preferred
Stock to 3,000,000 as a result of the two-for-one stock split
mentioned above. Currently, there are no shares of the Series E
Junior Participating Preferred Stock outstanding.
On July 19, 2000, EOG's Board of Directors authorized
100,000 shares of Fixed Rate Cumulative Perpetual Senior
Preferred Stock, Series B, with a $1,000 Liquidation Preference
per share (the "Series B"). Dividends are 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 of each year beginning September 15, 2000. EOG may
redeem all or part of the Series B at any time beginning on
December 15, 2009 at $1,000 per share, plus accrued and unpaid
dividends. The Series B is not convertible into, or exchangeable
for, common stock of EOG. There are 100,000 shares of the Series
B currently outstanding.
On July 25, 2000, EOG's Board of Directors authorized 500
shares of Flexible Money Market Cumulative Preferred Stock,
Series D, with a liquidation preference of $100,000 per share
(the "Series D"). Dividends were payable on the shares only if
declared by EOG's Board of Directors and were cumulative. The
initial dividend rate on the shares was 6.84% until December 15,
2004. Through December 15, 2004, dividends were payable, if
declared, on March 15, June 15, September 15 and December 15 of
each year beginning September 15, 2000. On December 15, 2004,
EOG redeemed all 500 outstanding shares of the Series D at a
redemption price of $100,000 per share plus accumulated and
unpaid dividends for a total of $50 million. On February 24,
2005, EOG filed a Certificate of Elimination with the Secretary
of State of the State of Delaware to eliminate the Series D from
EOG's Restated Certificate of Incorporation, as amended.
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 58 Chairman of the Board and Chief
Executive Officer; Director
Edmund P. Segner, III 51 President and Chief of Staff;
Director
Loren M. Leiker 51 Executive Vice President, Exploration
and Development
Gary L. Thomas 55 Executive Vice President, Operations
Barry Hunsaker, Jr. 54 Senior Vice President and General
Counsel
Timothy K. Driggers 43 Vice President and Chief Accounting
Officer
13
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 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 duly elected or
appointed and 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."
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, 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.
14
Acreage. The following table summarizes EOG's developed and
undeveloped acreage at December 31, 2004. 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 569,233 329,004 1,577,834 962,188 2,147,067 1,291,192
Wyoming 195,141 135,009 421,631 312,169 616,772 447,178
Oklahoma 259,347 146,278 204,026 142,695 463,373 288,973
Pennsylvania 81,793 70,676 185,755 176,521 267,548 247,197
New Mexico 101,059 66,638 259,581 161,421 360,640 228,059
Utah 80,119 56,519 224,266 146,682 304,385 203,201
Offshore Gulf of Mexico 208,545 76,184 189,738 95,975 398,283 172,159
Montana 130,367 6,503 153,052 116,966 283,419 123,469
Nevada - - 102,386 102,386 102,386 102,386
West Virginia 76,271 68,739 56,120 27,936 132,391 96,675
New York - - 100,494 89,142 100,494 89,142
Ohio 61,916 58,504 22,560 22,628 84,476 81,132
California 5,146 2,425 72,199 67,651 77,345 70,076
Colorado 22,509 1,309 76,720 53,922 99,229 55,231
Virginia - - 38,707 38,707 38,707 38,707
North Dakota 3,947 1,414 49,329 33,830 53,276 35,244
Louisiana 19,663 12,585 32,433 22,440 52,096 35,025
Kansas 10,658 9,409 19,911 17,227 30,569 26,636
Mississippi 25,819 14,295 43,680 12,298 69,499 26,593
Michigan - - 8,817 6,242 8,817 6,242
Arkansas 3,992 1,115 765 228 4,757 1,343
Alabama - - 258 193 258 193
Total United States 1,855,525 1,056,606 3,840,262 2,609,447 5,695,787 3,666,053
Canada
Alberta 1,348,898 1,074,648 658,939 618,289 2,007,837 1,692,937
Saskatchewan 372,196 341,924 191,318 137,534 563,514 479,458
Nova Scotia - - 749,213 374,607 749,213 374,607
Northwest Territories 699 184 828,898 181,154 829,597 181,338
British Columbia 8,323 1,920 75,181 67,217 83,504 69,137
Manitoba 17,300 16,198 48,968 48,968 66,268 65,166
New Brunswick 219 33 - - 219 33
Total Canada 1,747,635 1,434,907 2,552,517 1,427,769 4,300,152 2,862,676
Trinidad 44,557 43,237 237,475 191,620 282,032 234,857
United Kingdom 7,159 2,078 184,373 75,703 191,532 77,781
Total 3,654,876 2,536,828 6,814,627 4,304,539 10,469,503 6,841,367
Producing Well Summary. The following table reflects EOG's
ownership in natural gas and crude oil wells located in Texas,
the Gulf of Mexico, Oklahoma, New Mexico, Utah, Louisiana,
Mississippi, Pennsylvania, Wyoming, and various other states in
the United States, Canada, Trinidad and the United Kingdom at
December 31, 2004. Gross natural gas and crude oil wells include
528 with multiple completions.
Productive Wells
Gross Net
Natural Gas 17,701 14,765
Crude Oil 1,704 1,145
Total 19,405 15,910
15
Drilling and Acquisition Activities. During the years ended
December 31, 2004, 2003 and 2002, EOG expended approximately
$1,510 million, $1,333 million and $836 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:
2004 2003 2002
Gross Net Gross Net Gross Net
Development Wells Completed
United States and Canada
Gas 1,839 1,623.34 1,586 1,439.99 1,465 1,204.93
Oil 92 79.31 89 78.98 88 64.27
Dry 104 86.86 89 78.02 84 74.88
Total 2,035 1,789.51 1,764 1,596.99 1,637 1,344.08
Outside United States and Canada
Gas 5 4.10 - - - -
Oil - - - - - -
Dry - - - - - -
Total 5 4.10 - - - -
Total Development 2,040 1,793.61 1,764 1,596.99 1,637 1,344.08
Exploratory Wells Completed
United States and Canada
Gas 49 44.19 46 28.91 22 17.97
Oil 5 3.00 5 4.22 4 3.00
Dry 41 29.21 39 29.22 22 17.87
Total 95 76.40 90 62.35 48 38.84
Outside United States and Canada
Gas 1 0.95 2 0.55 1 0.95
Oil - - - - - -
Dry 3 1.93 2 1.50 - -
Total 4 2.88 4 2.05 1 0.95
Total Exploratory 99 79.28 94 64.40 49 39.79
Total 2,139 1,872.89 1,858 1,661.39 1,686 1,383.87
Wells in Progress at end of period 63 49.38 90 79.49 50 42.93
Total 2,202 1,922.27 1,948 1,740.88 1,736 1,426.80
Wells Acquired*
Gas 249 151.71 1,274 1,079.02 664 374.06
Oil 8 7.30 108 68.03 7 4.21
Total 257 159.01 1,382 1,147.05 671 378.27
*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 included in this
report as set forth in the Contingencies section in Note 7 of
Notes to Consolidated Financial Statements on page F-24.
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 2004.
16
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 common stock dividend declared per share. The
information shown in the following table is not adjusted for the
stock split discussed below.
Price Range
High Low Dividend Declared
2004
First Quarter $47.45 $42.45 $0.06
Second Quarter 63.69 45.32 0.06
Third Quarter 66.87 55.20 0.06
Fourth Quarter 76.50 64.15 0.06
2003
First Quarter $42.83 $35.70 $0.04
Second Quarter 45.56 36.56 0.05
Third Quarter 42.87 37.70 0.05
Fourth Quarter 47.52 40.85 0.05
On February 2, 2005, EOG announced that the Board of
Directors had approved a two-for-one stock split in the form of a
stock dividend, payable to record holders as of February 15, 2005
and to be issued on March 1, 2005. In addition, the Board
increased the quarterly cash dividend on the common stock by 33%,
resulting in a quarterly cash dividend of $0.08 per share pre-
split or $0.04 per share post-split.
As of February 15, 2005, there were approximately 275 record
holders of EOG's common stock, including individual participants
in security position listings. There are an estimated 77,000
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.
The following table sets forth, for the periods indicated,
EOG's repurchase activity:
(c)
(a) Total Number of (d)
Total (b) Shares Purchased as Maximum Number
Number of Average Part of Publicly of Shares that May Yet
Shares Price Paid Announced Plans or Be Purchased Under
Period Purchased(1) per Share Programs the Plans or Programs(2)
October 1, 2004 - October 31, 2004 525 $67.18 - 6,386,200
November 1, 2004 - November 30, 2004 90,721 65.57 - 6,386,200
December 1, 2004 - December 31, 2004 794 73.45 - 6,386,200
Total 92,040 $65.65 -
(1) The quarterly total number of shares of 92,040 consists
solely of 65,469 shares (117,743 shares for the full year 2004)
that were returned to EOG in payment of the exercise price of
employee stock options and 26,571 shares (42,059 shares for the
full year 2004) that were withheld by or returned to EOG to
satisfy tax withholding obligations that arose upon the exercise
of employee stock options or the vesting of restricted stock or
units.
(2) In September 2001, EOG announced that its Board of Directors
authorized the repurchase of up to 10,000,000 shares of EOG's
common stock. During 2004, EOG did not repurchase any shares
under the Board of Directors authorized repurchase program.
17
ITEM 6. Selected Financial Data
(In Thousands, Except Per Share Amounts)
Year Ended December 31 2004 2003 2002 2001 2000
Statement of Income Data:
Net Operating Revenues $2,271,225 $1,744,675 $1,094,682 $1,655,722 $1,484,356
Operating Income 979,195 697,314 180,977 675,387 691,324
Net Income Before Cumulative Effect of
Change in Accounting Principle 624,855 437,276 87,173 398,616 396,931
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax (1) - (7,131) - - -
Net Income 624,855 430,145 87,173 398,616 396,931
Preferred Stock Dividends 10,892 11,032 11,032 10,994 11,028
Net Income Available to Common $ 613,963 $ 419,113 $ 76,141 $ 387,622 $ 385,903
Net Income Per Share Available to Common
Basic
Net Income Available to Common
Before Cumulative Effect of Change
in Accounting Principle $ 5.25 $ 3.72 $ 0.66 $ 3.35 $ 3.30
Cumulative Effect of Change in
Accounting Principle, Net of
Income Tax (1) - (0.06) - - -
Net Income Per Share Available to
Common $ 5.25 $ 3.66 $ 0.66 $ 3.35 $ 3.30
Diluted
Net Income Available to Common
Before Cumulative Effect of Change
in Accounting Principle $ 5.15 $ 3.66 $ 0.65 $ 3.30 $ 3.24
Cumulative Effect of Change in
Accounting Principle, Net of
Income Tax (1) - (0.06) - - -
Net Income Per Share Available to
Common $ 5.15 $ 3.60 $ 0.65 $ 3.30 $ 3.24
Average Number of Common Shares
Basic 116,876 114,597 115,335 115,765 116,934
Diluted 119,188 116,519 117,245 117,488 119,102
(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 2000 through 2002 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.
At December 31 2004 2003 2002 2001 2000
Balance Sheet Data:
Net Oil and Gas Properties $5,101,603 $4,248,917 $3,321,548 $3,055,910 $2,525,007
Total Assets 5,798,923 4,749,015 3,813,568 3,414,044 3,001,253
Long-Term Debt 1,077,622 1,108,872 1,145,132 855,969 859,000
Shareholders' Equity 2,945,424 2,223,381 1,672,395 1,642,686 1,380,925
18
ITEM 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations
Overview
EOG Resources, Inc. (EOG) is one of the largest independent
(non-integrated) oil and natural gas companies in the United
States with substantial proved reserves in the United States,
Canada, offshore Trinidad and, to a lesser extent, the United
Kingdom North Sea. EOG operates under a consistent business and
operational strategy which focuses predominantly on achieving a
strong reinvestment rate of return, drilling internally generated
prospects, delivering long-term production growth and maintaining
a strong balance sheet, with a below average debt-to-total
capitalization ratio.
EOG had another year of record operating earnings in 2004.
Net income available to common for 2004 of $614 million was up
47% over 2003 earnings of $419 million, attributable primarily to
higher commodity prices and increased production. At December
31, 2004, EOG's total reserves were 5.6 trillion cubic feet
equivalent, an increase of 430 billion cubic feet equivalent
(Bcfe), or 8% higher than 2003.
Operations
Several important developments have occurred since January 1,
2004.
United States and Canada. During 2004, EOG opened a new
office in Fort Worth, Texas to expand its drilling success in the
Barnett Shale play of the Fort Worth Basin. EOG made significant
gas discoveries in the non-core portion of the trend located
south and west of the city of Fort Worth. EOG plans to focus on
increasing production and further defining the play's ultimate
size during 2005.
EOG's effort to identify plays with larger reserve potential
has proven a successful supplement to its base development and
exploitation program in the United States and Canada. EOG plans
to continue to drill smaller wells in large acreage plays, which
in the aggregate will contribute substantially to EOG's crude oil
and natural gas production. EOG has several larger potential
plays under way in Wyoming, Utah, Texas, Oklahoma and western
Canada.
International. In mid-2004, EOG began natural gas sales to
the National Gas Company of Trinidad and Tobago (NGC) under a
fifteen-year take-or-pay contract. This gas is being resold by
NGC to an anhydrous ammonia plant located in Point Lisas,
Trinidad. The plant is owned by Nitrogen (2000) Unlimited
(N2000). At December 31, 2004, EOG's subsidiary, EOG Resources
NITRO2000 Ltd., owned an approximate 23% equity interest in
N2000. Under the contract, EOG supplies approximately 60 million
cubic feet per day (MMcfd) gross of natural gas to NGC.
Although EOG continues to focus on United States and Canada
natural gas, EOG sees an increasing linkage between United States
and Canada natural gas demand and Trinidadian natural gas supply.
For example, liquefied natural gas (LNG) imports from existing
and planned facilities in Trinidad are serious contenders to meet
increasing United States demand. In addition, ammonia, methanol
and chemical production has been relocating from the United
States and Canada to Trinidad, driven by attractive natural gas
feedstock prices in the island nation. EOG anticipates that its
existing position with the supply contracts to the two ammonia
plants and the new methanol plant, will continue to give its
portfolio an even broader exposure to United States and Canada
natural gas fundamentals.
In 2004, EOG continued its progress in the Southern Gas
Basin of the United Kingdom North Sea. A development well was
drilled in the Valkyrie field and commenced production in August
2004. In addition, the production facilities were installed in
the Arthur field, which was discovered in 2003, and production
commenced in January 2005. EOG continues to review additional
opportunities in this area and expects to participate in several
exploration wells in 2005.
19
Capital Structure
As noted, one of management's key strategies is to keep a
strong balance sheet with a consistently below average debt-to-
total capitalization ratio. At December 31, 2004, EOG's debt-to-
total capitalization ratio was 27%, down from 33% at year-end
2003. By primarily utilizing cash provided from its operating
activities and proceeds from stock options exercised in 2004, EOG
funded its $1.5 billion exploration and development expenditures,
paid down $31 million of debt, redeemed all 500 outstanding
shares of Series D Preferred Stock for $50 million and increased
the dividend paid to common shareholders by 20%. In addition, in
2005, EOG's Board of Directors increased the quarterly cash
dividend on common stock by 33%. As management currently
assesses price forecast and demand trends for 2005, EOG believes
that operations and capital expenditure activity can essentially
be funded by cash from operations.
For 2005, EOG's estimated exploration and development
expenditure budget is approximately $1.6 billion, excluding
acquisitions. United States and Canada natural gas continues to
be a key component of this effort. When it fits EOG's strategy,
EOG will make acquisitions that bolster existing drilling
programs or offer EOG incremental exploration and/or production
opportunities. Management continues to believe EOG has one of
the strongest prospect inventories in EOG's history.
The following review of operations for each of the three
years in the period ended December 31, 2004 should be read in
conjunction with the consolidated financial statements of EOG and
notes thereto beginning with page F-1.
20
Results of Operations
Net Operating Revenues
During 2004, net operating revenues increased $527 million
to $2,271 million. Total wellhead revenues, which are revenues
generated from sales of natural gas, crude oil, condensate and
natural gas liquids from producing wells, increased 27% to $2,301
million as compared to $1,818 million in 2003. Natural Gas
Revenues consists of natural gas wellhead revenues and revenues
from marketing activities associated with the sales and purchases
of natural gas. Revenues from natural gas marketing activities
were $2 million for each of 2004 and 2003. Crude oil, condensate
and natural gas liquids revenues represent solely wellhead
revenues for these products. Wellhead volume and price
statistics for the years ended December 31, were as follows:
2004 2003 2002
Natural Gas Volumes (MMcf per day) (1)
United States 631 638 635
Canada 212 165 154
Trinidad 186 152 135
United Kingdom 7 - -
Total 1,036 955 924
Average Natural Gas Prices ($/Mcf) (2)
United States $ 5.72 $ 5.06 $ 2.89
Canada 5.22 4.66 2.67
Trinidad 1.51 1.35 1.20
United Kingdom 5.14 - -
Composite 4.86 4.40 2.60
Crude Oil and Condensate Volumes (MBbl per day) (1)
United States 21.1 18.5 18.8
Canada 2.7 2.3 2.1
Trinidad 3.6 2.4 2.4
Total 27.4 23.2 23.3
Average Crude Oil and Condensate Prices ($/Bbl) (2)
United States $40.73 $30.24 $24.79
Canada 37.68 28.54 23.62
Trinidad 39.12 28.88 23.58
Composite 40.22 29.92 24.56
Natural Gas Liquids Volumes (MBbl per day) (1)
United States 4.8 3.2 2.9
Canada 0.8 0.6 0.8
Total 5.6 3.8 3.7
Average Natural Gas Liquids Prices ($/Bbl) (2)
United States $27.79 $21.53 $14.76
Canada 23.23 19.13 11.17
Composite 27.13 21.13 14.05
Natural Gas Equivalent Volumes (MMcfe per day) (3)
United States 786 768 765
Canada 233 183 171
Trinidad 207 166 150
United Kingdom 7 - -
Total 1,233 1,117 1,086
Total Bcfe (3) Deliveries 451.5 407.8 396.3
(1) Million cubic feet per day or thousand barrels per day,
as applicable.
(2) Dollars per thousand cubic feet or per barrel, as
applicable.
(3) Million cubic feet equivalent per day or billion cubic
feet equivalent, as applicable; includes natural gas, crude
oil, condensate and natural gas liquids.
21
2004 compared to 2003. Wellhead natural gas revenues for
2004 increased $307 million, or 20%, to $1,842 million from
$1,535 million for 2003 due to increases in natural gas
deliveries ($134 million) and the composite average wellhead
natural gas price ($173 million). The composite average wellhead
natural gas price increased 10% to $4.86 per Mcf for 2004 from
$4.40 per Mcf in 2003.
Natural gas deliveries increased 81 MMcf per day, or 8%, to
1,036 MMcf per day for 2004 from 955 MMcf per day in 2003, due to
a 47 MMcf per day, or 28%, increase in Canada; a 34 MMcf per day,
or 22%, increase in Trinidad; and a 7 MMcf per day increase in
the United Kingdom due to commencement of production in August
2004, partially offset by a 7 MMcf per day, or 1% decline in the
United States. The increased deliveries in Canada (47 MMcf per
day) were attributable to property acquisitions completed in the
fourth quarter of 2003 and additional production related to post
acquisition drilling. The increase in Trinidad was attributable
to the increased production from the U(a) block (22 MMcf per day)
which began supplying natural gas in mid-2004 to the N2000
ammonia plant and commencement of production from the Parula
wells on the SECC block in February 2004 (12 MMcf per day).
Wellhead crude oil and condensate revenues increased $149
million, or 59%, to $403 million from $254 million as compared to
2003, due to increases in both the composite average wellhead
crude oil and condensate price ($103 million) and the wellhead
crude oil and condensate deliveries ($46 million). The composite
average wellhead crude oil and condensate price for 2004 was
$40.22 per barrel compared to $29.92 per barrel for 2003.
Wellhead crude oil and condensate deliveries increased 4.2
MBbl per day, or 18%, to 27.4 MBbl per day from 23.2 MBbl per day
for 2003. The increase was mainly due to production from new
wells in the United States (2.6 MBbl per day) and higher
production in Trinidad from the Parula wells (0.8 MBbl per day)
and from the U(a) block as a result of new production (0.4 MBbl
per day).
Natural gas liquids revenues were $26 million higher than a
year ago primarily due to increases in deliveries ($14 million)
and the composite average price ($12 million).
During 2004, EOG recognized losses on mark-to-market
commodity derivative contracts of $33 million, which included
realized losses of $82 million and collar premium payments of $1
million. During 2003, EOG recognized losses on mark-to-market
commodity derivative contracts of $80 million, which included
realized losses of $45 million and collar premium payments of $3
million.
2003 compared to 2002. Wellhead natural gas revenues for
2003 increased $657 million, or 75%, due to increases in the
composite average wellhead natural gas price and natural gas
deliveries. The composite average wellhead price for natural gas
increased 69% to $4.40 per Mcf for 2003 from $2.60 per Mcf in
2002.
Natural gas deliveries increased to 955 MMcf per day for
2003 from 924 MMcf per day for the comparable period in 2002.
The overall increase in natural gas deliveries was primarily due
to an increase in Canada of 7% to 165 MMcf per day and an
increase in Trinidad of 13% to 152 MMcf per day in 2003. The 7%,
or 11 MMcf per day, increase in Canada was primarily attributable
to a major property acquisition in the fourth quarter. The 13%,
or 17 MMcf per day, increase in Trinidad was attributable to a
full year of sales to the CNCL ammonia plant versus only six
months of sales in 2002.
Natural gas marketing activities increased natural gas
revenues by $2 million and $37 million for 2003 and 2002,
respectively.
Wellhead crude oil and condensate revenues increased $45
million, or 22%, due to increases in the composite average
wellhead crude oil and condensate price. The composite average
wellhead crude oil and condensate price for 2003 was $29.92 per
barrel compared to $24.56 per barrel for 2002.
Natural gas liquids revenues were $11 million higher than a
year ago primarily due to a 50% increase in the composite average
price and a 3% increase in deliveries.
During 2003, EOG recognized losses on mark-to-market
commodity derivative contracts of $80 million, which included
realized losses of $45 million and collar premium payments of $3
million. During 2002, EOG recognized losses on mark-to-market
commodity derivative contracts of $49 million, which included
realized losses of $21 million and a $2 million collar premium
payment.
22
Operating and Other Expenses
2004 compared to 2003. During 2004, operating expenses of
$1,292 million were $245 million higher than the $1,047 million
incurred in 2003. The following table presents the costs per
Mcfe for the years ended December 31:
2004 2003
Lease and Well, including
Transportation $0.60 $0.52
DD&A 1.12 1.08
G&A 0.25 0.25
Taxes Other than Income 0.30 0.21
Interest Expense, Net 0.14 0.14
Total Per-Unit Costs $2.41 $2.20
The higher per-unit rates of lease and well, DD&A and taxes
other than income for 2004 compared to 2003 were due primarily to
the reasons set forth below.
Lease and well expenses of $271 million were $58 million
higher than 2003 due primarily to a general increase in service
costs related to increased operating activities, including an
increase in the number of wells, in the United States ($18
million), Canada ($16 million), and Trinidad ($1 million);
increased transportation related costs in the United States ($14
million), Canada ($2 million) and the United Kingdom ($2
million); and changes in the Canadian exchange rate ($5 million).
Depreciation, depletion and amortization (DD&A) expenses of
$504 million increased $63 million from 2003 due primarily to
increased production in Canada ($18 million), the United States
($10 million), and Trinidad ($4 million); the commencement of
production in the United Kingdom ($2 million); increased DD&A
rates in the United States due to a gradual proportional increase
in production from higher cost properties ($13 million);
increased DD&A rates in Canada mainly from developing acquired
proved reserves ($8 million); and changes in the Canadian
exchange rate ($7 million).
General and administrative (G&A) expenses of $115 million
were $15 million higher than 2003 due primarily to expanded
operations.
Taxes other than income of $134 million were $48 million
higher than 2003 due primarily to a decrease in credits taken
against severance taxes resulting from the qualification of
additional wells for a Texas high cost gas severance tax
exemption ($19 million); an increase as a result of higher
wellhead revenues in the United States ($13 million), Trinidad
($2 million) and Canada ($1 million); higher property taxes as a
result of higher property valuation in the United States ($6
million); the results of a production tax audit lawsuit in the
first quarter of 2004 ($5 million); and an increase in the number
of wells and facilities in Canada ($2 million).
Exploration costs of $94 million were $18 million higher
than 2003 due primarily to increased geological and geophysical
expenditures in the United States ($6 million), Canada ($3
million), the United Kingdom ($3 million) and Trinidad ($1
million); and increased exploration administrative expenses
across EOG ($4 million).
Impairments of $82 million were $8 million lower than 2003
due primarily to lower amortization of unproved leases in the
United States ($10 million), partially offset by higher
amortization of unproved leases in Canada ($2 million). Total
impairments under Statement of Financial Accounting Standards
(SFAS) No. 144 - "Accounting for the Impairment or Disposal of
Long-Lived Assets" were $25 million in each of 2004 and 2003.
Net interest expense of $63 million was $4 million higher
than 2003 due primarily to a slightly higher average debt
balance.
Other Income (Expense), Net for 2004 included income from
equity investments of $11 million, gains on sales of reserves and
related assets of $6 million and foreign currency transaction
losses of $7 million as a result of applying the changes in the
Canadian exchange rate to certain intercompany short-term loans
that eliminate in consolidation.
23
Income tax provision increased $85 million to $301 million
compared to 2003, primarily resulting from higher income before
income taxes ($95 million) and an increase in state income taxes
($2 million), offset by lower deferred income taxes associated
with the Alberta, Canada corporate tax rate ($5 million) and
lower effective foreign income tax rates ($2 million). As a
result of these changes, the net effective tax rate for 2004
remained unchanged from the 2003 rate of 33%.
In November 2003, Canada enacted legislation reducing the
Canadian federal income tax rate for companies in the resource
sector from 28% to 27% for 2003, with further reductions to 21%
phased in over the next four years. This legislation also made
changes to the tax treatment of crown royalties and the resource
allowance. Beginning in 2003, Canadian taxpayers are allowed to
deduct 10% of actual provincial and other crown royalties. This
percentage increases each year through 2007, at which time 100%
of crown royalties will be deductible. The resource allowance, a
statutory deduction calculated as 25% of adjusted resource
profits, will be phased out through 2007, when the deduction will
be completely eliminated.
2003 compared to 2002. During 2003, operating expenses of
$1,047 million were $133 million higher than the $914 million
incurred in 2002. The following table presents the costs per
Mcfe for the years ended December 31:
2003 2002
Lease and Well, including
Transportation $0.52 $0.45
DD&A 1.08 1.00
G&A 0.25 0.22
Taxes Other than Income 0.21 0.18
Interest Expense, Net 0.14 0.15
Total Per-Unit Costs $2.20 $2.00
The higher per-unit rates of lease and well, DD&A, G&A and
taxes other than income for 2003 compared to 2002 were due
primarily to the reasons set forth below.
Lease and well expenses of $213 million were $33 million
higher than 2002 due primarily to a general increase in service
costs related to increased operating activities, including an
increase in the number of wells, in the United States ($15
million) and Canada ($4 million); increased lease and well
administrative expenses in the United States ($7 million); and
changes in the Canadian exchange rate ($6 million).
DD&A expenses of $442 million increased $44 million from the
prior year due primarily to more relative production from higher
cost properties in the United States ($20 million) and Canada ($5
million); increased production in Canada ($3 million) and
Trinidad ($2 million) and changes in the Canadian exchange rate
($8 million). Also, included in DD&A expenses for 2003 was $5
million of accretion expense related to SFAS No. 143 -
"Accounting for Asset Retirement Obligations."
G&A expenses of $100 million were $11 million higher than
the period a year ago due primarily to expanded operations ($9
million) and increased insurance expense ($5 million), partially
offset by decreased legal costs ($3 million).
Taxes other than income of $86 million were $14 million
higher than the prior year period primarily due to an increase of
approximately $35 million as a result of increased wellhead
revenues as previously discussed, partially offset by $24 million
of severance tax credits from the qualification of wells for a
Texas high cost gas severance tax exemption.
Exploration costs of $76 million were $16 million higher
than a year ago due primarily to an increase in technical staff
costs across EOG ($7 million) and increased geological and
geophysical expenditures in the United States ($5 million) and
Trinidad ($3 million).
Impairments increased $21 million to $89 million compared to
a year ago due to higher amortization of unproved leases in the
United States ($25 million). Total impairments under SFAS No.
144 - "Accounting for the Impairment or Disposal of Long-Lived
Assets" for 2003 and 2002 were $25 million and $30 million,
respectively.
24
Other Income (Expense), Net for 2003 included foreign
currency transaction gains of $9 million as a result of applying
the changes in the Canadian exchange rate to certain intercompany
short-term loans that eliminate in consolidation and income from
equity investments of $4 million.
Income tax provision increased $184 million to $217 million
for 2003 as compared to 2002 primarily resulting from higher
income before income taxes for federal ($187 million) and state
($4 million), expiration of the tight gas sands federal income
tax credit as of December 31, 2002 ($4 million), and higher
effective foreign income tax rates ($4 million), primarily offset
by net tax benefit associated with the Canadian tax law change
($14 million).
Capital Resources and Liquidity
Cash Flow
The primary sources of cash for EOG during the three-year
period ended December 31, 2004 included funds generated from
operations, funds from new borrowings and proceeds from sales of
treasury stock attributable to employee stock option exercises
and the employee stock purchase plan. Primary cash outflows
included funds used in operations, exploration and development
expenditures, oil and gas property acquisitions, repayment of
debt, redemption of preferred stock, common stock repurchases and
dividends.
2004 compared to 2003. Net operating cash inflows of $1,444
million in 2004 increased $195 million as compared to 2003
primarily reflecting an increase in wellhead revenues of $482
million, partially offset by an increase in cash operating
expenses of $139 million, an increase in current tax expense of
$72 million, unfavorable changes in working capital and other
liabilities of $48 million and an increase in realized losses
from mark-to-market commodity derivative contracts of $38
million.
Net investing cash outflows of $1,397 million in 2004
increased by $189 million as compared to 2003 due primarily to
increased additions to oil and gas properties of $171 million and
unfavorable changes in working capital related to investing
activities of $12 million. Changes in Components of Working
Capital Associated with Investing Activities included changes in
accounts payable associated with the accrual of exploration and
development expenditures and changes in inventories which
represent material and equipment used in drilling and related
activities.
Cash used by financing activities was $43 million in 2004
versus $57 million in 2003. Cash provided by financing
activities for 2004 included long-term debt borrowing of $150
million and proceeds from sales of treasury stock attributable to
employee stock option exercises and the employee stock purchase
plan of $76 million. Cash used by financing activities for 2004
included repayments of long-term debt borrowings of $175 million,
redemption of all 500 outstanding shares of Series D Preferred
Stock of $50 million and cash dividend payments of $38 million.
2003 compared to 2002. Net operating cash inflows of $1,249
million in 2003 increased $638 million as compared to 2002
primarily reflecting an increase wellhead commodity revenues of
$713 million and favorable changes in working capital and other
liabilities of $117 million, partially offset by an increase in
cash operating expenses of $75 million, an increase in current
tax expense of $75 million and an increase in realized losses
from mark-to-market commodity derivative contracts of $24
million.
Net investing cash outflows of $1,207 million in 2003
increased by $391 million as compared to 2002 due primarily to
increased additions to oil and gas properties of $485 million,
which includes $366 million related to two Canadian asset
purchases, partially offset by favorable changes in working
capital related to investing activities of $82 million. Changes
in Components of Working Capital Associated with Investing
Activities included changes in accounts payable associated with
the accrual of exploration and development expenditures and
changes in inventories which represent material and equipment
used in drilling and related activities.
25
Cash used by financing activities was $57 million in 2003
versus cash provided of $211 million in 2002. Financing
activities for 2003 included repayment of the outstanding
balances of commercial paper borrowings and the uncommitted line
of credit of $22 million and $14 million, respectively,
repurchases of EOG's common stock of $21 million, cash dividend
payments of $31 million and proceeds of $35 million from sales of
treasury stock attributable to employee stock option exercises
and the employee stock purchase plan.
Exploration and Development Expenditures
The table below sets out components of exploration and
development expenditures for the years ended December 31, 2004,
2003 and 2002, along with the total budgeted for 2005, excluding
acquisitions (in millions):
Actual Budgeted 2005
2004 2003 2002 (excluding acquisitions)
Expenditure Category
Capital
Drilling and Facilities $1,120 $ 731 $ 595
Leasehold Acquisitions 143 59 39
Producing Property Acquisitions 52 405 71
Capitalized Interest 10 9 9
Subtotal 1,325 1,204 714
Exploration Costs 94 76 60
Dry Hole Costs 92 41 47
Exploration and Development Expenditures 1,511 1,321 821 Approximately $1,600
Asset Retirement Costs (1) 16 12 -
Deferred Income Tax on Acquired Properties (17) - 15
Total (2) $1,510 $1,333 $ 836
(1) The Asset Retirement Costs are netted with $1 million net
gains recognized upon settlement of asset retirement
obligations for each of 2004 and 2003. Asset Retirement Costs
for 2003 does not include the cumulative effect of adoption of
SFAS No. 143 - "Accounting for Asset Retirement Obligations"
on January 1, 2003.
(2) Pro forma total expenditures for 2002 are not presented since
the pro forma application of SFAS No. 143 to the prior periods
would not result in pro forma total expenditures materially
different from the actual amounts reported.
Exploration and development expenditures of $1.5 billion for
2004 were $190 million higher than the prior year due primarily
to increased drilling expenditures ($439 million) resulting from
higher exploration and development activities in Canada and
Trinidad and higher cost structures in the United States and
Canada; increased lease acquisitions in the United States ($84
million), primarily in the non-core Barnett Shale area and, to a
lesser extent, in South Texas; and changes in the Canadian
exchange rate ($20 million); partially offset by decreased
property acquisitions ($353 million). The higher cost structure
was primarily due to increases in materials and services across
the industry. The 2004 exploration and development expenditures
of $1.5 billion includes $1,009 million in development, $440
million in exploration, $52 million in property acquisitions and
$10 million in capitalized interest. The 2003 exploration and
development expenditures of $1,321 million included $651 million
in development, $256 million in exploration, $405 million in
property acquisitions and $9 million in capitalized interest.
The level of exploration and development expenditures,
including acquisitions, will vary in future periods depending on
energy market conditions and other related economic factors. EOG
has significant flexibility with respect to financing
alternatives and the ability to adjust its exploration and
development expenditure budget as circumstances warrant. There
are no material continuing commitments associated with current
expenditure plans.
Derivative Transactions
During 2004, EOG recognized losses on mark-to-market
commodity derivative contracts of $33 million, which included
realized losses of $82 million and collar premium payments of $1
million. During 2003, EOG recognized losses on mark-to-market
commodity derivative contracts of $80 million, which included
realized losses of $45 million and collar premium payments of $3
million. (See Note 11 to the Consolidated Financial Statements.)
26
Presented below is a summary of EOG's 2005 natural gas
financial collar contracts at February 25, 2005, with prices
expressed in dollars per million British thermal units ($/MMBtu)
and notional volumes in million British thermal units per day
(MMBtud). As indicated, EOG does not have any financial collar
or swap contracts that cover periods beyond March 2005.
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, 2004. EOG accounts for
these collar and swap contracts using mark-to-market accounting.
Natural Gas Financial Collar Contracts
Floor Price Ceiling Price
Weighted Weighted Settlement
Volume Floor Range Average Ceiling Range Average Price
2005 (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu)
Jan(1) 75,000 $7.65 - 8.00 $7.77 $8.90 - 9.50 $9.10 $6.35
Feb(2) 75,000 7.65 - 8.00 7.77 9.19 - 9.50 9.32 6.36
Mar(2) 75,000 7.65 - 8.00 7.77 9.19 - 9.50 9.32 6.24
(1) Notional volumes of 25,000 MMBtud of the January 2005 collar
contracts were purchased at a premium of $0.10 per MMBtu.
(2) The collar contracts for February 2005 and March 2005 were
purchased at a premium of $0.10 per MMBtu.
Financing
EOG's long-term debt-to-total capitalization ratio was 27%
as of December 31, 2004 compared to 33% as of December 31, 2003.
During 2004, total long-term debt decreased $31 million to
$1,078 million (see Note 2 to the Consolidated Financial
Statements). The estimated fair value of EOG's long-term debt at
December 31, 2004 and 2003 was $1,146 million and $1,175 million,
respectively, based upon quoted market prices and, where such
prices were not available, upon interest rates currently
available to EOG at yearend. EOG's debt is primarily at fixed
interest rates. At December 31, 2004, a 1% decline in interest
rates would result in a $59 million increase in the estimated
fair value of the fixed rate obligations (see Note 11 to the
Consolidated Financial Statements).
During 2004, EOG utilized commercial paper, and during 2003,
EOG utilized commercial paper and committed bank loans, in
addition to operating cash flows, to fund its operations. These
loans are more fully described in Note 2 to the Consolidated
Financial Statements. While EOG maintains a $600 million
commercial paper program, the maximum outstanding at any time
during 2004 was $321 million, and the amount outstanding at
yearend was $92 million. EOG considers this excess availability,
which is contractually backed by the $600 million Revolving
Credit Agreement with domestic and foreign lenders described in
Note 2, combined with the $688 million of availability under its
shelf registration described below, to be ample to meet its
ongoing operating needs.
Based on resources available at December 31, 2004, during
2005, EOG plans to replace the Senior Unsecured Term Loan Facility
due 2005 with long-term debt. In 2004, the short-term commercial
paper loan balance was reduced ($6 million) and the $100 million,
6.50% Notes were paid off by long-term debt refinancing.
27
Contractual Obligations
The following table summarizes EOG's contractual obligations
at December 31, 2004 (in thousands):
2011 &
Contractual Obligations(1) Total 2005 2006 - 2008 2009 - 2010 beyond
Long-Term Debt (2) $1,077,622 $ 166,800 $ 400,822 $ - $ 510,000
Non-cancelable Operating Leases 45,784 13,497 20,934 5,594 5,759
Drilling Rig Commitments 2,214 1,142 1,072 - -
Pipeline Transportation Service
Commitments (3) 128,983 21,697 49,518 19,139 38,629
Seismic Purchase Obligations 7,904 7,904 - - -
Other Purchase Obligations 2,918 1,628 1,290 - -
Total Contractual Obligations $1,265,425 $ 212,668 $ 473,636 $ 24,733 $ 554,388
(1) This table does not include the liability for
dismantlement, abandonment and restoration costs of oil and
gas properties. Effective with adoption of SFAS No. 143,
"Accounting for Asset Retirement Obligations" on January 1,
2003, EOG recorded a separate liability for the fair value of
this asset retirement obligation. See Note 13 to the
Consolidated Financial Statements. In addition, this table
does not include EOG's pension or postretirement benefit
obligations. See Note 6 to the Consolidated Financial
Statements.
(2) Commercial paper and the Senior Unsecured Term Loan
Facility due 2005 are classified as long-term debt on the
Consolidated Balance Sheets based on EOG's intent and ability
to ultimately replace such amounts with other long-term debt.
See Note 2 to the Consolidated Financial Statements.
(3) Amounts shown are based on current pipeline
transportation rates and the Canadian foreign currency
exchange rate at December 31, 2004. Management does not
believe that any future changes in these rates before the
expiration dates of these commitments will have a material
adverse effect on the financial condition or results of
operations of EOG.
Shelf Registration
As of February 25, 2005, the amount available under various
filed registration statements with the Securities and Exchange
Commission for the offer and sale from time to time of EOG debt
securities, preferred stock and/or common stock totaled $688
million.
Off-Balance Sheet Arrangements
EOG does not participate in financial transactions that
generate relationships with unconsolidated entities or financial
partnerships. Such entities, often referred to as variable
interest entities (VIE) or special purpose entities (SPE), are
generally established for the purpose of facilitating off-balance
sheet arrangements or other contractually narrow or limited
purposes. EOG was not involved in any unconsolidated VIE or SPE
financial transactions during any of the reporting periods in
this document and has no intention to participate in such
transactions in the foreseeable future.
Foreign Currency Exchange Rate Risk
During 2004, EOG was exposed to foreign currency exchange
rate risk inherent in its operations in foreign countries,
including Canada, Trinidad and the United Kingdom. The foreign
currency most significant to EOG's operations during 2004 was the
Canadian Dollar. While the continued strengthening of the
Canadian Dollar in 2004 impacted both the revenues and expenses
recorded on the income statements of EOG's Canadian subsidiaries,
its impacts on the items were not to the same extent. Since the
Canadian natural gas prices are largely correlated to United
States prices, the changes in the Canadian currency exchange rate
have less of an impact on the Canadian revenues than the Canadian
expenses. EOG continues to monitor the foreign currency exchange
rates of countries in which it is currently conducting business
and may implement measures to protect against the foreign
currency exchange rate risk.
28
Effective March 9, 2004, EOG entered into a foreign currency
swap transaction with multiple banks to eliminate any exchange
rate impacts that may result from the notes offered by one of the
Canadian subsidiaries on the same date (see Note 2 to the
Consolidated Financial Statements). EOG accounts for the foreign
currency swap transaction using the hedge accounting method,
pursuant to the provisions of SFAS No. 133 - "Accounting for
Derivative Instruments and Hedging Activities," as amended by
SFAS Nos. 137, 138 and 149. Under those provisions, as of
December 31, 2004, EOG recorded the fair value of the swap of
$23.1 million in Other Liabilities in the Liabilities section of
the Consolidated Balance Sheets. Changes in the fair value of
the foreign currency swap resulted in no net impact to the
Consolidated Statements of Income. The after-tax net impact from
the foreign currency swap transaction resulted in a negative
change of $3.8 million for the year ended December 31, 2004.
This amount is included in Accumulated Other Comprehensive Income
in the Shareholders' Equity section of the Consolidated Balance
Sheets.
Outlook
Natural gas prices historically have been volatile, and this
volatility is expected to continue. Uncertainty continues to
exist as to the direction of future United States and Canada
natural gas and crude oil price trends, and there remains a
rather wide divergence in the opinions held by some in the
industry. In EOG's opinion, overall natural gas production in
the United States is declining. In addition, the increasing
recognition of natural gas as a more environmentally friendly
source of energy is likely to result in increases in demand.
Being primarily a natural gas producer, EOG is more significantly
impacted by changes in natural gas prices than by changes in
crude oil and condensate prices. Longer term natural gas prices
will be determined by the supply and demand for natural gas as
well as the prices of competing fuels, such as oil and coal.
Assuming a totally unhedged position for 2005, based on
EOG's tax position and the portion of EOG's anticipated natural
gas volumes for 2005 for which prices have not been determined
under long-term marketing contracts, EOG's price sensitivity for
each $0.10 per Mcf change in average wellhead natural gas price
is approximately $21 million for net income and operating cash
flow. EOG is not impacted as significantly by changing crude oil
price. EOG's price sensitivity for each $1.00 per barrel change
in average wellhead crude oil prices is approximately $6.5
million for net income and operating cash flow. For information
regarding EOG's natural gas hedge position as of December 31,
2004, see Note 11 to the Consolidated Financial Statements.
Marketing companies have played an important role in the
United States and Canada natural gas market. These companies
aggregate natural gas supplies through purchases from producers
like EOG and then resell the gas to end users, local distribution
companies or other buyers. In recent years, several of the
largest natural gas marketing companies have filed for bankruptcy
or are having financial difficulty, and others are exiting this
business. EOG does not believe that this will have a material
effect on its ability to market its natural gas production. EOG
continues to assess and monitor the credit worthiness of partners
to whom it sells its production and where appropriate, to seek
new markets.
EOG plans to continue to focus a substantial portion of its
exploration and development expenditures in its major producing
areas in the United States and Canada. However, in order to
diversify its overall asset portfolio and as a result of its
overall success realized in Trinidad and the United Kingdom North
Sea, EOG anticipates expending a portion of its available funds
in the further development of opportunities outside the United
States and Canada. In addition, EOG expects to conduct
exploratory activity in other areas outside of the United States
and Canada and will continue to evaluate the potential for
involvement in other exploitation type opportunities. Budgeted
2005 exploration and development expenditures, excluding
acquisitions, are approximately $1.6 billion and are structured
to maintain the flexibility necessary under EOG's strategy of
funding the United States and Canada exploration, exploitation,
development and acquisition activities primarily from available
internally generated cash flow.
The level of exploration and development expenditures may
vary in 2005 and will vary in future periods depending on energy
market conditions and other related economic factors. Based upon
existing economic and market conditions, EOG believes net
operating cash flow and available financing alternatives in 2005
will be sufficient to fund its net investing cash requirements
for the year. However, EOG has significant flexibility with
respect to its financing alternatives and adjustment of its
exploration, exploitation, development and acquisition
expenditure plans if circumstances warrant. While EOG has
certain continuing commitments associated with expenditure plans
related to operations in the United States, Canada, Trinidad and
the United Kingdom, such commitments are not expected to be
material when considered in relation to the total financial
capacity of EOG.
29
Environmental Regulations
Various federal, state and local laws and regulations
covering the discharge of materials into the environment, or
otherwise relating to protection of the environment, 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.
Summary of Critical Accounting Policies
EOG prepares its financial statements and the accompanying
notes in conformity with accounting principles generally accepted
in the United States of America, which requires management to
make estimates and assumptions about future events that affect
the reported amounts in the financial statements and the
accompanying notes. EOG identifies certain accounting policies
as critical based on, among other things, their impact on the
portrayal of EOG's financial condition, results of operations or
liquidity, and the degree of difficulty, subjectivity and
complexity in their deployment. Critical accounting policies
cover accounting matters that are inherently uncertain because
the future resolution of such matters is unknown. Management
routinely discusses the development, selection and disclosure of
each of the critical accounting policies. Following is a
discussion of EOG's most critical accounting policies:
Proved Oil and Gas Reserves
EOG's engineers estimate proved oil and gas reserves, which
directly impact financial accounting estimates, including
depreciation, depletion and amortization. Proved reserves
represent estimated quantities of natural gas, crude oil,
condensate, and natural gas liquids that geological and
engineering data demonstrate, with reasonable certainty, to be
recoverable in future years from known reservoirs under economic
and operating conditions existing at the time the estimates were
made. The process of estimating quantities of proved oil and gas
reserves is very complex, requiring significant subjective
decisions in the evaluation of all available geological,
engineering and economic data for each reservoir. The data for a
given reservoir may also change substantially over time as a
result of numerous factors including, but not limited to,
additional development activity, evolving production history and
continual reassessment of the viability of production under
varying economic conditions. Consequently, material revisions
(upward or downward) to existing reserve estimates may occur from
time to time.
Impairments
Oil and gas lease acquisition costs are capitalized when
incurred. Unproved properties with individually significant
acquisition costs are assessed quarterly on a
property-by-property basis, and any impairment in value is
recognized. Unproved properties with acquisition costs that are
not individually significant are aggregated, and the portion of
such costs estimated to be nonproductive, based on historical
experience, is amortized over the average holding period. If the
unproved properties are determined to be productive, the
appropriate related costs are transferred to proved oil and gas
properties. Lease rentals are expensed as incurred.
30
Oil and gas exploration costs, other than the costs of
drilling exploratory wells, are charged to expense as incurred.
The costs of drilling exploratory wells are capitalized pending
determination of whether they have discovered proved commercial
reserves. Exploratory drilling costs are capitalized when
drilling is complete if it is determined that there is economic
producibility supported by either actual production, a conclusive
formation test or by certain technical data if the discovery is
located offshore in the Gulf of Mexico. If proved commercial
reserves are not discovered, such drilling costs are expensed.
In some circumstances, it may be uncertain whether proved
commercial reserves have been found due to the requirement of a
significant capital investment. Such exploratory drilling costs
may continue to be capitalized if the reserve quantity is
sufficient to justify development when the investment is made and
additional exploratory wells are either in progress or firmly
planned. All other exploratory wells that do not meet these
criteria are expensed after one year. As of December 31, 2004
and 2003 EOG had exploratory drilling costs of $4.3 million and
$4.5 million, respectively, related to an outside operated,
deepwater offshore Gulf of Mexico discovery that has been
deferred for more than one year and will require significant
future capital expenditures before production can commence.
These costs meet the accounting requirements outlined above for
continued capitalization. As of December 31, 2004 and 2003,
there were no material exploratory drilling costs capitalized for
more than one year for projects that did not require a major
capital investment. Costs to develop proved reserves, including
the costs of all development wells and related equipment used in
the production of natural gas and crude oil, are capitalized.
When circumstances indicate that an asset may be impaired,
EOG compares expected undiscounted future cash flows at a
producing field level to the unamortized capitalized cost of the
asset. If the future undiscounted cash flows, based on EOG's
estimate of future crude oil and natural gas prices, operating
costs, anticipated production from proved reserves and other
relevant data, are lower than the unamortized capitalized cost,
the capitalized cost is reduced to fair value. Fair value is
calculated by discounting the future cash flows at an appropriate
risk-adjusted discount rate.
Depreciation, Depletion and Amortization for Oil and Gas Properties
The quantities of estimated proved oil and gas reserves are
a significant component of our calculation of depletion expense
and revisions in such estimates may alter the rate of future
expense. Holding all other factors constant, if reserves were
revised upward or downward, earnings would increase or decrease
respectively.
Depreciation, depletion and amortization of the cost of
proved oil and gas properties is calculated using the
unit-of-production method. The reserve base used to calculate
depletion, depreciation or amortization is the sum of proved
developed reserves and proved undeveloped reserves for leasehold
acquisition costs and the cost to acquire proved properties. The
reserve base includes only proved developed reserves for lease
and well equipment costs, which include development costs and
successful exploration drilling costs. Estimated future
dismantlement, restoration and abandonment costs, net of salvage
values, are taken into account. Certain other assets are
depreciated on a straight-line basis.
Assets are grouped in accordance with paragraph 30 of SFAS
No. 19. The basis for grouping is a reasonable aggregation of
properties with a common geological structural feature or
stratigraphic condition, such as a reservoir or field.
Amortization rates are updated quarterly to reflect: 1) the
addition of capital costs, 2) reserve revisions (upwards or
downwards) and additions, 3) property acquisitions and/or
property dispositions, and 4) impairments.
Stock Options
EOG accounts for stock options under the provisions and
related interpretations of Accounting Principles Board (APB)
Opinion No. 25 - "Accounting for Stock Issued to Employees." No
compensation expense is recognized for such options. As allowed
by SFAS No. 123 - "Accounting for Stock-Based Compensation"
issued in 1995, EOG has continued to apply APB Opinion No. 25 for
purposes of determining net income and to present the pro forma
disclosures required by SFAS No. 123.
31
In December 2002, the Financial Accounting Standards Board
(FASB) issued SFAS No. 148 - "Accounting for Stock-Based
Compensation - Transition and Disclosure - an amendment of FASB
Statement No. 123." In December 2004, the FASB issued SFAS No.
123(R), "Share-Based Payment," which supersedes SFAS No. 148.
SFAS No. 123(R) establishes standards for transactions in which
an entity exchanges its equity instruments for goods or services.
This standard requires a public entity to measure the cost of
employee services received in exchange for an award of equity
instruments based on the grant-date fair value of the award.
This eliminates the exception to account for such awards using
the intrinsic method previously allowable under APB Opinion No.
25. SFAS No. 123(R) will be effective for interim or annual
reporting periods beginning on or after June 15, 2005. EOG
currently expects to adopt SFAS No. 123(R) effective July 1, 2005
using the modified prospective method. EOG expects that the
adoption of SFAS No. 123(R) would reduce second half 2005 net
earnings by a pre-tax amount of approximately $10 million which
includes approximately $0.5 million for the Employee Stock
Purchase Plan. SFAS No. 123(R) also requires a public entity to
present its cash flows provided by tax benefits from stock
options exercised in the Financing Cash Flows section of the
Statement of Cash Flows. Had SFAS No. 123(R) been in effect,
EOG's Net Cash Provided by Operating Activities would have been
reduced and its Net Cash Provided by Financing Activities would
have been increased on its Consolidated Statements of Cash Flows
by $29 million, $12 million and $5 million for 2004, 2003 and
2002, respectively.
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;
the availability and cost of drilling rigs, experienced drilling
crews and tubular steel; the availability of pipeline
transportation capacity; the extent to which EOG can replicate on
its other Barnett Shale acreage the results of its most recent
Barnett Shale wells; the results of wells yet to be drilled that
are necessary to test whether substantial Barnett Shale acreage
positions outside of Johnson and Parker Counties, Texas, contain
suitable drilling prospects; whether EOG is successful in its
efforts to more densely develop its acreage in the Barnett Shale
and other production areas; 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.
32
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."
ITEM 8. Financial Statements and Supplementary Data
Information required hereunder is included in this report as
set forth in the "Index to Financial Statements" on page F-1.
ITEM 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
Not Applicable.
ITEM 9A. Controls and Procedures
Disclosure Controls and Procedures. EOG's management, with
the participation of EOG's principal executive officer and
principal financial officer, 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 period
covered by this report (Evaluation Date). Based on this
evaluation, the principal executive officer and principal
financial officer have concluded that EOG's disclosure controls
and procedures were effective as of the Evaluation Date 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.
Management's Report on Internal Control over Financial
Reporting. EOG's management is responsible for establishing and
maintaining effective internal control over financial reporting
(as defined in Rule 13a-15(f) or 15d-15(f) promulgated under the
Exchange Act). Even an effective internal control system, no
matter how well designed, has inherent limitations, including the
possibility of human error and circumvention or overriding of
controls and therefore can provide only reasonable assurance with
respect to reliable financial reporting. Furthermore, the
effectiveness of an internal control system in future periods can
change with conditions.
EOG's management assessed the effectiveness of EOG's
internal control over financial reporting as of December 31,
2004. In making this assessment, it used the criteria set forth
by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO) in Internal Control-Integrated Framework.
Based on this assessment, management believes that, as of
December 31, 2004, EOG's internal control over financial
reporting is effective based on those criteria. EOG's assessment
also appears on page F-2.
EOG's independent auditors have issued an audit report on
EOG's assessment of its internal control over financial
reporting. This report begins on page F-3.
There were no changes in EOG's internal control over
financial reporting that occurred during the fiscal quarter ended
December 31, 2004 that have materially affected, or are
reasonably likely to materially affect, EOG's internal control
over financial reporting.
ITEM 9B. Other Information
None.
33
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, 2004, 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, 2004, 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, 2004, under the caption "Compensation of
Directors and Executive Officers" of Item 1.
ITEM 12. Security Ownership of Certain Beneficial Owners and
Management
The information required by this Item with respect to
security ownership of certain beneficial owners and management is
incorporated by reference from the Proxy Statement to be filed
within 120 days after December 31, 2004, under the captions
"Election of Directors" and "Compensation of Directors and
Executive Officers" of Item 1.
Equity Compensation Plan Information
The Company has various plans under which employees and
nonemployee members of the Board of Directors of the Company and
its subsidiaries have been or may be granted certain equity
compensation consisting of stock options, restricted stock,
restricted stock units and phantom stock. The 1992 Stock Plan,
the 1993 Nonemployee Directors Stock Option Plan, and the
Employee Stock Purchase Plan have been approved by security
holders. Plans that have not been approved by security holders
are described below. The following table sets forth data for the
Company's equity compensation plans aggregated by the various
plans approved by security holders and those plans not approved
by security holders as of December 31, 2004.
(c)
(a) Number of Securities
Number of Remaining Available for
Securities to be (b) Future Issuance Under
Issued Upon Exercise Weighted-Average Equity Compensation
of Outstanding Exercise Price of Plans (Excluding
Options, Warrants Outstanding Options, Securities Reflected
Plan Category and Rights Warrants and Rights in Column (a))
Equity Compensation
Plans Approved by
Security Holders 3,561,527 $46.02 3,622,857(1)(2)
Equity Compensation
Plans Not Approved
by Security Holders 3,722,168 $33.03(3) 85,970(4)(5)
Total 7,283,695 $39.42(3) 3,708,827
(1) Of these securities, 256,590 shares remain available for purchase
under the Employee Stock Purchase Plan.
(2) Of these securities, 1,071,324 could be issued as restricted stock
or restricted stock units under the 1992 Stock Plan.
(3) Weighted-average exercise price does not include 43,875
phantom stock units in the 1996 Deferral Plan which are
included in column (a).
(4) Of these securities, 11,043 phantom stock units remain available for
issuance under the 1996 Deferral Plan.
(5) Of these securities, 85,970 could be issued as restricted stock or
restricted stock units under the 1994 Stock Plan.
34
Stock Plan Not Approved by Security Holders. The Board of
Directors of the Company approved the 1994 Stock Plan, which
provides equity compensation to employees who are not officers
within the meaning of Rule 16a-1 of the Securities Exchange Act
of 1934, as amended. Under the plan, employees have been or may
be granted stock options (rights to purchase shares of EOG common
stock at a price not less than the market price of the stock at
the date of grant). Stock options vest either immediately at the
date of grant or up to four years from the date of grant based on
the nature of the grants and as defined in individual grant
agreements. Terms for stock options granted under the plan have
not exceeded a maximum term of 10 years. Employees have also
been or may be granted shares of restricted stock and/or
restricted stock units without cost to the employee. The shares
and units granted vest to the employee at various times ranging
from one to five years as defined in individual grant agreements.
Upon vesting, restricted shares are released to the employee.
Upon vesting, restricted stock units are converted into one share
of EOG common stock and released to the employee.
Individual Equity Compensation Arrangement Not Approved by
Security Holders. The Board of Directors of the Company approved
a one-time grant of 35,000 stock options to nonemployee directors
of the Company in 1998, including a grant to Frank Wisner, of
which 2,500 shares remain outstanding. The grant has a 10-year
term and vested 50% on the first anniversary and 50% on the
second anniversary of the date of grant.
Deferral Plan Phantom Stock Account. The Board of Directors
of the Company approved the 1996 Deferral Plan, under which
payment of base salary, annual bonus and directors fees may be
deferred into a phantom stock account. Participants may also
defer receipt of shares of EOG common stock from the exercise of
a stock option or release of restricted stock or restricted stock
units into the phantom stock account. In the phantom stock
account, deferrals are treated as if they had purchased shares of
EOG common stock at the closing stock price on the date of
deferral. Dividends are credited quarterly and treated as if
reinvested in EOG common stock. Payment of the phantom stock
account is made in actual shares of EOG common stock. A total of
60,000 shares have been registered for issuance under the plan.
As of December 31, 2004, 48,957 phantom stock units had been
issued and 11,043 units remained available for issuance under the
plan.
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, 2004, under the
caption "Ratification of Appointment of Auditors - General" of
Item 2.
PART IV
ITEM 15. Financial Statements and Financial Statement Schedule
and Exhibits
(a)(1) and (a)(2) Financial Statements and Financial Statement
Schedule
See "Index to Financial Statements" set forth on page F-1.
(a)(3) Exhibits
See pages E-1 through E-5 for a listing of the exhibits.
35
INDEX TO FINANCIAL STATEMENTS
EOG RESOURCES, INC.
Page
Consolidated Financial Statements:
Management's Responsibility for Financial Reporting F-2
Report of Independent Registerd Public Accounting Firm F-3
Consolidated Statements of Income and Comprehensive Income for
Each of the Three Years in the Period Ended December 31, 2004 F-5
Consolidated Balance Sheets - December 31, 2004 and 2003 F-6
Consolidated Statements of Shareholders' Equity for Each of
the Three Years in the Period Ended December 31, 2004 F-7
Consolidated Statements of Cash Flows for Each of the Three
Years in the Period Ended December 31, 2004 F-8
Notes to Consolidated Financial Statements F-9
Supplemental Information to Consolidated Financial Statements F-30
Financial Statement Schedule:
Schedule II-Valuation and Qualifying Accounts S-1
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.
F-1
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The following consolidated financial statements of EOG
Resources, Inc. and its subsidiaries (EOG) were prepared by
management, which is responsible for their integrity, objectivity
and fair presentation. The statements have been prepared in
conformity with generally accepted accounting principles and,
accordingly, include some amounts that are based on the best
estimates and judgments of management.
EOG's management is also responsible for establishing and
maintaining effective internal control over financial reporting.
The system of internal control of EOG is designed to provide
reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for
external purposes in accordance with generally accepted
accounting principles. This system consists of 1) entity level
controls, including written policies and guidelines relating to
the ethical conduct of business affairs, 2) general computer
controls and 3) process controls over initiating, authorizing,
recording, processing and reporting transactions. Even an
effective internal control system, no matter how well designed,
has inherent limitations, including the possibility of human
error and circumvention or overriding of controls and therefore
can provide only reasonable assurance with respect to reliable
financial reporting. Furthermore, the effectiveness of an
internal control system in future periods can change with
conditions.
The adequacy of financial controls of EOG and the accounting
principles employed in financial reporting by EOG are under the
general oversight of the Audit Committee of the Board of
Directors. No member of this committee is an officer or employee
of EOG. The independent public accountants and internal auditors
have full, free, separate and direct access to the Audit
Committee and meet with the committee from time to time to
discuss accounting, auditing and financial reporting matters.
EOG's management assessed the effectiveness of EOG's
internal control over financial reporting as of December 31,
2004. In making this assessment, we used the criteria set forth
by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO) in Internal Control - Integrated Framework.
These criteria cover the control environment, risk assessment
process, control activities, information and communication
systems, and monitoring activities. Based on this assessment,
management believes that, as of December 31, 2004, EOG's internal
control over financial reporting is effective based on those
criteria.
Deloitte & Touche LLP, independent public accountants, was
engaged to audit the consolidated financial statements and
management's assessment of the effectiveness of EOG's internal
control over financial reporting, and to issue a report thereon.
In the conduct of the audit, Deloitte & Touche LLP was given
unrestricted access to all financial records and related data
including minutes of all meetings of shareholders, the Board of
Directors and committees of the Board. Management believes that
all representations made to Deloitte & Touche LLP during the
audit were valid and appropriate. Their audit was made in
accordance with standards of the Public Company Accounting
Oversight Board (United States) and included a review of the
system of internal controls to the extent considered necessary to
determine the audit procedures required to support their opinion
on the consolidated financial statements, management's assessment
of EOG's internal control over financial reporting and the
effectiveness of EOG's internal control over financial reporting.
Their report begins on page F-3.
MARK G. PAPA EDMUND P. SEGNER, III TIMOTHY K. DRIGGERS
Chairman of the Board President and Chief of Vice President and
and Chief Executive Staff Chief Accounting
Officer Officer
Houston, Texas
February 24, 2005
F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
EOG Resources, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets
of EOG Resources, Inc. and subsidiaries (the "Company") as of
December 31, 2004 and 2003, and the related consolidated
statements of income and comprehensive income, shareholders'
equity, and cash flows for each of the three years in the period
ended December 31, 2004. Our audits also included the financial
statement schedule listed in the Index at Item 15. We also have
audited management's assessment, included in the accompanying
Management's Responsibility for Financial Reporting, that the
Company maintained effective internal control over financial
reporting as of December 31, 2004, based on criteria established
in Internal Control-Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission. The
Company's management is responsible for these financial
statements and financial statement schedules, for maintaining
effective internal control over financial reporting, and for its
assessment of the effectiveness of internal control over
financial reporting. Our responsibility is to express an opinion
on these financial statements and financial statement schedules,
an opinion on management's assessment, and an opinion on the
effectiveness of the Company's internal control over financial
reporting based on our audits.
We conducted our audits in accordance with the standards of
the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial
statements are free of material misstatement and whether
effective internal control over financial reporting was
maintained in all material respects. Our audit of financial
statements included examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the
overall financial statement presentation. Our audit of internal
control over financial reporting included obtaining an
understanding of internal control over financial reporting,
evaluating management's assessment, testing and evaluating the
design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in
the circumstances. We believe that our audits provide a
reasonable basis for our opinions.
A company's internal control over financial reporting is a
process designed by, or under the supervision of, the company's
principal executive and principal financial officers, or persons
performing similar functions, and effected by the company's board
of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for
external purposes in accordance with accounting principles
generally accepted in the United States of America. A company's
internal control over financial reporting includes those policies
and procedures that (1) pertain to the maintenance of records
that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in
accordance with accounting principles generally accepted in the
United States of America and that receipts and expenditures of
the company are being made only in accordance with authorizations
of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial
statements.
Because of the inherent limitations of internal control over
financial reporting, including the possibility of collusion or
improper management override of controls, material misstatements
due to error or fraud may not be prevented or detected on a
timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to
future periods are subject to the risk that the controls may
become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may
deteriorate.
F-3
In our opinion, the consolidated financial statements
referred to above present fairly, in all material respects, the
financial position of the Company as of December 31, 2004 and
2003, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 2004, in
conformity with accounting principles generally accepted in the
United States of America. Also, in our opinion, such financial
statement schedules, when considered in relation to the basic
consolidated financial statements taken as a whole, present
fairly, in all material respects, the information set forth
therein. Also, in our opinion, management's assessment that the
Company maintained effective internal control over financial
reporting as of December 31, 2004, is fairly stated, in all
material respects, based on the criteria established in Internal
Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission.
Furthermore, in our opinion, the Company maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2004, based on the criteria
established in Internal Control-Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway
Commission.
DELOITTE & TOUCHE LLP
Houston, Texas
February 24, 2005
F-4
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(In Thousands, Except Per Share Amounts)
Year Ended December 31 2004 2003 2002
Net Operating Revenues
Natural Gas $1,843,895 $1,537,352 $ 915,129
Crude Oil, Condensate and Natural Gas Liquids 458,446 283,042 227,309
Losses on Mark-to-Market Commodity
Derivative Contracts (33,449) (80,414) (48,508)
Other, Net 2,333 4,695 752
Total 2,271,225 1,744,675 1,094,682
Operating Expenses
Lease and Well, including Transportation 271,086 212,601 179,429
Exploration Costs 93,941 76,358 60,228
Dry Hole Costs 92,142 41,156 46,749
Impairments 81,530 89,133 68,430
Depreciation, Depletion and Amortization 504,403 441,843 398,036
General and Administrative 115,013 100,403 88,952
Taxes Other Than Income 133,915 85,867 71,881
Total 1,292,030 1,047,361 913,705
Operating Income 979,195 697,314 180,977
Other Income (Expense), Net 9,945 15,273 (1,651)
Income Before Interest Expense and Income Taxes 989,140 712,587 179,326
Interest Expense
Incurred 72,759 67,252 68,641
Capitalized (9,631) (8,541) (8,987)
Net Interest Expense 63,128 58,711 59,654
Income Before Income Taxes 926,012 653,876 119,672
Income Tax Provision 301,157 216,600 32,499
Net Income Before Cumulative Effect of Change
in Accounting Principle 624,855 437,276 87,173
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax - (7,131) -
Net Income 624,855 430,145 87,173
Preferred Stock Dividends 10,892 11,032 11,032
Net Income Available to Common $ 613,963 $ 419,113 $ 76,141
Net Income Per Share Available to Common
Basic
Net Income Available to Common Before Cumulative
Effect of Change in Accounting Principle $ 5.25 $ 3.72 $ 0.66
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax - (0.06) -
Net Income Available to Common $ 5.25 $ 3.66 $ 0.66
Diluted
Net Income Available to Common Before Cumulative
Effect of Change in Accounting Principle $ 5.15 $ 3.66 $ 0.65
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax - (0.06) -
Net Income Available to Common $ 5.15 $ 3.60 $ 0.65
Average Number of Common Shares
Basic 116,876 114,597 115,335
Diluted 119,188 116,519 117,245
Comprehensive Income
Net Income $ 624,855 $ 430,145 $ 87,173
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustment 77,925 123,811 4,315
Foreign Currency Swap Transaction, Net of
Income Tax Benefit of $1,972 (3,844) - -
Available-for-Sale Security Transactions - - 926
Comprehensive Income $ 698,936 $ 553,956 $ 92,414
The accompanying notes are an integral part of these consolidated financial statements.
F-5
EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
At December 31 2004 2003
ASSETS
Current Assets
Cash and Cash Equivalents $ 20,980 $ 4,443
Accounts Receivable, Net 447,742 295,118
Inventories 40,037 21,922
Assets from Price Risk Management Activities 10,747 -
Income Taxes Receivable 3,232 7,976
Deferred Income Taxes 22,227 31,548
Other 41,838 35,007
Total 586,803 396,014
Oil and Gas Properties (Successful Efforts Method) 9,599,276 8,189,062
Less: Accumulated Depreciation, Depletion
and Amortization (4,497,673) (3,940,145)
Net Oil and Gas Properties 5,101,603 4,248,917
Other Assets 110,517 104,084
Total Assets $5,798,923 $4,749,015
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts Payable $ 424,581 $ 282,379
Accrued Taxes Payable 51,116 33,276
Dividends Payable 7,394 6,175
Liabilities from Price Risk Management Activities - 37,779
Deferred Income Taxes 103,933 73,611
Other 45,180 43,299
Total 632,204 476,519
Long-Term Debt 1,077,622 1,108,872
Other Liabilities 241,319 171,115
Deferred Income Taxes 902,354 769,128
Shareholders' Equity
Preferred Stock, $.01 Par, 10,000,000 Shares Authorized:
Series B, 100,000 Shares Issued, Cumulative,
$100,000,000 Liquidation Preference 98,826 98,589
Series D, 500 Shares Issued, Cumulative,
$50,000,000 Liquidation Preference - 49,827
Common Stock, $.01 Par, 320,000,000 Shares Authorized
and 124,730,000 Shares Issued 201,247 201,247
Additional Paid in Capital 21,047 1,625
Unearned Compensation (29,861) (23,473)
Accumulated Other Comprehensive Income 148,015 73,934
Retained Earnings 2,706,845 2,121,214
Common Stock Held in Treasury, 5,802,556 shares at
December 31, 2004 and 8,819,600 shares at
December 31, 2003 (200,695) (299,582)
Total Shareholders' Equity 2,945,424 2,223,381
Total Liabilities and Shareholders' Equity $5,798,923 $4,749,015
The accompanying notes are an integral part of these consolidated financial statements.
F-6
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(In Thousands, Except Per Share Amounts)
Accumulated Common
Additional Other Stock Total
Preferred Common Paid In Unearned Comprehensive Retained Held In Shareholders'
Stock Stock Capital Compensation Income (Loss) Earnings Treasury Equity
Balance at December 31, 2001 $147,582 $201,247 $ - $(14,953) $(55,118) $1,668,708 $(304,780) $1,642,686
Net Income - - - - - 87,173 - 87,173
Amortization of Preferred
Stock Discount 417 - - - - (417) - -
Preferred Stock Dividends
Declared - - - - - (10,615) - (10,615)
Common Stock Dividends
Declared, $.16 Per Share - - - - - (18,499) - (18,499)
Translation Adjustment - - - - 4,315 - - 4,315
Available-for-Sale Security
Transactions - - - - 926 - - 926
Treasury Stock Purchased - - - - - - (63,139) (63,139)
Treasury Stock Issued Under:
Stock Option Plans - - (9,457) - - (2,402) 28,666 16,807
Employee Stock Purchase Plan - - (39) - - - 2,301 2,262
Tax Benefits from Stock
Options Exercised - - 5,167 - - - - 5,167
Restricted Stock and Units - - 4,329 (4,951) - - 622 -
Amortization of Unearned
Compensation - - - 4,871 - - - 4,871
Treasury Shares Issued as
Compensation - - - - - - 441 441
Balance at December 31, 2002 147,999 201,247 - (15,033) (49,877) 1,723,948 (335,889) 1,672,395
Net Income - - - - - 430,145 - 430,145
Amortization of Preferred
Stock Discount 417 - - - - (417) - -
Preferred Stock Dividends
Declared - - - - - (10,615) - (10,615)
Common Stock Dividends
Declared, $0.19 Per Share - - - - - (21,847) - (21,847)
Translation Adjustment - - - - 123,811 - - 123,811
Treasury Stock Purchased - - - - - - (25,208) (25,208)
Treasury Stock Issued Under:
Stock Option Plans - - (16,522) - - - 50,292 33,770
Employee Stock Purchase Plan - - 84 - - - 2,515 2,599
Tax Benefits from Stock
Options Exercised - - 11,926 - - - - 11,926
Restricted Stock and Units - - 6,084 (14,467) - - 8,383 -
Amortization of Unearned
Compensation - - - 6,027 - - - 6,027
Treasury Stock Issued as
Compensation - - 53 - - - 325 378
Balance at December 31, 2003 148,416 201,247 1,625 (23,473) 73,934 2,121,214 (299,582) 2,223,381
Net Income - - - - - 624,855 - 624,855
Redemption of Preferred Stock,
$100,000 Per Share (50,000) - - - - - - (50,000)
Amortization of Preferred
Stock Discount 410 - - - - (410) - -
Preferred Stock Dividends
Declared - - - - - (10,482) - (10,482)
Common Stock Dividends
Declared, $0.24 Per Share - - - - - (28,332) - (28,332)
Translation Adjustment - - - - 77,925 - - 77,925
Treasury Stock Purchased - - - - - - (9,565) (9,565)
Foreign Currency Swap Transaction
Net of Income Tax Benefit
of $1,972 - - - - (3,844) - - (3,844)
Treasury Stock Issued Under:
Stock Option Plans - - (21,570) - - - 101,077 79,507
Employee Stock Purchase Plan - - 694 - - - 2,326 3,020
Tax Benefits from Stock
Options Exercised - - 29,396 - - - - 29,396
Restricted Stock and Units - - 10,902 (15,951) - - 5,049 -
Amortization of Unearned
Compensation - - - 9,563 - - - 9,563
Balance at December 31, 2004 $ 98,826 $201,247 $ 21,047 $(29,861) $148,015 $2,706,845 $(200,695) $2,945,424
The accompanying notes are an integral part of these consolidated financial statements.
F-7
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
Year Ended December 31 2004 2003 2002
Cash Flows From Operating Activities
Reconciliation of Net Income to Net Cash
Provided by Operating Activities:
Net Income $ 624,855 $ 430,145 $ 87,173
Items Not Requiring Cash
Depreciation, Depletion and Amortization 504,403 441,843 398,036
Impairments 81,530 89,133 68,430
Deferred Income Taxes 204,231 191,726 82,179
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax - 7,131 -
Other, Net 4,580 1,033 17,333
Dry Hole Costs 92,142 41,156 46,749
Mark-to-Market Commodity Derivative Contracts
Total Losses 33,449 80,414 48,508
Realized Losses (82,644) (44,870) (21,136)
Collar Premium (520) (3,003) (1,825)
Tax Benefits from Stock Options Exercised 29,396 11,926 5,168
Other, Net 537 2,141 (1,978)
Changes in Components of Working Capital
and Other Liabilities
Accounts Receivable (151,799) (27,945) (59,957)
Inventories (17,898) (2,840) (57)
Accounts Payable 136,716 74,645 (21,468)
Accrued Taxes Payable 18,197 12,056 (85,208)
Other Liabilities (1,764) (3,257) 7,816
Other, Net (2,683) (15,314) (1,199)
Changes in Components of Working Capital
Associated with Investing and Financing
Activities (28,381) (36,944) 43,093
Net Cash Provided by Operating Activities 1,444,347 1,249,176 611,657
Investing Cash Flows
Additions to Oil and Gas Properties (1,416,684) (1,245,539) (760,876)
Proceeds from Sales of Assets 13,459 13,553 7,514
Changes in Components of Working Capital
Associated with Investing Activities 26,788 38,491 (43,557)
Other, Net (20,471) (13,946) (19,213)
Net Cash Used in Investing Activities (1,396,908) (1,207,441) (816,132)
Financing Cash Flows
Net Commercial Paper and Line of Credit
Borrowings (Repayments) (6,250) (36,260) 39,163
Long-Term Debt Borrowings 150,000 - 250,000
Long-Term Debt Repayments (175,000) - -
Dividends Paid (37,595) (31,294) (29,152)
Redemption of Preferred Stock (50,000) - -
Treasury Stock Purchased - (21,295) (63,038)
Proceeds from Stock Options Exercised 75,510 35,138 17,339
Other, Net 97 (3,485) (3,008)
Net Cash Provided by (Used in) Financing
Activities (43,238) (57,196) 211,304
Effect of Exchange Rate Changes on Cash 12,336 10,056 507
Increase (Decrease) in Cash and Cash Equivalents 16,537 (5,405) 7,336
Cash and Cash Equivalents at Beginning of Year 4,443 9,848 2,512
Cash and Cash Equivalents at End of Year $ 20,980 $ 4,443 $ 9,848
The accompanying notes are an integral part of these consolidated financial statements.
F-8
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial
statements of EOG Resources, Inc. (EOG) include the accounts of
all domestic and foreign subsidiaries. Investments in
unconsolidated affiliates, in which EOG is able to exercise
significant influence, are accounted for using the equity method.
All material intercompany accounts and transactions have been
eliminated.
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenue and
expenses during the reporting period. Actual results could
differ from those estimates.
Certain reclassifications have been made to prior period
financial statements to conform with the current presentation.
Financial Instruments. EOG's financial instruments consist
of cash and cash equivalents, marketable securities, commodity
derivative contracts, accounts receivable, accounts payable and
long-term debt. The carrying values of cash and cash
equivalents, marketable securities, commodity derivative
contracts, accounts receivable and accounts payable approximate
fair value (see Note 2 for fair value of long-term debt).
Cash and Cash Equivalents. EOG records as cash equivalents
all highly liquid short-term investments with original maturities
of three months or less.
Oil and Gas Operations. EOG accounts for its natural gas
and crude oil exploration and production activities under the
successful efforts method of accounting.
Oil and gas lease acquisition costs are capitalized when
incurred. Unproved properties with individually significant
acquisition costs are assessed quarterly on a
property-by-property basis, and any impairment in value is
recognized. Unproved properties with acquisition costs that are
not individually significant are aggregated, and the portion of
such costs estimated to be nonproductive, based on historical
experience, is amortized over the average holding period. If the
unproved properties are determined to be productive, the
appropriate related costs are transferred to proved oil and gas
properties. Lease rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of
drilling exploratory wells, are charged to expense as incurred.
The costs of drilling exploratory wells are capitalized pending
determination of whether they have discovered proved commercial
reserves. Exploratory drilling costs are capitalized when
drilling is complete if it is determined that there is economic
producibility supported by either actual production, a conclusive
formation test or by certain technical data if the discovery is
located offshore in the Gulf of Mexico. If proved commercial
reserves are not discovered, such drilling costs are expensed.
In some circumstances, it may be uncertain whether proved
commercial reserves have been found due to the requirement of a
significant capital investment. Such exploratory drilling costs
may continue to be capitalized if the reserve quantity is
sufficient to justify development when the investment is made and
additional exploratory wells are either in progress or firmly
planned. All other exploratory wells that do not meet these
criteria are expensed after one year. As of December 31, 2004
and 2003, EOG had exploratory drilling costs of $4.3 million and
$4.5 million, respectively, related to an outside operated,
deepwater offshore Gulf of Mexico discovery that has been
deferred for more than one year and will require significant
future capital expenditures before production can commence.
These costs meet the accounting requirements outlined above for
continued capitalization. As of December 31, 2004 and 2003,
there were no material exploratory drilling costs capitalized for
more than one year for projects that did not require a major
capital investment. Costs to develop proved reserves, including
the costs of all development wells and related equipment used in
the production of natural gas and crude oil, are capitalized.
F-9
Depreciation, depletion and amortization of the cost of
proved oil and gas properties is calculated using the
unit-of-production method. The reserve base used to calculate
depletion, depreciation or amortization is the sum of proved
developed reserves and proved undeveloped reserves for leasehold
acquisition costs and the cost to acquire proved properties. The
reserve base includes only proved developed reserves for lease
and well equipment costs, which include development costs and
successful exploration drilling costs. Estimated future
dismantlement, restoration and abandonment costs, net of salvage
values, are taken into account. Certain other assets are
depreciated on a straight-line basis.
Assets are grouped in accordance with paragraph 30 of
Statement of Financial Accounting Standards (SFAS) No. 19. The
basis for grouping is a reasonable aggregation of properties with
a common geological structural feature or stratigraphic
condition, such as a reservoir or field.
Amortization rates are updated quarterly to reflect: 1) the
addition of capital costs, 2) reserve revisions (upwards or
downwards) and additions, 3) property acquisitions and/or
property dispositions, and 4) impairments.
EOG accounts for impairments under the provisions of SFAS
No. 144 - "Accounting for the Impairment or Disposal of Long-
Lived Assets." When circumstances indicate that an asset may be
impaired, EOG compares expected undiscounted future cash flows at
a producing field level to the unamortized capitalized cost of
the asset. If the future undiscounted cash flows, based on EOG's
estimate of future crude oil and natural gas prices, operating
costs, anticipated production from proved reserves and other
relevant data, are lower than the unamortized capitalized cost,
the capitalized cost is reduced to fair value. Fair value is
calculated by discounting the future cash flows at an appropriate
risk-adjusted discount rate.
Inventories, consisting primarily of tubular goods and well
equipment held for use in the exploration for and development and
production of natural gas and crude oil reserves, are carried at
cost with adjustments made from time to time to recognize any
reductions in value.
Arrangements for natural gas, crude oil, condensate and
natural gas liquids sales are evidenced by signed contracts with
determinable market prices and are recorded when production is
delivered. A significant majority of the purchasers of these
products have investment grade credit ratings and material credit
losses have been rare. Revenues are recorded on the entitlement
method based on EOG's percentage ownership of current production.
Each working interest owner in a well generally has the right to
a specific percentage of production, although actual production
sold on that owner's behalf may differ from that owner's
ownership percentage. Under entitlement accounting, a receivable
is recorded when underproduction occurs and a payable is recorded
when overproduction occurs.
Capitalized Interest Costs. Interest capitalization is
required for those properties if its effect, compared with the
effect of expensing interest, is material. Accordingly, certain
interest costs have been capitalized as a part of the historical
cost of unproved oil and gas properties. The amount capitalized
is an allocation of the interest cost incurred during the
reporting period. Capitalized interest is computed only during
the exploration and development activities and not on proved
properties. The interest rate used for capitalization purposes
is based on the interest rates on EOG's outstanding borrowings.
Accounting for Price Risk Management Activities. EOG
accounts for its price risk management activities under the
provisions of SFAS No. 133 - "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS Nos. 137,
138 and 149. The statement establishes accounting and reporting
standards requiring that every derivative instrument be recorded
in the balance sheet as either an asset or liability measured at
its fair value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. During the
three year period ending December 31, 2004, EOG elected not to
designate any of its price risk management activities as
accounting hedges under SFAS No. 133, and accordingly, accounted
for them using the mark-to-market accounting method. Under this
accounting method, the changes in the market value of outstanding
financial instruments are recognized as gains or losses in the
period of change. The gains or losses are recorded in Gains
(Losses) on Mark-to-Market Commodity Derivative Contracts. The
related cash flow impact is reflected as cash flows from
operating activities (see Note 11).
F-10
Income Taxes. EOG accounts for income taxes under the
provisions of SFAS No. 109 - "Accounting for Income Taxes." SFAS
No. 109 requires the asset and liability approach for accounting
for income taxes. Under this approach, deferred tax assets and
liabilities are recognized based on anticipated future tax
consequences attributable to differences between financial
statement carrying amounts of assets and liabilities and their
respective tax bases (see Note 5).
Foreign Currency Translation. For subsidiaries whose
functional currency is deemed to be other than the United States
dollar, asset and liability accounts are translated at year-end
exchange rates and revenue and expenses are translated at average
exchange rates prevailing during the year. Translation
adjustments are included in Accumulated Other Comprehensive
Income (Loss). Any gains or losses on transactions or monetary
assets or liabilities in currencies other than the functional
currency are included in net income in the current period.
Net Income Per Share. In accordance with the provisions of
SFAS No. 128 - "Earnings per Share," basic net income per share
is computed on the basis of the weighted-average number of common
shares outstanding during the periods. Diluted net income per
share is computed based upon the weighted-average number of
common shares plus the assumed issuance of common shares for all
potentially dilutive securities (see Note 8 for additional
information to reconcile the difference between the Average
Number of Common Shares outstanding for basic and diluted net
income per share).
Stock Options. EOG accounts for stock options under the
provisions and related interpretations of Accounting Principles
Board (APB) Opinion No. 25 - "Accounting for Stock Issued to
Employees." No compensation expense is recognized for such
options. As allowed by SFAS No. 123 - "Accounting for Stock-
Based Compensation" issued in 1995, EOG has continued to apply
APB Opinion No. 25 for purposes of determining net income and to
present the pro forma disclosures required by SFAS No. 123.
EOG's pro forma net income and net income per share of
common stock for 2004, 2003 and 2002, had compensation costs been
recorded in accordance with SFAS No. 123, are presented below (in
millions, except per share data):
2004 2003 2002
Net Income Available to Common - As Reported $614.0 $419.1 $ 76.1
Deduct: Total stock-based employee
compensation expense, Net of Income Tax (11.9) (13.9) (13.7)
Net Income Available to Common - Pro Forma $602.1 $405.2 $ 62.4
Net Income per Share Available to Common
Basic - As Reported $ 5.25 $ 3.66 $ 0.66
Basic - Pro Forma $ 5.15 $ 3.54 $ 0.54
Diluted - As Reported $ 5.15 $ 3.60 $ 0.65
Diluted - Pro Forma $ 5.05 $ 3.48 $ 0.53
For grants made prior to August 2004, the fair value of each
option grant is estimated using the Black-Scholes option-pricing
model with the following weighted-average assumptions used for
grants in 2004, 2003 and 2002, respectively: (1) dividend yield
of 0.4%, 0.4% and 0.4%, (2) expected volatility of 35%, 43% and
45%, (3) risk-free interest rate of 2.5%, 3.4% and 3.7% and
(4) expected life of 2.8 years, 5.2 years and 5.3 years.
F-11
Beginning in August 2004, EOG's stock options contain a
feature that limits the potential gain that can be realized by
requiring vested options to be exercised if the market price
reaches 200% of the grant price for five consecutive trading days
(Capped Option). The fair value of each Capped Option grant is
estimated using a Monte Carlo Simulation Model assuming a
dividend yield of 0.4%, expected volatility of 31%, risk-free
interest rate of 4.24% and a weighted-average expected life of
4.83 years. During 2004, approximately 1,377,000 stock options
were granted at a weighted average fair value of $21.06 and were
included in the above pro forma employee stock based compensation
expense calculation. Approximately 200,000 of the stock options
were granted before August 2004 with an average fair value of
$16.04, based on the Black-Scholes Option-Pricing Model.
Approximately 1,177,000 of the stock options were granted with
the Capped Option feature since August 1, 2004, with an average
fair value of $21.91, based on the Monte Carlo Simulation Model.
The average fair values for the stock options granted during 2003
and 2002 were $16.55 and $14.79, respectively.
The effects of applying SFAS No. 123 in this pro forma
disclosure should not be interpreted as being indicative of
future effects. SFAS No. 123 does not apply to awards prior to
1995, and the extent and timing of additional future awards
cannot be predicted.
New Accounting Pronouncements. In June 2001, the Financial
Accounting Standards Board (FASB) issued SFAS No. 143 -
"Accounting for Asset Retirement Obligations" effective for
fiscal years beginning after June 15, 2002. SFAS No. 143
essentially requires entities to record the fair value of a
liability for legal obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement
costs. EOG adopted the statement on January 1, 2003. The impact
of adopting the statement results in an after-tax charge of $7.1
million, which was reported in the first quarter of 2003 as
cumulative effect of change in accounting principle.
During the third quarter of 2003, the SEC made comments to
other registrants that oil and gas mineral rights acquired should
be classified as an intangible asset pursuant to SFAS No. 141 -
"Business Combinations," and SFAS No. 142 - "Goodwill and Other
Intangible Assets." On September 2, 2004, FASB Staff Position
142-2, "Application of FASB Statement No. 142, "Goodwill and
Other Intangible Assets," to Oil- and Gas-Producing Entities" was
issued. The FASB staff believes that the scope exception in
paragraph 8(b) of Statement 142 extends to its disclosure
provisions for drilling and mineral rights of oil- and gas-
producing entities. Accordingly, the SEC comments made to the
other registrants have no impact on EOG's financial statements.
On April 1, 2004, EOG adopted prospectively FASB Staff
Position No. 106-2 - "Accounting and Disclosure Requirements
related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003" (FSP 106-2), which provides guidance
on accounting for the effects of the Medicare Prescription Drug
Improvement Act of 2003 for employers that sponsor postretirement
health care plans that provide prescription drug benefits. The
adoption of FSP 106-2 did not have a material impact on EOG's
financial statements (see Note 6 for further information on EOG's
postretirement plan).
On October 22, 2004, the American Jobs Creation Act of 2004
(the Act) was enacted. The Act provides a deduction for income
from qualified domestic production activities, which will be
phased in from 2005 through 2010. The Act also provides for a
two-year phase out of the existing extra-territorial income
exclusion (ETI) for foreign sales that was viewed to be
inconsistent with international trade protocols by the European
Union. EOG expects the net effect of the phase out of the ETI
and the phase in of this new deduction to result in favorable
adjustments to the effective tax rate for 2005 and subsequent
years. Under the guidance in FASB Staff Position No. 109-1,
"Application of FASB Statement No. 109, Accounting for Income
Taxes, to the Tax Deduction on Qualified Production Activities
Provided by the American Jobs Creation Act of 2004," the
deduction will be treated as a "special deduction" as described
in FASB 109. As such, the special deduction has no effect on
deferred tax assets and liabilities existing at the enactment
date. Rather, the impact of this deduction will be reported in
the period in which the deduction is claimed on EOG's tax return.
F-12
The Act also creates a temporary incentive for United States
corporations to repatriate accumulated income earned abroad by
providing an 85% dividends received deduction for certain
dividends from controlled foreign corporations. The deduction is
subject to a number of limitations and, currently, uncertainty
remains as to how to interpret some provisions in the Act. The
Act limits the qualified dividends to the greater of $500 million
or the amount of earnings permanently reinvested outside the
United States, as reported in the 2002 financial statements,
which was $550 million. In addition, a comprehensive analysis of
foreign legal and tax ramifications must be completed before such
dividends are declared. As such, EOG is not yet in a position to
decide on whether, and to what extent, it might repatriate
foreign earnings that have not yet been remitted to the United
States. EOG expects to be in a position to complete the
assessment by September 30, 2005.
In December 2002, the FASB issued SFAS No. 148 - "Accounting
for Stock-Based Compensation - Transition and Disclosure - an
amendment of FASB Statement No. 123." In December 2004, the FASB
issued SFAS No. 123(R), "Share-Based Payment," which supersedes
SFAS No. 148. SFAS No. 123(R) establishes standards for
transactions in which an entity exchanges its equity instruments
for goods or services. This standard requires a public entity to
measure the cost of employee services received in exchange for an
award of equity instruments based on the grant-date fair value of
the award. This eliminates the exception to account for such
awards using the intrinsic method previously allowable under APB
Opinion No. 25. SFAS No. 123(R) will be effective for interim or
annual reporting periods beginning on or after June 15, 2005.
EOG currently expects to adopt SFAS No. 123(R) effective July 1,
2005 using the modified prospective method. EOG expects that the
adoption of SFAS No. 123(R) would reduce second half 2005 net
earnings by a pre-tax amount of approximately $10 million, taking
into consideration the estimated forfeitures and cancellations.
The amount includes approximately $0.5 million for the Employee
Stock Purchase Plan. SFAS No. 123(R) also requires a public
entity to present its cash flows provided by tax benefits from
stock options exercised in the Financing Cash Flows section of
the Statement of Cash Flows. Had SFAS No. 123(R) been in effect,
EOG's Net Cash Provided by Operating Activities would have been
reduced and its Net Cash Provided by Financing Activities would
have been increased on its Consolidated Statements of Cash Flows
by $29 million, $12 million and $5 million for 2004, 2003 and
2002, respectively (see Note 6 for further information on EOG's
stock-based compensation plans).
2. Long-Term Debt
Long-Term Debt at December 31 consisted of the following (in
thousands):
2004 2003
Commercial Paper $ 91,800 $ 98,050
Senior Unsecured Term Loan Facility due 2005 75,000 150,000
6.50% Notes due 2004 - 100,000
6.70% Notes due 2006 126,870 126,870
6.50% Notes due 2007 100,000 100,000
6.00% Notes due 2008 173,952 173,952
6.65% Notes due 2028 140,000 140,000
7.00% Subsidiary Debt due 2011 220,000 220,000
4.75% Subsidiary Debt due 2014 150,000 -
Total $1,077,622 $1,108,872
During 2004, EOG utilized commercial paper and during 2003,
EOG utilized commercial paper and short-term funding from
uncommitted credit facilities, both bearing market interest
rates, for various corporate financing purposes. Commercial
paper and uncommitted credit borrowings are classified as long-
term debt based on EOG's intent and ability to ultimately replace
such amounts with other long-term debt.
F-13
On July 23, 2003, EOG entered into a new three-year
Revolving Credit Agreement (Agreement) with domestic and foreign
lenders which provides for $600 million in long-term committed
credit, and concurrently cancelled the existing $300 million 364-
day credit facility and $300 million five-year credit facility
scheduled to expire in July 2003 and July 2004, respectively.
This Agreement provides EOG the ability to replace the commercial
paper, uncommitted credit borrowing and any maturity of debt.
Advances under the Agreement bear interest based upon a base rate
or a Eurodollar rate at the option of EOG. The Agreement also
provides for the allocation, at the option of EOG, of up to $75
million of the $600 million to its Canadian subsidiary. Advances
to the Canadian subsidiary, should they occur, would be
guaranteed by EOG and would bear interest at the option of the
Canadian subsidiary based upon a Canadian prime rate or a
Canadian banker's acceptance rate. EOG also has the option to
issue up to $100 million in letters of credit as part of this
Agreement. No amounts were borrowed under this Agreement at
December 31, 2004. The applicable base rates for this Facility,
had there been any amounts borrowed under this Agreement would
have been 5.25% and 4.00% at December 31, 2004 and December 31,
2003, respectively. The applicable Eurodollar rates for this
Facility, had there been any amounts borrowed under this
Agreement would have been 2.90% and 1.62% at December 31, 2004
and December 31, 2003, respectively.
EOG maintains a three-year Senior Unsecured Term Loan
Facility (Facility) with a group of banks whereby the banks lent
EOG $150 million with a maturity date of October 30, 2005. This
Facility calls for interest to be charged at a spread over LIBOR
(London InterBank Offering Rate) or the base rate at EOG's
option, and contains substantially the same covenants as those in
EOG's $600 million Long-Term Revolving Credit Agreement. On
March 31, 2004, EOG repaid $75 million of the $150 million loan.
The remaining $75 million balance is classified as long-term debt
based on EOG's intent and ability to ultimately replace such
amounts with other long-term debt. The applicable interest rates
for the Facility were 3.17% and 1.88% at December 31, 2004 and
December 31, 2003, respectively.
On March 9, 2004, under Rule 144A of the Securities Act of
1933, as amended, EOG Resources Canada Inc., a wholly owned
subsidiary of EOG, issued notes with a total principal amount of
US$150 million, an annual interest rate of 4.75% and a maturity
date of March 15, 2014. The notes are guaranteed by EOG. In
conjunction with the offering, EOG entered into a foreign
currency swap transaction with multiple banks for the equivalent
amount of the notes and related interest, which has in effect
converted this indebtedness into CAD$201.3 million with a 5.275%
interest rate.
The 6.00% to 6.70% Notes due 2006 to 2028 were issued
through public offerings and have effective interest rates of
6.16% to 6.81%. The Subsidiary Debt due 2011 bears interest at a
fixed rate of 7.00% and is guaranteed by EOG. The weighted
average interest rate for the commercial paper was 1.45% for
2004.
On September 15, 2004, EOG repaid in full upon maturity the
$100 million, 6.50% Notes.
At December 31, 2004, the aggregate annual maturities of
long-term debt were $75 million for 2005, $127 million in 2006,
$100 million for 2007, $174 million for 2008 and zero for 2009.
Both EOG's Credit Agreement and Facility contain certain
restrictive covenants, including a maximum debt-to-total
capitalization ratio of 65% and a minimum ratio of EBITDAX
(earnings before interest, taxes, DD&A, and exploration expense)
to interest expense of at least three times. Other than these
covenants, EOG does not have any other financial covenants in its
financing agreements. EOG continues to comply with these two
covenants and does not view them as materially restrictive.
Shelf Registration. As of February 25, 2005, the amount
available under various filed registration statements with the
SEC for the offer and sale from time to time of EOG debt
securities, preferred stock and/or common stock totaled $688
million.
Fair Value Of Long-Term Debt. At December 31, 2004 and
2003, EOG had $1,078 million and $1,109 million, respectively, of
long-term debt, which had fair values of approximately $1,146
million and $1,175 million, respectively. The fair value of
long-term debt is the value EOG would have to pay to retire the
debt, including any premium or discount to the debt-holder for
the differential between the stated interest rate and the
year-end market rate. The fair value of long-term debt is based
upon quoted market prices and, where such quotes were not
available, upon interest rates available to EOG at yearend.
F-14
3. Shareholders' Equity
Common Stock. EOG purchases its common stock from time to
time in the open market to be held in treasury for, among other
purposes, fulfilling any obligations arising under EOG's stock
plans and any other approved transactions or activities for which
such common stock shall be required. In September 2001, the
Board of Directors authorized the purchase of an aggregate
maximum of 10 million shares of common stock of EOG which
superseded all previous authorizations. At December 31, 2004,
6,386,200 shares remain available for repurchases under this
authorization. On February 2, 2005, EOG announced that the Board
of Directors had approved a two-for-one stock split in the form
of a stock dividend, payable to record holders as of February 15,
2005 and to be issued on March 1, 2005. In addition, the Board
increased the quarterly cash dividend on the common stock by 33%,
resulting in a quarterly cash dividend of $0.08 per share pre-
split or $0.04 per share post-split.
The following summarizes shares of common stock outstanding
at December 31, for each of the years ended December 31 (in
thousands):
Common Shares
Issued Treasury Outstanding
Balance at December 31, 2001 124,730 (9,278) 115,452
Treasury Stock Purchased - (1,703) (1,703)
Treasury Stock Issued Under Stock
Option Plans - 870 870
Treasury Stock Issued Under Employee
Stock Purchase Plan - 69 69
Restricted Stock and Units - 19 19
Treasury Stock Issued as Compensation - 13 13
Balance at December 31, 2002 124,730 (10,010) 114,720
Treasury Stock Purchased - (626) (626)
Treasury Stock Issued under Stock
Option Plans - 1,485 1,485
Treasury Stock Issued Under Employee
Stock Purchase Plan - 74 74
Restricted Stock and Units - 247 247
Treasury Stock Issued as Compensation - 10 10
Balance at December 31, 2003 124,730 (8,820) 115,910
Treasury Stock Purchased - (160) (160)
Treasury Stock Issued Under Stock
Option Plans - 2,961 2,961
Treasury Stock Issued Under Employee
Stock Purchase Plan - 68 68
Restricted Stock and Units - 148 148
Balance at December 31, 2004 124,730 (5,803) 118,927
On February 14, 2000, EOG's Board of Directors declared a
dividend of one preferred share purchase right (a "Right," and
the agreement governing the terms of such Rights, the "Rights
Agreement") for each outstanding share of common stock, par value
$0.01 per share. The Board of Directors has adopted this Rights
Agreement to protect stockholders from coercive or otherwise
unfair takeover tactics. The dividend was distributed to the
stockholders of record on February 24, 2000. As mentioned above,
on March 1, 2005, EOG will effect a two-for-one stock split in
the form of a stock dividend. In accordance with the Rights
Agreement, each share of common stock issued in connection with
the stock split will have one Right associated with it. Each
Right, expiring February 24, 2010, represents a right to buy from
EOG one hundredth (1/100) of a share of Series E Junior
Participating Preferred Stock (Preferred Share) for $90, once the
Rights become exercisable. This portion of a Preferred Share
will give the stockholder approximately the same dividend,
voting, and liquidation rights as would one share of common
stock. Prior to exercise, the Right does not give its holder any
dividend, voting, or liquidation rights. If issued, each one
hundredth (1/100) of a Preferred Share (i) will not be
redeemable; (ii) will entitle holders to quarterly dividend
payments of $0.01 per share, or an amount equal to the dividend
paid on one share of common stock, whichever is greater;
(iii) will entitle holders upon liquidation either to receive
$1 per share or an amount equal to the payment made on one share
of common stock, whichever is greater; (iv) will have the same
voting power as one share of common stock; and (v) if shares of
EOG's common stock are exchanged via merger, consolidation, or a
similar transaction, will entitle holders to a per share payment
equal to the payment made on one share of common stock.
F-15
The Rights will not be exercisable until ten days after the
public announcement that a person or group has become an
acquiring person (Acquiring Person) by obtaining beneficial
ownership of 10% or more of EOG's common stock, or if earlier,
ten business days (or a later date determined by EOG's Board of
Directors before any person or group becomes an Acquiring Person)
after a person or group begins a tender or exchange offer which,
if consummated, would result in that person or group becoming an
Acquiring Person. On February 24, 2005, the Rights Agreement was
amended to create an exception to the definition of Acquiring
Person to permit a qualified institutional investor to hold 10%
or more but less than 20% of EOG's common stock without being
deemed an Acquiring Person if the institutional investor meets
the following requirements: (i) the institutional investor is
described in Rule 13d-1(b)(1) promulgated under the Securities
Exchange Act of 1934 and is eligible to report (and, if such
institutional investor is the beneficial owner of greater than 5%
of EOG's common stock, does in fact report) beneficial ownership
of common stock on Schedule 13G; (ii) the institutional investor
is not required to file a Schedule 13D (or any successor or
comparable report) with respect to its beneficial ownership of
EOG's common stock; (iii) the institutional investor does not
beneficially own 15% or more of EOG's common stock (including in
such calculation the holdings of all of the institutional
investor's affiliates and associates other than those which,
under published interpretations of the United States Securities
and Exchange Commission or its staff, are eligible to file
separate reports on Schedule 13G with respect to their beneficial
ownership of EOG's common stock); and (iv) the institutional
investor does not beneficially own 20% or more of EOG's common
stock (including in such calculation the holdings of all of the
institutional investor's affiliates and associates).
If a person or group becomes an Acquiring Person, all
holders of Rights, except the Acquiring Person, may for $90,
purchase shares of EOG's common stock with a market value of
$180, based on the market price of the common stock prior to such
acquisition. If EOG is later acquired in a merger or similar
transaction after the Rights become exercisable, all holders of
Rights except the Acquiring Person may, for $90, purchase shares
of the acquiring corporation with a market value of $180 based on
the market price of the acquiring corporation's stock, prior to
such merger.
EOG's Board of Directors may redeem the Rights for $0.01 per
Right at any time before any person or group becomes an Acquiring
Person. If the Board of Directors redeems any Rights, it must
redeem all of the Rights. Once the Rights are redeemed, the only
right of the holders of Rights will be to receive the redemption
price of $0.01 per Right. The redemption price will be adjusted
if EOG has a stock split or stock dividends of EOG's common
stock. After a person or group becomes an Acquiring Person, but
before an Acquiring Person owns 50% or more of EOG's outstanding
common stock, the Board of Directors may exchange the Rights for
common stock or equivalent security at an exchange ratio of one
share of common stock or an equivalent security for each such
Right, other than Rights held by the Acquiring Person.
Preferred Stock. EOG currently has two authorized series of
preferred stock. On February 14, 2000, EOG's Board of Directors,
in connection with the Rights Agreement described above,
authorized 1,500,000 shares of Series E Junior Participating
Preferred Stock with the rights and preferences described above.
On February 24, 2005, EOG's Board of Directors increased the
authorized shares of Series E Junior Participating Preferred
Stock to 3,000,000 as a result of the two-for-one stock split
mentioned above. Currently, there are no shares of the Series E
Junior Participating Preferred Stock outstanding.
On July 19, 2000, EOG's Board of Directors authorized
100,000 shares of Fixed Rate Cumulative Perpetual Senior
Preferred Stock, Series B, with a $1,000 Liquidation Preference
per share (the "Series B"). Dividends are 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 of each year beginning September 15, 2000. EOG may
redeem all or part of the Series B at any time beginning on
December 15, 2009 at $1,000 per share, plus accrued and unpaid
dividends. The Series B is not convertible into, or exchangeable
for, common stock of EOG. There are 100,000 shares of the Series
B currently outstanding.
F-16
On July 25, 2000, EOG's Board of Directors authorized 500
shares of Flexible Money Market Cumulative Preferred Stock,
Series D, with a liquidation preference of $100,000 per share
(the "Series D"). Dividends were payable on the shares only if
declared by EOG's Board of Directors and were cumulative. The
initial dividend rate on the shares was 6.84% until December 15,
2004. Through December 15, 2004, dividends were payable, if
declared, on March 15, June 15, September 15 and December 15 of
each year beginning September 15, 2000. On December 15, 2004,
EOG redeemed all 500 outstanding shares of the Series D at a
redemption price of $100,000 per share plus accumulated and
unpaid dividends for a total of $50 million. On February 24,
2005, EOG filed a Certificate of Elimination with the Secretary
of State of the State of Delaware to eliminate the Series D from
EOG's Restated Certificate of Incorporation, as amended.
4. Other Income (Expense), Net
Other Income (Expense), Net for 2004 included income from
equity investments of $11 million, gains on sales of reserves and
related assets of $6 million and foreign currency transaction
losses of $7 million. Other Income (Expense), Net for 2003
included foreign currency transaction gains of $9 million and
income from equity investments of $4 million. The foreign
currency transaction gain and loss amounts for 2004 and 2003 are
results of applying the changes in the Canadian exchange rate to
certain intercompany short-term loans that eliminate in
consolidation.
F-17
5. Income Taxes
The principal components of EOG's net deferred income tax
liability at December 31 were as follows (in thousands):
2004 2003
Current Deferred Income Tax Assets
Commodity Hedging Contracts $ (7,701) $ 9,739
Deferred Compensation Plans 6,488 4,994
Net Operating Loss Carryforward - 5,225
United Kingdom Net Operating Loss
Carryforward (Current Portion) 10,160 -
Other 13,280 11,590
Total Current Deferred Income Tax Assets 22,227 31,548
Current Deferred Income Tax Liabilities
Timing Differences Associated With Different
Yearends in Foreign Jurisdictions 103,903 73,611
Other 30 -
Total Current Deferred Income Tax Liabilities 103,933 73,611
Total Net Current Deferred Income Tax Liabilities $ 81,706 $ 42,063
Noncurrent Deferred Income Tax Assets
(included in Other Assets)
United Kingdom Net Operating Loss Carryforward $ 21,764 $ 3,688
United Kingdom Oil and Gas Exploration and Development
Costs Deducted for Tax Over Book Depreciation,
Depletion and Amortization (20,465) -
Total Noncurrent Deferred Income Tax Assets $ 1,299 $ 3,688
Noncurrent Deferred Income Tax Assets
Non-Producing Leasehold Costs $ 41,718 $ 36,154
Seismic Costs Capitalized for Tax 25,563 21,365
Alternative Minimum Tax Credit Carryforward - 3,869
Other 22,740 20,124
Total Noncurrent Deferred Income Tax Assets 90,021 81,512
Noncurrent Deferred Income Tax Liabilities
Oil and Gas Exploration and Development Costs
Deducted for Tax Over Book Depreciation,
Depletion and Amortization 974,492 837,189
Capitalized Interest 16,683 13,451
Other 1,200 -
Total Noncurrent Deferred Income Tax Liabilities 992,375 850,640
Total Net Noncurrent Deferred Income Tax Liability $902,354 $769,128
Total Net Deferred Income Tax Liability $982,761 $807,503
The components of income before income taxes were as follows
(in thousands):
2004 2003 2002
United States $641,973 $442,109 $ 37,354
Foreign 284,039 211,767 82,318
Total $926,012 $653,876 $119,672
F-18
The principal components of EOG's income tax provision for
the years indicated below were as follows (in thousands):
2004 2003 2002
Current:
Federal $ 58,148 $ 3,844 $(61,013)
State 3,137 880 (5,130)
Foreign 35,641 20,150 16,463
Total 96,926 24,874 (49,680)
Deferred:
Federal 156,862 151,389 57,232
State 7,985 4,052 (358)
Foreign 39,384 36,285 25,305
Total 204,231 191,726 82,179
Income Tax Provision $301,157 $216,600 $ 32,499
The differences between taxes computed at the United States
federal statutory tax rate and EOG's effective rate were as
follows:
2004 2003 2002
Statutory Federal Income Tax Rate 35.00% 35.00% 35.00%
State Income Tax, Net of Federal Benefit 0.74 0.73 0.22
Income Tax Provision Related to Foreign Operations (1.83) (0.05) (3.54)
Change in Canadian Federal Tax Rate - (2.16) -
Change in Canadian Provincial Tax Rate (0.58) - -
Tight Gas Sands Federal Income Tax Credits - - (3.57)
Other (0.81) (0.40) (0.95)
Effective Income Tax Rate 32.52% 33.12% 27.16%
On October 22, 2004, the American Jobs Creation Act of 2004
(the Act) was enacted. The Act creates a temporary incentive for
United States corporations to repatriate accumulated income
earned abroad by providing an 85% dividends received deduction
for certain dividends from controlled foreign corporations. The
deduction is subject to a number of limitations and, currently,
uncertainty remains as to how to interpret some provisions in the
Act. The Act limits the qualified dividends to the greater of
$500 million or the amount of earnings permanently reinvested
outside the United States, as reported in the 2002 financial
statements, which was $550 million. In addition, a comprehensive
analysis of foreign legal and tax ramifications must be completed
before such dividends are declared. As such, EOG is not yet in a
position to decide on whether, and to what extent, it might
repatriate foreign earnings that have not yet been remitted to
the United States. EOG expects to be in a position to complete
the assessment by September 30, 2005.
EOG's foreign subsidiaries' undistributed earnings of
approximately $1 billion at December 31, 2004 are considered to
be indefinitely invested outside the United States and,
accordingly, no United States or state income taxes have been
provided thereon. Upon distribution of those earnings in the
form of dividends, EOG may be subject to both foreign withholding
taxes and United States income taxes, net of allowable foreign
tax credits. Determination of any potential amount of
unrecognized deferred income tax liabilities is not practicable.
EOG incurred a tax net operating loss of $191 million in
2002. During 2003, EOG utilized $176 million of the 2002 net
operating loss. The remaining net operating loss of $15 million
was utilized in 2004.
A foreign net operating loss of $80 million, of which $55
million was incurred during 2004, will be carried forward
indefinitely until utilized.
EOG had an alternative minimum tax (AMT) credit carryforward
from prior years of $6 million which was used to offset regular
income taxes in 2004.
F-19
6. Employee Benefit Plans
Pension Plans
EOG has a non-contributory defined contribution pension plan
and a matched defined contribution savings plan in place for most
of its employees in the United States. EOG's contributions to
these pension plans are based on various percentages of
compensation, and in some instances, are based upon the amount of
the employees' contributions. For 2004, 2003 and 2002, EOG's
total contributions to these pension plans amounted to $10.6
million, $8.2 million and $8.0 million, respectively.
In addition, EOG's Canadian subsidiary maintains a non-
contributory defined contribution pension plan and a matched
defined contribution savings plan and EOG's Trinidadian
subsidiary maintains a contributory defined benefit pension plan
and a matched savings plan. These pension plans are available to
most employees of the Canadian and Trinidadian subsidiaries and
EOG's combined contributions to these pension plans were
approximately $860,000, $630,000 and $460,000 for 2004, 2003 and
2002, respectively.
EOG's United Kingdom subsidiary introduced a pension plan as
of January 2005. The United Kingdom subsidiary will include a
defined non-contributory pension plan and a matched defined
contribution savings plan. The pension plan will be available to
all employees of the United Kingdom subsidiary.
F-20
Postretirement Plan
EOG has postretirement medical and dental benefits in place
for eligible employees and their eligible dependents. Benefits
are provided under the provisions of a contributory defined
dollar benefit plan. EOG accrues these postretirement benefit
costs over the service lives of the employees expected to be
eligible to receive such benefits. The following table summarizes
EOG's postretirement benefit plan as of December 31 of the years
indicated as follows (in thousands):
2004 2003 2002
Change in Benefit Obligation
Benefit Obligation at Beginning of Year $ 3,011 $ 1,875 $2,021
Service Cost 175 175 139
Interest Cost 136 131 115
Plan Participants' Contributions 73 64 58
Amendments - 773 -
Benefits Paid (136) (102) (95)
Actuarial (Gain) Loss (1,276) 95 (363)
Benefit Obligation at Yearend $ 1,983 $ 3,011 $1,875
Change in Plan Asset
Fair Value of Plan Asset at Beginning of Year $ - $ - $ -
Employer Contributions 63 38 37
Plan Participants' Contributions 73 64 58
Benefits Paid (136) (102) (95)
Fair Value of Plan Asset at Yearend $ - $ - $ -
Reconciliation of Funded Status to Balance Sheet
Funded Status $ 1,983 $ 3,011 $1,875
Unrecognized Net Actuarial Gain (Loss) 1,158 (64) 35
Unrecognized Prior Service Cost (1,517) (1,647) (948)
Accrued Benefit Cost at Yearend $ 1,624 $ 1,300 $ 962
Components of Net Periodic Benefit Cost
Service Cost $ 175 $ 175 $ 139
Interest Cost 136 131 115
Amortization of Prior Service Cost 129 75 75
Recognized Net Actuarial Gain (53) - (1)
Net Periodic Benefit Cost $ 387 $ 381 $ 328
Weighted-average discount rate assumptions used in the
determination of benefit obligations at December 31, 2004, 2003
and 2002 were 5.95%, 6.15% and 6.40%, respectively. Weighted-
average discount rate assumptions used in the determination of
net periodic benefit cost for years ended December 31, 2004, 2003
and 2002 were 6.15%, 6.40% and 7.00%, respectively.
F-21
Estimated Future Employer-Paid Benefits. The following
benefits, which reflect expected future service, as appropriate,
are expected to be paid by EOG in the next 10 years (in thousands):
Postretirement
Employer-Paid Benefits
2005 $ 84
2006 91
2007 96
2008 103
2009 126
2010 - 2014 924
Postretirement health care trend rates have zero effect on
the amounts reported for the postretirement health care plan for
both 2004 and 2003. A one-percentage point increase or decrease
in EOG's healthcare cost trend rates would have zero impact on
the postretirement benefit obligation, as any increase or
decrease in healthcare costs would be borne by the employee.
Stock Plans
EOG has various stock plans (Plans) under which employees
and non-employee members of the Board of Directors of EOG and its
subsidiaries have been or may be granted certain equity
compensation. Since the inception of the Plans, there have been
31,445,000 shares authorized for grant. At December 31, 2004,
3,708,827 shares remain available for grant.
Stock Options. Under the Plans, participants have been or
may be granted rights to purchase shares of common stock of EOG
at a price not less than the market price of the stock at the
date of grant. Stock options granted under the Plans vest either
immediately at the date of grant or up to four years from the
date of grant based on the nature of the grants and as defined in
individual grant agreements. Terms for stock options granted
under the Plans have not exceeded a maximum term of 10 years.
Beginning in August 2004, EOG's stock options contain a
feature that limits the potential gain that can be realized by
requiring vested options to be exercised if the market price
reaches 200% of the grant price for five consecutive trading
days.
The following table sets forth the option transactions for
the years ended December 31 (options in thousands):
2004 2003 2002
Average Average Average
Grant Grant Grant
Options Price Options Price Options Price
Outstanding at January 1 7,751 $30.38 7,842 $27.31 7,013 $24.69
Granted 1,307 63.94 1,515 39.13 1,809 33.82
Exercised (2,961) 26.85 (1,485) 22.73 (868) 19.90
Forfeited (140) 38.57 (121) 34.74 (112) 27.64
Outstanding at December 31 5,957 39.32 7,751 30.38 7,842 27.31
Options Exercisable at December 31 3,050 30.37 4,933 27.03 5,041 23.96
Available for Future Grant 3,709 1,178 2,932
F-22
EOG currently expects to adopt SFAS No. 123(R) effective
July 1, 2005 (see Note 1) and as a result, EOG expects the
expensing of the stock options would reduce second half 2005 net
earnings by a pre-tax amount of approximately $9.5 million.
The following table summarizes certain information for the
options outstanding at December 31, 2004 (options in thousands):
Options Outstanding Options Exercisable
Weighted Weighted Weighted
Average Average Average
Remaining Grant Grant
Range of Grant Prices Options Life (Years) Price Options Price
$14.00 to $17.99 362 4 $14.53 362 $14.53
18.00 to 22.99 512 4 20.05 512 20.05
23.00 to 28.99 44 3 24.97 42 24.85
29.00 to 33.99 1,627 7 33.32 1,067 33.14
34.00 to 39.99 1,905 8 37.47 882 36.75
40.00 to 54.99 292 8 45.60 177 44.03
55.00 to 73.99 1,215 10 64.78 8 61.22
5,957 7 39.32 3,050 30.37
During 2004, 2003 and 2002, EOG repurchased approximately
160,000, 626,000 and 1,703,000 of its common shares,
respectively. The difference between the cost of the treasury
shares and the exercise price of the options, net of federal
income tax benefit of $29.4 million, $11.9 million and $5.2
million, for the years 2004, 2003 and 2002, respectively, is
reflected as an adjustment to additional paid in capital to the
extent EOG has accumulated additional paid in capital relating to
treasury stock and to retained earnings thereafter.
Restricted Stock and Units. Under the Plans, employees may
be granted restricted stock and/or units without cost to them.
The shares and units granted vest to the employee at various
times ranging from one to five years from the date of grant based
on the nature of the grants and as defined in individual grant
agreements. Upon vesting, restricted shares are released to the
employee. Upon vesting, restricted units are converted into one
share of common stock and released to the employee. The
following summarizes shares of restricted stock and units granted
for the three years ended December 31 (shares and units in
thousands):
Restricted Shares and Units
2004 2003 2002
Outstanding at January 1 1,026 775 632
Granted 330 372 158
Released (41) (103) (10)
Forfeited or Expired (32) (18) (5)
Outstanding at December 31 1,283 1,026 775
Average Fair Value of Shares
Granted During Year $51.43 $40.43 $32.56
The fair value of the restricted shares and units at date of
grant has been recorded in shareholders' equity as unearned
compensation and is being amortized over the vesting period as
compensation expense. Related compensation expense for 2004,
2003 and 2002 was $9.6 million, $6.0 million and $4.9 million,
respectively.
F-23
Employee Stock Purchase Plan. EOG has an Employee Stock
Purchase Plan (ESPP) in place that allows eligible employees to
semi-annually purchase, through payroll deductions, shares of EOG
common stock at 85 percent of the fair market value at specified
dates. Contributions to the ESPP are limited to 10 percent of
the employees' pay (subject to certain ESPP limits) during each
of the two six-month offering periods. As of December 31, 2004,
approximately 256,600 common shares remained available for
issuance under the plan. EOG currently expects to adopt SFAS No.
123(R) effective July 1, 2005 (see Note 1) and as a result, EOG
expects the expense associated with the ESPP would reduce second
half 2005 net earnings by a pre-tax amount of approximately $0.5
million.
The following table summarizes ESPP activities for the years
ended December 31 (in thousands, except number of participants):
2004 2003 2002
Approximate Number of Participants 450 410 350
Shares Purchased 68 74 69
Aggregate Purchase Price $3,021 $2,599 $2,261
7. Commitments and Contingencies
Letters Of Credit. At December 31, 2004 and 2003, EOG had
standby letters of credit and guarantees outstanding totaling
approximately $433 million and $266 million, respectively. Of
these amounts, $370 million and $220 million, respectively,
represent guarantees of subsidiary indebtedness included under
Note 2 "Long-Term Debt" while $63 million and $46 million,
respectively, primarily represent guarantees of payment
obligations on behalf of subsidiaries. As of February 25, 2005,
there were no demands for payment under these guarantees.
Minimum Commitments. At December 31, 2004, total minimum
commitments from long-term non-cancelable operating leases,
drilling rig commitments, seismic purchase and other purchase
obligations, and pipeline transportation service commitments,
based on current transportation rates and the foreign currency
exchange rates at December 31, 2004, are as follows (in
thousands):
Total Minimum
Commitments
2005 $ 45,868
2006 - 2008 72,814
2009 - 2010 24,733
2011 and beyond 44,388
$187,803
Included in the table above are leases for buildings,
facilities and equipment with varying expiration dates through
2015. Rental expenses associated with these leases amounted to
$26 million, $22 million and $21 million for 2004, 2003 and 2002,
respectively.
Contingencies. There are various suits and claims against
EOG that have arisen in the ordinary course of business.
Management believes that the chance that these suits and claims
will individually or in the aggregate have a material adverse
effect on the financial condition or results of operations of EOG
is remote. When necessary, EOG has made accruals in accordance
with SFAS No. 5 - "Accounting for Contingencies," in order to
provide for these matters.
F-24
8. Net Income Per Share Available to Common
The following table sets forth the computation of Net Income
Per Share Available to Common for the years ended December 31 (in
thousands, except per share amounts):
2004 2003 2002
Numerator for basic and diluted
earnings per share -
Net income available to common $613,963 $419,113 $ 76,141
Denominator for basic earnings
per share -
Weighted average shares 116,876 114,597 115,335
Potential dilutive common shares -
Stock options 1,780 1,584 1,633
Restricted stock and units 532 338 277
Denominator for diluted earnings
per share -
Adjusted weighted average shares 119,188 116,519 117,245
Net Income Per Share Available to Common
Basic $ 5.25 $ 3.66 $ 0.66
Diluted $ 5.15 $ 3.60 $ 0.65
9. Supplemental Cash Flow Information
Cash paid for interest and income taxes was as follows for
the years ended December 31 (in thousands):
2004 2003 2002
Interest $ 60,967 $ 62,472 $ 54,432
Income taxes 56,654 26,330 15,946
10. Business Segment Information
EOG's operations are all natural gas and crude oil
exploration and production related. SFAS No. 131 - "Disclosures
about Segments of an Enterprise and Related Information,"
establishes standards for reporting information about operating
segments in annual financial statements and requires selected
information about operating segments in interim financial
reports. Operating segments are defined as components of an
enterprise about which separate financial information is
available and evaluated regularly by the chief operating decision
maker, or decision making group, in deciding how to allocate
resources and in assessing performance. EOG's chief operating
decision making process is informal and involves the Chairman and
Chief Executive Officer and other key officers. This group
routinely reviews and makes operating decisions related to
significant issues associated with each of EOG's major producing
areas in the United States and each significant international
location. For segment reporting purposes, the major United
States producing areas have been aggregated as one reportable
segment due to similarities in their operations as allowed by
SFAS No. 131.
F-25
Financial information by reportable segment is presented below
for the years ended December 31, or at December 31 (in thousands):
United United
States Canada Trinidad Kingdom Other Total
2004
Net Operating Revenues $1,656,325(1) $ 448,562(1) $153,377 $ 12,961 $ - $2,271,225(1)
Depreciation, Depletion and Amortization 382,718 99,879 20,022 1,784 - 504,403
Operating Income (Loss) 682,619 222,155 91,245 (16,824) - 979,195
Interest Income 292 679 659 - - 1,630
Other Income (Expense) 1,072 (4,487) 10,892 838 - 8,315
Interest Expense, Net 41,571 21,415 - 142 - 63,128
Income (Loss) Before Income Taxes 642,412 196,932 102,796 (16,128) - 926,012
Income Tax Provision (Benefit) 231,250 45,785 31,414 (7,292) - 301,157
Additions to Oil and Gas Properties 936,463 294,571 59,205 34,303 - 1,324,542
Total Assets 3,727,231 1,600,486 401,434 69,772 - 5,798,923
2003
Net Operating Revenues $1,335,145(2) $ 309,418(2) $100,112 $ - $ - $1,744,675(2)
Depreciation, Depletion and Amortization 359,439 66,334 16,070 - - 441,843
Operating Income (Loss) 487,133 163,783 55,433 (9,195) 160 697,314
Interest Income 1,385 950 454 - - 2,789
Other Income (Expense) 2,777 6,354 3,418 (71) 6 12,484
Interest Expense, Net 43,421 14,618 670 - 2 58,711
Income (Loss) Before Income Taxes 447,874 156,469 58,635 (9,266) 164 653,876
Income Tax Provision (Benefit) 163,359 36,190 20,671 (3,486) (134) 216,600
Additions to Oil and Gas Properties 605,667 552,164 31,942 14,610 - 1,204,383
Total Assets 3,119,474 1,302,753 309,727 17,061 - 4,749,015
2002
Net Operating Revenues $ 846,007(3) $ 169,106(3) $ 79,551 $ - $ 18 $1,094,682(3)
Depreciation, Depletion and Amortization 334,318 49,622 14,085 - 11 398,036
Operating Income (Loss) 93,600 40,587 49,450 (250) (2,410) 180,977
Interest Income 765 229 348 - - 1,342
Other Income (Expense) (3,652) 261 394 - 4 (2,993)
Interest Expense, Net 45,907 13,534 211 - 2 59,654
Income (Loss) Before Income Taxes 44,806 27,543 49,981 (250) (2,408) 119,672
Income Tax Provision (Benefit) (7,684) 20,359 20,974 300 (1,450) 32,499
Additions to Oil and Gas Properties 517,598 160,840 35,689 - - 714,127
Total Assets 2,864,862 665,202 283,395 66 43 3,813,568
(1) EOG had sales activity with a single significant purchaser in
the United States and Canada segments in 2004 that totaled $280
million of consolidated Net Operating Revenues.
(2) EOG had sales activity with two significant purchasers, one
totaled $222 million and the other totaled $182 million, of
consolidated Net Operating Revenues in the United States and
Canada segments in 2003.
(3) EOG had sales activity with a single significant purchaser in
the United States and Canada segments in 2002 that totaled $163
million of the consolidated Net Operating Revenues.
F-26
11. Price, Interest Rate and Credit Risk Management Activities
Price and Interest Rate Risks. EOG engages in price risk
management activities from time to time. These activities are
intended to manage EOG's exposure to fluctuations in commodity
prices for natural gas and crude oil. EOG utilizes derivative
financial instruments, primarily price swaps and collars, as the
means to manage this price risk. In addition to these financial
transactions, EOG is a party to various physical commodity
contracts for the sale of hydrocarbons that cover varying periods
of time and have varying pricing provisions. Under SFAS No. 133
- - "Accounting for Derivative Instruments and Hedging Activities,"
as amended by SFAS Nos. 137, 138 and 149, these various physical
commodity contracts qualify for the normal purchases and normal
sales exception and therefore, are not subject to hedge
accounting or mark-to-market accounting. The financial impact of
these various physical commodity contracts is included in
revenues at the time of settlement, which in turn affects average
realized hydrocarbon prices.
During 2004, 2003 and 2002, EOG elected not to designate any
of its derivative financial contracts as accounting hedges and
accordingly, accounted for these derivative financial contracts
using mark-to-market accounting. During 2004, EOG recognized
losses on mark-to-market commodity derivative contracts of $33
million, which included realized losses of $82 million and collar
premium payments of $1 million. During 2003, EOG recognized
losses on mark-to-market commodity derivative contracts of $80
million, which included realized losses of $45 million and collar
premium payments of $3 million. During 2002, EOG recognized
losses on mark-to-market commodity derivative contracts of $49
million, which included realized losses of $21 million and a $2
million collar premium payment.
Presented below is a summary of EOG's 2005 natural gas
financial collar contracts at December 31, 2004 with prices
expressed in dollars per million British thermal units ($/MMBtu)
and notional volumes in million British thermal units per day
(MMBtud). As indicated, EOG does not have any financial collar
or swap contracts that cover periods beyond March 2005.
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, 2004. EOG accounts for
these collar contracts using mark-to-market accounting. The
total fair value of the natural gas financial collar contracts at
December 31, 2004 was $11 million.
Natural Gas Financial Collar Contracts
Floor Price Ceiling Price
Weighted Weighted
Volume Floor Range Average Ceiling Range Average
2005 (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu)
Jan(1) 75,000 $7.65 - 8.00 $7.77 $8.90 - 9.50 $9.10
Feb(2) 75,000 7.65 - 8.00 7.77 9.19 - 9.50 9.32
Mar(2) 75,000 7.65 - 8.00 7.77 9.19 - 9.50 9.32
(1) Notional volumes of 25,000 MMBtud of the January 2005 collar
contracts were purchased at a premium of $0.10 per MMBtu.
(2) The collar contracts for February 2005 and March 2005 were
purchased at a premium of $0.10 per MMBtu.
The following table summarizes the estimated fair value of
financial instruments and related transactions at December 31 of
the years indicated as follows (in millions):
2004 2003
Carrying Estimated Carrying Estimated
Amount Fair Value(1) Amount Fair Value(1)
Long-Term Debt(2) $1,078 $1,146 $1,109 $1,175
NYMEX-Related Commodity Market Positions 11 11 (38) (38)
(1) Estimated fair values have been determined by using
available market data and valuation methodologies. Judgment is
required in interpreting market data and the use of different
market assumptions or estimation methodologies may affect the
estimated fair value amounts.
(2) See Note 2.
F-27
Credit Risk. While notional contract amounts are used to
express the magnitude of commodity price and interest rate swap
agreements, the amounts potentially subject to credit risk, in
the event of nonperformance by the other parties, are
substantially smaller. EOG evaluates its exposure to all
counterparties on an ongoing basis, including those arising from
physical and financial transactions. In some instances, EOG
requires collateral, parent guarantees or letters of credit to
minimize credit risk. At December 31, 2004, EOG's net accounts
receivable balance related to United States and Canada
hydrocarbon sales included two receivable balances, each of which
constituted 11% of the total balance. These receivables were due
from two integrated oil and gas companies. The related amounts
were collected during early 2005. The amounts due from an
integrated oil and gas company and a utility company at December
31, 2003, which approximated 14% and 11%, respectively, of the
United States and Canada net accounts receivable balance, were
collected during early 2004. No other individual purchaser
accounted for 10% or more of the United States and Canada net
accounts receivable balance at December 31, 2004 and 2003. At
December 31, 2004, EOG had an allowance for doubtful accounts of
$21 million, of which $19 million is associated with the Enron
bankruptcies recorded in December 2001.
Substantially all of EOG's accounts receivable at
December 31, 2004 and 2003 result from hydrocarbon sales and/or
joint interest billings to third party companies including
foreign state-owned entities in the oil and gas industry. This
concentration of customers and joint interest owners may impact
EOG's overall credit risk, either positively or negatively, in
that these entities may be similarly affected by changes in
economic or other conditions. In determining whether or not to
require collateral or other credit enhancements from a customer
or joint interest owner, EOG analyzes the entity's net worth,
cash flows, earnings, and credit ratings. Receivables are
generally not collateralized. During the three-year period ended
December 31, 2004, credit losses incurred on receivables by EOG
have been immaterial.
12. Accounting for Certain Long-Lived Assets
EOG reviews its oil and gas properties for impairment
purposes by comparing the expected undiscounted future cash flows
at a producing field level to the unamortized capitalized cost of
the asset. During 2004, 2003 and 2002, such reviews indicated
that unamortized capitalized costs of certain properties were
higher than their expected undiscounted future cash flows due
primarily to downward reserve revisions for certain producing
fields. As a result, during 2004, 2003 and 2002, EOG recorded in
Impairments pre-tax charges of $17 million, $21 million and $30
million, respectively, in the United States operating segment and
$8 million, $4 million and $0, respectively, in the Canada
operating segment. The carrying values for assets determined to
be impaired were adjusted to estimated fair values based on
projected future net cash flows discounted using EOG's risk-
adjusted discount rate. Amortization expenses of acquisition
costs of unproved properties, including amortization of
capitalized interest, were $57 million, $64 million and $38
million for 2004, 2003 and 2002, respectively.
13. Accounting for Asset Retirement Obligations
EOG adopted SFAS No. 143 - "Accounting for Asset Retirement
Obligations" on January 1, 2003. The adoption of the statement
resulted in an after-tax charge of $7.1 million, which was
reported in the first quarter of 2003 as Cumulative Effect of
Change in Accounting Principle. The following table presents the
reconciliation of the beginning and ending aggregate carrying
amount of short-term and long-term legal obligations associated
with the retirement of oil and gas properties pursuant to SFAS
No. 143 for 2004 (in thousands):
Asset Retirement Obligations
Short-Term Long-Term Total
Balance at December 31, 2003 $ 5,320 $118,624 $123,944
Liabilities Incurred 2,060 14,728 16,788
Liabilities Settled (4,831) (5,422) (10,253)
Accretion 164 5,423 5,587
Revision 1,333 744 2,077
Reclassification 2,894 (2,894) -
Foreign Currency Translation 30 586 616
Balance at December 31, 2004 $ 6,970 $131,789 $138,759
F-28
Pro forma net income and earnings per share are not
presented for the comparable period in 2002 because the pro forma
application of SFAS No. 143 to the prior period would not result
in pro forma net income and earnings per share materially
different from the actual amounts reported for the period in the
accompanying Consolidated Statements of Income.
14. Investment in Caribbean Nitrogen Company Limited and
Nitrogen (2000) Unlimited
EOG, through certain wholly owned subsidiaries, owns equity
interests in two Trinidadian companies: Caribbean Nitrogen
Company Limited (CNCL) and Nitrogen (2000) Unlimited (N2000).
During the first quarters of 2003 and 2004, EOG completed
separate share sale agreements whereby a portion of the EOG
subsidiaries' shareholdings in CNCL and N2000 was sold to a third
party energy company. The sales left EOG with equity interests
of 12% in CNCL and 23% in N2000 and did not result in any gain or
loss.
In February 2005, a portion of EOG's shareholdings in
N2000 was sold to a subsidiary of one of the other shareholders.
The sale resulted in a pre-tax gain of approximately $2 million.
EOG's equity interest in N2000 is now 10%.
The other shareholders in CNCL are Ferrostaal AG, Clico
Energy Company Limited, KBRDC CNC (Cayman) Ltd. and Koch CNC
(Nevis) LLC. At December 31, 2004, investment in CNCL was $15
million. CNCL commenced production in June 2002, and at December
31, 2004, was producing approximately 1,850 metric tons of
ammonia daily. At December 31, 2004, CNCL had a long-term debt
balance of $203 million, which is non-recourse to CNCL's
shareholders. EOG will be liable for its share of any post-
completion deficiency funds, loans to fund the costs of
operation, payment of principal and interest to the principal
creditor and other cash deficiencies of CNCL up to $30 million,
approximately $4 million of which is net to EOG's interest. The
Shareholders' Agreement requires the consent of the holders of
90% or more of the shares to take certain material actions.
Accordingly, given its current level of equity ownership, EOG is
able to exercise significant influence over the operating and
financial policies of CNCL and therefore, it accounts for the
investment using the equity method. During 2004, EOG recognized
equity income of $5 million and received cash dividends of $5
million from CNCL.
The other shareholders in N2000 are FS Petrochemicals (St.
Kitts) Limited, CE Limited, KBRDC Nitrogen 2000 (St. Lucia) Ltd.
and Koch N2000 (Nevis) LLC. At December 31, 2004, investment in
N2000 was $26 million. N2000 commenced production in August
2004, and at December 31, 2004, was producing approximately 1,950
metric tons of ammonia daily. At December 31, 2004, N2000 had a
long-term debt balance of $228 million, which is non-recourse to
N2000's shareholders. At December 31, 2004, EOG was liable for
its share of any post-completion deficiency funds, loans to fund
the costs of operation, payment of principal and interest to the
principal creditor and other cash deficiencies of N2000 up to $30
million, approximately $7 million of which is net to EOG's
interest. The Shareholders' Agreement requires the consent of
the holders of 100% of the shares to take certain material
actions. Accordingly, given its current level of equity
ownership, EOG is able to exercise significant influence over the
operating and financial policies of N2000 and therefore, it
accounts for the investment using the equity method. During
2004, EOG recognized equity income of $6 million.
15. Property Acquisitions
On October 1, 2003, a Canadian subsidiary of EOG closed an
asset purchase of natural gas properties in the Wintering Hills,
Drumheller East and Twining areas of southeast Alberta from a
subsidiary of Husky Energy Inc. for approximately US$320 million.
These properties are essentially adjacent to existing EOG
operations or are properties in which EOG already had a working
interest. The transaction was partially funded by commercial
paper borrowings of US$140.5 million on October 1, 2003. The
remainder of the purchase price, US$179.5 million, was funded by
EOG's available cash balance. Subsequent to the closing, the
purchase price was reduced by exercised preferential rights on
the properties which totaled approximately US$5 million. In late
December 2003, a Canadian subsidiary of EOG closed another
property acquisition for US$46 million.
F-29
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(In Thousands Except Per Share Amounts Unless Otherwise Indicated)
(Unaudited Except for Results of Operations for Oil and Gas
Producing Activities)
Oil and Gas Producing Activities
The following disclosures are made in accordance with SFAS
No. 69 - "Disclosures about Oil and Gas Producing Activities":
Oil and Gas Reserves. Users of this information should be
aware that the process of estimating quantities of "proved,"
"proved developed" and "proved undeveloped" crude oil and natural
gas reserves is very complex, requiring significant subjective
decisions in the evaluation of all available geological,
engineering and economic data for each reservoir. The data for a
given reservoir may also change substantially over time as a
result of numerous factors including, but not limited to,
additional development activity, evolving production history, and
continual reassessment of the viability of production under
varying economic conditions. Consequently, material revisions
(upward or downward) to existing reserve estimates may occur from
time to time. Although every reasonable effort is made to ensure
that reserve estimates reported represent the most accurate
assessments possible, the significance of the subjective
decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other
estimates presented in connection with financial statement
disclosures.
Proved reserves represent estimated quantities of natural
gas, crude oil, condensate, and natural gas liquids that
geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known
reservoirs under economic and operating conditions existing at
the time the estimates were made.
Proved developed reserves are proved reserves expected to be
recovered, through wells and equipment in place and under
operating methods being utilized at the time the estimates were
made.
Proved undeveloped reserves are reserves that are expected
to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required
for completion. Reserves on undrilled acreage are limited to
those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be
demonstrated with certainty that there is continuity of
production from the existing productive formation. Estimates for
proved undeveloped reserves are not attributed to any acreage for
which an application of fluid injection or other improved
recovery technique is contemplated, unless such techniques have
been proved effective by actual tests in the area and in the same
reservoir.
Canadian provincial royalties are determined based on a
graduated percentage scale which varies with prices and
production volumes. Canadian reserves, as presented on a net
basis, assume prices and royalty rates in existence at the time
the estimates were made, and EOG's estimate of future production
volumes. Future fluctuations in prices, production rates, or
changes in political or regulatory environments could cause EOG's
share of future production from Canadian reserves to be
materially different from that presented.
F-30
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Estimates of proved and proved developed reserves at
December 31, 2004, 2003 and 2002 were based on studies performed
by the engineering staff of EOG for all reserves. Opinions by
DeGolyer and MacNaughton (D&M), independent petroleum
consultants, for the years ended December 31, 2004, 2003 and 2002
covered producing areas containing 77%, 72% and 73%,
respectively, of proved reserves of EOG on a net-equivalent-cubic-
feet-of-gas basis. D&M's opinions indicate that the estimates of
proved reserves prepared by EOG's engineering staff for the
properties reviewed by D&M, when compared in total on a net-
equivalent-cubic-feet-of-gas basis, do not differ materially from
the estimates prepared by D&M. Such estimates by D&M in the
aggregate varied by not more than 5% from those prepared by the
engineering staff of EOG. All reports by D&M were developed
utilizing geological and engineering data provided by EOG.
No major discovery or other favorable or adverse event
subsequent to December 31, 2004 is believed to have caused a
material change in the estimates of proved or proved developed
reserves as of that date.
The following table sets forth EOG's net proved and proved
developed reserves at December 31 for each of the four years in
the period ended December 31, 2004, and the changes in the net
proved reserves for each of the three years in the period then
ended as estimated by the engineering staff of EOG.
NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
United United
States Canada Trinidad Kingdom TOTAL
NET PROVED RESERVES
Natural Gas (Bcf)(1)
Net proved reserves at December 31, 2001 2,007.3 644.1 1,145.1 - 3,796.5
Revisions of previous estimates 9.4 4.7 (21.7) - (7.6)
Purchases in place 9.9 102.9 - - 112.8
Extensions, discoveries and other additions 217.0 83.9 232.4 - 533.3
Sales in place (0.8) (1.5) - - (2.3)
Production (236.6) (56.2) (49.3) - (342.1)
Net proved reserves at December 31, 2002 2,006.2 777.9 1,306.5 - 4,090.6
Revisions of previous estimates (24.9) (18.5) (74.9) - (118.3)
Purchases in place 43.9 361.0 - - 404.9
Extensions, discoveries and other additions 345.5 118.3 129.3 59.2 652.3
Sales in place (30.8) - - - (30.8)
Production (238.3) (60.2) (55.4) - (353.9)
Net proved reserves at December 31, 2003 2,101.6 1,178.5 1,305.5 59.2 4,644.8
Revisions of previous estimates (62.8) (26.8) 34.2 - (55.4)
Purchases in place 44.4 16.6 - - 61.0
Extensions, discoveries and other additions 537.8 208.0 37.9 - 783.7
Sales in place (1.3) (0.6) - - (1.9)
Production (237.2) (77.4) (68.2) (2.4) (385.2)
Net proved reserves at December 31, 2004 2,382.5 1,298.3 1,309.4 56.8 5,047.0
F-31
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
United United
States Canada Trinidad Kingdom TOTAL
Liquids (MBbl)(2)
Net proved reserves at December 31, 2001 52,383 6,652 13,099 - 72,134
Revisions of previous estimates 3,543 396 (572) - 3,367
Purchases in place 624 865 - - 1,489
Extensions, discoveries and other additions 14,763 279 3,041 - 18,083
Sales in place (33) - - - (33)
Production (7,925) (1,026) (874) - (9,825)
Net proved reserves at December 31, 2002 63,355 7,166 14,694 - 85,215
Revisions of previous estimates 1,487 214 (1,120) - 581
Purchases in place 738 1,379 - - 2,117
Extensions, discoveries and other additions 15,669 598 1,212 84 17,563
Sales in place (344) - - - (344)
Production (7,897) (1,091) (881) - (9,869)
Net proved reserves at December 31, 2003 73,008 8,266 13,905 84 95,263
Revisions of previous estimates 2,649 (116) 3,417 69 6,019
Purchases in place 157 1 - - 158
Extensions, discoveries and other additions 9,859 920 229 - 11,008
Sales in place (411) (14) - - (425)
Production (9,474) (1,290) (1,291) (9) (12,064)
Net proved reserves at December 31, 2004 75,788 7,767 16,260 144 99,959
Bcf Equivalent (Bcfe)(1)
Net proved reserves at December 31, 2001 2,321.6 684.0 1,223.7 - 4,229.3
Revisions of previous estimates 30.7 7.1 (25.1) - 12.7
Purchases in place 13.6 108.1 - - 121.7
Extensions, discoveries and other additions 305.6 85.6 250.6 - 641.8
Sales in place (1.0) (1.5) - - (2.5)
Production (284.2) (62.4) (54.5) - (401.1)
Net proved reserves at December 31, 2002 2,386.3 820.9 1,394.7 - 4,601.9
Revisions of previous estimates (15.9) (17.2) (81.7) - (114.8)
Purchases in place 48.3 369.3 - - 417.6
Extensions, discoveries and other additions 439.6 121.8 136.5 59.7 757.6
Sales in place (32.9) - - - (32.9)
Production (285.7) (66.7) (60.7) - (413.1)
Net proved reserves at December 31, 2003 2,539.7 1,228.1 1,388.8 59.7 5,216.3
Revisions of previous estimates (47.0) (27.5) 54.8 0.4 (19.3)
Purchases in place 45.4 16.6 - - 62.0
Extensions, discoveries and other additions 597.0 213.5 39.3 - 849.8
Sales in place (3.8) (0.7) - - (4.5)
Production (294.1) (85.1) (75.9) (2.5) (457.6)
Net proved reserves at December 31, 2004 2,837.2 1,344.9 1,407.0 57.6 5,646.7
F-32
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
United United
States Canada Trinidad Kingdom TOTAL
NET PROVED DEVELOPED RESERVES
Natural Gas (Bcf) (1)
December 31, 2001 1,588.4 587.6 620.6 - 2,796.6
December 31, 2002 1,658.7 683.3 555.2 - 2,897.2
December 31, 2003 1,749.3 889.2 429.9 - 3,068.4
December 31, 2004 1,855.7 1,070.1 760.9 56.8 3,743.5
Liquids (MBbl) (2)
December 31, 2001 41,205 6,532 8,435 - 56,172
December 31, 2002 47,476 7,045 7,135 - 61,656
December 31, 2003 56,321 7,995 5,229 - 69,545
December 31, 2004 60,478 7,414 10,874 144 78,910
Bcf Equivalents (Bcfe) (1)
December 31, 2001 1,835.7 626.8 671.1 - 3,133.6
December 31, 2002 1,943.6 725.5 598.0 - 3,267.1
December 31, 2003 2,087.3 937.2 461.2 - 3,485.7
December 31, 2004 2,218.5 1,114.7 826.2 57.6 4,217.0
(1) Billion cubic feet or billion cubic feet equivalent, as
applicable.
(2) Thousand barrels; includes crude oil, condensate and
natural gas liquids.
Capitalized Costs Relating to Oil and Gas Producing
Activities. The following table sets forth the capitalized costs
relating to EOG's natural gas and crude oil producing activities
at December 31 of the years indicated as follows:
2004 2003
Proved properties $ 9,307,422 $ 7,990,675
Unproved properties 291,854 198,387
Total 9,599,276 8,189,062
Accumulated depreciation, depletion
and amortization (4,497,673) (3,940,145)
Net capitalized costs $ 5,101,603 $ 4,248,917
Costs Incurred in Oil and Gas Property Acquisition,
Exploration and Development Activities. The acquisition,
exploration and development costs disclosed in the following
tables are in accordance with definitions in SFAS No. 19 -
"Financial Accounting and Reporting by Oil and Gas Producing
Companies" and SFAS No. 143 - "Accounting for Asset Retirement
Obligations."
Acquisition costs include costs incurred to purchase, lease,
or otherwise acquire property.
Exploration costs include additions to exploration wells
including those in progress and exploration expenses.
F-33
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Development costs include additions to production facilities and
equipment and additions to development wells including those in
progress.
The following tables set forth costs incurred related to EOG's
oil and gas activities for the years ended December 31:
United United
States Canada Trinidad Kingdom Other TOTAL
2004
Acquisition Costs of Properties
Unproved $ 129,230 $ 13,490 $ 74 $ - $ - $ 142,794
Proved 47,653 4,587 - - - 52,240
Subtotal 176,883 18,077 74 - - 195,034
Exploration Costs 212,324 27,771 35,227 27,818 3,443 306,583
Development Costs 660,799 270,435 46,864 30,910 - 1,009,008
Subtotal 1,050,006 316,283 82,165 58,728 3,443 1,510,625
Asset Retirement Costs(1) 5,644 6,610 1,754 2,223 - 16,231
Deferred Income Tax on Acquired
Properties - (16,834) - - - (16,834)
Total $1,055,650 $306,059 $83,919 $60,951 $3,443 $1,510,022
2003
Acquisition Costs of Properties
Unproved $ 43,890 $ 14,536 $ 172 $ - $ - $ 58,598
Proved 18,347 386,532 - - - 404,879
Subtotal 62,237 401,068 172 - - 463,477
Exploration Costs 145,104 15,429 20,517 20,958 4,664 206,672
Development Costs 480,257 145,539 23,140 2,812 - 651,748
Subtotal 687,598 562,036 43,829 23,770 4,664 1,321,897
Asset Retirement Costs(1) 8,167 3,552 - - - 11,719
Total $ 695,765 $565,588 $43,829 $23,770 $4,664 $1,333,616
2002
Acquisition Costs of Properties
Unproved $ 28,232 $ 4,754 $ 5,629 $ - $ - $ 38,615
Proved 22,589 48,487 - - - 71,076
Subtotal 50,821 53,241 5,629 - - 109,691
Exploration Costs 120,058 25,866 18,117 - 2,384 166,425
Development Costs 423,436 107,952 13,600 - - 544,988
Subtotal 594,315 187,059 37,346 - 2,384 821,104
Deferred Income Tax on Acquired
Properties - 14,938 - - - 14,938
Total(2) $ 594,315 $201,997 $37,346 $ - $2,384 $ 836,042
(1) The Asset Retirement Costs for the United States are netted with $1
million net gains recognized upon settlement of asset retirement
obligations for each of 2004 and 2003. Asset Retirement Costs for
2003 do not include the cumulative effect of adoption of SFAS No.
143 - "Accounting for Asset Retirement Obligations" on January 1,
2003.
(2) Pro forma total costs incurred for 2002 are not presented as the
pro forma application of SFAS No. 143 to the prior period would not
result in pro forma total expenditures materially different from
the actual amount reported.
F-34
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Results of Operations for Oil and Gas Producing Activities(1).
The following tables set forth results of operations for oil and gas
producing activities for the years ended December 31:
United United
States Canada Trinidad Kingdom Other(2) TOTAL
2004
Natural Gas, Crude Oil
and Condensate Revenues $1,687,646 $448,346 $153,377 $ 12,972 $ - $2,302,341
Other, Net 2,128 205 - - - 2,333
Total 1,689,774 448,551 153,377 12,972 - 2,304,674
Exploration Expenses 71,823 10,264 7,109 4,745 - 93,941
Dry Hole Expenses 45,164 11,447 15,851 19,680 - 92,142
Production Costs 294,338 83,527 14,670 1,790 - 394,325
Impairments 68,309 13,221 - - - 81,530
Depreciation, Depletion and Amortization 382,718 99,879 20,022 1,784 - 504,403
Income (Loss) Before Income Taxes 827,422 230,213 95,725 (15,027) - 1,138,333
Income Tax Provision (Benefit) 295,063 75,146 33,953 (7,230) - 396,932
Results of Operations $ 532,359 $155,067 $ 61,772 $ (7,797) $ - $ 741,401
2003
Natural Gas, Crude Oil
and Condensate Revenues $1,410,946 $309,336 $100,112 $ - $ - $1,820,394
Other, Net 4,613 82 - - - 4,695
Total 1,415,559 309,418 100,112 - - 1,825,089
Exploration Expenses 65,885 5,726 3,997 739 11 76,358
Dry Hole Expenses 20,706 4,139 7,890 8,421 - 41,156
Production Costs 219,447 58,249 11,363 51 2 289,112
Impairments 81,661 7,473 - - (1) 89,133
Depreciation, Depletion and Amortization 359,439 66,334 16,070 - - 441,843
Income (Loss) Before Income Taxes 668,421 167,497 60,792 (9,211) (12) 887,487
Income Tax Provision (Benefit) 239,534 61,928 24,661 (3,673) (5) 322,445
Results of Operations $ 428,887 $105,569 $ 36,131 $ (5,538) $ (7) $ 565,042
2002
Natural Gas, Crude Oil
and Condensate Revenues $ 891,991 $170,875 $ 79,551 $ - $ 21 $1,142,438
Other, Net 2,521 (1,769) - - - 752
Total 894,512 169,106 79,551 - 21 1,143,190
Exploration Expenses 52,830 5,529 1,656 152 61 60,228
Dry Hole Expenses 26,107 20,642 - - - 46,749
Production Costs 186,041 48,261 9,977 64 7 244,350
Impairments 65,813 2,619 - - (2) 68,430
Depreciation, Depletion and Amortization 334,318 49,622 14,085 - 11 398,036
Income (Loss) Before Income Taxes 229,403 42,433 53,833 (216) (56) 325,397
Income Tax Provision (Benefit) 82,136 10,319 23,971 (70) (20) 116,336
Results of Operations $ 147,267 $ 32,114 $ 29,862 $ (146) $ (36) $ 209,061
(1) Excludes gains or losses on mark-to-market commodity
derivative contracts, interest charges and general corporate
expenses for each of the three years in the period ended
December 31, 2004.
(2) Other includes other international operations.
F-35
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves. The following information has been
developed utilizing procedures prescribed by SFAS No. 69 and based on
crude oil and natural gas reserve and production volumes estimated by
the engineering staff of EOG. It may be useful for certain comparison
purposes, but should not be solely relied upon in evaluating EOG or
its performance. Further, information contained in the following
table should not be considered as representative of realistic
assessments of future cash flows, nor should the Standardized Measure
of Discounted Future Net Cash Flows be viewed as representative of the
current value of EOG.
The future cash flows presented below are based on sales prices,
cost rates, and statutory income tax rates in existence as of the date
of the projections. It is expected that material revisions to some
estimates of crude oil and natural gas reserves may occur in the
future, development and production of the reserves may occur in
periods other than those assumed, and actual prices realized and costs
incurred may vary significantly from those used.
Management does not rely upon the following information in making
investment and operating decisions. Such decisions are based upon a
wide range of factors, including estimates of probable as well as
proved reserves, and varying price and cost assumptions considered
more representative of a range of possible economic conditions that
may be anticipated.
The following table sets forth the standardized measure of
discounted future net cash flows from projected production of EOG's
crude oil and natural gas reserves for the years ended December 31:
United United
States Canada Trinidad Kingdom TOTAL