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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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Form 10-K
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[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
[ ] 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)
1200 Smith Street, Suite 300, Houston, Texas 77002-7361
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: 713-651-7000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock, $.01 par value New York Stock Exchange
Preferred Share Purchase Rights New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None.
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past
90 days. Yes X No___.
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K [X].
Aggregate market value of the voting stock held by nonaffiliates
of the registrant, based on the closing sale price in the daily
composite list for transactions on the New York Stock Exchange on
March 12, 2001 was $47.50. As of March 12, 2001, there were
116,731,591 shares of the registrant's Common Stock, $.01 par value,
outstanding.
Documents incorporated by reference. Portions of the following
documents are incorporated by reference into the indicated parts of
this report: 2000 Annual Report to Stockholders - Part I, II and IV;
and Proxy Statement for the May 8, 2001 Annual Meeting of Shareholders
to be filed within 120 days after December 31, 2000 ("Proxy
Statement") - Part III.
TABLE OF CONTENTS
Page
PART I
Item 1. Business ..................................................... 1
General ..................................................... 1
Business Segments ........................................... 1
Exploration and Production .................................. 1
Marketing ................................................... 3
Wellhead Volumes and Prices,and Lease and Well Expenses ..... 4
Competition ................................................. 5
Regulation .................................................. 5
Relationship Between EOG and Enron Corp. .................... 7
Other Matters ............................................... 7
Current Executive Officers of the Registrant ................ 10
Item 2. Properties
Oil and Gas Exploration and Production Properties and
Reserves .................................................... 11
Item 3. Legal Proceedings ............................................ 14
Item 4. Submission of Matters to a Vote of Security Holders .......... 14
PART II
Item 5. Market for the Registrant's Common Equity and Related
Shareholder Matters ......................................... 14
Item 6. Selected Financial Data ...................................... 14
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations ................................... 14
Item 7A. Quantitative and Qualitative Disclosures About Market Risk ... 14
Item 8. Financial Statements and Supplementary Data .................. 15
Item 9. Disagreements on Accounting and Financial Disclosure.......... 15
PART III
Item 10. Directors and Executive Officers of the Registrant ........... 15
Item 11. Executive Compensation ....................................... 15
Item 12. Security Ownership of Certain Beneficial Owners
and Management .............................................. 15
Item 13. Certain Relationships and Related Transactions ............... 15
PART IV
Item 14. Financial Statements and Financial Statement Schedule,
Exhibits and Reports on Form 8-K ............................ 16
1
PART I
ITEM 1. Business
General
EOG Resources, Inc., a Delaware corporation organized in 1985
("EOG"), together with its subsidiaries, explores for, develops,
produces and markets natural gas and crude oil primarily in major
producing basins in the United States, as well as in Canada and
Trinidad and, to a lesser extent, selected other international areas.
EOG's principal producing areas are further described under
"Exploration and Production" below. At December 31, 2000, EOG's
estimated net proved natural gas reserves were 3,381 billion cubic
feet ("Bcf") and estimated net proved crude oil, condensate and
natural gas liquids reserves were 73 million barrels ("MMBbl") (see
"Supplemental Information to Consolidated Financial Statements" on
page 43 of EOG's 2000 Annual Report to Shareholders ("Annual Report to
Shareholders")). At such date, approximately 56% of EOG's reserves (on
a natural gas equivalent basis) was located in the United States, 15%
in Canada and 29% in Trinidad. As of December 31, 2000, EOG employed
approximately 850 persons, including foreign national employees.
EOG's business strategy is to maximize the rate of return on
investment of capital by controlling all operating and capital costs.
This strategy is intended to enhance the generation of cash flow and
earnings from each unit of production on a cost-effective basis. EOG
focuses its drilling activity toward natural gas deliverability in
addition to natural gas reserve replacement and to a lesser extent
crude oil exploitation. EOG focuses on the cost-effective utilization
of advances in technology associated with the gathering, processing
and interpretation of three-dimensional seismic data, developing
reservoir simulation models and drilling operations through the use of
new and/or improved drill bits, mud motors, mud additives, 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 selected tactical
acquisitions that result in additional economies of scale or land
positions with significant additional prospects. Achieving and
maintaining the lowest possible operating cost structure that is
consistent with prudent and safe operations are also important goals
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. Unless otherwise defined, all
references to wells are gross.
Business Segments
EOG's operations are all natural gas and crude oil exploration
and production related.
Exploration and Production
North America Operations
EOG's North American operations are organized into eight largely
autonomous business units or divisions, each focusing on one or more
basins, utilizing personnel who have developed experience and
expertise unique to the geology of the region, thereby leveraging
EOG's knowledge and cost structure into enhanced returns on invested
capital.
At December 31, 2000, 85% of EOG's proved United States reserves
(on a natural gas equivalent basis) was natural gas and 15% was crude
oil, condensate and natural gas liquids. A substantial portion of
EOG's United States natural gas reserves is in long-lived fields with
well-established production histories. EOG believes that opportunities
exist to increase production in many of these fields through continued
infill and other development drilling. The following is a summary of
significant developments during 2000 and certain drilling plans for
2001 for EOG's North American operating divisions.
Midland, Texas Division. The division's operations primarily
focus on the Southeastern New Mexico area, Val Verde Basin and Midland
Basin of West Texas. During 2000, the Midland Division increased
average daily production 31% from 111 million cubic feet equivalent
("MMcfe") per day in 1999 to 145 MMcfe per day in 2000. The division
drilled 67 gross wells in 2000. In early 2000, the division completed
a property trade with Burlington Resources Oil & Gas Company, which
added approximately 170,000 acres in the Permian Basin to the
division's net acreage. During 2000, three new exploration trends in
the Permian Basin were defined and over 200,000 acres of new leasehold
and seismic options were added in these areas. Plans for 2001 include
drilling over 90 wells in the Permian Basin and acquiring new
leasehold and new three-dimensional seismic in high potential trends.
2
Denver, Colorado Division. Key producing areas for the Denver
Division are the Big Piney - LaBarge Platform; Vernal -
Chapita/Natural Buttes; California - North Shafter; and Southwest
Wyoming - Cepo/Cedar Chest. Net production in the division averaged
133 million cubic feet ("MMcf") per day of natural gas and
5.7 thousand barrels ("MBbl") per day of crude oil, condensate, and
natural gas liquids in 2000. At December 31, 2000, natural gas
deliverability net to EOG was approximately 140 MMcf per day. During
2000, the division drilled twelve successful wells in North Shafter.
For 2001, the division plans to drill more wells in this area to
continue to gather information and ultimately determine the size and
potential of the oil field. During 2000, the division also integrated
and merged 520 square miles of three-dimensional seismic data,
covering the LaBarge Platform in Big Piney, Wyoming to identify and
develop both shallow and deep exploratory prospects. The division
plans to drill more than 200 wells during 2001.
Oklahoma City/Mid-Continent Division. The Mid-Continent
division's activities are concentrated in the Oklahoma and Texas
panhandles and in the deeper Anadarko Basin. Production from the
division is primarily from the Morrow, Toronto, and Council Grove
formations. During 2000, the division drilled 105 gross wells
replacing reserves by over 150%. During 2000, net production for the
division averaged approximately 70 MMcf per day of natural gas and
0.7 MBbl per day of crude oil and condensate. The division assembled
an additional 400,000 acres in the panhandle areas during 2000, and
plans to drill over 150 wells during 2001. EOG anticipates an active
Mid-Continent drilling program for several years.
Tyler, Texas Division. The Tyler Division increased average
daily production by 35% from 110 MMcfe per day in 1999 to 149 MMcfe
per day in 2000. Key areas of production for the division are the
Sabine Uplift Region, Upper Texas Coast and Mississippi Salt Basin.
During 2000, the division assimilated and exploited properties in the
Sabine Uplift Region which were acquired through a December 31, 1999
property trade. Net production for the division averaged approximately
113 MMcf per day of natural gas and 5.9 MBbl per day of crude oil,
condensate and natural gas liquids in 2000. Plans are to drill
another 50 wells in the Sabine Uplift areas, 20 wells in the Upper
Texas and Louisiana Coastal areas, and 30 wells in the Mississippi
Salt Basin during 2001. The division also plans to enter several new
exploratory areas, including the Bossier play in Louisiana.
Corpus Christi, Texas Division. The Corpus Christi Division's
activities are focused in the Lobo/Roleta, Frio and Wilcox producing
horizons in South Texas. The principal areas of activity are in the
Frio trend in Matagorda County and the Lobo/Roleta trend which occurs
primarily in Webb and Zapata Counties. Early in 2000, the division
made a discovery of over 100 billion cubic feet equivalent ("Bcfe") in
the Roleta trend. Two to three rigs drilled in the Roleta throughout
the year, drilling 39 gross wells with a success rate of approximately
90%. The division exceeded 100% reserve replacement while increasing
average daily production 21% from 152 MMcfe per day in 1999 to 184
MMcfe per day in 2000. The growth came from significant acreage that
was added in three trends: the Lobo and Wilcox in South Texas and the
Geopressured Frio along the Texas Gulf Coast. During 2000, the
division identified seven fields with upside potential: Zwebb - Webb
and Zapata Counties; El Huerfano - Zapata County; Pok-A-Dot - Zapata
County; Tiffany - Webb County; Rosita - Duval County; Bucks Bayou
North - Matagorda County; and Bay City Area - Matagorda County.
Pittsburgh, Pennsylvania Division. This newest EOG division was
added in late 2000 following the purchase of Somerset Oil & Gas
Company, Inc., a small independent oil and gas operator in Appalachia
with assets located primarily in Western Pennsylvania. The
acquisition added approximately 150 Bcf of reserves and 400 Devonian
drilling locations to EOG's portfolio. For 2001, the division plans
to assemble a substantial acreage position for exploration plays,
shoot additional two-dimensional seismic and drill at least four
exploratory wells. In addition, the division will focus on completing
its staffing to become a fully operational exploitation and
exploration unit.
Houston, Texas/Offshore Division. The Offshore Division focuses
on the Gulf of Mexico Shelf in Texas and Louisiana. Two fields, Eugene
Island 135 and Matagorda Island 623, account for a significant portion
of the division's production. During 2000, total daily production
averaged 91 MMcfe per day compared to 133 MMcfe per day in 1999 due
primarily to approximately 28 MMcf per day of natural gas production
that was traded on December 31, 1999. By year-end 2000, the division
had replaced, through successful drilling, the reduction in volumes
related to the property trade. During 2000, the division drilled or
participated in five wells that resulted in an increase in production,
including one exploratory discovery at Matagorda Island 704 which
added 5 MMcf per day.
Calgary, Canada Division. The Calgary Division is engaged in the
exploration for and the development, production and marketing of
natural gas, natural gas liquids and crude oil in Western Canada,
principally in the provinces of Alberta, Saskatchewan, and Manitoba.
The division conducts operations from offices in Calgary, Alberta.
During 2000, the division was again successful with its strategy of
drilling a large number of shallow gas wells in Western Canada, adding
both production and reserves. The division increased production from
134 MMcfe per day in 1999 to 146 MMcfe per day in 2000 and set a
division record by drilling 434 wells, most of which were shallow gas.
Key producing areas were Sandhills, Blackfoot and Grande Prairie
(Wapiti). Also in 2000, the division acquired a small Canadian
producer, Q Energy Limited, which had assets adjacent to the
division's existing Sandhills operation. For 2001, the division plans
to drill at least 375 shallow gas wells in the Sandhills and
3
Blackfoot areas and carry out further seismic and aeromagnetic surveys
on the Northwest Territories acreage where drilling is planned for
early 2002.
Outside North America Operations
EOG has producing operations offshore Trinidad and is evaluating
exploration, exploitation and development opportunities in selected
other international areas.
Trinidad. In November 1992, EOG was awarded a 95% working
interest concession in the South East Coast Consortium ("SECC") Block
offshore Trinidad, encompassing three undeveloped fields previously
held by three government-owned energy companies. The Kiskadee and Ibis
fields have since been developed, and the Oilbird field is anticipated
to be developed within the next several years. Existing surplus
processing and transportation capacity at the Pelican field facilities
owned and operated by Trinidad and Tobago government-owned companies
is being used to process and transport the production. Natural gas is
being sold into the local market under a take-or-pay agreement with
the National Gas Company of Trinidad and Tobago. In 2000, deliveries
net to EOG averaged 125 MMcf per day of natural gas and 2.6 MBbl per
day of crude oil and condensate.
In 1996, EOG 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 contract committed EOG to the
acquisition of three-dimensional seismic data and the drilling of
three wells. The first well, Osprey, was drilled in 1998 and was
successful, encountering over 400 feet of net pay. This is the largest
exploration discovery in EOG's history. During the fourth quarter of
1999, EOG drilled an unsuccessful exploration well, the Motmot, and in
the first quarter of 2000, the Tanager well was determined to be
unsuccessful. These wells fulfilled the drilling obligations on the
block. In 2000, EOG drilled the successful appraisal development OA2
well, which resulted in an increase of booked reserves by 71 Bcfe to a
field total of 746 Bcfe. At December 31, 2000, EOG held approximately
71,000 net undeveloped acres in Trinidad.
In January 2000, EOG signed a 15-year natural gas supply contract
for approximately 60 MMcf per day with the National Gas Company of
Trinidad and Tobago. This natural gas will supply a 1,850 metric ton
per day anhydrous ammonia plant that is to be constructed by Caribbean
Nitrogen Company Limited, a Trinidadian company in which EOG has a 16%
interest.
Other International. EOG continues to evaluate other selected
conventional natural gas and crude oil opportunities outside North
America primarily by pursuing exploitation opportunities in countries
where indigenous natural gas and crude oil reserves have been
identified.
Marketing
Wellhead Marketing. EOG's North America wellhead natural gas
production is currently being sold on the spot market and under
long-term natural gas contracts at market responsive prices. In many
instances, the long-term contract prices closely approximate the
prices received for natural gas being sold on the spot market.
Wellhead natural gas volumes from Trinidad are sold at prices that are
based on a fixed price schedule with annual escalations. Prior to the
Share Exchange (as described in "Relationship Between EOG and Enron
Corp." on page 7) and under terms of the production sharing contracts,
natural gas volumes in India were sold to a nominee of the Government
of India at a price linked to a basket of world market fuel oil
quotations with floor and ceiling limits.
Substantially all of EOG's wellhead crude oil and condensate is
sold under various terms and arrangements at market responsive prices.
Other Marketing. EOG Resources Marketing, Inc. ("EOGM"), a wholly
owned subsidiary of EOG, is a marketing company engaging in various
marketing activities. Both EOG and EOGM contract to provide, under
short and long-term agreements, natural gas to various purchasers and
then aggregate the necessary supplies for the sales with purchases
from various sources including third-party producers, marketing
companies, pipelines or from EOG's own production and arrange for any
necessary transportation to the points of delivery. In addition, EOGM
has purchased and constructed several small gas gathering systems in
order to facilitate its entry into the gas gathering business on a
limited basis. Both EOG and EOGM utilize other short and long-term
hedging and trading mechanisms including sales and purchases utilizing
NYMEX-related commodity market transactions from time to time. These
marketing activities have provided an effective balance in managing a
portion of EOG's exposure to commodity price risks for both natural
gas and crude oil and condensate wellhead prices. (See "Other Matters-
Risk Management").
4
Wellhead Volumes and Prices, and Lease and Well Expenses
The following table sets forth certain information regarding
EOG's wellhead volumes of and average prices for natural gas per
thousand cubic feet ("Mcf"), crude oil and condensate, and natural gas
liquids per barrel ("Bbl"), and average lease and well expenses per
thousand cubic feet equivalent ("Mcfe"-natural gas equivalents are
determined using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of
crude oil, condensate or natural gas liquids) delivered during each of
the three years in the period ended December 31, 2000. As a result of
the consensus of Emerging Issues Task Force Issue 00-10, "Accounting
for Shipping and Handling Fees and Costs," EOG reclassified all prior
periods to reflect certain transportation expenses incurred as lease
and well expenses, instead of deductions from revenues as previously
reported.
Year Ended December 31,
---------------------------
2000 1999 1998
------ ------ ------
Natural Gas Volumes (MMcf per day)
United States............................. 654 654 671(1)
Canada..................................... 129 115 105
Trinidad................................... 125 123 139
India(2)................................... - 46 56
----- ----- -----
Total.................................... 908 938 971
===== ===== =====
Crude Oil and Condensate Volumes (MBbl per day)
United States.............................. 22.8 14.4 14.0
Canada..................................... 2.1 2.6 2.6
Trinidad................................... 2.6 2.4 3.0
India(2)................................... - 4.1 5.1
----- ----- -----
Total.................................... 27.5 23.5 24.7
===== ===== =====
Natural Gas Liquids Volumes (MBbl per day)
United States.............................. 4.0 2.6 2.9
Canada..................................... 0.7 0.8 1.0
----- ----- -----
Total.................................... 4.7 3.4 3.9
===== ===== =====
Average Natural Gas Prices ($/Mcf)
United States.............................. $ 3.96 $ 2.20 $ 2.01(3)
Canada..................................... 3.33 1.88 1.48
Trinidad................................... 1.17 1.08 1.06
India(2)................................... - 2.09 2.57
Composite................................ 3.49 2.01 1.85
Average Crude Oil and Condensate Prices ($/Bbl)
United States.............................. $29.68 $18.55 $12.89
Canada..................................... 27.76 16.77 11.82
Trinidad................................... 30.14 16.21 12.26
India(2)................................... - 12.80 12.86
Composite................................ 29.57 17.12 12.69
Average Natural Gas Liquids Prices ($/Bbl)
United States.............................. $20.45 $13.41 $ 9.50
Canada..................................... 16.75 8.23 5.32
Composite................................ 19.87 12.24 8.38
Lease and Well Expenses ($/Mcfe)
United States.............................. $ .35 $ .33 $ .34
Canada..................................... .52 .46 .44
Trinidad................................... .16 .13 .12
India(2)................................... - .35 .34
Composite................................ .35 .33 .33
_______________________________________________________________________________
(1) Includes 48 MMcf per day delivered under the terms of a volumetric
production payment agreement effective October 1, 1992, as amended.
Delivery obligations were terminated in December 1998.
(2) See "Relationship Between EOG and Enron Corp." regarding the Share
Exchange Agreement on Page 7.
(3) Includes an average equivalent wellhead value of $1.88 per Mcf for the
volumes described in note (1).
5
Competition
EOG actively 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 producers
and suppliers, including competition from other world wide energy
supplies, such as natural gas from Canada.
Regulation
United States Regulation of Natural Gas and Crude Oil Production.
Natural gas and crude oil production operations are subject to various
types of regulation, including regulation in the United States by
state and federal agencies.
United States legislation affecting the oil and gas industry is
under constant review for amendment or expansion. Also, numerous
departments and agencies, both federal and state, are authorized by
statute to issue and have issued rules and regulations which, among
other things, require permits for the drilling of wells, regulate the
spacing of wells, prevent the waste of natural gas and liquid
hydrocarbon resources through proration and restrictions on flaring,
require drilling bonds and regulate environmental and safety matters.
The regulatory burden on the oil and gas industry increases its cost
of doing business and, consequently, affects its profitability.
A substantial portion of EOG's oil and gas leases in the Big
Piney area and in the Gulf of Mexico, as well as some in other areas,
are granted by the federal government and administered by the Bureau
of Land Management (the "BLM") and the Minerals Management Service
(the "MMS"), both federal agencies. Operations conducted by EOG on
federal oil and gas leases must comply with numerous statutory and
regulatory restrictions concerning the above and other matters.
Certain operations must be conducted pursuant to appropriate permits
issued by the BLM and the MMS.
BLM and MMS leases contain relatively standardized terms
requiring compliance with detailed regulations and, in the case of
offshore leases, orders pursuant to the Outer Continental Shelf Lands
Act (which are subject to change by the MMS). Such offshore operations
are subject to numerous regulatory requirements, including the need
for prior MMS approval for exploration, development, and production
plans, stringent engineering and construction specifications
applicable to offshore production facilities, regulations restricting
the flaring or venting of production, and regulations governing the
plugging and abandonment of offshore wells and the removal of all
production facilities. Under certain circumstances, the MMS may
require operations on federal leases to be suspended or terminated.
Any such suspension or termination could adversely affect EOG's
interests.
The MMS amended the regulations governing the calculation of
royalties and the valuation of crude oil produced from federal leases,
effective June 1, 2000. The new rules modified the valuation
procedures for both arm's-length and non-arm's-length crude oil
transactions to decrease reliance on oil posted prices and assign a
value to crude oil that, in the opinion of MMS, better reflects its
market value. Two industry trade associations have sought judicial
review of the new rules in federal district court. EOG cannot predict
what effect the outcome of the litigation will be or what effect, if
any, it will have on EOG's operations.
In March 2000, a federal district court vacated MMS regulations
which sought to clarify the types of costs that are deductible
transportation costs for purposes of royalty valuation of production
sold off the lease. In particular, MMS disallowed deduction of costs
associated with marketer fees, cash out and other pipeline imbalance
penalties, or long-term storage fees. The United States has appealed
the district court ruling. EOG cannot predict what the outcome of the
appeal will be or what effect, if any, it will have on EOG's
operations.
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 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA").
These statutes are administered by the Federal Energy Regulatory
Commission (the "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 the FERC might prospectively impose more
restrictive conditions on such sales.
6
Since 1985, the FERC has endeavored to enhance competition in
natural gas markets by making natural gas transportation more
accessible to natural gas buyers and sellers on an open and
nondiscriminatory basis. These efforts culminated in Order No. 636 and
various rehearing orders ("Order No. 636"), which mandate a
fundamental restructuring of interstate natural gas pipeline sales and
transportation services, including the "unbundling" by interstate
natural gas pipelines of the sales, transportation, storage, and other
components of their service, and to separately state the rates for
each unbundled service. Order No. 636 does not directly regulate EOG's
activities, but has an indirect effect because of its broad scope.
Order No. 636 has ended interstate pipelines' traditional role as
wholesalers of natural gas, and substantially increased competition in
natural gas markets. In spite of this uncertainty, Order No. 636 may
enhance EOG's ability to market and transport its natural gas
production, although it may also subject EOG to more restrictive
pipeline imbalance tolerances and greater penalties for violation of
such tolerances.
EOG owns, directly or indirectly, certain natural gas pipelines
that it believes meet the traditional tests the FERC has used to
establish a pipeline's status as a gatherer not subject to FERC
jurisdiction under the NGA. State regulation of gathering facilities
generally includes various safety, environmental, and in some
circumstances, nondiscriminatory take requirements, but does not
generally entail rate regulation. Natural gas gathering may receive
greater regulatory scrutiny at both the state and federal levels as a
result of pipeline restructuring under Order No. 636. For example, the
Texas Railroad Commission has approved changes to its regulations
governing transportation and gathering services performed by
intrastate pipelines and gatherers, which prohibit such entities from
unduly discriminating in favor of their affiliates. EOG's gathering
operations could be adversely affected should they be subject in the
future to the application of state or federal regulation of rates and
services.
EOG's natural gas gathering operations also may be or become
subject to safety and operational regulations relating to the design,
installation, testing, construction, operation, replacement, and
management of facilities. Additional rules and legislation pertaining
to these matters are considered or adopted from time to time. EOG
cannot predict what effect, if any, such legislation might have on its
operations, but the industry could be required to incur additional
capital expenditures and increased costs depending on future
legislative and regulatory changes.
The FERC recently began a broad review of its transportation
regulations, including how they operate in conjunction with state
proposals for retail gas marketing restructuring, whether to eliminate
cost-of-service rates for short-term transportation, whether to
allocate all short-term capacity on the basis of competitive auctions,
and whether changes to its long-term transportation policies may also
be appropriate to alleviate a market bias toward short-term contracts.
This review culminated in part with the FERC's issuance of Order
No. 637 on February 9, 2000.
Order No. 637 revises the FERC's current regulatory framework for
purposes of improving the efficiency of the market and providing
captive pipeline customers with the opportunity to reduce their cost
of holding long-term pipeline capacity while continuing to protect
against the exercise of market power. Order No. 637 revises FERC
pricing policy by waiving price ceilings for short-term released
capacity for a two year period and permitting pipelines to file for
peak/off-peak and term differentiated rate structures. Order No. 637
does not, however, require the allocation of all short-term capacity
on the basis of competitive auctions--as had been proposed by the
FERC. Order No. 637 adopts changes in regulations relating to
scheduling procedures, capacity segmentation and pipeline penalties to
improve the competitiveness and efficiency of the interstate pipeline
grid. It also narrows pipeline customers' right of first refusal to
remove economic biases in the current rule, while still protecting
captive customers' ability to resubscribe to long-term capacity.
Finally, it improves the FERC's reporting requirements to provide more
transparent pricing information and permit more effective monitoring
of the market. Appeals of Order No. 637 are pending court review.
EOG cannot predict what the outcome of that review will be or what
effect it will have on EOG's operations.
While Order No. 637, and any subsequent FERC action will affect
EOG only indirectly, the Order and related inquiries are intended to
further enhance competition in natural gas markets, while maintaining
adequate consumer protections.
EOG cannot predict the effect that any of the aforementioned
orders or the challenges to such orders will ultimately have on EOG's
operations. Additional proposals and proceedings that might affect the
natural gas industry are considered from time to time by Congress, the
FERC and the courts. EOG cannot predict when or whether any such
proposals or proceedings may become effective. It should also be noted
that the natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less regulated
approach currently being pursued by the FERC will continue
indefinitely.
Environmental Regulation. 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.
7
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 each environmental law and regulation, but inasmuch as such laws
and regulations are frequently changed, EOG is unable to predict the
ultimate cost of compliance.
Canadian Regulation. In Canada, the petroleum industry is
subject to extensive controls and operates under various provincial
and federal legislation and regulations governing land tenure,
royalties, taxes, production rates, operational standards,
environmental protection, health and safety, exports and other
matters. EOG operates within this regulatory framework and continues
to monitor and evaluate the impact of the regulatory regime when
determining parameters for engaging in oil and gas activities and
investments in Canada. The price of natural gas and crude oil in
Canada has been deregulated and is determined by market conditions and
negotiations between buyers and sellers in a North American market
place. The North American Free Trade Agreement supports the on-going
cross-border commercial transactions of the natural gas and crude oil
business.
Various matters relating to the transportation and export of
natural gas continue to be subject to regulation by provincial
agencies and federally, by the National Energy Board; however, the
North American Free Trade Agreement may have reduced the risk of
altering existing cross-border commercial transactions through the
assurance of fair implementation of regulatory changes, minimal
disruption of contractual arrangements and the prohibition of
discriminatory order restrictions and export taxes.
Canadian governmental regulations may have a material effect on
the economic parameters for engaging in oil and gas activities in
Canada and may have a material effect on the advisability of
investments in Canadian oil and gas drilling activities. EOG is
monitoring political, regulatory and economic developments in Canada.
Other International Regulation. EOG's exploration and production
operations outside North America are subject to various types of
regulations imposed by the respective governments of the countries in
which EOG's operations are conducted, and may affect EOG's operations
and costs within that country. EOG currently has operations offshore
Trinidad.
Relationship Between EOG and Enron Corp.
On August 16, 1999, EOG and Enron Corp. closed the Share Exchange
Agreement in which EOG acquired 62,270,000 shares of EOG's common
stock out of 82,270,000 shares then owned by Enron Corp., and in
return Enron Corp. received all of the stock of EOGI-India, Inc., a
subsidiary of EOG ("Share Exchange"). EOGI-India, Inc. owned, through
subsidiaries, all of EOG's assets and operations in India and China,
and had received from EOG an indirect $600 million cash capital
contribution, plus certain intercompany receivables, prior to the
Share Exchange. EOG recognized a $575 million tax-free gain on the
Share Exchange based on the fair value of the shares received, net of
transaction fees of $14 million. On the closing of the Share
Exchange, all of Enron Corp.'s officers and directors then serving as
Company directors resigned from EOG's board. Following the closing of
the Share Exchange, Enron Corp. sold 8,500,000 shares of Company stock
pursuant to a public offering in which EOG also sold 27,000,000 shares
of its common stock. Subsequent to the closing of the Share Exchange
and the common stock offering, Enron Corp. sold securities that are
mandatorily exchangeable at maturity into a minimum of 9,746,250 EOG
shares and a maximum of 11,500,000 EOG shares, the latter being an
amount equal to all of Enron Corp.'s remaining shares in EOG. The
maturity date for these securities is July 31, 2002.
EOG and Enron Corp. have in the past entered into material
transactions and agreements incident to their respective businesses.
Such transactions and agreements have related to, among other things,
the purchase and sale of natural gas and crude oil, hedging and
trading activities and the provision of certain corporate services.
Many of these agreements are still in place, and EOG and Enron Corp.
may enter into similar types of transactions and agreements in the
future. EOG intends that the terms of any future transactions and
agreements with Enron Corp. will be at least as favorable to EOG as
could be obtained from other third parties.
Other Matters
Energy Prices. Since EOG is primarily a natural gas company, it
is more significantly impacted by changes in natural gas prices than
in the prices for crude oil, condensate or natural gas liquids.
Average North America wellhead natural gas prices have fluctuated, at
times rather dramatically, during the last three years. These
fluctuations resulted in a 15% decrease in the average wellhead
natural gas price for North America received by EOG from 1997 to 1998,
an increase of 11% from 1998 to 1999, and an increase of 80% from 1999
to 2000. Wellhead natural gas volumes from Trinidad are sold at prices
that are based on a fixed schedule with annual escalations. 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 the consumers, EOG is unable to predict what changes may
occur in natural gas prices in the future.
8
Substantially all of EOG's wellhead crude oil and condensate is
sold under various terms and arrangements at market responsive prices.
Crude oil and condensate prices also have fluctuated during the last
three years. Due to the many uncertainties associated with the world
political environment, the availabilities of other world wide energy
supplies and the relative competitive relationships of the various
energy sources in the view of the consumers, EOG is unable to predict
what changes may occur in crude oil and condensate prices in the
future.
Risk Management. EOG engages in price risk management activities
from time to time primarily for non-trading and to a lesser extent for
trading purposes. Derivative financial instruments (primarily price
swaps and costless collars) are utilized for non-trading purposes to
hedge the impact of market fluctuations of natural gas and crude oil
market prices on net income and cash flow.
At December 31, 2000, EOG had outstanding swap contracts covering
notional volumes of approximately 0.7 million barrels ("MMBbl") of
crude oil and condensate for 2001. EOG elected not to designate these
crude oil swap contracts as a hedge of its 2001 crude oil production,
and accordingly, is accounting for these swap contracts under mark-to-
market accounting. At December 31, 2000, the fair value of these swap
contracts was $0.4 million.
In February 2001, EOG entered into price swap agreements covering
notional volumes of 0.6 MMBbl of oil for the period March 2001 to
December 2001 at an average price of $28.09 per Bbl and notional
volumes of 100,000 million British thermal units of natural gas per
day (MMBtu/d) for the months of April and May 2001 at an average price
of $5.16 per MMBtu. EOG will account for these swap contracts under
mark-to-market accounting.
In February 2001, a Canadian subsidiary of EOG priced certain
natural gas physical agreements for approximately 47,000 MMBtu/d for
the months of April and May 2001 at an average NYMEX price of US$5.16
per MMBtu less applicable basis (location) adjustments.
At December 31, 2000, based on EOG's tax position and the portion
of EOG's anticipated natural gas volumes for 2001 for which prices
have not, in effect, been hedged using NYMEX-related commodity market
transactions and long-term marketing contracts, EOG's price
sensitivity for each $.10 per Mcf change in average wellhead natural
gas prices is $19 million (or $0.16 per share) for net income and $19
million for current operating cash flow. EOG is not impacted as
significantly by changing crude oil prices for those volumes not
otherwise hedged. EOG's price sensitivity for each $1.00 per barrel
change in average wellhead crude oil prices is $6 million (or $0.05
per share) for net income and $6 million for current operating cash
flow.
Tight Gas Sand Tax Credits(Section 29) and Severance Tax Exemption.
United States federal tax law provides a tax credit for production of
certain fuels produced from nonconventional sources (including
natural gas produced from tight formations), subject to a number of
limitations. Fuels qualifying for the credit must be produced
from a well drilled or a facility placed in service after
November 5, 1990 and before January 1, 1993, and must be sold before
January 1, 2003.
The credit, which is currently approximately $.52 per million
British thermal units of natural gas, is computed by reference to the
price of crude oil, and is phased out as the price of crude oil
exceeds $23.50 in 1980 dollars (adjusted for inflation) with complete
phaseout if such price exceeds $29.50 in 1980 dollars (similarly
adjusted). Under this formula, the commencement of phaseout would be
triggered if the average price for crude oil rose above approximately
$47 per barrel in current dollars. Significant benefits from the tax
credit have accrued and continue to accrue to EOG since a portion (and
in some cases a substantial portion) of EOG's natural gas production
from new wells drilled after November 5, 1990, and before January 1,
1993, on EOG's leases in several of EOG's significant producing areas
qualify for this tax credit. In 1999 and 2000, EOG entered into
arrangements with a third party whereby certain Section 29 credits
were sold by EOG to the third party, and payments for such credits
will be received on an as-generated basis.
Natural gas production from wells spudded or completed after May
24, 1989 and before September 1, 1996 in tight formations in Texas
qualifies for a ten-year exemption from severance taxes, subject to
certain limitations, during the period beginning September 1, 1991 and
ending August 31, 2001. In addition, natural gas production from
qualifying wells spudded or completed after August 31, 1996 and before
September 1, 2010 is entitled to use of a reduced severance tax rate.
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.
Other. All of EOG's natural gas and crude oil activities are
subject to the risks normally incident to the exploration for and
development and production of natural gas and crude oil, including
blowouts, cratering and fires, each of which could result in damage to
life and 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,
9
insurance is maintained by EOG against some, but not all, of the risks.
Losses and liabilities arising from such events could reduce revenues
and increase costs to EOG to the extent not covered by insurance.
EOG's operations outside of North America are subject to certain
risks, including expropriation of assets, risks of increases in taxes
and government royalties, renegotiation of contracts with foreign
governments, political instability, payment delays, limits on
allowable levels of production and currency exchange and repatriation
losses, as well as changes in laws, regulations and policies governing
operations of foreign companies generally.
10
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............ 54 Chairman of the Board and Chief
Executive Officer; Director
Edmund P. Segner, III..... 47 President and Chief of Staff;
Director
Loren M. Leiker.......... 47 Executive Vice President,
Exploration and Development
Gary L. Thomas.......... 51 Executive Vice President,
North America Operations
Barry Hunsaker, Jr...... 50 Senior Vice President and
General Counsel
Timothy K. Driggers...... 39 Vice President, Accounting and
Land Administration
David R. Looney........... 44 Vice President, Finance
Mark G. Papa was elected Chairman of the Board and Chief
Executive Officer in August 1999, President and Chief Executive
Officer and Director of EOG 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. From May 1986 through January 1994, Mr. Papa served as
Senior Vice President--Operations. 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. Mr. Segner was a director of EOG from
January 1997 to October 1997. Prior to joining EOG, Mr. Segner was
Executive Vice President and Chief of Staff of Enron Corp.
Loren M. Leiker joined EOG in April 1989 as Senior Vice
President, Exploration. He was elected Executive Vice President,
Exploration in May 1998 and Executive Vice President, Exploration and
Development in February 2000.
Gary L. Thomas was elected Executive Vice President, North
America Operations in May 1998. He was previously Senior Vice
President and General Manager of EOG's Midland Division. 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. Prior to joining EOG,
Mr. Hunsaker was a partner in the law firm of Vinson & Elkins L.L.P.
Timothy K. Driggers was elected Vice President and Controller of
EOG in October 1999 and was subsequently named Vice President,
Accounting and Land Administration. He was Assistant Controller of
Enron Corp. from October 1998 through September 1999. Mr. Driggers
held management positions in the Financial Planning and Reporting
Department of EOG from August 1995 through September 1998. Prior to
joining EOG, Mr. Driggers was a Senior Audit Manager at Arthur
Andersen LLP.
David R. Looney was elected Vice President, Finance of EOG in
August 1999. He joined EOG as Assistant Treasurer in February 1998.
Prior to joining EOG, Mr. Looney spent over 17 years in the commercial
banking industry, specializing in capital formation for companies
involved in the energy industry.
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 first meeting following the
Annual Meeting of Shareholders, each to hold office until the
corresponding meeting of the Board in the next year or until a
successor shall have been elected, appointed or shall have qualified.
11
ITEM 2. Properties
Oil and Gas Exploration and Production Properties and Reserves
Reserve Information. For estimates of EOG's net proved and
proved developed reserves of natural gas and liquids, including crude
oil, condensate and natural gas liquids, see "Supplemental Information
to Consolidated Financial Statements" in the Annual Report to
Shareholders.
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. Accordingly, reserve
estimates are often different from the quantities ultimately
recovered. The meaningfulness of such estimates is highly dependent
upon the accuracy of the assumptions upon which they were based.
In general, the volume of production from oil and gas properties
owned by EOG 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.
12
Acreage. The following table summarizes EOG's developed and
undeveloped acreage at December 31, 2000. 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..................... 466,616 309,737 684,492 520,044 1,151,108 829,781
Wyoming................... 288,597 175,764 564,256 365,041 852,853 540,805
Offshore Gulf of Mexico... 290,890 80,827 382,525 249,452 673,415 330,279
Montana................... 119,566 560 268,313 209,702 387,879 210,262
New Mexico................ 112,863 55,799 222,803 121,575 335,666 177,374
Utah...................... 217,087 76,287 142,181 83,642 359,268 159,929
Pennsylvania.............. 67,637 67,637 82,500 82,500 150,137 150,137
Oklahoma.................. 120,012 66,442 147,082 79,650 267,094 146,092
California................ 2,801 1,549 90,741 81,012 93,542 82,561
South Dakota.............. - - 52,238 52,238 52,238 52,238
Kansas.................... 12,412 10,596 37,045 32,836 49,457 43,432
Mississippi............... 8,222 7,965 37,684 34,595 45,906 42,560
Colorado.................. 24,884 1,425 100,227 40,943 125,111 42,368
Louisiana................. 11,517 9,446 26,115 16,499 37,632 25,945
New York.................. - - 28,260 24,258 28,260 24,258
North Dakota.............. 3,170 976 3,490 3,227 6,660 4,203
Arkansas.................. 7,922 1,095 2,010 639 9,932 1,734
Other..................... 240 - 211 193 451 193
--------- --------- --------- --------- --------- ---------
Total United States...... 1,754,436 866,105 2,872,173 1,998,046 4,626,609 2,864,151
Canada
Saskatchewan.............. 354,506 321,788 205,567 196,248 560,073 518,036
Alberta................... 447,522 312,547 346,124 288,878 793,646 601,425
Manitoba.................. 12,103 10,269 21,849 20,649 33,952 30,918
British Columbia.......... 656 164 14,768 8,909 15,424 9,073
Northwest Territories..... - - 605,053 189,089 605,053 189,089
--------- --------- --------- --------- --------- ---------
Total Canada............. 814,787 644,768 1,193,361 703,773 2,008,148 1,348,541
Other International
Trinidad.................. 22,856 22,346 74,551 70,823 97,407 93,169
France.................... - - 168,032 168,032 168,032 168,032
Ghana..................... - - 1,899,743 474,936 1,899,743 474,936
--------- --------- --------- --------- --------- ---------
Total Other International 22,856 22,346 2,142,326 713,791 2,165,182 736,137
--------- --------- --------- --------- --------- ---------
Total................... 2,592,079 1,533,219 6,207,860 3,415,610 8,799,939 4,948,829
========= ========= ========= ========= ========= =========
Producing Well Summary. The following table reflects EOG's
ownership in gas and oil wells located in Texas, the Gulf of Mexico,
Oklahoma, New Mexico, Utah, Pennsylvania, Wyoming, and various other
states, Canada and Trinidad at December 31, 2000. Gross gas and oil
wells include 233 with multiple completions.
Productive Wells
----------------
Gross Net
------- -------
Gas ....................................... 7,921 5,881
Oil ....................................... 1,411 1,145
------ ------
Total.................................... 9,332 7,026
====== ======
13
Drilling and Acquisition Activities. During the years ended
December 31, 2000, 1999, and 1998 EOG spent approximately $687
million, $461 million and $769 million, respectively, for exploratory
and development drilling and acquisition of leases and producing
properties. EOG drilled, participated in the drilling of or acquired
wells as set out in the table below for the periods indicated:
Year Ended December 31,
----------------------------------------------------
2000 1999 1998
---------------- ---------------- ---------------
Gross Net Gross Net Gross Net
------- -------- ------- ------- ------- ------
Development Wells Completed
North America
Gas............................... 743 611.93 613 515.64 478 402.80
Oil............................... 93 83.46 53 52.02 38 34.98
Dry............................... 51 44.03 68 58.43 79 62.16
----- -------- ----- ------ ----- ------
Total........................... 887 739.42 734 626.09 595 499.94
Outside North America
Gas............................... - - 6 2.00 - -
Oil............................... - - 6 1.90 21 6.30
Dry............................... - - - - - -
----- -------- ----- ------ ----- ------
Total........................... - - 12 3.90 21 6.30
----- -------- ----- ------ ----- ------
Total Development................ 887 739.42 746 629.99 616 506.24
----- -------- ----- ------ ----- ------
Exploratory Wells Completed
North America
Gas............................... 19 11.85 21 14.57 5 4.40
Oil............................... 4 4.00 2 2.00 6 5.50
Dry............................... 26 20.00 19 14.55 22 15.70
----- -------- ----- ------ ----- ------
Total........................... 49 35.85 42 31.12 33 25.60
Outside North America
Gas............................... - - 1 0.30 1 1.00
Oil............................... - - - - 1 .90
Dry............................... 1 1.00 1 1.00 - -
----- -------- ----- ------ ----- ------
Total........................... 1 1.00 2 1.30 2 1.90
----- -------- ----- ------ ----- ------
Total Exploratory................. 50 36.85 44 32.42 35 27.50
----- -------- ----- ------ ----- ------
Total........................... 937 776.27 790 662.41 651 533.74
Wells in Progress at end of period.. 46 40.19 25 21.34 28 15.73
----- -------- ----- ------ ----- ------
Total............................. 983 816.46 815 683.75 679 549.47
===== ======== ===== ====== ===== ======
Wells Acquired*
Gas............................... 1,315 985.37 576 380.01 333 317.23
Oil............................... 168 120.70 422 402.34 - 1.70
----- -------- ----- ------ ----- ------
Total.......................... 1,483 1,106.07 998 782.35 333 318.93
===== ======== ===== ====== ===== ======
__________________
*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.
14
ITEM 3. Legal Proceedings
The information required by this item is incorporated by
reference from the Contingencies section of Note 7 of Notes to
Consolidated Financial Statements included in the Annual Report to
Shareholders.
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 2000.
PART II
ITEM 5. Market for the Registrant's Common Equity and Related
Shareholder Matters
Information required by this item is incorporated by reference
from page 53 of the Annual Report to Shareholders.
ITEM 6. Selected Financial Data
Information required by this item is incorporated by reference
from page 52 of the Annual Report to Shareholders.
ITEM 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Information required by this item is incorporated by reference
from pages 18 through 23 of the Annual Report to Shareholders.
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 or the
ability to increase reserves or 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: timing and extent of changes in
commodity prices for crude oil, natural gas and related products and
interest rates; extent of EOG's success in discovering, developing,
marketing and producing reserves and in acquiring oil and gas
properties; political developments around the world; and financial
market conditions.
In light of these risks, uncertainties and assumptions, the
events anticipated by EOG's forward-looking statements might not
occur. EOG undertakes no obligations to update or revise its
forward-looking statements, whether as a result of new information,
future events or otherwise.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk
EOG's exposure to interest rate risk and commodity price risk is
discussed respectively in the Financing and Outlook sections of the
"Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Capital Resources and Liquidity," which is
incorporated by reference from pages page 22 of the Annual Report to
Shareholders. EOG's exposure to foreign currency exchange rate risks
and other market risks is insignificant.
15
ITEM 8. Financial Statements and Supplementary Data
Information required by this item is incorporated by reference from
portions of the Annual Report to Shareholders as indicated:
Cross Reference to Applicable Sections
Of Annual Report to Shareholders Page
-------------------------------------- ----
Report of Independent Public Accountants.......................... 24
Consolidated Financial Statements................................. 26
Notes to Consolidated Financial Statements........................ 30
Supplemental Information to Consolidated Financial Statements..... 43
Unaudited Quarterly Financial Information......................... 51
ITEM 9. Disagreements on Accounting and Financial Disclosure
None.
PART III
ITEM 10. 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, 2000, under the caption entitled "Election
of Directors."
See list of "Current Executive Officers of the Registrant" in
Part I located elsewhere herein.
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, 2000, under the caption "Compensation of Directors and
Executive Officers."
ITEM 12. Security Ownership of Certain Beneficial Owners and Management
The information required by this Item is incorporated by
reference from the Proxy Statement to be filed within 120 days after
December 31, 2000, under the captions "Election of Directors" and
"Compensation of Directors and Executive Officers."
ITEM 13. Certain Relationships and Related Transactions
The information required by this Item is incorporated by
reference from the Proxy Statement to be filed within 120 days after
December 31, 2000, under the caption "Certain Transactions."
16
PART IV
ITEM 14. Financial Statements and Financial Statement Schedule,
Exhibits and Reports on Form 8-K
(a)(1) Financial Statements and Supplemental Data
Cross Reference to Applicable Sections
Of Annual Report to Shareholders Page
-------------------------------------- ----
Consolidated Financial Statements............................... 26
Notes to Consolidated Financial Statements...................... 30
Supplemental Information to Consolidated Financial Statements... 43
Unaudited Quarterly Financial Information....................... 51
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To EOG Resources, Inc.:
We have audited in accordance with auditing standards
generally accepted in the United States, the financial statements
included in EOG Resources, Inc.'s Annual Report to Shareholders,
incorporated by reference in this Form 10-K, and have issued our
report thereon dated February 15, 2001. Our audit was made for
the purpose of forming an opinion on those statements taken as a
whole. The schedule included in this item is the responsibility
of the Company's management and is presented for purposes of
complying with the Securities and Exchange Commission's rules and
is not part of the basic financial statements. This schedule has
been subjected to the auditing procedures applied in the audit of
the basic financial statements and, in our opinion, fairly state
in all material respects the financial data required to be set
forth therein in relation to the basic financial statements taken
as a whole.
ARTHUR ANDERSEN LLP
Houston, Texas
February 15, 2001
17
(a)(2) Financial Statement Schedule
Schedule II
EOG RESOURCES, INC.
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 2000, 1999 and 1998
(In Thousands)
- -------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
- -------------------------------------------------------------------------------------------------
Additions Deductions For
Balance at Charged to Purpose For Balance at
Beginning of Costs and Which Reserves End of
Description Year Expenses Were Created Year
- -------------------------------------------------------------------------------------------------
2000
Reserves deducted from assets
to which they apply--
Revaluation of Accounts Receivable..... $ 1,060 $ 500 $ 2 $ 1,558
======= ======= ======= =======
1999
Reserves deducted from assets
to which they apply--
Revaluation of Accounts Receivable..... $11,375 $ 1,972 $12,287 $ 1,060
======= ======= ======= =======
1998
Reserves deducted from assets
to which they apply--
Revaluation of Accounts Receivable..... $ 7,025 $ 4,350 $ - $11,375
======= ======= ======= =======
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.
(a)(3) Exhibits
See pages 18 through 22 for a listing of the exhibits.
(b) Reports on Form 8-K
No Current Reports on Form 8-K were filed by EOG during the three
months ended December 31, 2000.
18
EXHIBITS
Exhibits not incorporated herein by reference to a prior filing
are designated by an asterisk (*) and are filed herewith; all exhibits
not so designated are incorporated herein by reference to EOG's
Form S-1 Registration Statement, Registration No. 33-30678, filed on
August 24, 1989 ("Form S-1"), or as otherwise indicated.
Exhibit
Number Description
3.1(a) -- Restated Certificate of Incorporation (Exhibit 3.1 to
Form S-1).
3.1(b) -- Certificate of Amendment of Restated Certificate of
Incorporation (Exhibit 4.1(b) to Form S-8 Registration
Statement No. 33-52201, filed February 8, 1994).
3.1(c) -- Certificate of Amendment of Restated Certificate of
Incorporation (Exhibit 4.1(c) to Form S-8 Registration
Statement No. 33-58103, filed March 15, 1995).
3.1(d) -- Certificate of Amendment of Restated Certificate of
Incorporation, dated June 11, 1996 (Exhibit 3(d) to
Form S-3 Registration Statement No. 333-09919, filed
August 9, 1996).
3.1(e) -- Certificate of Amendment of Restated Certificate of
Incorporation, dated May 7, 1997 (Exhibit 3(e) to Form S-3
Registration Statement No. 333-44785, filed January 23,
1998).
3.1(f) -- Certificate of Ownership and Merger, dated August 26,
1999 (Exhibit 3.1(f) to EOG's Annual Report on Form 10-K
for the year ended December 31, 1999).
3.1(g) -- Certificate of Designations of Series E Junior
Participating Preferred Stock, dated February 14, 2000
(Exhibit 2 to Form 8-A Registration Statement, filed
February 18, 2000).
3.1(h) -- Certificate of Designation, Preferences and Rights of
Fixed Rate Cumulative Perpetual Senior Preferred Stock,
Series B, dated July 19, 2000. (Exhibit 3.1(h) to EOG's
Registration Statement on Form S-3 Registration Statement
No. 333-46858, filed September 28, 2000)
3.1(i) -- Certificate of Designation, Preferences and Rights of
the Flexible Money Market Cumulative Preferred Stock,
Series D, dated July 25, 2000 (Exhibit 3.1(i) to EOG's
Registration Statement on Form S-3 Registration Statement
No. 333-46858, filed September 28,2000).
3.1(j) -- Certificate of Elimination of the Fixed Rate
Cumulative Perpetual Senior Preferred Stock, Series A,
dated September 15, 2000 (Exhibit 3.1(j) to EOG's
Registration Statement on Form S-3 Registration Statement
No. 333-46858, filed September 28,2000)
3.1(k) -- Certificate of Elimination of the Flexible Money
Market Cumulative Preferred Stock, Series C, dated
September 15, 2000 (Exhibit 3.1(k) to EOG's Registration
Statement on Form S-3 Registration Statement No. 333-46858,
filed September 28,2000)
3.2 -- By-laws, dated August 23, 1989, as amended
December 12, 1990, February 8, 1994, January 19, 1996,
February 13, 1997, May 5, 1998, September 7, 1999 and
February 14, 2000 (Exhibit 3.1 to EOG's Current Report on
Form 8-K, filed February 18, 2000).
4.1(a) -- Specimen of Certificate evidencing the Common Stock
(Exhibit 3.3 to EOG's Annual Report on Form 10-K for the
year ended December 31, 1999).
4.1(b) -- Specimen of Certificate Evidencing Fixed Rate
Cumulative Perpetual Senior Preferred Stock, Series B
(Exhibit 4.3(g) to EOG's Registration Statement on Form S-4
Registration Statement No. 333-36056, filed June 7, 2000).
19
Exhibit
Number Description
4.1(c) -- Specimen of Certificate Evidencing Flexible Money
Market Cumulative Preferred Stock, Series D (Exhibit 4.3(g)
to EOG's Registration Statement on Form S-4 Registration
Statement No. 333-36416, filed June 12, 2000).
4.2 -- Rights Agreement, dated as of February 14, 2000,
between EOG and First Chicago Trust Company of New York,
which includes the form of Rights Certificate as Exhibit B
and the Summary of Rights to Purchase Preferred Shares as
Exhibit C (Exhibit 1 to EOG's Registration Statement on
Form 8-A, filed February 18, 2000).
4.3(a) -- Amended and Restated 1994 Stock Plan (Exhibit 4.3 to
Form S-8 Registration Statement No. 33-58103, filed
March 15, 1995).
4.3(b) -- Amendment to Amended and Restated 1994 Stock Plan,
dated effective as of December 12, 1995 (Exhibit 4.3(a) to
EOG's Annual Report on Form 10-K for the year ended
December 31, 1995).
4.3(c) -- Amendment to Amended and Restated 1994 Stock Plan,
dated effective as of December 10, 1996 (Exhibit 4.3(a) to
Form S-8 Registration Statement No. 333-20841, filed
January 31, 1997).
4.3(d) -- Third Amendment to Amended and Restated 1994 Stock
Plan, dated effective as of December 9, 1997 (Exhibit
4.3(d) to EOG's Annual Report on Form 10-K for the year
ended December 31, 1997).
4.3(e) -- Fourth Amendment to Amended and Restated 1994 Stock
Plan, dated effective as of May 5, 1998 (Exhibit 4.3(e) to
EOG's Annual Report on Form 10-K for the year ended
December 31, 1998).
4.3(f) -- Fifth Amendment to Amended and Restated 1994 Stock
Plan, dated effective as of December 8, 1998 (Exhibit
4.3(f) to EOG's Annual Report on Form 10-K for the year
ended December 31, 1998).
4.4 -- Form of Rights Certificate (Exhibit 3 to EOG's
Registration Statement on Form 8-A, filed February 18,
2000).
4.5 -- Indenture dated as of September 1, 1991, between EOG
and Chase Bank of Texas National Association (formerly,
Texas Commerce Bank National Association) (Exhibit 4(a) to
EOG's Registration Statement on Form S-3 Registration
Statement No. 33-42640, filed September 6, 1991).
4.6 -- Indenture dated as of _________, 2000, between EOG and
The Bank of New York (Exhibit 4.6 to EOG's Registration
Statement on Form S-3 Registration Statement No. 333-46858,
filed September 28, 2000).
10.2(a) -- Stock Restriction and Registration Agreement dated as
of August 23, 1989 (Exhibit 10.2 to Form S-1).
10.2(b) -- Amendment to Stock Restriction and Registration
Agreement, dated December 9, 1997, between EOG and Enron
Corp. (Exhibit 10.2(b) to EOG's Annual Report on Form 10-K
for the year ended December 31, 1997).
10.3 -- Tax Allocation Agreement, entered into effective as of
the Deconsolidation Date, between Enron Corp., EOG, and the
subsidiaries of EOG listed therein as additional parties
(Exhibit 10.3 to EOG's Annual Report on Form 10-K for the
year ended December 31, 1998).
10.4(a) -- Share Exchange Agreement, dated as of July 19, 1999,
between Enron Corp. and EOG (Exhibit 2 to Form S-3
Registration Statement No. 333-83533, filed July 23, 1999).
20
Exhibit
Number Description
10.4(b) -- Letter Amendment, dated July 30, 1999, to Share
Exchange Agreement, between Enron Corp. and EOG
(Exhibit 2.2 to EOG's Current Report on Form 8-K, filed
August 31, 1999).
10.4(c) -- Letter Amendment, dated August 10, 1999, to Share
Exchange Agreement, between Enron Corp. and EOG
(Exhibit 2.3 to EOG's Current Report on Form 8-K, filed
August 31, 1999).
*10.4(d) -- Consent Agreement between EOG, Enron Corp., Enron
Finance Partners, LLC, Enron Intermediate Holdings, LLC,
Enron Asset Holdings, LLC and Aeneas, LLC, dated November
28, 2000.
10.14(a) -- 1993 Nonemployee Directors' Stock Option Plan
(Exhibit 10.14 to EOG's Annual Report on Form 10-K for the
year ended December 31, 1992).
10.14(b) -- First Amendment to 1993 Nonemployee Directors' Stock
Option Plan (Exhibit 10.14(b) to EOG's Annual Report on
Form 10-K for the year ended December 31, 1996).
10.16 -- Interest Rate and Currency Exchange Agreement, dated
as of June 1, 1991, between Enron Risk Management Services
Corp. and Enron Oil & Gas Marketing, Inc. (Exhibit 10.17 to
EOG's Annual Report on Form 10-K for the year ended
December 31, 1991), Confirmation dated June 14, 1992
(Exhibit 10.17 to Form S-1 Registration Statement,
No. 33-50462, filed August 5, 1992) and Confirmations dated
March 25, 1991, April 25, 1991, and September 23, 1992
(assigned to Enron Risk Management Services Corp. by Enron
Finance Corp. pursuant to an Assignment and Assumption
Agreement, dated as of November 1, 1993, by and between
Enron Finance Corp., Enron Risk Management Services Corp.
and Enron Oil & Gas Marketing, Inc.). (Exhibit 10.16 to
EOG's Annual Report on Form 10-K for the year ended
December 31, 1993).
10.17 -- Assignment and Assumption Agreement, dated as of
November 1, 1993, by and between Enron Oil & Gas
Marketing, Inc., EOG and Enron Risk Management Services
Corp. (Exhibit 10.17 to EOG's Annual Report on Form 10-K
for the year ended December 31, 1993).
10.18 -- ISDA Master Agreement, dated as of November 1, 1993,
between EOG and Enron Risk Management Services Corp., and
Confirmation Nos. 1268.0, 1286.0, 1291.0, 1292.0, 1304.0,
1305.0, 1321.0, 1335.0, 1338.0, 1370.0, 1471.0, 1485.0,
1486.0, 1494.0, 1495.0, 1509.0, 1514.0, 1533.01, 1569.0,
1986.0, 2217.0, 2227.0, 2278.0, 2299.0, 2372.0, 2647.0
(Exhibit 10.18 to EOG's Annual Report on Form 10-K for the
year ended December 31, 1993).
10.25 -- Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron
Corp. Annual Report on Form 10-K for the year ended
December 31, 1991).
10.26 -- Enron Corp. 1988 Deferral Plan (Exhibit 10.49 to
Form S-1).
10.28 -- Enron Executive Supplemental Survivor Benefits Plan
Effective January 1, 1987 (Exhibit 10.51 to Form S-1).
10.34 -- 1992 Stock Plan (As Amended and Restated Effective
June 28, 1999) (Exhibit A to EOG's Proxy Statement, dated
June 4, 1999, with respect to EOG's Annual Meeting of
Shareholders).
10.60 -- Services Agreement, dated January 1, 1997, between
Enron Corp. and EOG (Exhibit 10.60 to EOG's Annual Report
on Form 10-K for the year ended December 31, 1997).
10.61 -- Equity Participation and Business Opportunity
Agreement, dated December 9, 1997, between EOG and Enron
Corp. (Exhibit 10 to Form S-3 Registration Statement
No. 333-44785, filed January 23, 1998).
21
Exhibit
Number Description
10.63(a) -- 1996 Deferral Plan (Exhibit 10.63(a) to EOG's Annual
Report on Form 10-K for the year ended December 31, 1997).
10.63(b) -- First Amendment to 1996 Deferral Plan, dated effective
as of December 9, 1997 (Exhibit 10.63(b) to EOG's Annual
Report on Form 10-K for the year ended December 31, 1997).
10.63(c) -- Second Amendment to 1996 Deferral Plan, dated
effective as of December 8, 1998 (Exhibit 10.63(c) to EOG's
Annual Report on Form 10-K for the year ended December 31,
1998).
10.64(a) -- Executive Employment Agreement between EOG and Mark G.
Papa, effective as of November 1, 1997 (Exhibit 10.64 to
EOG's Annual Report on Form 10-K for the year ended
December 31, 1997).
10.64(b) -- First Amendment to Executive Employment Agreement
between EOG and Mark G. Papa, effective as of February 1,
1999 (Exhibit 10.64(b) to EOG's Annual Report on Form 10-K
for the year ended December 31, 1998).
10.64(c) -- Second Amendment to Executive Agreement between EOG
and Mark G. Papa, effective as of June 28, 1999 (Exhibit
10.64(c) to EOG's Annual Report on Form 10-K for the year
ended December 31, 1999).
10.65(a) -- Executive Employment Agreement between EOG and
Edmund P. Segner, III, effective as of September 1, 1998
(Exhibit 10.65(a) to EOG's Annual Report on Form 10-K for
the year ended December 31, 1998).
10.65(b) -- First Amendment to Executive Employment Agreement
between EOG and Edmund P. Segner, III, effective as of
February 1, 1999 (Exhibit 10.65(b) to EOG's Annual Report
on Form 10-K for the year ended December 31, 1998).
10.65(c) -- Second Amendment to Executive Employment Agreement
between EOG and Edmund P. Segner, III, effective as of
June 28, 1999 (Exhibit 10.65(c) to EOG's Annual Report on
Form 10-K for the year ended December 31, 1999).
10.66(a) -- Executive Employment Agreement between EOG and Barry
Hunsaker, Jr., effective as of September 1, 1998 (Exhibit
10.66(a) to EOG's Annual Report on Form 10-K for the year
ended December 31, 1999).
10.66(b) -- First Amendment to Executive Employment Agreement
between EOG and Barry Hunsaker, Jr., effective as of
December 21, 1998 (Exhibit 10.66(b) to EOG's Annual Report
on Form 10-K for the year ended December 31, 1999).
10.66(c) -- Second Amendment to Executive Employment Agreement
between EOG and Barry Hunsaker, Jr., effective as of
February 1, 1999 (Exhibit 10.66(c) to EOG's Annual Report
on Form 10-K for the year ended December 31, 1999).
10.67(a) -- Executive Employment Agreement between EOG and Loren M
Leiker, effective as of March 1, 1998 (Exhibit 10.67(a) to
EOG's Annual Report on Form 10-K for the year ended
December 31, 1999).
10.67(b) -- First Amendment to Executive Employment Agreement
between EOG and Loren M. Leiker, effective as of
February 1, 1999 (Exhibit 10.67(b) to EOG's Annual Report
on Form 10-K for the year ended December 31, 1999).
10.68(a) -- Executive Employment Agreement between EOG and Gary L.
Thomas, effective as of September 1, 1998 (Exhibit 10.68(a)
to EOG's Annual Report on Form 10-K for the year ended
December 31, 1999).
10.68(b) -- First Amendment to Executive Employment Agreement
between EOG and Gary L. Thomas, effective as of February 1,
1999 (Exhibit 10.68(b) to EOG's Annual Report on Form 10-K
for the year ended December 31, 1999).
22
Exhibit
Number Description
*12 -- Computation of Ratio of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred Dividends.
*13 -- Annual Report to Shareholders
*21 -- List of subsidiaries.
*23.1 -- Consent of DeGolyer and MacNaughton.
23.2 -- Opinion of DeGolyer and MacNaughton dated February 8,
2000 (Exhibit 23.2 to EOG's Current Report on Form 8-K,
filed on February 27, 2001).
*23.3 -- Consent of Arthur Andersen LLP.
*24 -- Powers of Attorney.
23
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized, on the 23rd day of March, 2001.
EOG RESOURCES, INC.
(Registrant)
By /s/TIMOTHY K. DRIGGERS
---------------------------
(Timothy K. Driggers)
Vice President Accounting
and Land Administration
(Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed by the following persons on behalf
of registrant and in the capacities with EOG Resources, Inc. indicated
and on the 23rd day of March, 2001.
Signature Title
/s/ MARK G. PAPA Chairman and Chief Executive Officer and
- --------------------------------- Director (Principal Executive Officer)
(Mark G. Papa)
/s/ TIMOTHY K. DRIGGERS Vice President Accounting
- --------------------------------- and Land Administration
(Timothy K. Driggers) (Principal Accounting Officer)
/s/ DAVID R. LOONEY Vice President Finance
- --------------------------------- (Principal Financial Officer)
(David R. Looney)
*EDMUND P. SEGNER, III President and Chief of Staff and Director
- ---------------------------------
(Edmund P. Segner, III)
*FRED C. ACKMAN Director
- ---------------------------------
(Fred C. Ackman)
*GEORGE A. ALCORN Director
- ---------------------------------
(George A. Alcorn)
*EDWARD RANDALL, III Director
- ---------------------------------
(Edward Randall, III)
*DONALD F. TEXTOR Director
- ---------------------------------
(Donald F. Textor)
*FRANK G. WISNER Director
- ---------------------------------
(Frank G. Wisner)
*By /s/ PATRICIA L. EDWARDS
------------------------------
(Patricia L. Edwards)
(Attorney-in-fact for persons indicated)