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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report: February 27, 2002
----------------------------
EOG RESOURCES, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 1-9743 47-0684736
(State or other jurisdiction (Commission File (I.R.S. Employer
of incorporation or organization) Number) Identification No.)
333 CLAY STREET
SUITE 4200
HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip code)
713/651-7000
(Registrant's telephone number, including area code)
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2
EOG RESOURCES, INC.
Item 7. Financial Statements and Exhibits.
(a) Financial Statements of EOG Resources, Inc.
Financial Statements of EOG Resources, Inc. and its
Consolidated Subsidiaries for the fiscal year ended December 31, 2001,
including Report of Arthur Andersen LLP, Independent Public Accountants.
(b) Exhibits.
23.1 Consent of DeGolyer and MacNaughton.
23.2 Opinion of DeGolyer and MacNaughton dated January 25, 2002.
23.3 Consent of Arthur Andersen LLP.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act
of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned hereunto duly authorized.
EOG RESOURCES, INC.
(Registrant)
Date: February 27, 2002 By: /s/ TIMOTHY K. DRIGGERS
-----------------------------
Timothy K. Driggers
Vice President, Accounting
& Land Administration
(Principal Accounting Officer)
3
EOG RESOURCES, INC.
TABLE OF CONTENTS
Page No.
Management's Discussion and Analysis of Financial
Condition and Results of Operations........................ 4
Management's Responsibility for Financial Reporting.......... 13
Report of Independent Public Accountants..................... 14
Consolidated Statements of Income and Comprehensive Income
for the years ended December 31, 2001, 2000 and 1999....... 15
Consolidated Balance Sheets, December 31, 2001 and 2000....... 16
Consolidated Statements of Shareholders' Equity for
the years ended December 31, 2001, 2000 and 1999........... 17
Consolidated Statements of Cash Flows for the years
ended December 31, 2001, 2000 and 1999..................... 18
Notes to Consolidated Financial Statements................... 19
Supplemental Information to Consolidated
Financial Statements...................................... 36
Exhibits
Exhibit 23.1 - Consent of DeGolyer and MacNaughton......... 45
Exhibit 23.2 - Opinion of DeGolyer and MacNaughton
dated January 25, 2002.................................. 46
Exhibit 23.3 - Consent of Arthur Andersen LLP.............. 48
4
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following review of operations for each of the three years in
the period ended December 31, 2001 should be read in conjunction with
the consolidated financial statements of EOG Resources, Inc. ("EOG")
and notes thereto beginning with page 15.
Results of Operations
---------------------
Net Operating Revenues. Wellhead volume and price statistics for the
specified years were as follows:
Year Ended December 31,
------------------------
2001 2000 1999
------ ------ ------
Natural Gas Volumes (MMcf per day)(1)
United States........................................ 680 654 654
Canada............................................... 126 129 115
Trinidad............................................. 115 125 123
India (2)............................................ - - 46
------ ------ ------
Total............................................ 921 908 938
====== ====== ======
Average Natural Gas Prices ($/Mcf)(3)
United States........................................ $4.26 $3.96 $2.20
Canada............................................... 3.78 3.33 1.88
Trinidad............................................. 1.22 1.17 1.08
India (2)............................................ - - 2.09
Composite........................................ 3.81 3.49 2.01
Crude Oil and Condensate Volumes (MBbl per day)(1)
United States........................................ 22.0 22.8 14.4
Canada............................................... 1.7 2.1 2.6
Trinidad............................................. 2.1 2.6 2.4
India (2)............................................ - - 4.1
------ ------ ------
Total............................................ 25.8 27.5 23.5
====== ====== ======
Average Crude Oil and Condensate Prices ($/Bbl)(3)
United States........................................ $25.06 $29.68 $18.55
Canada............................................... 22.70 27.76 16.77
Trinidad............................................. 24.14 30.14 16.21
India (2)............................................ - - 12.80
Composite........................................ 24.83 29.57 17.12
Natural Gas Liquids Volumes (MBbl per day)(1)
United States........................................ 3.5 4.0 2.6
Canada............................................... 0.5 0.7 0.8
------ ------ ------
Total............................................ 4.0 4.7 3.4
====== ====== ======
Average Natural Gas Liquids Prices ($/Bbl)(3)
United States........................................ $17.17 $20.45 $13.41
Canada............................................... 15.05 16.75 8.23
Composite........................................ 16.89 19.87 12.24
Natural Gas Equivalent Volumes (MMcfe per day)(4)
United States........................................ 833 814 757
Canada............................................... 139 146 134
Trinidad............................................. 128 141 138
India (2)............................................ - - 70
------ ------ ------
Total............................................ 1,100 1,101 1,099
====== ====== ======
Total Bcfe(4)Deliveries............................... 401 403 401
-------------------------------
(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) See Note 4 to the Consolidated Financial Statements regarding the
Share Exchange Agreement with Enron Corp.
(3) Dollars per thousand cubic feet or per barrel, as applicable.
(4) Million cubic feet equivalent per day or billion cubic feet
equivalent, as applicable; includes natural gas, crude oil, condensate
and natural gas liquids.
5
2001 compared to 2000. During 2001, net operating revenues
increased $165 million to $1,655 million. Total wellhead revenues of
$1,540 million increased by $49 million, or 3%, as compared to 2000.
Average wellhead natural gas prices for 2001 were approximately
9% higher than the comparable period in 2000, increasing net operating
revenues by $110 million. Average wellhead crude oil and condensate
prices were 16% lower, decreasing net operating revenues by $45
million. North America wellhead natural gas deliveries were
approximately 3% higher than the comparable period in 2000. The
increase in volumes was primarily due to increased production in the
Midland and Pittsburgh divisions, partially offset by decreased
production in the Denver and Corpus Christi divisions and the
implementation of a production moderation strategy in late third
quarter. Combined with reduced production in Trinidad, the overall
natural gas production was 1% higher than the comparable period in
2000, increasing net operating revenues by $14 million. Wellhead
crude oil and condensate volumes were 6% lower than in 2000,
decreasing net operating revenues by $20 million. The decrease in
wellhead crude oil and condensate volumes is primarily due to
decreased deliveries worldwide. Natural gas liquids prices and
deliveries were both approximately 15% lower than 2000, decreasing net
operating revenues by $4 million and $5 million, respectively.
During 2001, EOG recognized mark-to-market gains on commodity
contracts of $98 million, of which $62 million were realized gains.
Gains on sales of reserves and related assets and other, net
totaled a gain of $1 million during 2001 compared to a gain of $9
million in 2000. The difference is due primarily to a $7 million gain
on sales of certain North America properties in 2000.
Other marketing activities associated with sales and purchases of
natural gas transactions increased net operating revenue by $16
million during 2001, compared to a $10 million reduction in 2000.
2000 compared to 1999. During 2000, net operating revenues
increased $648 million to $1,490 million. Total wellhead revenues of
$1,491 million increased by $641 million, or 75%, as compared to 1999.
Average wellhead natural gas prices for 2000 were approximately
74% higher than the comparable period in 1999 increasing net operating
revenues by approximately $491 million. Average wellhead crude oil and
condensate prices were up by 73% increasing net operating revenues by
$125 million. Wellhead natural gas volumes were approximately
3% lower than the comparable period in 1999 decreasing net operating
revenues by nearly $20 million. The decrease in wellhead natural gas
volumes is primarily due to the transfer of producing properties in
connection with the Share Exchange described in Note 4 to the
Consolidated Financial Statements, partially offset by increased
deliveries in Canada and Trinidad. Wellhead crude oil and condensate
volumes were 17% higher than in 1999, increasing net operating
revenues by $26 million. The increase in wellhead crude oil and
condensate volumes is primarily due to increased deliveries in the
United States and Trinidad, partially offset by the transfer of
producing properties in the Share Exchange and decreased deliveries in
Canada. Natural gas liquids prices and deliveries were approximately
62% and 39% higher than 1999, increasing net operating revenues by $13
million and $6 million, respectively.
Gains (losses) on sales of reserves and related assets and other,
net totaled a gain of $9 million during 2000 compared to a loss of
nearly $1 million in 1999. The difference is due primarily to a
$7 million gain on sales of certain North America properties in 2000.
Other marketing activities associated with sales and purchases of
natural gas transactions decreased net operating revenues by $10
million during 2000, compared to a $7 million reduction in 1999.
Operating Expenses
------------------
2001 compared to 2000. During 2001, operating expenses of $980
million, which includes $19 million of charges related to the Enron
bankruptcies, were approximately $187 million higher than the $793
million incurred in 2000.
Lease and well expenses increased $35 million to $175 million
primarily due to higher production costs, continually expanding
operations and increases in production activity in North America.
Exploration expenses of $67 million remained essentially flat compared
to 2000. Dry hole expenses of $71 million increased $54 million from
2000. Impairments increased $33 million to $79 million primarily as a
result of write-down of assets in the United States. Depreciation,
depletion and amortization ("DD&A") expense increased $33 million to
$392 million primarily due to increased DD&A rates. General and
administrative ("G&A") expenses increased $13 million primarily due to
expanded operations. Taxes other than income remained approximately
the same as compared to 2000.
6
Total operating costs per unit of production, which include lease
and well, DD&A, G&A, taxes other than income and interest expense,
increased 9% to $1.97 per thousand cubic feet equivalent ("Mcfe") in
2001 from $1.80 in 2000. This increase is primarily due to higher per
unit rates of lease and well, DD&A and G&A expenses, partially offset
by a lower per unit rate of interest expense.
During the fourth quarter of 2001, EOG recorded charges
associated with Enron Corp. bankruptcy of $19 million, of which $17
million were related to 2001 and 2002 natural gas and oil derivative
contracts.
Interest Expense. The decrease in net interest expense of $16
million for 2001 as compared to 2000 is primarily due to lower long-
term debt levels during the year.
2000 compared to 1999. During 2000, operating expenses of $793
million were approximately $31 million lower than the $824 million
incurred in 1999.
Lease and well expenses increased $9 million to $141 million
primarily due to continually expanding operations and increases in
production activity in North America. Exploration expenses of $67
million and dry hole expenses of $17 million increased $14 million and
$5 million, respectively, from 1999 due to increased exploratory
drilling activities. Impairments decreased $115 million to $46
million primarily due to charges of $15 million pursuant to a change
in EOG's strategy related to certain offshore operations in the second
quarter of 1999, the impairment of various North America properties in
the fourth quarter of 1999, and non-recurring charges of $114 million
related primarily to assets determined no longer central to EOG's
business in the third quarter of 1999. DD&A expense increased $30
million primarily due to increased DD&A rates. G&A expenses decreased
$16 million primarily due to non-recurring costs in 1999 of $14
million related to the Share Exchange, the potential sale of EOG and
personnel expenses partially offset by savings resulting from the
discontinuance of the India and China operations as a result of the
Share Exchange. Taxes other than income increased $42 million
reflecting higher state severance taxes associated with higher taxable
wellhead revenues resulting from higher average prices.
Total operating costs per unit of production, which include lease
and well, DD&A, G&A, taxes other than income and interest expense,
increased 10% to $1.80 Mcfe in 2000 from $1.64 in 1999. This increase
is primarily due to higher per unit rates of lease and well, DD&A and
taxes other than income, partially offset by a lower per unit rate of
G&A expenses. Excluding the aforementioned 1999 charges of $14
million in G&A expenses, the per unit operating costs for EOG were
$1.60 per Mcfe in 1999. The per unit operating costs in 2000 of $1.80
was $.20 higher than the adjusted per unit operating costs of 1999,
primarily due to higher per unit rates of lease and well, DD&A and
taxes other than income.
Other Income (Expense). Other income of $611 million for 1999
included a $575 million net gain from the Share Exchange, a
$59.6 million gain on the sale of 3.2 million options owned by EOG to
purchase Enron Corp. common stock, and a $19.4 million charge for
estimated exit costs related to EOG's decision to dispose of certain
international assets.
Income Taxes. Income tax provision increased approximately $238
million for 2000 as compared to 1999 as a result of a higher pre-tax
income year to year after removing the non-taxable gain on the Share
Exchange in 1999.
Capital Resources and Liquidity
-------------------------------
Cash Flow. The primary sources of cash for EOG during the
three-year period ended December 31, 2001 included cash generated from
operations, including realized gains from mark-to-market commodity
derivative contracts, proceeds from the sales of other assets,
selected oil and gas reserves and related assets and funds from new
borrowings and proceeds from equity offerings. Primary cash outflows
included funds used in operations, exploration and development
expenditures, common stock repurchases, dividends paid to EOG
shareholders, repayments of debt and cash contributed to transferred
subsidiaries in the Share Exchange.
Net operating cash flows of $1,197 million in 2001 increased
approximately $230 million as compared to 2000 primarily due to higher
net operating revenues resulting from higher natural gas prices, net
of increased cash operating expenses, and lower current income taxes,
partially offset by a lower tax benefit from stock options exercised.
Changes in working capital and other liabilities increased operating
cash flows by $75 million as compared to 2000 primarily due to changes
in accounts receivable, accrued royalties payable and accrued
production taxes caused by fluctuation of commodity prices at each
yearend. Net investing cash outflows of $1,088 million in 2001
increased by $421 million as compared to 2000 due primarily to
increased exploration and development expenditures of $426 million
(including producing property acquisitions) and decreased proceeds
from sales of reserves and related assets, partially offset by
decreased equity investments. Changes in components of working
capital associated with investing activities included changes in
7
accounts payable associated with the accrual of exploration and
development expenditures and changes in inventories which represent
materials and equipment used in drilling and related activities. Cash
used in financing activities in 2001 was $127 million as compared to
$305 million in 2000. Financing activities in 2001 included
repayments of debt of $4 million, common stock repurchases of $127
million and dividend payments of $29 million, partially offset by
proceeds from sales of treasury stock of $31 million.
Net operating cash flows of $967 million in 2000 increased
approximately $524 million as compared to 1999 due to higher net
operating revenues resulting from higher prices, net of cash operating
expenses, and higher tax benefits from stock options exercised
partially offset by higher current income taxes. Changes in working
capital and other liabilities decreased operating cash flows by $16
million as compared to 1999 primarily due to changes in accounts
receivable, accrued royalties payable and accrued production taxes
caused by fluctuation of commodity prices at each yearend. Net
investing cash outflows of $667 million in 2000 increased by $304
million as compared to 1999 due primarily to increased exploration and
development expenditures of $226 million (including producing property
acquisitions), increased equity investments, and the non-recurrence of
proceeds from sales of Enron Corp. options in 1999, partially offset
by increased proceeds from sales of reserves and related assets.
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 materials and equipment used in drilling
and related activities. Cash used in financing activities in 2000 was
$305 million as compared to $62 million in 1999. Financing activities
in 2000 included repayments of debt of $131 million, common stock
repurchases of $273 million and dividend payments of $26 million,
partially offset by proceeds from sales of treasury stock of $127
million.
Discretionary cash flow available to common, a frequently used
measure of performance for exploration and production companies, is
generally derived by adjusting net income to include tax benefits on
stock options exercised and to eliminate the effects of depreciation,
depletion and amortization, impairments, deferred income taxes, gains
on sales of oil and gas reserves and related assets, certain other
non-cash amounts, except for amortization of deferred revenue and
exploration and dry hole costs. EOG generated discretionary cash flow
available to common of approximately $1,162 million in 2001, $1,007
million in 2000, $477 million in 1999. Discretionary cash flow
available to common should not be considered as an alternative to
income from operations or to cash flows from operating activities (as
determined in accordance with accounting principles generally accepted
in the United States) and should not be construed as an indication of
a company's operating performance or as a measure of liquidity.
Exploration and Development Expenditures. The table below sets
out components of exploration and development expenditures for the
years ended December 31, 2001, 2000 and 1999, along with the total
budgeted for 2002, excluding acquisitions.
1999
Excluding India and Budgeted 2002
Actual China Operations(1) (excluding acquisitions)
------------------------ ------------------- ------------------------
Expenditure Category 2001 2000 1999
-------------------- ------ ------ ------
(In Millions)
Capital
Drilling and Facilities.................. $ 722 $ 443 $ 319 $ 293
Leasehold Acquisitions................... 76 51 21 21
Producing Property Acquisitions.......... 168 102 45 43
Capitalized Interest..................... 9 7 11 8
------ ------ ------ -------
Subtotal............................... 975 603 396 365
Exploration Costs......................... 67 67 53 51
Dry Hole Costs............................ 71 17 12 12
------ ------ ------ -------
Subtotal............................... 1,113 687 461 428
Deferred Income Taxes..................... 50 23 - -
------ ------ ------ -------
Total.................................. $1,163 $ 710 $ 461 $ 428 $600 - $750
====== ====== ====== ======= ===========
(1) See Note 4 to Consolidated Financial Statements.
Total exploration and development expenditures increased
$453 million in 2001 as compared to 2000 primarily due to increased
exploration and development activities in North America and Trinidad,
and acquisitions of oil and gas properties in North America.
8
Derivative Transactions. During 2001, EOG recognized mark-to-
market gains on commodity derivative contracts of $98 million, of
which $62 million were realized gains (see Note 12 to the Consolidated
Financial Statements).
The following is a summary of EOG's price swap and physical
contract positions at February 20, 2002:
(a) 2002 Price Swap Positions
o Natural Gas Price Swaps - Tabulated below is a summary of EOG's
2002 natural gas price swap positions with prices expressed in
dollars per million British thermal units ($/MMBtu) and notional
volumes in million British thermal units per day (MMBtud). EOG
accounts for these swap contracts under mark-to-market accounting.
Average Price Volume
2002 ($/MMBtu) (MMBtud)
---------------------- ------------- --------
January (closed) $ 3.21 140,000
February (closed) $ 3.13 190,000
March $ 3.13 140,000
April and May $ 2.68 290,000
June $ 2.76 200,000
July through December $ 3.26 100,000
o Crude Oil Price Swaps - Notional volumes of two thousand barrels
of oil per day for the period March 2002 to December 2002 at an
average price of $21.50 per barrel. EOG accounts for these swap
contracts under mark-to-market accounting.
(b) 2002 Natural Gas Physical Contracts
EOG had 2002 natural gas physical contracts for 95,000
MMBtud at an average price of $3.03 per MMBtu for January
and February 2002 in the U.S. and approximately 24,000
MMBtud at an average price of US$3.35 per MMBtu for the
period January through December 2002 in Canada.
Financing. EOG's long-term debt-to-total-capitalization ratio
was 34% as of December 31, 2001 compared to 38% as of December 31,
2000.
During 2001, total long-term debt decreased slightly to
$856 million primarily due to higher cash flow from operations
primarily resulting from slightly higher natural gas prices, partially
offset by additions to oil and gas properties and significant share
repurchases of common stock (see Note 2 to the Consolidated Financial
Statements). The estimated fair value of EOG's long-term debt at
December 31, 2001 and 2000 was $838 million and $831 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, 2001, a 1% change in interest rates would result in a
$47 million change in the estimated fair value of the fixed rate
obligations (see Note 12 to the Consolidated Financial Statements).
The following table summarizes EOG's contractual obligations at
December 31, 2001 (in thousands):
2008 &
Contractual Obligations(1) Total 2002 2003 - 2005 2006 - 2007 beyond
------------------------- -------- -------- ----------- ----------- --------
Long-Term Debt............................. $855,969 $ - $195,147 $226,870 $433,952
Non-cancelable Operating Leases............ 32,779 7,773 18,896 6,110 -
Drilling Rig Commitments................... 28,234 24,711 3,523 - -
Transportation Service Commitments(2)...... 49,473 16,377 17,541 10,427 5,128
-------- -------- -------- -------- --------
Total Contractual Obligations.............. $966,455 $ 48,861 $235,107 $243,407 $439,080
======== ======== ======== ======== ========
(1) See Notes 2 and 7 to Consolidated Financial Statements.
(2) Amounts shown are based on current transportation rates and foreign currency exchange rate at
December 31, 2001. Management does not believe that any future changes in these rates before the
expiration dates of these commitments will have a materially adverse effect on the financial
condition or results of operations of EOG.
9
Shelf Registration. During the third quarter of 2000, EOG filed
a shelf registration statement for the offer and sale from time to
time of up to $600 million of EOG debt securities, preferred stock
and/or common stock. The registration statement was declared
effective by the Securities and Exchange Commission on October 27,
2000. As of February 20, 2002, EOG had sold no securities pursuant to
this shelf registration. When combined with the unused portion of a
previously filed registration statement declared effective in January
1998, these registration statements provide for the offer and sale
from time to time of EOG debt securities, preferred stock and/or
common stock by EOG in an aggregate amount up to $688 million.
Outlook. Natural gas prices historically have been volatile, and
this volatility is expected to continue. Uncertainty continues to
exist as to the direction of future North America natural gas and
crude oil price trends, and there remains a rather wide divergence in
the opinions held by some in the industry. This divergence in opinion
is caused by various factors including the current industrial
recession and economic downturn, improvements in the technology used
in drilling and completing crude oil and natural gas wells,
improvements being realized in the availability and utilization of
natural gas storage capacity and warmer weather experienced in the
latter part of 2001. However, the increasing recognition of natural
gas as a more environmentally friendly source of energy along with the
availability of significant domestically sourced supplies should
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. At December 31,
2001, based on EOG's tax position and the portion of EOG's anticipated
natural gas volumes for 2002 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 $0.10
per Mcf change in average wellhead natural gas prices is $15 million
(or $0.13 per share) for net income and $23 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 $5 million (or $0.04 per share) for net income and $8
million for current operating cash flow.
EOG plans to continue to focus a substantial portion of its
exploration and development expenditures in its major producing areas
in North America. However, in order to diversify its overall asset
portfolio and as a result of its overall success realized in Trinidad,
EOG anticipates expending a portion of its available funds in the
further development of opportunities outside North America. In
addition, EOG expects to conduct limited exploratory activity in other
areas outside of North America and will continue to evaluate the
potential for involvement in other exploitation type opportunities.
Budgeted 2002 exploration and development expenditures, excluding
acquisitions, are in the range of $600 - $750 million, addressing the
continuing uncertainty with regard to the future of the North America
natural gas and crude oil and condensate price environment. Budgeted
expenditures for 2002 are structured to maintain the flexibility
necessary under EOG's continuing strategy of funding North America
exploration, exploitation, development and acquisition activities
primarily from available internally generated cash flow.
The level of exploration and development expenditures may vary in
2002 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 2002 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 Trinidad, such commitments are not
anticipated to be material when considered in relation to the total
financial capacity of EOG.
Environmental Regulations. Various federal, state and local laws
and regulations covering the discharge of materials into the
environment, or otherwise relating to protection of the environment,
may affect EOG's operations and costs as a result of their effect on
natural gas and crude oil exploration, exploitation, development and
production operations. In addition, EOG has acquired certain oil and
gas properties from third parties whose actions with respect to the
management and disposal or release of hydrocarbons or other wastes
were not under EOG's control. Under environmental laws and
regulations, EOG could be required to remove or remediate wastes
disposed of or released by prior owners or operators. EOG also has
acquired or merged with companies that own and operate oil and gas
properties. Any obligations or liabilities of these companies under
environmental laws would continue as liabilities of the acquired
company, or of EOG in the event of a merger, even if the obligations
or liabilities resulted from actions that took place before the
acquisition or merger. Compliance with such laws and regulations has
not had a material adverse effect on EOG's operations or financial
condition. It is not anticipated, based on current laws and regulations,
that EOG will be required in the near future to expend amounts that are
material in relation to its total exploration and development
expenditure program by reason of environmental laws and
regulations. However, inasmuch as such laws and regulations are
frequently changed, EOG is unable to predict the ultimate cost
of compliance.
10
EOG also could incur costs related to the clean up of sites to
which it sent regulated substances for disposal and for damages to
natural resources or other claims related to releases of regulated
substances at such sites. In this regard, EOG has been named as a
potentially responsible party in certain proceedings initiated
pursuant to the Comprehensive Environmental Response, Compensation,
and Liability Act and may be named as a potentially responsible party
in other similar proceedings in the future. It is not anticipated
that the costs incurred by EOG in connection with the presently
pending proceedings will, individually or in the aggregate, have a
materially adverse effect on the financial condition or results of
operations of EOG.
Summary of Significant Accounting Policies
------------------------------------------
Principles of Consolidation. The consolidated financial
statements of EOG, a Delaware corporation, 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 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.
Beginning 2001, the "Impairment of Unproved Oil and Gas Properties"
caption on the Consolidated Statements of Income was renamed
"Impairments" to include the impairment loss of long-lived assets as
described in Statement of Financial Accounting Standards ("SFAS") No.
121--"Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to Be Disposed of " ("SFAS 121 Impairments"). As a
result, EOG reclassified all prior periods to reflect such SFAS 121
Impairments in Impairments, instead of Depreciation, Depletion and
Amortization ("DD&A") as previously reported. SFAS 121 Impairments
reclassified from DD&A to Impairments were $11 million and $133
million for 2000 and 1999, respectively.
Financial Instruments. EOG's financial instruments consist of
cash and cash equivalents, marketable securities, accounts receivable,
accounts payable and long-term debt. The carrying values of cash and
cash equivalents, marketable securities, accounts receivable and
accounts payable approximate fair value (see Note 2 "Long-Term Debt"
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 significant acquisition costs are
assessed quarterly on a property-by-property basis, and any impairment
in value is recognized. Unproved properties with acquisition costs
that are not individually significant are aggregated, and the portion
of such costs estimated to be nonproductive, based on historical
experience, is amortized over the average holding period. If the
unproved properties are determined to be productive, the appropriate
related costs are transferred to proved oil and gas properties. Lease
rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of drilling
exploratory wells, are charged to expense as incurred. The costs of
drilling exploratory wells are capitalized pending determination of
whether they have discovered proved commercial reserves. If proved
commercial reserves are not discovered, such drilling costs are
expensed. Costs to develop proved reserves, including the costs of all
development wells and related equipment used in the production of
natural gas and crude oil, are capitalized.
Depreciation, depletion and amortization of the cost of proved
oil and gas properties is calculated using the unit-of-production
method. Estimated future dismantlement, restoration and abandonment
costs (classified as long-term liabilities), net of salvage values,
are taken into account. Certain other assets are depreciated on a
straight-line basis.
Periodically, or when circumstances indicate that an asset may be
impaired, EOG compares expected undiscounted future cash flows at a
producing field level to the unamortized capitalized cost of the
asset. If the future undiscounted cash flows, based on EOG's estimate
of future crude oil and natural gas prices and operating costs and
anticipated production from proved
11
reserves are lower than the unamortized capitalized cost, the
capitalized cost is reduced to fair value. Fair value is calculated
by discounting the future cash flows at an appropriate risk-adjusted
discount rate.
Inventories, consisting primarily of tubular goods and well
equipment held for use in the exploration for, and development and
production of natural gas and crude oil reserves, are carried at cost
with adjustments made from time to time to recognize any reductions in
value.
Natural gas revenues are recorded when production is delivered.
EOG natural gas 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 may differ
from an owner's ownership percentage. Under entitlement accounting, a
receivable is recorded when underproduction occurs and a payable when
overproduction occurs.
Gains and losses associated with the sale of in place natural gas
and crude oil reserves and related assets are classified as net
operating revenues in the consolidated statements of income and
comprehensive income based on EOG's strategy of continuing such sales
in order to maximize the economic value of its assets.
New Accounting Pronouncements. In June 1998, the Financial
Accounting Standards Board ("FASB") issued Statement of Financial
Accounting Standards ("SFAS") No. 133--"Accounting for Derivative
Instruments and Hedging Activities" effective for fiscal years
beginning after June 15, 1999. SFAS No. 133, as amended by SFAS No.
137 and No. 138, cannot be applied retroactively. EOG adopted SFAS
No. 133, as amended, on January 1, 2001 for the accounting periods
which begin thereafter. The adoption of SFAS No. 133 did not have a
material impact on EOG's financial statements.
In June 2001, the FASB issued SFAS No. 143--"Accounting for Asset
Retirement Obligations" effective for fiscal years beginning after
June 15, 2002. SFAS No.143 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.
The fair value of the liability is added to the carrying amount of the
associated asset and this additional carrying amount is depreciated
over the life of the asset. If the obligation is settled for other
than the carrying amount of the liability, a gain or loss is
recognized on settlement. This statement will impact how EOG accounts
for its abandonment liability related to its oil and gas wells. EOG
is currently evaluating the effect of adopting SFAS No. 143 on its
financial statements and has not yet determined the timing of
adoption.
In August 2001, the FASB issued SFAS No. 144--"Accounting for the
Impairment or Disposal of Long-Lived Assets" effective for fiscal
years beginning after December 15, 2001. SFAS No. 144, which
supersedes SFAS No. 121--"Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of," provides that
long-lived assets to be disposed of by sale be measured at the lower
of carrying amount or fair value less cost to sell. In addition, SFAS
No. 144, which also supersedes the accounting and reporting provisions
of Accounting Principles Board ("APB") Opinion No. 30--"Reporting the
Results of Operations -- Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently
Occurring Events and Transactions," broadens the reporting of
discontinued operations to include all components of an entity with
operations that can be distinguished from the rest of the entity and
that will be eliminated from the ongoing operations of the entity in a
disposal transaction. EOG adopted the provisions of SFAS No. 144 on
January 1, 2002. This statement will impact how EOG tests for long-
lived asset impairments. EOG does not expect the impact of SFAS No.
144 to have a material effect on its financial position or results of
operations.
Accounting for Price Risk Management Activities. 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 costless collars, as
the means to manage this price risk. EOG adopted SFAS No. 133--
"Accounting for Derivative Instruments and Hedging Activities," as
amended by SFAS No. 137 and No. 138, on January 1, 2001 for the
accounting periods which begin thereafter. 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. Special
accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the statements
of income and requires a company to formally document, designate and
assess the effectiveness of transactions that receive hedge accounting
treatment. The adoption of SFAS No. 133 did not have a material impact
on EOG's financial statements. During 2001, 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 Mark-to-market
12
Gains (Losses) on Commodity Derivative Contracts in the Net Operating
Revenues section of the Consolidated Statements of Income. The
related cash flow impact is reflected as cash flows from operating
activities in the Consolidated Statements of Cash Flows (see Note 12
"Prices and Interest Rate Risk Management Activities").
Capitalized Interest Costs. Certain interest costs have been
capitalized as a part of the historical cost of unproved oil and gas
properties and work in progress for development drilling and related
facilities with significant cash outlays.
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 "Income
Taxes").
Foreign Currency Translation. For subsidiaries whose functional
currency is deemed to be other than the U.S. 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 as a
separate component of shareholders' equity. 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 "Net Income Per Share Available to Common" for
additional information to reconcile the difference between the Average
Number of Common Shares outstanding for basic and diluted net income
per share).
Stock Option Plans. EOG accounts for stock options under the
provisions and related interpretations of APB Opinion No. 25--
"Accounting for Stock Issued to Employees." No compensation expense
is recognized for such options. As allowed by SFAS No. 123--
"Accounting for Stock-Based Compensation" issued in 1995, EOG has
continued to apply APB Opinion No. 25 for purposes of determining net
income and to present the pro forma disclosures required by SFAS No.
123.
Information Regarding Forward-Looking Statements
------------------------------------------------
This Current Report on Form 8-K includes forward-looking
statements within the meaning of Section 27A of the Securities Act of
1933 and Section 21E of the Securities Exchange Act of 1934. All
statements other than statements of historical facts, including, among
others, statements regarding EOG's future financial position, business
strategy, budgets, reserve information, projected levels of
production, projected costs and plans and objectives of management for
future operations, are forward-looking statements. EOG typically uses
words such as "expect," "anticipate," "estimate," "strategy,"
"intend," "plan," "target" and "believe" or the negative of those
terms or other variations of them or by comparable terminology to
identify its forward-looking statements. In particular, statements,
express or implied, concerning future operating results, the ability
to increase reserves, 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 and
interest rates; the extent and effect of any hedging activities
engaged in by EOG; the extent of EOG's success in discovering,
developing, marketing and producing reserves and in acquiring oil and
gas properties; the accuracy of reserve estimates, which by their
nature involve the exercise of professional judgment and may therefore
be imprecise; political developments around the world, including
terrorist activities and responses to such activities; 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.
13
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The following consolidated financial statements of EOG
Resources, Inc. and its subsidiaries ("EOG") were prepared by
management, which is responsible for their integrity, objectivity and
fair presentation. The statements have been prepared in conformity
with accounting principles generally accepted in the United States
and, accordingly, include some amounts that are based on the best
estimates and judgments of management.
Arthur Andersen LLP, independent public accountants, was engaged
to audit the consolidated financial statements of EOG and issue a
report thereon. In the conduct of the audit, Arthur Andersen LLP was
given unrestricted access to all financial records and related data
including minutes of all meetings of shareholders, the Board of
Directors and committees of the Board. Their audit was made in
accordance with auditing standards generally accepted in the United
States and included a review of the system of internal controls to the
extent considered necessary to determine the audit procedures required
to support their opinion on the consolidated financial statements.
Management believes that all representations made to Arthur
Andersen LLP during the audit were valid and appropriate.
The system of internal controls of EOG is designed to provide
reasonable assurance as to the reliability of financial statements and
the protection of assets from unauthorized acquisition, use or
disposition. This system includes, but is not limited to, written
policies and guidelines including a published code for the conduct of
business affairs, conflicts of interest and compliance with laws
regarding antitrust, antiboycott and foreign corrupt practices
policies, the careful selection and training of qualified personnel,
and a documented organizational structure outlining the separation of
responsibilities among management representatives and staff groups.
The adequacy of financial controls of EOG and the accounting
principles employed in financial reporting by EOG are under the
general oversight of the Audit Committee of the Board of Directors. No
member of this committee is an officer or employee of EOG. The
independent public accountants and internal auditors have full, free,
separate and direct access to the Audit Committee and meet with the
committee from time to time to discuss accounting, auditing and
financial reporting matters. It should be recognized that there are
inherent limitations to the effectiveness of any system of internal
control, including the possibility of human error and circumvention or
override. Accordingly, even an effective system can provide only
reasonable assurance with respect to the preparation of reliable
financial statements and safeguarding of assets. Furthermore, the
effectiveness of an internal control system can change with
circumstances.
It is management's opinion that, considering the criteria for
effective internal control over financial reporting and safeguarding
of assets which consists of interrelated components including the
control environment, risk assessment process, control activities,
information and communication systems, and monitoring, EOG maintained
an effective system of internal control as to the reliability of
financial statements and the protection of assets against unauthorized
acquisition, use or disposition during the year ended December 31,
2001.
MARK G. PAPA EDMUND P. SEGNER, III TIMOTHY K. DRIGGERS
Chairman and President and Chief of Staff Vice President, Accounting
Chief Executive and Land Administration
Officer
Houston, Texas
February 21, 2002
14
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To EOG Resources, Inc.:
We have audited the accompanying consolidated balance sheets of
EOG Resources, Inc. (a Delaware corporation) and subsidiaries as of
December 31, 2001 and 2000, and the related consolidated statements of
income and comprehensive income, shareholders' equity and cash flows
for each of the three years in the period ended December 31, 2001.
These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States. Those standards require that
we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position of
EOG Resources, Inc. and subsidiaries as of December 31, 2001 and 2000,
and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2001, in conformity
with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
February 21, 2002
15
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(In Thousands, Except Per Share Amounts)
Year Ended December 31,
------------------------------------
2001 2000 1999
---------- ---------- ----------
NET OPERATING REVENUES
Natural Gas.............................................................. $1,298,102 $1,155,804 $ 683,469
Crude Oil, Condensate and Natural Gas Liquids............................ 258,101 325,726 159,373
Mark-to-market Gains (Losses) on Commodity Derivative Contracts.......... 97,750 (1,000) -
Gains (Losses) on Sales of Reserves and Related Assets and Other, Net.... 934 9,365 (743)
---------- ---------- ----------
Total................................................................. 1,654,887 1,489,895 842,099
OPERATING EXPENSES
Lease and Well........................................................... 175,446 140,915 132,233
Exploration Costs........................................................ 67,467 67,196 52,773
Dry Hole Costs........................................................... 71,360 17,337 11,893
Impairments.............................................................. 79,156 46,478 161,817
Depreciation, Depletion and Amortization................................. 392,399 359,265 329,668
General and Administrative............................................... 79,963 66,932 82,857
Taxes Other Than Income.................................................. 95,333 94,909 52,670
Charges Associated with Enron Bankruptcy................................. 19,211 - -
---------- ---------- ----------
Total................................................................. 980,335 793,032 823,911
---------- ---------- ----------
OPERATING INCOME........................................................... 674,552 696,863 18,188
OTHER INCOME (EXPENSE)
Gain on Share Exchange................................................... - - 575,151
Other, Net............................................................... 2,003 (2,300) 36,192
---------- ---------- ----------
Total................................................................. 2,003 (2,300) 611,343
---------- ---------- ----------
INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES............................ 676,555 694,563 629,531
INTEREST EXPENSE
Incurred................................................................. 53,756 67,714 72,413
Capitalized.............................................................. (8,646) (6,708) (10,594)
---------- ---------- ----------
Net Interest Expense.................................................. 45,110 61,006 61,819
---------- ---------- ----------
INCOME BEFORE INCOME TAXES................................................. 631,445 633,557 567,712
INCOME TAX PROVISION (BENEFIT)............................................. 232,829 236,626 (1,382)
---------- ---------- ----------
NET INCOME................................................................. 398,616 396,931 569,094
PREFERRED STOCK DIVIDENDS.................................................. 10,994 11,028 535
---------- ---------- ----------
NET INCOME AVAILABLE TO COMMON............................................. $ 387,622 $ 385,903 $ 568,559
========== ========== ==========
EARNINGS PER SHARE AVAILABLE TO COMMON
Basic.................................................................... $ 3.35 $ 3.30 $ 4.04
========== ========== ==========
Diluted.................................................................. $ 3.30 $ 3.24 $ 4.01
========== ========== ==========
AVERAGE NUMBER OF COMMON SHARES
Basic.................................................................... 115,765 116,934 140,648
========== ========== ==========
Diluted.................................................................. 117,488 119,102 141,627
========== ========== ==========
COMPREHENSIVE INCOME
NET INCOME................................................................. $ 398,616 $ 396,931 $ 569,094
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Translation Adjustment.................................. (22,044) (12,338) 16,038
Unrealized Gain (Loss) on Available-for-sale Security, Net of Tax........ (1,318) 392 -
---------- ---------- ----------
COMPREHENSIVE INCOME....................................................... $ 375,254 $ 384,985 $ 585,132
========== ========== ==========
The accompanying notes are an integral part of these consolidated financial statements.
16
EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands)
At December 31,
---------------------------
ASSETS 2001 2000
----------- -----------
CURRENT ASSETS
Cash and Cash Equivalents.............................................. $ 2,512 $ 20,152
Accounts Receivable, net............................................... 194,624 342,579
Inventories............................................................ 18,871 16,623
Assets from Price Risk Management Activities........................... 19,161 438
Federal Income Tax Deposit............................................. 19,332 -
Other.................................................................. 17,921 15,073
----------- -----------
Total.............................................................. 272,421 394,865
OIL AND GAS PROPERTIES (Successful Efforts Method)...................... 6,065,603 5,122,728
Less: Accumulated Depreciation, Depletion and Amortization............ (3,009,693) (2,597,721)
----------- -----------
Net Oil and Gas Properties......................................... 3,055,910 2,525,007
OTHER ASSETS............................................................ 85,713 81,381
----------- -----------
TOTAL ASSETS........................................................... $ 3,414,044 $ 3,001,253
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable....................................................... $ 219,561 $ 246,468
Accrued Taxes Payable.................................................. 40,219 78,838
Dividends Payable...................................................... 5,045 4,525
Accrued Employee Benefits.............................................. 16,345 13,654
Other.................................................................. 29,677 26,631
----------- -----------
Total.............................................................. 310,847 370,116
LONG-TERM DEBT.......................................................... 855,969 859,000
OTHER LIABILITIES....................................................... 53,522 51,133
DEFERRED INCOME TAXES................................................... 551,020 340,079
SHAREHOLDERS' EQUITY
Preferred Stock, $.01 Par, 10,000,000 Shares Authorized:
Series B, 100,000 shares Issued, Cumulative,
$100,000,000 Liquidation Preference............................... 98,116 97,879
Series D, 500 shares Issued, Cumulative,
$50,000,000 Liquidation Preference................................ 49,466 49,285
Common Stock, $.01 Par, 320,000,000 shares Authorized and
124,730,000 shares Issued............................................ 201,247 201,247
Additional Paid In Capital............................................. - 4,221
Unearned Compensation.................................................. (14,953) (3,756)
Accumulated Other Comprehensive Loss................................... (55,118) (31,756)
Retained Earnings...................................................... 1,668,708 1,301,067
Common Stock Held in Treasury, 9,278,382 shares at December 31, 2001
and 7,825,708 shares at December 31, 2000............................ (304,780) (237,262)
----------- -----------
Total Shareholders' Equity............................................. 1,642,686 1,380,925
----------- -----------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY............................. $ 3,414,044 $ 3,001,253
=========== ===========
The accompanying notes are an integral part of these consolidated financial statements.
17
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, 1998.... $ -- $201,600 $ 401,524 $(4,900) $(35,848) $ 838,371 $ (120,443) $ 1,280,304
Net Income..................... -- -- -- -- -- 569,094 -- 569,094
Preferred Stock Issued....... 147,175 -- -- -- -- -- -- 147,175
Amortization of Preferred
Stock Discount.............. 15 -- -- -- -- -- -- 15
Common Stock Issued.......... -- 270 577,662 -- -- -- -- 577,932
Preferred Stock Dividends
Paid/Declared................ -- -- -- -- -- (535) -- (535)
Common Stock Dividends
Declared, $.12 Per Share.... -- -- -- -- -- (16,377) -- (16,377)
Translation Adjustment........ -- -- -- -- 16,038 -- -- 16,038
Treasury Stock Purchased..... -- -- -- -- -- -- (2,143) (2,143)
Treasury Stock Received in Share
Exchange.................... -- -- -- -- -- -- (1,459,484) (1,459,484)
Common Stock Retired......... -- (623) (978,224) -- -- (458,033) 1,436,880 --
Treasury Stock Issued Under
Stock Option Plans.......... -- -- (2,274) 136 -- (1,582) 16,854 13,134
Tax Benefits from Stock
Options Exercised.......... -- -- 1,387 -- -- -- -- 1,387
Amortization of Unearned
Compensation................ -- -- -- 3,146 -- -- -- 3,146
Other.......................... -- -- (75) -- -- -- -- (75)
--------------------------------------------------------------------------------------------------
Balance at December 31, 1999.... 147,190 201,247 -- (1,618) (19,810) 930,938 (128,336) 1,129,611
Net Income..................... -- -- -- -- -- 396,931 -- 396,931
Amortization of Preferred
Stock Discount.............. 419 -- -- -- -- (419) -- --
Exchange Offer Fees.......... (445) -- -- -- -- -- -- (445)
Preferred Stock Dividends
Paid/Declared............... -- -- -- -- -- (10,609) -- (10,609)
Common Stock Dividends
Declared, $.14 Per Share..... -- -- -- -- -- (15,774) -- (15,774)
Translation Adjustment......... -- -- -- -- (12,338) -- -- (12,338)
Unrealized Gain on Available-
for-sale Security........... -- -- -- -- 392 -- -- 392
Treasury Stock Purchased..... -- -- -- -- -- -- (272,723) (272,723)
Treasury Stock Issued Under
Stock Option Plans.......... -- -- (36,701) -- -- -- 163,350 126,649
Tax Benefits from Stock
Options Exercised.......... -- -- 41,307 -- -- -- -- 41,307
Restricted Stock and Units..... -- -- 2,805 (3,411) -- -- 606 --
Amortization of Unearned
Compensation................ -- -- -- 1,273 -- -- -- 1,273
Equity Derivative Transactions. -- -- (3,190) -- -- -- -- (3,190)
Other.......................... -- -- -- -- -- -- (159) (159)
--------------------------------------------------------------------------------------------------
Balance at December 31, 2000.... 147,164 201,247 4,221 (3,756) (31,756) 1,301,067 (237,262) 1,380,925
Net Income..................... -- -- -- -- -- 398,616 -- 398,616
Amortization of Preferred
Stock Discount.............. 418 -- -- -- -- (418) -- --
Preferred Stock Dividends
Paid/Declared............... -- -- -- -- -- (10,576) -- (10,576)
Common Stock Dividends
Declared, $.16 Per Share..... -- -- -- -- -- (18,523) -- (18,523)
Translation Adjustment......... -- -- -- -- (22,044) -- -- (22,044)
Unrealized Loss on Available-
for-sale Security............ -- -- -- -- (1,318) -- -- (1,318)
Treasury Stock Purchased..... -- -- -- -- -- -- (126,769) (126,769)
Treasury Stock Issued Under
Stock Option Plans........ -- -- (19,097) -- -- (1,458) 50,403 29,848
Treasury Stock Issued Under
Employee Stock Purchase Plan. -- -- (104) -- -- -- 1,061 957
Tax Benefits from Stock
Options Exercised.......... -- -- 7,332 -- -- -- -- 7,332
Restricted Stock and Units.... -- -- 6,583 (14,467) -- -- 7,884 --
Amortization of Unearned
Compensation................ -- -- -- 3,270 -- -- -- 3,270
Equity Derivative Transactions. -- -- 1,201 -- -- -- -- 1,201
Other.......................... -- -- (136) -- -- -- (97) (233)
--------------------------------------------------------------------------------------------------
Balance at December 31, 2001.... $147,582 $201,247 $ -- $ (14,953) $(55,118) $1,668,708 $ (304,780) $ 1,642,686
==================================================================================================
The accompanying notes are an integral part of these consolidated financial statements.
18
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
Year Ended December 31,
-------------------------------------
2001 2000 1999
----------- ---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of Net Income to Net Operating Cash Inflows:
Net Income................................................................... $ 398,616 $ 396,931 $ 569,094
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization................................... 392,399 359,265 329,668
Impairments................................................................ 79,156 46,478 161,817
Deferred Income Taxes...................................................... 164,945 97,729 (26,252)
Charges Related to Enron Bankruptcy.................................... 19,211 -- --
Other, Net................................................................. 10,423 6,693 25,583
Exploration Costs............................................................ 67,467 67,196 52,773
Dry Hole Costs............................................................... 71,360 17,337 11,893
Mark-to-market Commodity Derivative Contracts
Total (Gains) Losses........................................................ (97,750) 1,000 --
Realized Gains (Losses)..................................................... 62,110 (1,438) --
Losses (Gains) On Sales of Reserves and Related Assets and Other, Net...... 835 (5,539) 5,602
Gains on Sales of Other Assets............................................... -- -- (59,647)
Gain on Share Exchange....................................................... -- -- (575,151)
Tax Benefits from Stock Options Exercised.................................... 7,332 41,307 1,387
Other, Net................................................................... (3,127) (8,935) (19,081)
Changes in Components of Working Capital and Other Liabilities
Accounts Receivable......................................................... 146,235 (191,492) (12,914)
Inventories................................................................. (2,248) 2,345 5,180
Accounts Payable............................................................ (26,949) 97,374 4,395
Accrued Taxes Payable....................................................... (38,619) 54,556 2,449
Other Liabilities........................................................... (3,422) 348 (15,438)
Other, Net.................................................................. (16,442) 11,378 (9,960)
Changes in Components of Working Capital
Associated with Investing and Financing Activities........................ (34,105) (25,123) (7,879)
----------- ----------- ---------
NET OPERATING CASH INFLOWS.................................................... 1,197,427 967,410 443,519
INVESTING CASH FLOWS
Additions to Oil and Gas Properties.......................................... (974,016) (602,638) (396,450)
Exploration Costs............................................................ (67,467) (67,196) (52,773)
Dry Hole Costs............................................................... (71,360) (17,337) (11,893)
Proceeds from Sales of Reserves and Related Assets........................... 8,032 26,189 10,934
Proceeds from Sales of Other Assets...................................... -- -- 82,965
Changes in Components of Working Capital
Associated with Investing Activities...................................... 32,405 22,798 7,909
Other, Net................................................................... (15,649) (28,977) (4,057)
----------- ----------- ----------
NET INVESTING CASH OUTFLOWS................................................... (1,088,055) (667,161) (363,365)
FINANCING CASH FLOWS
Long-Term Debt
Third Party................................................................. (4,155) (131,306) 47,527
Affiliate................................................................... -- -- (200,000)
Proceeds from Preferred Stock Issued..................................... -- -- 147,175
Proceeds from Common Stock Issued............................................ -- -- 577,932
Dividends Paid............................................................... (28,580) (26,071) (17,395)
Treasury Stock Purchased..................................................... (126,769) (272,723) (2,143)
Proceeds from Sales of Treasury Stock........................................ 30,805 127,090 13,341
Equity Contribution to Transferred Subsidiaries.............................. -- -- (608,750)
Other, Net................................................................... 1,687 (1,923) (19,308)
----------- ----------- ----------
NET FINANCING CASH OUTFLOWS................................................... (127,012) (304,933) (61,621)
----------- ----------- ----------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.............................. (17,640) (4,684) 18,533
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR............................... 20,152 24,836 6,303
----------- ----------- ----------
CASH AND CASH EQUIVALENTS AT END OF YEAR..................................... $ 2,512 $ 20,152 $ 24,836
=========== =========== ==========
The accompanying notes are an integral part of these consolidated financial statements.
19
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"), a Delaware corporation,
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
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.
Beginning 2001, the "Impairment of Unproved Oil and Gas Properties"
caption on the Consolidated Statements of Income was renamed
"Impairments" to include the impairment loss of long-lived assets as
described in Statement of Financial Accounting Standards ("SFAS") No.
121--"Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to Be Disposed of " ("SFAS 121 Impairments"). As a
result, EOG reclassified all prior periods to reflect such SFAS 121
Impairments in Impairments, instead of Depreciation, Depletion and
Amortization ("DD&A") as previously reported. SFAS 121 Impairments
reclassified from DD&A to Impairments were $11 million and $133
million for 2000 and 1999, respectively.
Financial Instruments. EOG's financial instruments consist of
cash and cash equivalents, marketable securities, accounts
receivable, accounts payable and long-term debt. The carrying values
of cash and cash equivalents, marketable securities, accounts
receivable and accounts payable approximate fair value (see Note 2
"Long-Term Debt" 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 significant acquisition costs are
assessed quarterly on a property-by-property basis, and any
impairment in value is recognized. Unproved properties with
acquisition costs that are not individually significant are
aggregated, and the portion of such costs estimated to be
nonproductive, based on historical experience, is amortized over the
average holding period. If the unproved properties are determined to
be productive, the appropriate related costs are transferred to
proved oil and gas properties. Lease rentals are expensed as
incurred.
Oil and gas exploration costs, other than the costs of drilling
exploratory wells, are charged to expense as incurred. The costs of
drilling exploratory wells are capitalized pending determination of
whether they have discovered proved commercial reserves. If proved
commercial reserves are not discovered, such drilling costs are
expensed. Costs to develop proved reserves, including the costs of
all development wells and related equipment used in the production of
natural gas and crude oil, are capitalized.
Depreciation, depletion and amortization of the cost of proved
oil and gas properties is calculated using the unit-of-production
method. Estimated future dismantlement, restoration and abandonment
costs (classified as long-term liabilities), net of salvage values,
are taken into account. Certain other assets are depreciated on a
straight-line basis.
Periodically, or when circumstances indicate that an asset may
be impaired, EOG compares expected undiscounted future cash flows at
a producing field level to the unamortized capitalized cost of the
asset. If the future undiscounted cash flows, based on EOG's estimate
of future crude oil and natural gas prices and operating costs and
anticipated production from proved reserves, 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.
20
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Inventories, consisting primarily of tubular goods and well
equipment held for use in the exploration for, and development and
production of natural gas and crude oil reserves, are carried at cost
with adjustments made from time to time to recognize any reductions
in value.
Natural gas and liquids revenues are recorded when production is
delivered. Additionally, natural gas 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 may differ from an owner's ownership percentage.
Under entitlement accounting, a receivable is recorded when
underproduction occurs and a payable when overproduction occurs.
Gains and losses associated with the sale of in place natural
gas and crude oil reserves and related assets are classified as net
operating revenues in the consolidated statements of income and
comprehensive income based on EOG's strategy of continuing such sales
in order to maximize the economic value of its assets.
New Accounting Pronouncements. In June 1998, the Financial
Accounting Standards Board ("FASB") issued Statement of Financial
Accounting Standards ("SFAS") No. 133--"Accounting for Derivative
Instruments and Hedging Activities" effective for fiscal years
beginning after June 15, 1999. SFAS No. 133, as amended by SFAS No.
137 and No. 138, cannot be applied retroactively. EOG adopted SFAS
No. 133, as amended, on January 1, 2001 for the accounting periods
which begin thereafter. The adoption of SFAS No. 133 did not have a
material impact on EOG's financial statements.
In June 2001, the FASB issued SFAS No. 143--"Accounting for
Asset Retirement Obligations" effective for fiscal years beginning
after June 15, 2002. SFAS No. 143 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. The fair value of the liability is added to the
carrying amount of the associated asset and this additional carrying
amount is depreciated over the life of the asset. If the obligation
is settled for other than the carrying amount of the liability, a
gain or loss is recognized on settlement. This statement will impact
how EOG accounts for its abandonment liability related to its oil and
gas wells. EOG is currently evaluating the effect of adopting SFAS
No. 143 on its financial statements and has not yet determined the
timing of adoption.
In August 2001, the FASB issued SFAS No. 144--"Accounting for the
Impairment or Disposal of Long-Lived Assets" effective for fiscal
years beginning after December 15, 2001. SFAS No. 144, which
supersedes SFAS No. 121--"Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of," provides that
long-lived assets to be disposed of by sale be measured at the lower
of carrying amount or fair value less cost to sell. In addition,
SFAS No. 144, which also supersedes the accounting and reporting
provisions of Accounting Principles Board ("APB") Opinion No. 30--
"Reporting the Results of Operations -- Reporting the Effects of
Disposal of a Segment of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions," broadens the
reporting of discontinued operations to include all components of an
entity with operations that can be distinguished from the rest of the
entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction. EOG adopted the provisions of SFAS
No. 144 on January 1, 2002. This statement will impact how EOG tests
for long-lived asset impairments. EOG does not expect the impact of
SFAS No. 144 to have a material effect on its financial position or
results of operations.
Accounting for Price Risk Management Activities. 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 costless collars, as
the means to manage this price risk. EOG adopted SFAS No. 133--
"Accounting for Derivative Instruments and Hedging Activities," as
amended by SFAS No. 137 and No. 138, on January 1, 2001 for the
accounting periods which begin thereafter. The statement establishes
accounting and reporting standards requiring that every derivative
instrument be recorded in the balance sheet as either an asset
21
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. Special
accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the statements
of income and requires a company to formally document, designate and
assess the effectiveness of transactions that receive hedge
accounting treatment. The adoption of SFAS No. 133 did not have a
material impact on EOG's financial statements. During 2001, 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 Mark-to-market Gains
(Losses) on Commodity Derivative Contracts in the Net Operating
Revenues section of the Consolidated Statements of Income. The
related cash flow impact is reflected as cash flows from operating
activities in the Consolidated Statements of Cash Flows (see Note 12
"Prices and Interest Rate Risk Management Activities").
Capitalized Interest Costs. Certain interest costs have been
capitalized as a part of the historical cost of unproved oil and gas
properties and work in progress for development drilling and related
facilities with significant cash outlays.
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 "Income Taxes").
Foreign Currency Translation. For subsidiaries whose functional
currency is deemed to be other than the U.S. 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 as a
separate component of shareholders' equity. 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 "Net Income Per Share Available to Common" 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 Plans. EOG accounts for stock options under
the provisions and related interpretations of 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.
2. Long-Term Debt
--------------
Long-Term Debt at December 31 consisted of the following (in
thousands):
2001 2000
--------- ---------
Uncommitted Credit Facilities............... $ 95,147 $ 38,800
6.50% Notes due 2004........................ 100,000 100,000
6.70% Notes due 2006........................ 126,870 150,000
6.50% Notes due 2007........................ 100,000 100,000
6.00% Notes due 2008........................ 173,952 175,000
6.65% Notes due 2028........................ 140,000 150,000
Subsidiary Debt due 2001.................... -- 105,000
Subsidiary Debt due 2002.................... -- 40,200
Subsidiary Debt due 2011.................... 120,000 --
--------- ---------
Total.................................. $ 855,969 $ 859,000
========= =========
22
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
EOG maintains two credit facilities with different expiration
dates. In July 2001, the $375 million credit facility that was
scheduled to expire was renewed for $300 million and the $400 million
facility due to expire in 2004 was reduced to $300 million, thereby
reducing aggregate long-term committed credit from $775 million to
$600 million. Credit facility expirations are as follows: $300
million in July 2002 and $300 million in July 2004. With respect to
the $300 million expiring in 2002, EOG may, at its option, extend the
final maturity date of any advances made under the facility by one
full year from the expiration date of the facility, effectively
qualifying such debt as long term. Advances under both agreements
bear interest, at the option of EOG, based upon a base rate or a
Eurodollar rate. No amounts were borrowed on these committed
credit facilities at December 31, 2001.
During 2001 and 2000, EOG utilized commercial paper and
short-term funding from uncommitted credit facilities, bearing market
interest rates, for various corporate financing purposes. Commercial
paper and uncommitted credit borrowings are classified as long-term
debt based on EOG's intent and ability to ultimately replace such
amounts with other long-term debt.
The 6.00% to 6.70% Notes due 2004 to 2028 were issued through
public offerings and have effective interest rates of 6.14% to 6.83%.
The Subsidiary Debts due 2001 and 2002 were fully paid in 2001 by
increased borrowings from commercial paper and uncommitted credit
facilities. The Subsidiary Debt due 2011 bears interest at a fixed
rate of 7% and is guaranteed by EOG.
At December 31, 2001, the aggregate annual maturities of long-
term debt outstanding were none for 2002, none for 2003, $100 million
for 2004, none for 2005, and $127 million in 2006.
EOG's credit facilities 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. During the third quarter of 2000, EOG filed
a shelf registration statement for the offer and sale from time to
time of up to $600 million of EOG debt securities, preferred stock
and/or common stock. The registration statement was declared
effective by the Securities and Exchange Commission on October 27,
2000. As of February 21, 2002, EOG had sold no securities pursuant
to this shelf registration. When combined with the unused portion of
a previously filed registration statement declared effective in
January 1998, these registration statements provide for the offer and
sale from time to time of EOG debt securities, preferred stock and/or
common stock by EOG in an aggregate amount up to $688 million.
Fair Value Of Long-Term Debt. At December 31, 2001 and 2000,
EOG had $856 million and $859 million, respectively, of long-term
debt which had fair values of approximately $838 million and
$831 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 debtholder for the differential between the stated
interest rate and the year-end market rate. The fair value of
long-term debt is based upon quoted market prices and, where such
quotes were not available, upon interest rates available to EOG at
yearend.
3. Shareholders' Equity
--------------------
EOG purchases from time to time in the open market its common
stock to be held in treasury for the purpose of, but not limited to,
fulfilling any obligations arising under EOG's stock option 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, 2001, 8,617,000 shares remain available for
repurchases under this authorization.
To supplement its share repurchase program, EOG enters into equity
derivative transactions from time to time. These transactions are
accounted for as equity transactions with premiums received recorded
to Additional Paid In Capital in the Consolidated Balance Sheets.
Settlement alternatives under all circumstances are at the option of
EOG and include physical share, net share and net cash settlement.
During the second quarter of 2001, EOG sold put options for $1.2
million obligating EOG to purchase up to 0.6 million shares of its
common stock at an average price of $33.42 per share. These options
expired unexercised in December 2001. During the first half of 2000,
EOG entered into a series of equity derivative transactions receiving
$0.6 million. During the third quarter of 2000, EOG closed
substantially all of its equity derivative contracts which were to
expire in April 2001 by paying $3.75 million. EOG had one million
put options which it had written
23
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
which were outstanding at December 31, 2000. The strike price of
these options was $18.00 per share, and they expired unexercised in
April 2001.
On July 23, 1999, EOG filed a registration statement with the
Securities and Exchange Commission for the public offering of
27,000,000 shares of EOG's common stock. The public offering was
completed on August 16, 1999, and the portion of net proceeds
received by EOG was used to repay short-term borrowings used to fund
a significant portion of the cash capital contribution in connection
with the Share Exchange Agreement ("Share Exchange") described in
Note 4 "Transactions with Enron Corp." As a result of the public
offering and the retirement of the 62,270,000 shares of EOG's common
stock received from Enron Corp. in the Share Exchange transaction,
the number of shares of EOG's common stock issued was reduced to
124,730,000 from 160,000,000 prior to the Share Exchange.
The following summarizes shares of common stock outstanding (in
thousands):
Common Shares
------------------------------
2001 2000 1999
-------- -------- --------
Outstanding at January 1................................ 116,904 119,105 153,724
Repurchased............................................ (3,281) (8,910) (130)
Issued Pursuant to Stock Options and Stock Plans....... 1,829 6,709 781
Retired................................................ - - (62,270)
Public Offering........................................ - - 27,000
Outstanding at December 31.............................. 115,452 116,904 119,105
Series A. On December 10, 1999, EOG issued 100,000 shares of
Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A,
with a $1,000 Liquidation Preference per share, in a private
transaction. Dividends will be payable on the shares only if declared
by EOG's board of directors and will be cumulative. If declared,
dividends will be payable at a rate of $71.95 per share, per year on
March 15, June 15, September 15, and December 15 of each year
beginning March 15, 2000. EOG may redeem all or a part of the
Series A preferred stock at any time beginning on December 15, 2009
at $1,000 per share, plus accrued and unpaid dividends. The shares
may also be redeemable, in whole but not in part, in the event that
certain amendments are made to the Dividend Received Percentage. The
Series A preferred shares are not convertible into, or exchangeable
for, common stock of EOG.
Series C. On December 22, 1999, EOG issued 500 shares of
Flexible Money Market Cumulative Preferred Stock, Series C, with a
liquidation preference of $100,000 per share, in a private
transaction. Dividends will be payable on the shares only if declared
by EOG's board of directors and will be cumulative. The initial
dividend rate on the shares will be 6.84% until December 15, 2004
(the "Initial Period-End Dividend Payment Date"). Through the Initial
Period-End Dividend Payment Date dividends will be payable, if
declared, on March 15, June 15, September 15, and December 15 of each
year beginning March 15, 2000. The cash dividend rate for each
subsequent dividend period will be determined pursuant to periodic
auctions conducted in accordance with certain auction procedures. The
first auction date will be December 14, 2004. After December 15,
2004 (unless EOG has elected a "Non-Call Period" for a subsequent
dividend period), EOG may redeem the shares, in whole or in part, on
any dividend payment date at $100,000 per share plus accumulated and
unpaid dividends. The shares may also be redeemable, in whole but not
in part, in the event that certain amendments are made to the
Dividend Received Percentage. The Series C preferred shares are not
convertible into, or exchangeable for, common stock of EOG.
During the third quarter of 2000, EOG completed two exchange
offers for its preferred stock whereby shares of EOG's Series A
preferred stock were exchanged for shares of EOG's Series B preferred
stock, and shares of EOG's Series C preferred stock were exchanged
for shares of EOG's Series D preferred stock. All preferred shares
were validly tendered and not withdrawn prior to expiration of the
offers. EOG accepted all of the tendered shares and issued the
respective series in exchange. Both exchange offers were registered
under the Securities Act of 1933. The Series B preferred stock has
substantially the same terms as Series A and the Series D preferred
stock has substantially the same terms as Series C.
On February 14, 2000, EOG's Board of Directors declared a
dividend of one preferred share purchase right (a "Right," and the
agreement governing the terms of such Rights, the "Rights Agreement")
for each outstanding share of common stock, par value $.01 per share.
The Board of Directors has adopted this Rights Agreement to protect
stockholders from coercive or otherwise unfair takeover tactics. The
dividend was distributed to the stockholders of record on
February 24, 2000. Each Right, expiring February 24, 2010, represents
a right to buy from EOG one hundredth (1/100) of a share of Series E
Junior Participating Preferred Stock ("Preferred Share") for $90,
once the Rights become exercisable. This portion of a Preferred Share
will give the stockholder approximately the same dividend, voting,
and liquidation rights as would one share of common
24
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
As amended on December 13, 2001, 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.
If a person or group becomes an Acquiring Person, all holders of
Rights except the Acquiring Person may, for $90, purchase shares of
EOG's common stock with a market value of $180, based on the market
price of the common stock prior to such acquisition. If EOG is later
acquired in a merger or similar transaction after the Rights become
exercisable, all holders of Rights except the Acquiring Person may,
for $90, purchase shares of the acquiring corporation with a market
value of $180 based on the market price of the acquiring
corporation's stock, prior to such merger.
EOG's Board of Directors may redeem the Rights for $.01 per
Right at any time before any person or group becomes an Acquiring
Person. If the Board of Directors redeems any Rights, it must redeem
all of the Rights. Once the Rights are redeemed, the only right of
the holders of Rights will be to receive the redemption price of
$.01 per Right. The redemption price will be adjusted if EOG has a
stock split or stock dividends of EOG's common stock. After a person
or group becomes an Acquiring Person, but before an Acquiring Person
owns 50% or more of EOG's outstanding common stock, the Board of
Directors may exchange the Rights for common stock or equivalent
security at an exchange ratio of one share of common stock or an
equivalent security for each such Right, other than Rights held by
the Acquiring Person.
4. Transactions with Enron Corp.
-----------------------------
Enron Corp. Bankruptcy. In December 2001, Enron Corp. and
certain of its affiliates, including Enron North America Corp., filed
voluntary petitions for reorganization under Chapter 11 of the United
States Bankruptcy Code. EOG recorded $19.2 million in charges
associated with the Enron bankruptcies in the fourth quarter of 2001
related to certain contracts with Enron affiliates, including 2001
and 2002 natural gas and crude oil derivative contracts. EOG has
other contractual relationships with Enron Corp. and certain of its
affiliates. Based on EOG's review of these other matters, EOG
believes that Enron Corp.'s Chapter 11 proceedings will not have a
material adverse effect on EOG's financial position.
Share Exchange. On August 16, 1999, EOG and Enron Corp.
completed the Share Exchange whereby EOG received 62,270,000 shares
of EOG's common stock out of 82,270,000 shares owned by Enron Corp.
in exchange for all the stock of EOG's subsidiary, EOGI-India, Inc.
Prior to the Share Exchange, EOG made an indirect capital
contribution of approximately $600 million in cash, plus certain
intercompany receivables, to EOGI-India, Inc. At the time of
completion of this transaction, this subsidiary owned, through
subsidiaries, all of EOG's assets and operations in India and China.
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. Immediately following the Share Exchange, EOG
retired the 62,270,000 shares of EOG's common stock received in the
transaction. The weighted average basis in the treasury shares
retired was first deducted from and fully eliminated existing
additional paid in capital with the remaining value deducted from
retained earnings. This transaction is a tax-free exchange to EOG. On
August 30, 1999, EOG changed its corporate name to "EOG
Resources, Inc." from "Enron Oil & Gas Company" and has since made
similar changes to its subsidiaries' names.
25
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Immediately prior to the closing of the Share Exchange, Enron
Corp. owned 82,270,000 shares of EOG's common stock, representing
approximately 53.5 percent of all of the shares of EOG's common stock
that were issued and outstanding. As a result of the closing of the
Share Exchange, the sale by Enron Corp. of 8,500,000 shares of EOG's
common stock as a selling stockholder in the public offering referred
to in Note 3 "Shareholders' Equity," and the completion on August 17,
1999 and August 20, 1999 of the offering of Enron Corp. notes
mandatorily exchangeable at maturity into a minimum of 9,746,250 up
to a maximum of 11,500,000 shares of EOG's common stock, Enron Corp's
maximum remaining interest in EOG after the automatic conversion of
its notes on July 31, 2002, will be under two percent (assuming the
notes are exchanged for less than the 11,500,000 shares of EOG's
common stock). As a result of Enron Corp.'s bankruptcy filing and
because the Enron Corp. notes were unsecured, EOG believes it is
unlikely that they will be exchanged for the shares of EOG's common
stock. The entire 11,500,000 shares of EOG's common stock are
included in EOG's outstanding common stock. Two entities not
affiliated with Enron Corp. have recently filed Schedule 13Gs with the
Securities and Exchange Commission with respect to these shares.
Effective as of August 16, 1999, the closing date of the Share
Exchange, the members of the board of directors of EOG who were
officers or directors of Enron Corp. resigned their positions as
directors of EOG.
Natural Gas and Crude Oil, Condensate and Natural Gas Liquids
Net Operating Revenues. Prior to the Share Exchange, Natural Gas and
Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues
included revenues from and associated costs paid to various
subsidiaries and affiliates of Enron Corp. pursuant to contracts
which, in the opinion of management, were no less favorable than
could be obtained from third parties. Revenues from sales to Enron
Corp. and its affiliates totaled $57.3 million in 1999 prior to the
Share Exchange. Natural Gas and Crude Oil, Condensate and Natural
Gas Liquids Net Operating Revenues also included certain commodity
price swap and NYMEX-related commodity transactions with Enron Corp.
affiliated companies, which in the opinion of management, were no
less favorable than could be received from third parties (see Note 12
"Price and Interest Rate Risk Management Activities").
General and Administrative Expenses. Prior to the Share
Exchange, EOG was charged by Enron Corp. for all direct costs
associated with its operations. Such direct charges, excluding
benefit plan charges (see Note 6 "Employee Benefit Plans"), totaled
$10.6 million for the year ended December 31, 1999. Additionally,
certain administrative costs not directly charged to any Enron Corp.
operations or business segments were allocated to the entities of the
consolidated group. Approximately $3.4 million was incurred by EOG
for indirect general and administrative expenses for 1999.
Management believes that these charges were reasonable.
Sale of Enron Corp. Options. In December 1997, EOG and Enron
Corp. entered into an Equity Participation and Business Opportunity
Agreement. Under the agreement, among other things, Enron Corp.
granted EOG options to purchase 3.2 million shares of Enron Corp.
During 1999, EOG sold the 3.2 million options and recognized a pre-
tax gain of $59.6 million. The gain on sale of the options is
included in other income (expense) - other, net in the consolidated
statements of income and comprehensive income.
26
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Income Taxes
The principal components of EOG's net deferred income tax
liability at December 31, 2001 and 2000 were as follows (in
thousands):
2001 2000
-------- --------
Deferred Income Tax Assets
Non-Producing Leasehold Costs................................... $ 26,727 $ 22,623
Seismic Costs Capitalized for Tax............................... 17,828 15,536
Trading Activity................................................ - 4,420
Section 29 Credit Monetization.................................. - 12,774
Other........................................................... 26,325 16,743
-------- --------
Total Deferred Income Tax Assets........................... 70,880 72,096
Deferred Income Tax Liabilities
Oil and Gas Exploration and Development Costs Deducted for
Tax Over Book Depreciation, Depletion and Amortization....... 599,945 403,808
Capitalized Interest............................................ 8,373 5,697
Trading Activity................................................ 10,107 -
Other........................................................... 3,475 2,670
-------- --------
Total Deferred Income Tax Liabilities...................... 621,900 412,175
-------- --------
Net Deferred Income Tax Liability.......................... $551,020 $340,079
======== ========
The components of income (loss) before income taxes were as follows (in thousands):
2001 2000 1999
-------- -------- --------
United States...................................................... $488,741 $491,823 $580,285
Foreign............................................................ 142,704 141,734 (12,573)
-------- -------- --------
Total........................................................... $631,445 $633,557 $567,712
======== ======== ========
Total income tax provision (benefit) was as follows (in thousands):
2001 2000 1999
-------- -------- --------
Current:
Federal........................................................... $ 36,737 $ 81,912 $ 5,510
State............................................................. 5,475 7,528 3,234
Foreign........................................................... 25,672 49,457 16,126
-------- -------- --------
Total............................................................ 67,884 138,897 24,870
Deferred:
Federal........................................................... 131,127 78,833 (49,474)
State............................................................. 10,411 10,324 (502)
Foreign........................................................... 23,407 8,572 23,724
-------- -------- --------
Total............................................................ 164,945 97,729 (26,252)
-------- -------- --------
Income Tax Provision (Benefit)...................................... $232,829 $236,626 $ (1,382)
======== ======== ========
The differences between taxes computed at the U.S. federal statutory tax rate and EOG's
effective rate were as follows:
2001 2000 1999
-------- -------- --------
Statutory Federal Income Tax Rate................................... 35.00% 35.00% 35.00%
State Income Tax, Net of Federal Benefit............................ 1.64 1.83 0.31
Income Tax Provision Related to Foreign Operations.................. 0.36 1.32 1.60
Tight Gas Sands Federal Income Tax Credits........................ (0.16) - (1.45)
Revision of Prior Years' Tax Estimates.............................. (0.21) 0.16 (0.21)
Share Exchange...................................................... - - (35.46)
Other............................................................... 0.24 (0.96) (0.03)
------- ------- -------
Effective Income Tax Rate...................................... 36.87% 37.35% (0.24)%
======= ====== =======
27
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
EOG's foreign subsidiaries' undistributed earnings of
approximately $515 million at December 31, 2001 are considered to be
indefinitely invested outside the U.S. and, accordingly, no
U.S. federal or state income taxes have been provided thereon. Upon
distribution of those earnings in the form of dividends, EOG may be
subject to both foreign withholding taxes and U.S. income taxes, net
of allowable foreign tax credits. Determination of any potential
amount of unrecognized deferred income tax liabilities is not
practicable.
In 1999 and 2000, EOG entered into arrangements with a third
party whereby certain Section 29 credits (Tight Gas Sands Federal
Income Tax Credits) were sold by EOG to the third party, and payments
for such credits will be received on an as-generated basis. As a
result of these transactions, EOG recorded a deferred tax asset
representing a tax gain on the sale of the Section 29 credit
properties, which will reverse as the results of operations of such
properties are recognized for book purposes.
6. Employee Benefit Plans
----------------------
Employees of EOG were covered by various retirement, stock
purchase and other benefit plans of Enron Corp. through August 1999.
During the year ended December 31, 1999, EOG was charged $4.4 million
for all such benefits, including pension expense totaling
$0.9 million by Enron Corp.
Pension Plans
Since August 1999, EOG has adopted defined contribution pension
and savings plans for most of its employees in the United States.
EOG's contributions to these plans are based on various percentages
of compensation, and in some instances, are based upon the amount of
the employees' contributions to the plan. For 2001 and 2000, the
cost of these plans amounted to approximately $6.2 million and $5.5
million, respectively. From August 31, 1999 to December 31, 1999 the
cost of these plans amounted to approximately $1.2 million.
EOG also has in effect pension and savings plans related to its
Canadian and Trinidadian subsidiaries. Activity related to these
plans is not material relative to EOG's operations.
Postretirement Plan
During 2000, EOG adopted postretirement medical and dental
benefits for eligible employees and their eligible dependents.
Benefits are provided under the provisions of a contributory defined
dollar benefit plan. EOG accrues these postretirement benefit costs
over the service lives of the employees expected to be eligible to
receive such benefits. As of December 31, 2001 and December 31, 2000,
the postretirement plan had a benefit obligation of $2.0 million and
$1.5 million, respectively. During 2001 and 2000, EOG recognized a
net periodic benefit cost related to this plan of $0.4 million and
$0.3 million, respectively.
Stock Plans
Stock Options. EOG has various stock plans ("the Plans") under
which employees of EOG and its subsidiaries and nonemployee members
of the Board of Directors 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 the individual grant agreements. Terms for stock
options granted under the Plans have not exceeded a maximum term of
10 years.
28
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table sets forth the option transactions under the
Plans for the years ended December 31 (options in thousands):
2001 2000 1999
----------------- ------------------ -----------------
Average Average Average
Grant Grant Grant
Options Price Options Price Options Price
------- -------- ------- ------- ------- -------
Outstanding at January 1................. 7,056 $ 20.70 12,667 $ 18.66 15,036 $ 18.35
Granted................................ 1,631 36.63 1,317 30.88 1,280 19.88
Exercised............................. (1,563) 19.18 (6,726) 18.90 (822) 16.22
Forfeited............................. (111) 23.84 (202) 19.09 (2,827) 18.26
------ ------ ------
Outstanding at December 31............... 7,013 24.69 7,056 20.70 12,667 18.66
====== ====== ======
Options Exercisable at December 31....... 4,034 22.04 3,845 19.83 8,118 19.23
====== ====== ======
Options Available for Future Grant....... 4,531 6,387 5,564
====== ====== ======
Average Fair Value of Options
Granted During Year.................... $16.76 $12.20 $ 7.43
====== ====== ======
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 2001, 2000, and 1999,
respectively: (1) dividend yield of 0.5%, 0.6% and 0.6%, (2) expected
volatility of 43%, 30%, and 28%, (3) risk-free interest rate of 4.6%,
6.0%, and 5.9%, and (4) expected life of 6.0 years, 6.0 years and
6.0 years.
The following table summarizes certain information for the
options outstanding at December 31, 2001 (options in thousands):
Options Outstanding Options Exercisable
------------------------------- ----------------------
Weighted Weighted Weighted
Average Average Average
Remaining Grant Grant
Range of Grant Prices Options Life Price Options Price
--------------------- ------- --------- --------- -------- ----------
(years)
$ 13.00 to $ 17.99.............. 1,653 6 $14.66 1,104 $14.85
18.00 to 22.99.............. 2,356 6 20.12 1,783 20.13
23.00 to 28.99.............. 411 4 24.03 392 23.89
29.00 to 39.99.............. 2,381 9 34.35 631 33.97
40.00 to 54.99.............. 212 8 46.46 124 46.94
------ ------
7,013 7 24.69 4,034 22.04
====== ======
29
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
EOG's pro forma net income and net income per share of common stock for 2001, 2000 and 1999, had
compensation costs been recorded in accordance with SFAS No. 123, are presented below (in millions
except per share data):
2001 2000 1999
------------------- ------------------- -------------------
As As As
Reported Pro Forma Reported Pro Forma Reported Pro Forma
-------- --------- -------- --------- -------- ---------
Net Income Available to Common................ $ 387.6 $ 375.7 $ 385.9 $ 373.4 $ 568.6 $ 565.7
Net Income per Share Available to Common
Basic........................................ $ 3.35 $ 3.25 $ 3.30 $ 3.19 $ 4.04 $ 4.02
======= ======= ======= ======= ======= =======
Diluted...................................... $ 3.30 $ 3.20 $ 3.24 $ 3.14 $ 4.01 $ 3.99
======= ======= ======= ======= ======= =======
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.
The Black-Scholes model used by EOG to calculate option values,
as well as other currently accepted option valuation models, were
developed to estimate the fair value of freely tradable, fully
transferable options without vesting and/or trading restrictions,
which significantly differ from EOG's stock option awards. These
models also require highly subjective assumptions, including future
stock price volatility and expected time until exercise, which
significantly affect the calculated values. Accordingly, management
does not believe that this model provides a reliable single measure
of the fair value of EOG's stock option awards.
Restricted Stock and Units. Under the Plans, participants may
be granted restricted stock and/or units without cost to the
participant. The shares and units granted vest to the participant at
various times ranging from one to five years. Upon vesting, the
restricted shares are released to the participants and the restricted
units released to the participants are converted into one share of
common stock. The following summarizes shares of restricted stock and
units granted (shares and units in thousands):
Restricted Shares and Units
---------------------------
2001 2000 1999
-------- ------- --------
Outstanding at January 1................................. 309 288 378
Granted................................................ 353 201 23
Released to Participants............................... (15) (178) (39)
Forfeited or Expired................................... (15) (2) (74)
------ ------ ------
Outstanding at December 31............................... 632 309 288
------ ------ ------
Average Fair Value of Shares Granted During Year......... $42.08 $16.10 $20.67
====== ====== ======
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 2001, 2000 and
1999 was approximately $3.3 million, $1.3 million and $3.1 million,
respectively.
Employee Stock Purchase Plan. During 2001, EOG implemented an
Employee Stock Purchase Plan (the "ESPP") that allows eligible
employees to semiannually 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, 2001, 467,699
common shares remained available for issuance under the plan. During
2001, 306 employees participated in the plan and 32,301 common shares
were purchased at an aggregate price of approximately $1 million.
Treasury Shares. During 2001, 2000 and 1999, EOG purchased
approximately 1,828,000, 6,709,000, and 130,000 of its common shares,
respectively, to offset the dilution resulting from shares issued
under the EOG employee stock plans. The difference between the cost
of the treasury shares and the exercise price of the options, net of
federal income tax benefit of $7.3 million, $41.3 million, and
$1.4 million for the years 2001, 2000 and 1999, respectively, is
reflected as an adjustment to additional paid in capital to the
extent EOG has accumulated additional paid in capital relating to
treasury stock and retained earnings thereafter.
30
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
7. Commitments and Contingencies
-----------------------------
Letters Of Credit. At December 31, 2001 and 2000, EOG had
letters of credit and guarantees outstanding totaling approximately
$136 million and $122 million, respectively. Of these amounts, $120
million and $105 million, respectively, represent guarantees of
subsidiary indebtedness included under Note 2 "Long-Term Debt."
Other Commitments. EOG has leases for buildings, facilities and
equipment with varying expiration dates through 2007. Rental
expenses associated with these leases amounted to $20 million, $15
million and $ 16 million for 2001, 2000 and 1999, respectively.
At December 31, 2001, total minimum commitments from minimum
rental commitments under long-term non-cancelable operating leases,
drilling rig commitments and transportation service commitments based
upon current transportation rates and foreign currency exchange rate
at December 31, 2001, are as follows (in thousands):
Total Minimum
Commitments
-------------
2002........................ $ 48,861
2003 - 2005................. 39,960
2006 - 2007................. 16,537
2008 and thereafter......... 5,128
--------
$110,486
========
Contingencies. On July 21, 1999, two stockholders of EOG filed
separate lawsuits purportedly on behalf of EOG against Enron Corp.
and those individuals who were then directors of EOG, alleging that
Enron Corp. and those directors breached their fiduciary duties of
good faith and loyalty in approving the Share Exchange. The lawsuits
sought to rescind the transaction or to receive monetary damages and
costs and expenses, including reasonable attorneys' and experts'
fees. A Stipulation of Dismissal without prejudice of these suits
was entered by the court on December 12, 2001.
During 2000 and 2001, EOG was engaged in arbitration hearings to
settle a disagreement over the timing of the conversion of a 5%
overriding royalty interest held by a third party in EOG's Trinidad
SECC block to a 15% working interest. The arbitration resulted in a
decision in favor of EOG.
EOG and numerous other companies in the natural gas industry are
named as defendants in various lawsuits alleging violations of the
civil False Claims Act. These lawsuits have been consolidated for pre-
trial proceedings in the United States District Court for the
District of Wyoming. The plaintiffs contend that defendants have
underpaid royalties on natural gas and natural gas liquids produced
on federal and Indian lands through the use of below-market prices,
improper deductions, improper measurement techniques and transactions
with affiliated companies. Plaintiffs allege that the royalties paid
by defendants were lower than the royalties required to be paid under
federal regulations and that the forms filed by defendants with the
Minerals Management Service reporting these royalty payments were
false, thereby violating the civil False Claims Act. The United
States has intervened in certain of the cases as to some of the
defendants, but has not intervened as to EOG. Based on EOG's present
understanding of these cases, EOG believes that it has substantial
defenses to these claims and intends to vigorously assert these
defenses. However, if EOG is found to have violated the Civil False
Claims Act, EOG could be subject to a variety of sanctions, including
treble damages and substantial monetary fines.
There are various other suits and claims against EOG that have
arisen in the ordinary course of business. However, management does
not believe these suits and claims will individually or in the
aggregate have a material adverse effect on the financial condition
or results of operations of EOG. EOG has been named as a potentially
responsible party in certain Comprehensive Environmental Response,
Compensation, and Liability Act proceedings. However, management does
not believe that any potential assessments resulting from such
proceedings will individually or in the aggregate have a materially
adverse effect on the financial condition or results of operations of
EOG.
31
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. Net Income Per Share Available to Common
----------------------------------------
The following table sets forth the computation of basic and diluted earnings from net income
available to common for the years ended December 31 (in thousands, except per share amounts):
2001 2000 1999
--------- --------- ---------
Numerator for basic and diluted earnings per share -
Net income available to common......................... $ 387,622 $ 385,903 $ 568,559
========= ========= =========
Denominator for basic earnings per share -
Weighted average shares................................. 115,765 116,934 140,648
Potential dilutive common shares -
Stock options........................................... 1,453 2,038 964
Restricted stock and units.............................. 270 130 15
--------- --------- ---------
Denominator for diluted earnings per share -
Adjusted weighted average shares...................... 117,488 119,102 141,627
========= ========= =========
Net income per share of common stock
Basic................................................... $ 3.35 $ 3.30 $ 4.04
========= ========= =========
Diluted................................................. $ 3.30 $ 3.24 $ 4.01
========= ========= =========
9. Supplemental Cash Flow Information
----------------------------------
On August 16, 1999, EOG and Enron Corp. completed the Share
Exchange whereby EOG received 62,270,000 shares of EOG's common stock
out of 82,270,000 shares owned by Enron Corp. in exchange for all the
stock of EOG's subsidiary, EOGI-India, Inc (see Note 4 "Transactions
with Enron Corp."). Prior to the Share Exchange, EOG made an indirect
capital contribution of approximately $600 million in cash, plus
certain intercompany receivables, to EOGI-India, Inc. At the time of
completion of this transaction, EOG's net investment in
EOGI-India, Inc. was $870 million.
Cash paid for interest and income taxes was as follows for the years ended December 31 (in thousands):
2001 2000 1999
-------- --------- --------
Interest (net of amount capitalized).......................... $ 45,715 $ 61,679 $ 67,965
Income taxes.................................................. 106,312 87,285 19,810
32
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 U.S. producing
areas have been aggregated as one reportable segment due to
similarities in their operations as allowed by SFAS No. 131.
Financial information by reportable segment is presented below for
the years ended December 31, or at December 31 (in thousands):
United States Canada Trinidad India(1) Other(2) Total
-------------- ------------ --------- --------- --------- -------------
2001
Net Operating Revenues...................... $ 1,394,457(3) $ 191,219(3) $ 69,140 $ -- $ 71 $ 1,654,887(3)
Depreciation, Depletion and Amortization.... 348,539 31,821 12,031 -- 8 392,399
Operating Income (Loss)..................... 536,671 107,524 36,761 -- (6,404) 674,552
Interest Income............................. 415 2,943 1,702 -- -- 5,060
Other Income (Expense)...................... (3,284) 71 154 -- 2 (3,057)
Interest Expense............................ 45,061 750 (701) -- -- 45,110
Income (Loss) Before Income Taxes........... 488,741 109,788 39,318 -- (6,402) 631,445
Income Tax Provision (Benefit).............. 187,285 28,438 20,166 -- (3,060) 232,829
Additions to Oil and Gas Properties......... 729,655 176,101 68,260 -- -- 974,016
Total Assets................................ 2,676,160 510,476 227,229 -- 179 3,414,044
2000
Net Operating Revenues...................... $ 1,223,315(3) $ 184,092(3) $ 82,430 $ -- $ 58 $ 1,489,895(3)
Depreciation, Depletion and Amortization.... 310,685 34,621 13,959 -- -- 359,265
Operating Income (Loss)..................... 552,091 103,229 41,974 -- (431) 696,863
Interest Income............................. 354 2,186 915 -- 382 3,837
Other Income (Expense)..................... (6,343) 302 31 -- (127) (6,137)
Interest Expense............................ 54,279 11,140 (4,413) -- -- 61,006
Income (Loss) Before Income Taxes........... 491,823 94,577 47,333 -- (176) 633,557
Income Tax Provision (Benefit).............. 181,506 31,159 24,076 -- (115) 236,626
Additions to Oil and Gas Properties......... 499,207 69,157 33,223 -- 1,051 602,638
Total Assets................................ 2,465,642 374,476 159,872 -- 1,263 3,001,253
1999
Net Operating Revenues...................... $ 635,587(3) $ 97,817(3) $ 62,689 $ 53,897 $ (7,891) $ 842,099(3)
Depreciation, Depletion and Amortization.... 279,056 29,570 12,787 7,223 1,032 329,668
Operating Income (Loss)..................... (7,714) 33,941 32,643 22,699 (63,381) 18,188
Interest Income............................. 113 184 626 51 63 1,037
Other Income (Expense)...................... 630,872 112 128 (992) (19,814) 610,306
Interest Expense............................ 42,986 9,459 323 (2,625) 11,676 61,819
Income (Loss) Before Income Taxes........... 580,285 24,778 33,074 24,383 (94,808) 567,712
Income Tax Provision (Benefit).............. (4,200) 4,637 18,484 8,858 (29,161) (1,382)
Additions to Oil and Gas Properties......... 292,970 63,783 7,361 23,281 9,055 396,450
Total Assets................................ 2,118,843 344,465 145,186 -- 2,299 2,610,793
(1) See Note 4"Transactions with Enron Corp."
(2) Other includes China operations in 1999. See Note 4 "Transactions with Enron Corp."
(3) EOG had sales activity in 2001 with a certain purchaser in the United States and Canada segments that totaled
approximately $224.5 million of the Consolidated Net Operating Revenues. Sales activity with another purchaser
in the United States and Canada segments in 2000 and 1999 totaled approximately $183.2 million and $98.1 million,
respectively, of the Consolidated Net Operating Revenues.
33
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. Other Income (Expense), Net
---------------------------
Other income (expense) - other, net for the year ended December
31, 1999, included the gain of $59.6 million on the sale of 3.2
million shares of Enron Corp. options granted to EOG under the 1997
Equity Participation and Business Opportunity Agreement with Enron
Corp., and $19.4 million loss relating to anticipated costs of
abandonment of certain international activities.
12. Price and Interest Rate Risk Management Activities
--------------------------------------------------
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
costless collars, as the means to manage this price risk.
During 2001 and 2000, EOG elected not to designate any of its
derivative contracts as accounting hedges and accordingly, accounted
for these derivative contracts under mark-to-market accounting.
During 2001, EOG recognized mark-to-market gains on commodity
contracts of $98 million, of which $62 million were realized gains.
During 2000, EOG recognized and realized approximately $1 million
mark-to-market losses on commodity contracts.
During the fourth quarter of 2001, as a result of the Enron
Corp.'s bankruptcy proceedings, EOG wrote off $17 million in Charges
Related to Enron Bankruptcy in the Consolidated Statements of Income
and Comprehensive Income related to 2001 and 2002 natural gas and
crude oil derivative contracts entered into with a subsidiary of
Enron Corp. (see Note 4 to the Consolidated Financial Statements).
These contracts covered approximately 19.5 trillion British thermal
units and 0.8 million barrels ("MMBbl").
At December 31, 2001, excluding positions related to the Enron
bankruptcies, EOG had open natural gas price swap contracts covering
approximately 15% of its 2002 North America production. The fair
value of these contracts was $19.6 million. Tabulated below is a
summary of these open natural gas price swap positions at December
31, 2001, with prices expressed in dollars per million British
thermal units ("$/MMBtu") and volumes in million British thermal
units per day ("MMBtud"):
Average Price Volume
2002 ($/MMBtu) (MMBtud)
--------------------- ------------- --------
January $ 3.21 140,000
February $ 3.13 190,000
March through May $ 3.09 140,000
June through December $ 3.24 100,000
At December 31, 2001, excluding positions related to the Enron
bankruptcies, EOG had outstanding oil swap contracts, covering
notional volumes of approximately 0.5 MMBbl. At December 31, 2001,
the fair value of these contracts was a negative $0.4 million. At
December 31, 2000, EOG had outstanding swap positions covering
notional volumes of approximately 0.7 MMBbl of crude oil and
condensate for 2001 that had a fair value of $0.4 million. Such swap
positions were settled in 2001 for a loss of $1.7 million.
34
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Subsequent to December 31, 2001, EOG entered into certain
natural gas and crude oil swap contracts. The following is a summary
of EOG's price swap positions at February 20, 2002, including these
contracts:
o Natural Gas Price Swaps
Average Price Volume
2002 ($/MMBtu) (MMBtud)
---------------------- ------------- --------
January (closed) $ 3.21 140,000
February (closed) $ 3.13 190,000
March $ 3.13 140,000
April and May $ 2.68 290,000
June $ 2.76 200,000
July through December $ 3.26 100,000
o Crude Oil Price Swaps - Notional volumes of two thousand barrels
of oil per day for the period March 2002 to December 2002 at an
average price of $21.50 per barrel.
During 2001, 2000 and 1999, EOG recognized in natural gas and
crude oil and condensate revenues hedge losses of $1 million, $17
million and $5 million, respectively, related to closed hedge
positions.
Interest Rate Swap Agreements and Foreign Currency Contracts.
At December 31, 2000, a subsidiary of EOG and EOG were parties to
offsetting foreign currency and interest rate swap agreements with an
aggregate notional principal amount of $210 million. Such swap
agreements terminated in January 2001. Presently, EOG is not a party
to any foreign currency or interest rate swap agreement.
The following table summarizes the estimated fair value of financial instruments and related
transactions at December 31, 2001 and 2000:
2001 2000
------------------------ ------------------------
Carrying Estimated Carrying Estimated
Amount Fair Value(1) Amount Fair Value(1)
-------- ------------- -------- -------------
(In Millions) (In Millions)
Long-Term Debt(2)................................ $ 856.0 $ 838.3 $ 859.0 $ 831.1
NYMEX-Related Commodity Market Positions.......... 19.2 19.2 (5.6) (5.6)
(1) Estimated fair values have been determined by using available market data and valuation methodologies.
Judgment is necessarily required in interpreting market data and the use of different market assumptions
or estimation methodologies may affect the estimated fair value amounts.
(2) See Note 2 "Long-Term Debt."
Credit Risk. While notional contract amounts are used to
express the magnitude of commodity price and interest rate swap
agreements, the amounts potentially subject to credit risk, in the
event of nonperformance by the other parties, are substantially
smaller. EOG evaluates its exposure to all counterparties on an
ongoing basis, including those arising from physical and financial
transactions. In some instances EOG requires collateral from its
counterparties to minimize any risk, and EOG is actively considering
other means of reducing its exposure to individual companies. At
December 31, 2001, approximately 11% of EOG's net accounts receivable
balance related to natural gas, crude oil and condensate sales was
due from a major utility company. The amount due from this utility
company at December 31, 2000, which approximated 10% of the net
accounts receivable balance, was collected during 2001. No other
individual purchaser accounted for 10% or more of the net accounts
receivable balance at December 31, 2001 and 2000. At December 31,
2001, EOG had an allowance for doubtful accounts of $20.1 million,
of which $19.2 million is associated with the Enron Corp. bankruptcy.
35
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
13. Concentration of Credit Risk
----------------------------
Substantially all of EOG's accounts receivable at December 31,
2001 and 2000 result from crude oil and natural gas sales and/or
joint interest billings to third party companies including foreign
state-owned entities in the oil and gas industry. This concentration
of customers and joint interest owners may impact EOG's overall
credit risk, either positively or negatively, in that these entities
may be similarly affected by changes in economic or other conditions.
In determining whether or not to require collateral from a customer
or joint interest owner, EOG analyzes the entity's net worth, cash
flows, earnings, and credit ratings. Receivables are generally not
collateralized. Historical credit losses incurred on receivables by
EOG have been immaterial except for those associated with the Enron
bankruptcies.
14. Accounting for Certain Long-Lived Assets
----------------------------------------
Periodically, EOG reviews its oil and gas properties for
impairment purposes by comparing the expected undiscounted future
cash flows at a producing field level to the unamortized capitalized
cost of the asset. During 2001 and 2000, 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 and lower natural gas and crude oil
prices. As a result, EOG recorded in Impairments pre-tax charges of
$39 million and $11 million, respectively, for 2001 and 2000 in the
United States operating segment. The carrying values for assets
determined to be impaired were adjusted to estimated fair values
based on projected future net cash flows discounted using EOG risk-
adjusted discount rate.
In 1999, as a result of the change to EOG's portfolio of assets
brought about by the Share Exchange (see Note 4 "Transactions with
Enron Corp."), EOG conducted a re-evaluation of its overall business.
As a result of this re-evaluation, some of EOG's projects were no
longer deemed central to its business. EOG recorded non-cash charges
in connection with the impairment and/or EOG's decision to dispose of
such projects of $133 million pre-tax ($89 million after-tax). In
addition, EOG recorded charges of $15 million pre-tax ($10 million
after-tax) pursuant to a change in EOG's strategy related to certain
offshore operations in the second quarter and an impairment of
various North America properties in the fourth quarter of 1999 to
Impairments. In the United States operating segment, a pre-tax
impairment charge of $85 million was recorded to Impairments. The
carrying values for assets determined to be impaired were adjusted to
estimated fair values based on projected future discounted net cash
flows for such assets. In the Other operating segment, a pre-tax
charge of $36 million was recorded to Impairments to fully write-off
EOG's basis and a pre-tax charge of $19 million was recorded to other
income (expense) - other, net for the estimated exit costs related to
EOG's decision to dispose of certain international operations. Net
loss for the Other operating segment operations for 1999, excluding
these charges, was approximately $3 million.
15. Investment in Caribbean Nitrogen Company Limited
------------------------------------------------
EOG, through a subsidiary, owns an approximate 16% equity
interest in a Trinidadian company named Caribbean Nitrogen Company
Limited ("CNCL"). The other shareholders in CNCL are subsidiaries of
Ferrostall AG, Duke Energy, Halliburton and CL Financial Ltd. At
December 31, 2001, investment in CNCL was approximately $12.7 million
with the final equity payment of approximately $1.2 million due in
the first quarter of 2002. CNCL is constructing an ammonia plant in
Trinidad and is expected to commence production in 2002. At December
31, 2001, CNCL had a long-term debt balance of approximately $197
million, which is non-recourse to CNCL's shareholders. EOG will be
liable for its share of any pre-completion deficiency funds loans to
fund plant cost overruns up to $15 million, approximately $2.6 million
of which is net to EOG's interest. EOG will also be liable for its
share of any post-completion deficiency funds loans to fund the costs
of operation, payment of principal and interest to the principal
creditor and other cash deficiencies of CNCL up to $30 million,
approximately $5 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.
36
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 to existing reserve estimates 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 recompletion.
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.
As a result of the re-evaluation of EOG's portfolio of assets
following the Share Exchange (see Note 4 "Transactions with Enron
Corp."), on November 12, 1999 senior management proposed to the Board
of Directors ("the Board") of EOG to defer the development of the Big
Piney Madison deep Paleozoic formation methane reserves in Wyoming
for the foreseeable future. The Board approved the recommendation. As
a result, the 1.2 trillion cubic feet of methane reserves in the
formation, which are located on acreage owned by EOG and held by
production for the foreseeable future, and which were classified as
proved undeveloped reserves at December 31, 1998, were removed as a
revision during 1999. At December 31, 1998, these reserves
represented approximately $100 million or 5% of EOG's Standardized
Measure of Discounted Future Net Cash Flows as adjusted for the sale
of the India and China reserves as a result of the Share Exchange.
At December 31, 2001, EOG had no plan to develop these reserves for
the foreseeable future.
37
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Estimates of proved and proved developed reserves at
December 31, 2001, 2000 and 1999 were based on studies performed by
the engineering staff of EOG for reserves in the United States,
Canada, Trinidad, India and China (See Note 4 to the Consolidated
Financial Statements regarding operations transferred under the Share
Exchange). Opinions by DeGolyer and MacNaughton ("D&M"), independent
petroleum consultants, for the years ended December 31, 2001, 2000,
and 1999 covered producing areas containing 71%, 49% and 52%,
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, 2001 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, 2001, 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 States Canada Trinidad SUBTOTAL India(1) Other(2) TOTAL
------------- ------ --------- -------- -------- -------- --------
Natural Gas (Bcf)(3)
Net proved reserves at December 31, 1998........ 2,853.4(4) 464.2 976.4 4,294.0 824.6 110.3 5,228.9
Revisions of previous estimates............... (1,199.1)(5) (1.3) 4.5 (1,195.9) - - (1,195.9)
Purchases in place............................ 108.5 34.0 - 142.5 - - 142.5
Extensions, discoveries and other additions... 208.2 69.8 51.0 329.0 - - 329.0
Sales in place(1)........................... (70.9) (1.4) - (72.3) (807.9) (110.3) (990.5)
Production.................................... (242.9) (41.8) (37.3) (322.0) (16.7) - (338.7)
-------- ------ -------- -------- ------ ------ --------
Net proved reserves at December 31, 1999........ 1,657.2 523.5 994.6 3,175.3 - - 3,175.3
Revisions of previous estimates............. 47.2 6.4 (0.4) 53.2 - - 53.2
Purchases in place............................ 188.8 39.4 - 228.2 - - 228.2
Extensions, discoveries and other additions... 255.4 23.8 65.1 344.3 - - 344.3
Sales in place............................... (84.2) (0.1) - (84.3) - - (84.3)
Production.................................... (243.0) (47.3) (45.8) (336.1) - - (336.1)
-------- ------ ------- -------- ------ ------ --------
Net proved reserves at December 31, 2000........ 1,821.4 545.7 1,013.5 3,380.6 - - 3,380.6
Revisions of previous estimates.............. 15.0 (26.8) (121.6) (133.4) - - (133.4)
Purchases in place............................ 66.1 111.5 - 177.6 - - 177.6
Extensions, discoveries and other additions... 358.3 59.7 295.2 713.2 - - 713.2
Sales in place............................... (1.0) - - (1.0) - - (1.0)
Production.................................... (252.5) (46.0) (42.0) (340.5) - - (340.5)
--------- ------ ------- -------- ------ ------ --------
Net proved reserves at December 31, 2001........ 2,007.3 644.1 1,145.1(6) 3,796.5 - - 3,796.5
========= ====== ======= ======== ====== ====== ========
38
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
United
States Canada Trinidad SUBTOTAL India(1) Other(2) TOTAL
----------- ------- --------- -------- --------- -------- ----------
Liquids (MBbl)(7)
Net proved reserves at December 31, 1998....... 36,827 7,592 16,204 60,623 42,785 1,162 104,570
Revisions of previous estimates.............. 5,085 117 (72) 5,130 - - 5,130
Purchases in place........................... 2,753 39 - 2,792 - - 2,792
Extensions, discoveries and other additions.. 9,520 2,416 509 12,445 - - 12,445
Sales in place(1).......................... (121) (37) - (158) (41,306) (1,162) (42,626)
Production................................... (6,217) (1,231) (878) (8,326) (1,479) - (9,805)
--------- ------- ------- -------- -------- ------- --------
Net proved reserves at December 31, 1999....... 47,847 8,896 15,763 72,506 - - 72,506
Revisions of previous estimates.............. (1,951) 46 28 (1,877) - - (1,877)
Purchases in place........................... 3,948 - - 3,948 - - 3,948
Extensions, discoveries and other additions.. 12,433 404 738 13,575 - - 13,575
Sales in place.............................. (484) (2,474) - (2,958) - - (2,958)
Production................................... (9,780) (1,055) (957) (11,792) - - (11,792)
--------- ------- ------- -------- -------- ------- --------
Net proved reserves at December 31, 2000....... 52,013 5,817 15,572 73,402 - - 73,402
Revisions of previous estimates.............. (3,111) 1,294 (3,691) (5,508) - - (5,508)
Purchases in place........................... 586 35 - 621 - - 621
Extensions, discoveries and other additions.. 12,380 361 1,967 14,708 - - 14,708
Sales in place............................... (192) (35) - (227) - - (227)
Production................................... (9,293) (820) (749) (10,862) - - (10,862)
--------- ------- ------- -------- -------- ------- --------
Net proved reserves at December 31, 2001...... 52,383 6,652 13,099(6) 72,134 - - 72,134
========= ======= ======= ======== ======== ======= ========
Bcf Equivalent (Bcfe)(3)
Net proved reserves at December 31, 1998...... 3,074.5(4) 509.7 1,073.6 4,657.8 1,081.3 117.2 5,856.3
Revisions of previous estimates.............. (1,168.8)(5) (0.6) 4.1 (1,165.3) - - (1,165.3)
Purchases in place........................... 125.1 34.3 - 159.4 - - 159.4
Extensions, discoveries and other additions.. 265.3 84.3 54.0 403.6 - - 403.6
Sales in place(1)......................... (71.6) (1.6) - (73.2) (1,055.7) (117.2) (1,246.1)
Production................................... (280.2) (49.2) (42.5) (371.9) (25.6) - (397.5)
--------- ------- ------- -------- -------- ------ --------
Net proved reserves at December 31, 1999...... 1,944.3 576.9 1,089.2 3,610.4 - - 3,610.4
Revisions of previous estimates............. 35.5 6.8 (0.2) 42.1 - - 42.1
Purchases in place......................... 212.5 39.4 - 251.9 - - 251.9
Extensions, discoveries and other additions.. 330.0 26.2 69.5 425.7 - - 425.7
Sales in place............................. (87.1) (15.0) - (102.1) - - (102.1)
Production................................... (301.7) (53.7) (51.6) (407.0) - - (407.0)
--------- ------- ------- -------- -------- ------- --------
Net proved reserves at December 31, 2000...... 2,133.5 580.6 1,106.9 3,821.0 - - 3,821.0
Revisions of previous estimates.......... (3.7) (19.1) (143.7) (166.5) - - (166.5)
Purchases in place........................... 69.7 111.6 - 181.3 - - 181.3
Extensions, discoveries and other additions.. 432.5 62.0 307.0 801.5 - - 801.5
Sales in place.............................. (2.2) (0.2) - (2.4) - - (2.4)
Production................................... (308.2) (50.9) (46.5) (405.6) - - (405.6)
--------- ------- ------- -------- -------- ------- --------
Net proved reserves at December 31, 2001....... 2,321.6 684.0 1,223.7(6)4,229.3 - - 4,229.3
========= ======= ======= ======= ======== ======= ========
39
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
United States Canada Trinidad SUBTOTAL India(1) TOTAL
------------- ------ ---------- ---------- --------- ---------
Net proved developed reserves at
Natural Gas (Bcf)(3)
December 31, 1998............. 1,429.7 387.4 283.0 2,100.1 407.4 2,507.5
December 31, 1999............. 1,446.5 451.1 250.2 2,147.8 -- 2,147.8
December 31, 2000............. 1,498.6 479.4 207.0 2,185.0 -- 2,185.0
December 31, 2001............. 1,588.4 587.6 620.6(8) 2,796.6 -- 2,796.6
Liquids (MBbl)(7)
December 31, 1998............. 33,045 7,465 4,782 45,292 33,472 78,764
December 31, 1999............. 41,717 7,041 3,833 52,591 -- 52,591
December 31, 2000............. 42,132 5,695 2,967 50,794 -- 50,794
December 31, 2001............. 41,205 6,532 8,435(8) 56,172 -- 56,172
Bcf Equivalents (Bcfe)(3)
December 31, 1998............. 1,628.0 432.1 311.7 2,371.8 608.2 2,980.0
December 31, 1999............. 1,696.8 493.3 273.2 2,463.3 -- 2,463.3
December 31, 2000............. 1,751.4 513.6 224.8 2,489.8 -- 2,489.8
December 31, 2001............. 1,835.7 626.8 671.1(8) 3,133.6 -- 3,133.6
___________________________
(1) See Note 4 "Transactions with Enron Corp."
(2) Other includes China operations only. See Note 4 "Transactions with Enron Corp."
(3) Billion cubic feet or billion cubic feet equivalent, as applicable.
(4) Includes 1,180 Bcf of proved undeveloped methane reserves contained, along with high
concentrations of carbon dioxide and other gases, in deep Paleozoic (Madison) formations
in the Big Piney area of Wyoming.
(5) Includes reduction of the 1,180 Bcf of proved undeveloped methane reserves mentioned
in (4) as a result of EOG's decision to defer the development of the Big Piney Madison
deep Paleozoic formation methane reserves in Wyoming for the foreseeable future.
(6) Includes net proved reserves of 263.5 Bcf, 2,031 MBbl or 275.7 Bcfe, as applicable,
from the SECC Block beyond the concession term. EOG believes that such concession term
will be extended by the Trinidadian government as a matter of course.
(7) Thousand barrels; includes crude oil, condensate and natural gas liquids.
(8) Includes net proved developed reserves of 4.3 Bcf, 50 MBbl or 4.6 Bcfe, as applicable,
from the SECC Block beyond the concession term. EOG believes that such concession term
will be extended by the Trinidadian government as a matter of course.
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,
2001 and 2000:
2001 2000
------------ ------------
Proved Properties.............................................. $ 5,847,053 $ 4,966,667
Unproved Properties............................................ 218,550 156,061
----------- -----------
Total..................................................... 6,065,603 5,122,728
Accumulated depreciation, depletion and amortization........... (3,009,693) (2,597,721)
----------- -----------
Net capitalized costs.......................................... $ 3,055,910 $ 2,525,007
=========== ===========
Costs Incurred in Oil and Gas Property Acquisition, Exploration
and Development Activities. The acquisition, exploration and
development costs disclosed in the following tables are in accordance
with definitions in SFAS No. 19--"Financial Accounting and Reporting
by Oil and Gas Producing Companies."
Acquisition costs include costs incurred to purchase, lease, or
otherwise acquire property.
Exploration costs include exploration expenses, additions to
exploration wells including those in progress, and depreciation of
support equipment used in exploration activities.
40
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Development costs include additions to production facilities and equipment, additions to development
wells including those in progress and depreciation of support equipment and related facilities used in
development activities.
The following tables set forth costs incurred related to EOG's oil and gas activities for the years
ended December 31:
United States Canada Trinidad Other SUBTOTAL India(1) China(1) TOTAL
------------- -------- --------- ------- ----------- -------- --------- ----------
2001
Acquisition Costs of Properties
Unproved........................ $ 69,308 $ 6,967 $ - $ - $ 76,275 $ - $ - $ 76,275
Proved.......................... 95,646 72,660 - - 168,306 - - 168,306
--------- -------- -------- ------- ---------- ------- ------- ----------
Subtotal................... 164,954 79,627 - - 244,581 - - 244,581
Exploration Costs................. 163,602 16,708 13,695 8,739 202,744 - - 202,744
Development Costs................ 512,175 92,374 60,969 - 665,518 - - 665,518
--------- -------- -------- ------- ---------- ------- ------- ----------
Subtotal................... 840,731 188,709 74,664 8,739 1,112,843 - - 1,112,843
Deferred Income Taxes............. 19,411 30,845 - - 50,256 - - 50,256
--------- -------- -------- ------- ---------- ------- ------- ----------
Total...................... $ 860,142 $219,554 $ 74,664 $ 8,739 $1,163,099 $ - $ - $1,163,099
========= ======== ======== ======= ========== ======= ======= ==========
2000
Acquisition Costs of Properties
Unproved........................ $ 45,456 $ 5,741 $ - $ - $ 51,197 $ - $ - $ 51,197
Proved.......................... 88,473 13,965 - - 102,438 - - 102,438
--------- -------- -------- ------- ---------- ------- ------- ----------
Subtotal................... 133,929 19,706 - - 153,635 - - 153,635
Exploration Costs................. 98,654 9,711 10,849 3,581 122,795 - - 122,795
Development Costs................ 335,053 46,000 29,688 - 410,741 - - 410,741
--------- -------- -------- ------- ---------- ------- ------- ----------
Subtotal................... 567,636 75,417 40,537 3,581 687,171 - - 687,171
Deferred Income Taxes............. 18,744 3,685 - - 22,429 - - 22,429
--------- -------- -------- ------- ---------- ------- ------- ----------
Total...................... $ 586,380 $ 79,102 $ 40,537 $ 3,581 $ 709,600 $ - $ - $ 709,600
========= ======== ======== ======= ========== ======= ======= ==========
1999
Acquisition Costs of Properties
Unproved........................ $ 18,964 $ 2,276 $ - $ - $ 21,240 $ - $ - $ 21,240
Proved.......................... 22,092 20,838 - - 42,930 - - 42,930
--------- -------- -------- ------- ---------- ------- ------- ----------
Subtotal................... 41,056 23,114 - - 64,170 - - 64,170
Exploration Costs................. 65,070 6,516 8,425 4,350 84,361 1,083 1,014 86,458
Development Costs................ 234,900 39,544 4,801 20 279,265 23,281 7,942 310,488
--------- -------- -------- ------- ---------- ------- ------- ----------
Subtotal................... 341,026 69,174 13,226 4,370 427,796 24,364 8,956 461,116
Deferred Income Taxes............. - - - - - - - -
--------- -------- -------- ------- ---------- ------- ------- ----------
Total...................... $ 341,026 $ 69,174 $ 13,226 $ 4,370 $ 427,796 $24,364 $ 8,956 $ 461,116
========= ======== ======== ======= ========== ======= ======= ==========
(1) See Note 4 "Transactions with Enron Corp."
41
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
States Canada Trinidad SUBTOTAL India(2) Other(3) TOTAL
---------- --------- -------- ---------- -------- -------- ----------
2001
Natural Gas, Crude Oil
and Condensate Revenues..................... $1,295,894 $ 191,096 $ 69,141 $1,556,131 $ - $ 72 $1,556,203
Gains (Losses) on Sales of
Reserves and Related Assets and Other, Net.. 811 123 - 934 - - 934
---------- --------- -------- ---------- -------- ------- ----------
Total................................... 1,296,705 191,219 69,141 1,557,065 - 72 1,557,137
Exploration Expenses, including Dry Hole...... 113,419 12,596 6,405 132,420 - 6,407 138,827
Production Costs.............................. 219,504 34,426 10,308 264,238 - 49 264,287
Impairments................................... 76,801 2,355 - 79,156 - - 79,156
Depreciation, Depletion and Amortization...... 348,397 31,821 12,031 392,249 - 9 392,258
---------- --------- -------- ---------- -------- -------- ----------
Income (Loss) before Income Taxes............. 538,584 110,021 40,397 689,002 - (6,393) 682,609
Income Tax Provision (Benefit)................ 198,243 32,663 22,218 253,124 - (2,238) 250,886
---------- --------- -------- ---------- -------- -------- ----------
Results of Operations......................... $ 340,341 $ 77,358 $ 18,179 $ 435,878 $ - $ (4,155) $ 431,723
========== ========= ======== ========== ======== ======== ==========
2000
Natural Gas, Crude Oil
and Condensate Revenues..................... $1,215,051 $ 183,989 $ 82,431 $1,481,471 $ - $ 59 $1,481,530
Gains (Losses) on Sales of
Reserves and Related Assets and Other, Net.. 9,262 103 - 9,365 - - 9,365
---------- --------- -------- ---------- -------- -------- ----------
Total................................... 1,224,313 184,092 82,431 1,490,836 - 59 1,490,895
Exploration Expenses, including Dry Hole...... 72,000 4,881 7,314 84,195 - 337 84,532
Production Costs............................. 181,266 31,784 15,669 228,719 - 129 228,848
Impairments................................... 39,775 6,703 - 46,478 - - 46,478
Depreciation, Depletion and Amortization...... 310,612 34,621 13,959 359,192 - 2 359,194
---------- --------- -------- ---------- -------- -------- ----------
Income (Loss) before Income Taxes............. 620,660 106,103 45,489 772,252 - (409) 771,843
Income Tax Provision (Benefit)................ 226,657 41,274 25,019 292,950 - (143) 292,807
---------- --------- -------- ---------- -------- -------- ----------
Results of Operations......................... $ 394,003 $ 64,829 $ 20,470 $ 479,302 $ - $ (266) $ 479,036
========== ========= ======== ========== ======== ======== ==========
1999
Natural Gas, Crude Oil
and Condensate Revenues..................... $ 629,435 $ 96,781 $ 62,689 $ 788,905 $ 53,897 $ 40 $ 842,842
Gains (Losses) on Sales of
Reserves and Related Assets and Other, Net.. 6,152 1,036 - 7,188 - (7,931) (743)
---------- --------- -------- ---------- -------- -------- ----------
Total................................... 635,587 97,817 62,689 796,093 53,897 (7,891) 842,099
Exploration Expenses, including Dry Hole...... 49,181 5,122 5,865 60,168 1,083 3,415 64,666
Production Costs.............................. 129,868 24,698 8,322 162,888 13,413 2,333 178,634
Impairments................................... 121,933 2,480 - 124,413 - 37,404 161,817
Depreciation, Depletion and Amortization...... 279,054 29,570 12,787 321,411 7,223 1,034 329,668
---------- --------- -------- ---------- -------- -------- ----------
Income (Loss) before Income Taxes............. 55,551 35,947 35,715 127,213 32,178 (52,077) 107,314
Income Tax Provision (Benefit)................ 14,605 12,259 19,643 46,507 15,445 (18,227) 43,725
---------- --------- -------- ---------- -------- -------- ----------
Results of Operations......................... $ 40,946 $ 23,688 $ 16,072 $ 80,706 $ 16,733 $(33,850) $ 63,589
========== ========= ======== ========== ======== ======== ==========
(1) Excludes mark-to-market gains or losses on commodity derivative contracts, interest charges and general
corporate expenses for each of the three years in the period ended December 31, 2001.
(2) See Note 4 "Transactions with Enron Corp."
(3) Other includes China (in 1999) and other international operations. See Note 4 "Transactions with Enron Corp."
42
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 States Canada Trinidad TOTAL
-------------- ------------ ------------ ------------
2001
Future cash inflows.................................. $ 5,677,824 $ 1,490,552 $ 1,472,197 $ 8,640,573
Future production costs.............................. (1,528,474) (371,124) (335,395) (2,234,993)
Future development costs............................. (387,048) (31,232) (110,331) (528,611)
----------- ----------- ----------- -----------
Future net cash flows before income taxes............ 3,762,302 1,088,196 1,026,471 5,876,969
Future income taxes.................................. (930,505) (295,739) (265,709) (1,491,953)
----------- ----------- ----------- -----------
Future net cash flows................................ 2,831,797 792,457 760,762 4,385,016
Discount to present value at 10% annual rate......... (1,121,771) (321,980) (413,876) (1,857,627)
----------- ----------- ----------- -----------
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(1).................. $ 1,710,026 $ 470,477 $ 346,886 $ 2,527,389
=========== =========== =========== ===========
2000
Future cash inflows.................................. $18,500,822 $ 4,704,243 $ 1,860,366 $25,065,431
Future production costs.............................. (2,766,579) (389,819) (668,549) (3,824,947)
Future development costs............................. (279,407) (44,011) (194,741) (518,159)
----------- ----------- ----------- -----------
Future net cash flows before income taxes............ 15,454,836 4,270,413 997,076 20,722,325
Future income taxes.................................. (5,074,986) (1,451,776) (230,712) (6,757,474)
----------- ----------- ----------- -----------
Future net cash flows................................ 10,379,850 2,818,637 766,364 13,964,851
Discount to present value at 10% annual rate......... (4,368,717) (1,304,886) (377,811) (6,051,414)
----------- ----------- ----------- -----------
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves...................... $ 6,011,133 $ 1,513,751 $ 388,553 $ 7,913,437
=========== =========== =========== ===========
1999
Future cash inflows.................................. $ 4,653,014 $ 1,159,024 $ 1,455,951 $ 7,267,989
Future production costs............................. (1,277,485) (300,332) (486,902) (2,064,719)
Future development costs............................ (175,039) (46,966) (158,778) (380,783)
----------- ----------- ----------- -----------
Future net cash flows before income taxes........... 3,200,490 811,726 810,271 4,822,487
Future income taxes.................................. (630,876) (226,118) (253,373) (1,110,367)
----------- ----------- ----------- -----------
Future net cash flows................................ 2,569,614 585,608 556,898 3,712,120
Discount to present value at 10% annual rate......... (842,382) (207,717) (267,965) (1,318,064)
----------- ----------- ----------- -----------
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves..................... $ 1,727,232 $ 377,891 $ 288,933 $ 2,394,056
=========== =========== =========== ===========
(1) Natural gas prices have declined since December 31, 2001; consequently, the discounted future net cash flows
would be reduced if the standardized measure was calculated in the first quarter of 2002.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the changes
in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the
period ended December 31, 2001.
United States Canada Trinidad SUBTOTAL India(1) Other(2) TOTAL
-------------- ---------- --------- ------------ ---------- --------- ------------
December 31, 1998....................... $ 1,570,547(3) $ 306,318 $ 237,795 $ 2,114,660 $ 386,293 $ 19,961 $ 2,520,914
Sales and transfers of oil
and gas produced, net of
production costs...................... (520,961) (73,044) (47,578) (641,583) (40,484) 2,334 (679,733)
Net changes in prices and
production costs...................... 265,946 77,195 76,381 419,522 -- -- 419,522
Extensions, discoveries,
additions and improved
recovery net of related costs.......... 310,470 68,396 8,523 387,389 -- -- 387,389
Development costs incurred............. 42,500 16,100 -- 58,600 23,820 8,010 90,430
Revisions of estimated
development costs..................... 133,741 687 8,178 142,606 -- -- 142,606
Revisions of previous quantity estimates. (163,423)(4) (505) 2,051 (161,877) -- -- (161,877)
Accretion of discount.................. 171,588 33,815 37,790 243,193 -- -- 243,193
Net change in income taxes............... (27,883) (79,397) (22,874) (130,154) -- -- (130,154)
Purchases of reserves in place........... 102,086 18,769 -- 120,855 -- -- 120,855
Sales of reserves in place............. (81,607) (1,276) -- (82,883) (369,629) (30,305) (482,817)
Changes in timing and other............ (75,772) 10,833 (11,333) (76,272) -- -- (76,272)
---------- ---------- -------- ----------- --------- --------- -----------
December 31, 1999......................... 1,727,232 377,891 288,933 2,394,056 -- -- 2,394,056
Sales and transfers of oil
and gas produced, net of
production costs...................... (1,048,804) (152,602) (66,761) (1,268,167) -- -- (1,268,167)
Net changes in prices and
production costs...................... 5,459,629 1,850,021 153,961 7,463,611 -- -- 7,463,611
Extensions, discoveries,
additions and improved
recovery net of related costs....... 1,502,377 94,379 20,544 1,617,300 -- -- 1,617,300
Development costs incurred............. 77,000 24,100 29,600 130,700 -- -- 130,700
Revisions of estimated
development costs...................... (19,055) 39 (39,590) (58,606) -- -- (58,606)
Revisions of previous quantity estimates. 153,862 30,376 (129) 184,109 -- -- 184,109
Accretion of discount.................. 190,045 48,912 45,192 284,149 -- -- 284,149
Net change in income taxes............... (2,436,834) (606,556) 8,566 (3,034,824) -- -- (3,034,824)
Purchases of reserves in place......... 671,604 136,138 -- 807,742 -- -- 807,742
Sales of reserves in place............. (331,960) (22,454) -- (354,414) -- -- (354,414)
Changes in timing and other.............. 66,037 (266,493) (51,763) (252,219) -- -- (252,219)
---------- ---------- -------- ------------ --------- --------- -----------
December 31, 2000......................... 6,011,133 1,513,751 388,553 7,913,437 -- -- 7,913,437
Sales and transfers of oil
and gas produced, net of
production costs...................... (1,060,926) (156,787) (58,832) (1,276,545) -- -- (1,276,545)
Net changes in prices and
production costs...................... (6,400,910) (1,822,229) (194,995) (8,418,134) -- -- (8,418,134)
Extensions, discoveries,
additions and improved
recovery net of related costs.......... 347,088 48,271 114,871 510,230 -- -- 510,230
Development costs incurred............. 101,900 27,500 71,088 200,488 -- -- 200,488
Revisions of estimated
development cost....................... (5,296) 2,931 10,947 8,582 -- -- 8,582
Revisions of previous quantity estimates. (3,563) (12,536) 47,418 31,319 -- -- 31,319
Accretion of discount.................. 862,118 223,154 54,297 1,139,569 -- -- 1,139,569
Net change in income taxes............... 2,313,068 592,322 15,087 2,920,477 -- -- 2,920,477
Purchases of reserves in place......... 35,686 78,790 -- 114,476 -- -- 114,476
Sales of reserves in place............... (6,165) (303) -- (6,468) -- -- (6,468)
Changes in timing and other.............. (484,107) (24,387) (101,548) (610,042) -- -- (610,042)
----------- ---------- --------- ----------- --------- --------- -----------
December 31, 2001......................... $ 1,710,026 $ 470,477 $ 346,886(5) $ 2,527,389 $ -- $ -- $ 2,527,389
=========== ========== ========= =========== ========= ========= ===========
(1) See Note 4 "Transactions with Enron Corp."
(2) Other includes China operations only. See Note 4 "Transactions with Enron Corp."
(3) Includes approximately $100,284 in 1998 related to the reserves in the Big Piney deep Paleozoic formations.
(4) Includes reserves reduction of approximately $172,057, discounted before income taxes, related to the
reserves in the Big Piney deep Paleozoic formations.
(5) Includes cash flows of $34.1 million from proved reserves of 275.7 Bcfe from the SECC Block beyond the concession
term. EOG believes that such concession term will be extended by the Trinidadian government as a matter of course.
44
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Concluded)
Unaudited Quarterly Financial Information
Quarter Ended
---------------------------------------------------
March 31 June 30 Sept. 30 Dec. 31
---------- ---------- ---------- ----------
2001
Net Operating Revenues.......................... $ 597,253 $ 466,048 $ 354,172 $ 237,414
========= ========= ========= =========
Operating Income (Loss)......................... $ 354,024 $ 234,239 $ 123,947 $ (37,658)
========= ========= ========= =========
Income (Loss) before Income Taxes............... $ 340,096 $ 224,865 $ 114,977 $ (48,493)
Income Tax Provision (Benefit).................. 124,849 88,662 43,014 (23,696)
--------- --------- --------- ---------
Net Income (Loss)............................... 215,247 136,203 71,963 (24,797)
Preferred Stock Dividends..................... 2,721 2,757 2,759 2,757
--------- --------- --------- ---------
Net Income (Loss) Available to Common........... $ 212,526 $ 133,446 $ 69,204 $ (27,554)
========= ========= ========= =========
Net Income (Loss) per Share
Available to Common
Basic (1)..................................... $ 1.83 $ 1.15 $ 0.60 $ (0.24)
========= ========= ========= =========
Diluted (1)................................... $ 1.79 $ 1.13 $ 0.59 $ (0.24)
========= ========= ========= =========
Average Number of Common Shares
Basic......................................... 116,384 115,870 115,692 115,115
========= ========= ========= =========
Diluted....................................... 118,952 118,047 117,141 115,115
========= ========= ========= =========
2000
Net Operating Revenues.......................... $ 259,897 $ 322,725 $ 402,152 $ 505,121
========= ========= ========= =========
Operating Income................................ $ 80,210 $ 139,235 $ 203,658 $ 273,760
========= ========= ========= =========
Income before Income Taxes..................... $ 65,659 $ 124,417 $ 188,943 $ 254,538
Income Tax Provision............................ 24,169 46,900 72,466 93,091
--------- --------- --------- ---------
Net Income...................................... 41,490 77,517 116,477 161,447
Preferred Stock Dividends..................... 2,654 2,860 2,755 2,759
--------- --------- --------- ---------
Net Income Available to Common.................. $ 38,836 $ 74,657 $ 113,722 $ 158,688
========= ========= ========= =========
Net Income per Share
Available to Common
Basic (1)..................................... $ 0.33 $ 0.64 $ 0.98 $ 1.36
========= ========= ========= =========
Diluted (1)................................... $ 0.33 $ 0.63 $ 0.95 $ 1.33
========= ========= ========= =========
Average Number of Common Shares
Basic......................................... 117,827 116,666 116,559 116,684
========= ========= ========= =========
Diluted....................................... 118,273 119,179 119,262 119,582
========= ========= ========= =========
(1) The sum of quarterly net income per share available to common may not agree with total year net
income per share available to common as each quarterly computation is based on the weighted average of
common shares outstanding.
45
EXHIBIT 23.1
CONSENT OF DEGOLYER AND MACNAUGHTON
February 25, 2002
We hereby consent to the references to our firm and to the
opinions delivered to EOG Resources, Inc., formerly Enron Oil & Gas
Company (the Company), regarding our comparison of estimates prepared
by us with those furnished to us by the Company of the proved oil,
condensate, natural gas liquids, and natural gas reserves of certain
selected properties owned by the Company. The opinions are contained
in our letter reports dated February 8, 2000, February 8, 2001 and
January 25, 2002 for estimates as of December 31, 1999, December 31,
2000, and December 31, 2001, respectively. The opinions are referred
to in the section "Supplemental Information to Consolidated Financial
Statements - Oil and Gas Producing Activities" in the Company's Current
Report on Form 8-K dated February 27, 2002, to be filed with the
Securities and Exchange Commission (the "Form 8-K"). DeGolyer and
MacNaughton also consents to the inclusion of our letter report,
dated January 25, 2002, addressed to the Company as Exhibit (23.2) to
the Company's Form 8-K. Additionally, we hereby consent to the
incorporation by reference of such references to our firm and to our
opinions included in the Company's Form 8-K in the Company's
previously filed Registration Statement Nos. 33-48358, 33-52201, 33-
58103, 33-62005, 333-09919, 333-20841, 333-18511, 333-31715, 333-
44785, 333-69483, 333-46858, 333-62256 and 333-63184.
DeGOLYER and MacNAUGHTON
46
EXHIBIT 23.2
OPINION OF DEGOLYER AND MACNAUGHTON
January 25, 2002
EOG Resources, Inc.
333 Clay Street, Suite 4200
Houston, Texas 77002
Gentlemen:
Pursuant to your request, we have prepared estimates of the
proved crude oil, condensate, natural gas liquids, and natural gas
reserves, as of December 31, 2001, of certain selected properties in
the United States, Canada, and Trinidad owned by EOG Resources, Inc.
(EOG). The properties consist of working and royalty interests
located in California, New Mexico, Texas, Utah, and Wyoming and
offshore from Texas, Louisiana, and Alabama; in Alberta and
Saskatchewan, Canada; and offshore from Trinidad. The estimates are
reported in detail in our "Report as of December 31, 2001, on Proved
Reserves of Certain Properties in the United States owned by EOG
Resources, Inc. Selected Properties," our "Report as of December 31,
2001, on Proved Reserves of Certain Properties in Canada owned by EOG
Resources, Inc. Selected Properties," our "Report as of December 31,
2001 on Proved Reserves of the U(a) Block Offshore Trinidad owned by
EOG Resources, Inc.," and our "Report as of December 31, 2001, on
Proved Reserves of the Kiskadee and Oil Bird Fields Offshore Trinidad
owned by EOG Resources, Inc." hereinafter collectively referred to as
the "Reports." We also have reviewed information provided to us by
EOG that it represents to be EOG's estimates of the reserves, as of
December 31, 2001, for the same properties as those included in the
Reports.
Proved reserves estimated by us and referred to herein are
judged to be economically producible in future years from known
reservoirs under existing economic and operating conditions and
assuming continuation of current regulatory practices using
conventional production methods and equipment. Proved reserves are
defined as those that have been proved to a high degree of certainty
by reason of actual completion, successful testing, or in certain
cases by adequate core analyses and electrical-log interpretation
when the producing characteristics of the formation are known from
nearby fields. These reserves are defined areally by reasonable
geological interpretation of structure and known continuity of oil-
or gas-saturated material. This definition is in agreement with the
definition of proved reserves prescribed by the Securities and
Exchange Commission (SEC).
EOG represents that its estimates of the proved reserves, as of
December 31, 2001, net to its interests in the properties included in
the Reports are as follows, expressed in thousands of barrels (Mbbl)
or millions of cubic feet (MMcf):
Oil, Condensate, and Net
Natural Gas Liquids Natural Gas Equivalent
(Mbbl) (MMcf) (MMcf)
-------------------- ------------ ------------
49,274 2,711,201 3,006,845
Note: Net equivalent million cubic feet is based on 1 barrel
of oil, condensate, or natural gas liquids being
equivalent to 6,000 cubic feet of gas.
EOG has advised us, and we have assumed, that its estimates of
proved oil, condensate, natural gas liquids, and natural gas reserves
are in accordance with the rules and regulations of the SEC.
Proved reserves net to EOG's interests estimated by us for the
properties included in the Reports, as of December 31, 2001, are as
follows, expressed in thousands of barrels (Mbbl) or millions of
cubic feet (MMcf):
47
Oil, Condensate, and Net
Natural Gas Liquids Natural Gas Equivalent
(Mbbl) (MMcf) (MMcf)
-------------------- ----------- ------------
47,089 2,726,906 3,009,440
Note: Net equivalent million cubic feet is based on 1 barrel
of oil, condensate, or natural gas liquids being
equivalent to 6,000 cubic feet of gas.
In making a comparison of the detailed reserves estimates
prepared by us and by EOG of the properties involved, we have found
differences, both positive and negative, in reserves estimates for
individual properties. These differences appear to be compensating to
a great extent when considering the reserves of EOG in the properties
included in the Reports, resulting in overall differences not being
substantial. It is our opinion that the reserves estimates prepared
by EOG on the properties reviewed by us and referred to above, when
compared on the basis of net equivalent million cubic feet of gas, do
not differ materially from those prepared by us.
Submitted,
DeGOLYER and MacNAUGHTON
48
EXHIBIT 23.3
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report included in this Form 8-K, into EOG
Resources, Inc.'s previously filed Registration Statement File Nos.
33-48358, 33-52201, 33-58103, 33-62005, 333-09919, 333-20841, 333-18511,
333-31715, 333-46858, 333-44785, 333-69483, 333-62256 and 333-63184.
ARTHUR ANDERSEN LLP
Houston, Texas
February 27, 2002