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 20, 2003
EOG RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Delaware 1-9743 47-0684736
(State or other (Commission File (I.R.S. Employer
jurisdiction Number) Identification No.)
of incorporation or
organization)
333 Clay Street
Suite 4200
Houston, Texas 77002
(Address of principal executive offices) (Zip code)
713/651-7000
(Registrant's telephone number, including area code)
EOG RESOURCES, INC.
Item 7. Financial Statements and Exhibits.
(a) Financial Statements of EOG Resources, Inc.
Financial Statements of EOG Resources, Inc. and its
Consolidated Subsidiaries for the fiscal year ended December 31,
2002, including Reports of Independent Public Accountants.
(b) Exhibits.
23.1 Consent of DeGolyer and MacNaughton.
23.2 Opinion of DeGolyer and MacNaughton dated January 31, 2003.
23.3 Consent of Deloitte & Touche LLP.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act
of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned hereunto duly authorized.
EOG RESOURCES, INC.
(Registrant)
Date: February 20, 2003 By: /s/ TIMOTHY K. DRIGGERS
Timothy K. Driggers
Vice President, Accounting
& Land Administration
(Principal Accounting Officer)
EOG RESOURCES, INC.
TABLE OF CONTENTS
Page No.
Management's Discussion and Analysis of Financial Condition
and Results of Operations 4
Management's Responsibility for Financial Reporting 14
Reports of Independent Public Accountants 15
Consolidated Statements of Income and Comprehensive Income
for the years ended December 31, 2002, 2001 and 2000 17
Consolidated Balance Sheets, December 31, 2002 and 2001 18
Consolidated Statements of Shareholders'
Equity for the years ended December 31, 2002, 2001 and 2000 19
Consolidated Statements of Cash Flows for the years
ended December 31, 2002, 2001 and 2000 20
Notes to Consolidated Financial Statements 21
Supplemental Information to Consolidated Financial Statements 37
Exhibits
Exhibit 23.1 - Consent of DeGolyer and MacNaughton 47
Exhibit 23.2 - Opinion of DeGolyer and MacNaughton
dated January 31, 2003 48
Exhibit 23.3 - Consent of Deloitte & Touche LLP 50
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, 2002 should be read in
conjunction with the consolidated financial statements of EOG
Resources, Inc. ("EOG") and notes thereto beginning with page 17.
Results of Operations
Net Operating Revenues. Wellhead volume and price
statistics for the specified years were as follows:
Year Ended December 31,
2002 2001 2000
Natural Gas Volumes (MMcf per day)(1)
United States 635 680 654
Canada 154 126 129
Trinidad 135 115 125
Total 924 921 908
Average Natural Gas Prices ($/Mcf)(2)
United States $2.89 $4.26 $3.96
Canada 2.67 3.78 3.33
Trinidad 1.20 1.22 1.17
Composite 2.60 3.81 3.49
Crude Oil and Condensate Volumes (MBbl per day)(1)
United States 18.8 22.0 22.8
Canada 2.1 1.7 2.1
Trinidad 2.4 2.1 2.6
Total 23.3 25.8 27.5
Average Crude Oil and Condensate Prices ($/Bbl)(2)
United States $24.79 $25.06 $29.68
Canada 23.62 22.70 27.76
Trinidad 23.58 24.14 30.14
Composite 24.56 24.83 29.57
Natural Gas Liquids Volumes (MBbl per day)(1)
United States 2.9 3.5 4.0
Canada 0.8 0.5 0.7
Total 3.7 4.0 4.7
Average Natural Gas Liquids Prices ($/Bbl)(2)
United States $14.76 $17.17 $20.45
Canada 11.17 15.05 16.75
Composite 14.05 16.89 19.87
Natural Gas Equivalent Volumes (MMcfe per day)(3)
United States 765 833 814
Canada 171 139 146
Trinidad 150 128 141
Total 1,086 1,100 1,101
Total Bcfe(3) Deliveries 396 401 403
___________________
(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Dollars per thousand cubic feet or per barrel, as applicable.
(3) Million cubic feet equivalent per day or billion cubic feet equivalent,
as applicable; includes natural gas, crude oil, condensate and natural
gas liquids.
2002 compared to 2001. During 2002, net operating revenues
decreased $560 million to $1,095 million. Total wellhead
revenues of $1,105 million decreased by $435 million, or 28%, as
compared to 2001.
Wellhead natural gas revenues for 2002 decreased
approximately $405 million primarily due to a general decline in
average wellhead natural gas prices, partially offset by an
increase in natural gas deliveries in Canada and Trinidad. The
average wellhead price for natural gas decreased 32% to $2.60 per
Mcf for the year 2002 compared to $3.81 per Mcf in 2001.
Natural gas deliveries increased slightly to 924 MMcf per
day for the year of 2002 compared to 921 MMcf per day for the
comparable period a year ago. The overall increase in natural
gas deliveries was due to an increase in Canada of 22% to 154
MMcf per day in 2002 and an increase in Trinidad of 17% to 135
MMcf per day in 2002. The higher production in 2002 was
attributable to drilling activities and strategic property
acquisitions in Canada, and the commencement of production from
the U(a) Block in Trinidad. This increase was partially offset
by the overall decrease in production in the United States
Divisions of 7% or 45 MMcf per day.
Wellhead crude oil and condensate revenues decreased
approximately $25 million, due primarily to a decline in domestic
crude oil and condensate deliveries with essentially flat
wellhead crude oil and condensate prices. The average wellhead
crude oil and condensate price for 2002 was $24.56 per barrel
compared to $24.83 per barrel for 2001.
Crude oil and condensate deliveries decreased 10% to 23.3
MBbl per day for the year of 2002 compared to 25.8 MBbl per day
in 2001. The decrease in volumes was primarily due to decreased
crude oil and condensate production in the Offshore, Midland and
Tyler Divisions as a result of a natural decline in production.
This natural decline in production was partially offset by
increased production in Trinidad due to the commencement of
production from the U(a) Block, and drilling activities and
strategic property acquisitions in Canada.
Natural gas liquids revenues were $6 million lower than a
year ago primarily due to a decrease in prices of 17% and a
decrease in deliveries of 8%.
During 2002, EOG recognized losses on mark-to-market
commodity derivative contracts of $49 million, of which $23
million were realized losses.
Other marketing activities associated with sales and
purchases of natural gas transactions increased net operating
revenues by $37 million and $16 million in 2002 and 2001,
respectively.
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
revenues by $16 million during 2001, compared to a $10 million
reduction in 2000.
Operating Expenses
2002 compared to 2001. During 2002, operating expenses of
$914 million were approximately $66 million lower than the $980
million incurred in 2001.
Dry hole costs of $47 million decreased $25 million from
2001.
Taxes other than income decreased $23 million to $72 million
as compared to 2001 due to decreased wellhead revenue in North
America resulting in lower production taxes and decreased ad
valorem taxes.
Impairments decreased $11 million to $68 million primarily
as a result of improved value-to-cost relationship on a field by
field basis and decreased amortization of unproved leases in
2002.
Exploration costs of $60 million were $7 million lower than
a year ago primarily due to decreased geological and geoscience
expenditures.
Lease and well expenses increased $4 million to $179 million
compared to a year ago primarily due to continually expanding
operations and increases in production activity in Canada,
partially offset by a fewer number of workovers in the Offshore
Division.
Depreciation, depletion and amortization ("DD&A") expenses
increased $6 million to $398 million primarily due to increased
activity in Canada and the Pittsburgh Division along with higher
per unit costs related to certain fields in the Denver Division,
partially offset by a natural production decline in the Midland,
Oklahoma City, Tyler and Offshore Divisions.
General and administrative ("G&A") expenses increased $9
million to $89 million primarily due to the settlement of
litigation in the second quarter, increased insurance expense and
expanded operations.
Interest Expense. The increase in net interest expense of
$15 million for 2002 as compared to 2001 is primarily due to
higher average debt balance for the year of 2002 (see Note 2 to
the Consolidated Financial Statements) and the one-time close-out
fees associated with the completion of the Section 29 (Tight Gas
Sands Federal Income Tax Credits) financing begun in 1999.
Per-Unit Costs. The following table presents the operating
costs per thousand cubic feet equivalent (Mcfe) for years ended
December 31, 2002 and 2001.
Year Ended December 31,
2002 2001
Lease and Well $0.45 $0.44
DD&A 1.00 0.98
G&A 0.22 0.20
Taxes Other than Income 0.18 0.24
Interest Expense 0.15 0.11
Total Per-Unit Costs $2.00 $1.97
The lower per-unit rate of taxes other than income for 2002
compared to 2001 is due primarily to decreased average wellhead
natural gas prices.
The higher per-unit G&A and interest expense rates for 2002
compared to 2001 are due to reasons delineated in the above G&A
and interest expense discussions.
Income Taxes. Income tax provision decreased approximately
$200 million for 2002 as compared to 2001 primarily as a result
of a lower pre-tax income in 2002 and a reduction in the overall
foreign effective tax rate.
2001 compared to 2000. During 2001, operating expenses of
$980 million, which includes $19 million of charges related to
the bankruptcy of Enron and certain of its affiliates, 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. DD&A expenses increased $33 million
to $392 million primarily due to increased DD&A rates. G&A
expenses increased $13 million primarily due to expanded
operations. Taxes other than income remained approximately the
same as compared to 2000.
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 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 the Enron bankruptcies 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.
Capital Resources and Liquidity
Cash Flow. The primary sources of cash for EOG during the
three-year period ended December 31, 2002 included cash generated
from operations, proceeds from the sales of selected oil and gas
reserves and related assets, funds from new borrowings and
proceeds from stock options exercised. Primary cash outflows
included funds used in operations, exploration and development
expenditures, common stock repurchases and dividends paid to EOG
shareholders.
Net operating cash flows of $669 million in 2002 decreased
approximately $529 million as compared to 2001 primarily due to
lower average natural gas and liquids prices partially offset by
lower cash operating expenses and lower current income taxes.
Changes in working capital and other liabilities decreased
operating cash flows by $145 million as compared to 2001
primarily due to changes in accounts receivable, accrued
royalties payable and accrued production taxes caused by
fluctuation of commodity prices at each yearend.
Net investing cash outflows of $873 million in 2002
decreased by $216 million as compared to 2001 due primarily to
decreased exploration and development expenditures of $292
million (including producing property acquisitions), partially
offset by increased uses of working capital related to investing
activities and increased equity investments. 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 provided by financing activities in 2002 was $211
million as compared to cash used of $127 million in 2001.
Financing activities in 2002 included funds from new borrowings
of $289 million, common stock repurchases of $63 million,
dividend payments of $29 million and proceeds from stock options
exercised of $17 million. New borrowings included $120 million of
commercial paper borrowings and $250 million of promissory note
issuances, partially offset by a decrease in uncommitted line of
credit borrowings of $81 million.
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 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 stock options exercised of $31 million.
Exploration and Development Expenditures. The table below
sets out components of exploration and development expenditures
for the years ended December 31, 2002, 2001 and 2000, along with
the total budgeted for 2003, excluding acquisitions.
Actual Budgeted 2003
Expenditure Category 2002 2001 2000 (excluding acquisitions)
(In Millions)
Capital
Drilling and Facilities $ 595 $ 722 $ 443
Leasehold Acquisitions 39 76 51
Producing Property Acquisitions 71 168 102
Capitalized Interest 9 9 7
Subtotal 714 975 603
Exploration Costs 60 67 67
Dry Hole Costs 47 71 17
Subtotal 821 1,113 687 $800 - $950
Deferred Income Tax Gross Up 15 50 23
Total $ 836 $1,163 $ 710
Total exploration and development expenditures of $836
million decreased $327 million in 2002 as compared to 2001
primarily due to decreased exploration and development activities
in the United States and Trinidad along with fewer strategic
property acquisitions, partially offset by increased exploration
and development activities in Canada. Included in the 2002
expenditures are $545 million in development, $196 million in
exploration, $71 million in property acquisition, $15 million in
deferred income tax gross up and $9 million in capitalized
interest.
Derivative Transactions. During 2002, EOG recognized losses
on mark-to-market commodity derivative contracts of $49 million,
which included realized losses of $21 million and a $2 million
collar premium payment (see Note 11 to the Consolidated Financial
Statements).
Presented below is a summary of EOG's 2003 natural gas
financial collar contracts and natural gas and crude oil
financial price swap contracts as of February 19, 2003 with
prices expressed in dollars per million British thermal units
($/MMBtu) and in dollars per barrel ($/Bbl), as applicable, and
notional volumes in million British thermal units per day
(MMBtud) and in barrels per day (Bbld), as applicable. EOG
accounts for these collar and swap contracts using mark-to-market
accounting.
Natural Gas Financial Collar Contracts Financial Price Swap Contracts
Floor Price Ceiling Price Natural Gas Crude Oil
Floor Weighted Ceiling Weighted Weighted Weighted
Volume Range Average Range Average Volume Average Volume Average
Month (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu) (Bbld) ($/Bbl)
Jan 50,000 $3.87 $3.87 $6.09 $6.09 -- -- 2,000 $27.34
Feb 125,000 3.76 - 4.30 4.04 5.05 - 6.30 5.87 -- -- 2,000 26.91
Mar 125,000 3.61 - 4.20 3.93 5.00 - 6.20 5.77 100,000 $5.19 4,000 27.96
Apr 125,000 3.59 - 4.02 3.82 4.80 - 6.03 5.33 100,000 4.96 5,000 27.77
May 125,000 3.54 - 3.92 3.74 4.70 - 5.92 5.24 100,000 4.82 5,000 27.04
Jun 125,000 3.56 - 3.89 3.74 4.70 - 5.90 5.25 100,000 4.77 5,000 26.43
Jul 125,000 3.59 - 3.91 3.76 4.73 - 5.91 5.27 100,000 4.77 5,000 25.90
Aug 125,000 3.60 - 3.91 3.76 4.73 - 5.91 5.27 100,000 4.77 5,000 25.49
Sep 125,000 3.60 - 3.89 3.75 4.73 - 5.89 5.26 100,000 4.74 5,000 25.19
Oct 125,000 3.60 - 3.90 3.75 4.73 - 5.90 5.27 100,000 4.74 5,000 24.90
Nov 125,000 3.77 - 4.04 3.90 4.90 - 6.04 5.43 -- -- 5,000 24.70
Dec 125,000 3.92 - 4.18 4.04 5.05 - 6.18 5.57 -- -- 5,000 24.47
Financing. EOG's long-term debt-to-total-capitalization
ratio was 40.6% as of December 31, 2002 compared to 34.3% as of
December 31, 2001.
During 2002, total long-term debt increased to
$1,145 million primarily due to capital expenditures exceeding
cash flow from operations (see Note 2 to the Consolidated
Financial Statements). The estimated fair value of EOG's
long-term debt at December 31, 2002 and 2001 was $1,225 million
and $838 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, 2002, a 1% decline in
interest rates would result in a $59 million increase in the
estimated fair value of the fixed rate obligations (see Note 11
to the Consolidated Financial Statements).
The following table summarizes EOG's contractual obligations
at December 31, 2002 (in thousands):
2009 &
Contractual Obligations(1) Total 2003 2004 - 2006 2007 - 2008 beyond
Long-Term Debt $1,145,132 $ -- $511,180 $273,952 $360,000
Non-cancelable Operating Leases 38,581 11,083 22,755 3,783 960
Drilling Rig Commitments 1,470 1,470 -- -- --
Transportation Service Commitments(2) 37,065 9,255 18,533 5,988 3,289
Total Contractual Obligations $1,222,248 $21,808 $552,468 $283,723 $364,249
(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, 2002.
Management does not believe that any future changes in these
rates before the expiration dates of these commitments will
have a materially adverse effect on the financial condition or
results of operations of EOG.
Shelf Registration. 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 19, 2003, 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, fluctuations in the
availability and utilization of natural gas storage capacity and
ever-changing weather patterns. However, the increasing
recognition of natural gas as a more environmentally friendly
source of energy could result in increases in demand. Being
primarily a natural gas producer, EOG is more significantly
impacted by changes in natural gas prices than by changes in
crude oil and condensate prices.
Marketing companies have played an important role in the
North American natural gas market. These companies aggregate
natural gas supplies through purchases from producers like EOG
and then resell the gas to end users, local distribution
companies or other buyers. Several of the largest natural gas
marketing companies have recently filed for bankruptcy or are
currently in financial difficulty, and others are exiting this
business. EOG does not believe that this will have a material
effect on its ability to market its natural gas production. EOG
continues to assess and monitor the credit worthiness of partners
to whom it sells its production and where appropriate, to seek
new markets.
EOG plans to continue to focus a substantial portion of its
exploration and development expenditures in its major producing
areas in North America. However, in order to diversify its
overall asset portfolio and as a result of its overall success
realized in Trinidad, EOG anticipates expending a portion of its
available funds in the further development of opportunities
outside North America. In addition, EOG expects to conduct
limited exploratory activity in other areas outside of North
America, including the United Kingdom North Sea, and will
continue to evaluate the potential for involvement in other
exploitation type opportunities. Budgeted 2003 exploration and
development expenditures, excluding acquisitions, are in the
range of $800 - $950 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 2003 are structured to maintain the
flexibility necessary under EOG's strategy of funding North
America exploration, exploitation, development and acquisition
activities primarily from available internally generated cash
flow.
The level of exploration and development expenditures may
vary in 2003 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 2003
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 expected to
be material when considered in relation to the total financial
capacity of EOG.
Environmental Regulations. Various federal, state and local
laws and regulations covering the discharge of materials into the
environment, or otherwise relating to protection of the
environment, may affect EOG's operations and costs as a result of
their effect on natural gas and crude oil exploration,
exploitation, development and production operations. In
addition, EOG has acquired certain oil and gas properties from
third parties whose actions with respect to the management and
disposal or release of hydrocarbons or other wastes were not
under EOG's control. Under environmental laws and regulations,
EOG could be required to remove or remediate wastes disposed of
or released by prior owners or operators. EOG also has acquired
or merged with companies that own and operate oil and gas
properties. Any obligations or liabilities of these companies
under environmental laws would continue as liabilities of the
acquired company, or of EOG in the event of a merger, even if the
obligations or liabilities resulted from actions that took place
before the acquisition or merger. Compliance with such laws and
regulations has not had a material adverse effect on EOG's
operations or financial condition. It is not anticipated, based
on current laws and regulations, that EOG will be required in the
near future to expend amounts that are material in relation to
its total exploration and development expenditure program by
reason of environmental laws and regulations. However, inasmuch
as such laws and regulations are frequently changed, EOG is
unable to predict the ultimate cost of compliance.
EOG also could incur costs related to the clean up of sites
to which it sent regulated substances for disposal 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 include the accounts of all domestic and
foreign subsidiaries. Investments in unconsolidated affiliates,
in which EOG is able to exercise significant influence, are
accounted for using the equity method. All material intercompany
accounts and transactions have been eliminated.
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenue and
expenses during the reporting period. Actual results could differ
from those estimates.
Certain reclassifications have been made to prior period
financial statements to conform with the current presentation.
Beginning 2001, the "Impairment of Unproved Oil and Gas
Properties" caption on the Consolidated Statements of Income was
renamed "Impairments" to include the impairment 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 superseded by SFAS No. 144-"Accounting for
the Impairment or Disposal of Long-Lived Assets." As a result,
EOG reclassified all prior periods to reflect such SFAS 121
Impairments in Impairments, instead of DD&A as previously
reported. SFAS 121 Impairments reclassified from DD&A to
Impairments was $11 million for 2000.
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 to the Consolidated Financial Statements 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.
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
is recorded when overproduction occurs.
New Accounting Pronouncements. In June 2001, the Financial
Accounting Standards Board ("FASB") issued SFAS No.
143-"Accounting for Asset Retirement Obligations" effective for
fiscal years beginning after June 15, 2002. SFAS No. 143
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. Increase in the
liability due to passage of time, as a result of applying an
interest method of allocation to the amount of the liability at
the beginning of a period, is recognized as an increase in the
carrying amount of the liability and as an expense classified as
an operating item in the statement of income. If the obligation
is settled for other than the carrying amount of the liability, a
gain or loss is recognized on settlement. EOG adopted the
statement on January 1, 2003. The impact of adopting the
statement results in an after-tax loss of approximately $6.5
million which will be reported as cumulative adjustment for
change in accounting principle in the first quarter of 2003.
In April 2002, the FASB issued SFAS No. 145-"Rescission of
FASB Statements No. 4, 44, and 64, Amendment of FASB Statement
No. 13, and Technical Corrections" effective for financial
statements issued on or after May 15, 2002. SFAS No. 145
requires gains and losses on the extinguishment of debt to be
classified as income or loss from continuing operations, unless
the requirements of Accounting Principles Board Opinion ("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" are met, upon which the gain or loss would be
considered unusual and infrequent and classified as an
extraordinary item. Prior to adoption of SFAS No. 145, all gains
and losses from extinguishment of debt were classified as
extraordinary items. SFAS No. 145 also creates consistency
between accounting for sale-leaseback transactions and certain
lease modifications with economic effects similar to sale-
leaseback transactions, along with various amendments which make
technical corrections and clarifications. EOG adopted this
statement on January 1, 2003. The adoption of SFAS No. 145 did
not have any effect on its financial position or results of
operations.
In June 2002, the FASB issued SFAS No. 146-"Accounting for
Costs Associated with Exit or Disposal Activities." SFAS No. 146
nullifies the guidance of the Emerging Issues Task Force (EITF)
Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." SFAS No.
146 requires that a liability for a cost associated with an exit
or disposal activity be recognized only when the liability is
incurred and measured initially at fair value. SFAS No. 146 is
effective for exit or disposal activities initiated after
December 31, 2002. EOG does not expect the impact of SFAS No.
146 to have a material effect on its financial position or
results of operations.
In October 2002, the FASB issued SFAS No. 147-"Acquisitions
of Certain Financial Institutions", effective for acquisitions on
or after October 1, 2002. The statement relates to the
application of the purchase method of accounting for acquisitions
of financial institutions. The statement is currently not
applicable to EOG.
In December 2002, the FASB issued SFAS No. 148-"Accounting
for Stock-Based Compensation-Transition and Disclosure - an
amendment of FASB Statement No. 123." This statement provides
alternative methods of transition for a voluntary change to the
fair value based method of accounting for stock-based employee
compensation, along with the requirement of disclosure in both
annual and interim financial statements about the method used and
effect on reported results. EOG has not decided whether it will
utilize the fair value method of accounting for stock-based
employee compensation and is currently evaluating the alternative
methods provided by SFAS No. 148. Based on EOG's current level
of stock-based employee compensation activities and its existing
financial statement footnote disclosure regarding such
activities, EOG does not expect the impact of implementing any of
the alternative methods to be material.
Accounting for Price Risk Management Activities. EOG
accounts for its price risk management activities under the
provisions of SFAS No. 133-"Accounting for Derivative Instruments
and Hedging Activities," as amended by SFAS No. 137 and No. 138.
The statement establishes accounting and reporting standards
requiring that every derivative instrument be recorded in the
balance sheet as either an asset or liability measured at its
fair value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. During 2001
and 2002, EOG elected not to designate any of its price risk
management activities as accounting hedges under SFAS No. 133,
and accordingly, accounted for them using the mark-to-market
accounting method. Under this accounting method, the changes in
the market value of outstanding financial instruments are
recognized as gains or losses in the period of change. The gains
or losses are recorded in Gains (Losses) on Mark-to-market
Commodity Derivative Contracts 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
11 to the Consolidated Financial Statements).
Capitalized Interest Costs. Certain interest costs have
been capitalized as a part of the historical cost of unproved oil
and gas properties.
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 to the Consolidated Financial
Statements).
Foreign Currency Translation. For subsidiaries whose
functional currency is deemed to be other than the United States
dollar, asset and liability accounts are translated at year-end
exchange rates and revenue and expenses are translated at average
exchange rates prevailing during the year. Translation adjustments
are included in Accumulated Other Comprehensive Loss in the
Shareholders' Equity section of the Consolidated Balance Sheets.
Accumulated translation losses were $50 million and $54 million at
December 31, 2002 and 2001, respectively. 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 to the Consolidated
Financial Statements for additional information to reconcile the
difference between the Average Number of Common Shares
outstanding for basic and diluted net income per share).
Stock Options. EOG accounts for stock options under the
provisions and related interpretations of APB Opinion No.
25-"Accounting for Stock Issued to Employees." No compensation
expense is recognized for such options. As allowed by SFAS No.
123-"Accounting for Stock-Based Compensation" issued in 1995, EOG
has continued to apply APB Opinion No. 25 for purposes of
determining net income and to present the pro forma disclosures
required by SFAS No. 123.
Information Regarding Forward-Looking Statements
This Current Report on Form 8-K includes forward-looking
statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of
1934. All statements other than statements of historical facts,
including, among others, statements regarding EOG's future
financial position, business strategy, budgets, reserve
information, projected levels of production, projected costs and
plans and objectives of management for future operations, are
forward-looking statements. EOG typically uses words such as
"expect," "anticipate," "estimate," "strategy," "intend," "plan,"
"target" and "believe" or the negative of those terms or other
variations of them or by comparable terminology to identify its
forward-looking statements. In particular, statements, express
or implied, concerning future operating results, the ability to
replace or increase reserves or to increase production, or the
ability to generate income or cash flows are forward-looking
statements. Forward-looking statements are not guarantees of
performance. Although EOG believes its expectations reflected in
forward-looking statements are based on reasonable assumptions,
no assurance can be given that these expectations will be
achieved. Important factors that could cause actual results to
differ materially from the expectations reflected in the forward-
looking statements include, among others: the timing and extent
of changes in commodity prices for crude oil, natural gas and
related products 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; acts of war; and financial market
conditions. In light of these risks, uncertainties and
assumptions, the events anticipated by EOG's forward-looking
statements might not occur. EOG undertakes no obligations to
update or revise its forward-looking statements, whether as a
result of new information, future events or otherwise.
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The following consolidated financial statements of EOG
Resources, Inc. and its subsidiaries ("EOG") were prepared by
management, which is responsible for their integrity, objectivity
and fair presentation. The statements have been prepared in
conformity with accounting principles generally accepted in the
United States and, accordingly, include some amounts that are
based on the best estimates and judgments of management.
Deloitte & Touche LLP, independent public accountants, was
engaged to audit the consolidated financial statements of EOG and
issue a report thereon. In the conduct of the audit, Deloitte &
Touche LLP was given unrestricted access to all financial records
and related data including minutes of all meetings of
shareholders, the Board of Directors and committees of the Board.
Their audit was made in accordance with auditing standards
generally accepted in the United States of America and included a
review of the system of internal controls to the extent
considered necessary to determine the audit procedures required
to support their opinion on the consolidated financial
statements. Management believes that all representations made to
Deloitte & Touche LLP during the audit were valid and
appropriate.
The system of internal controls of EOG is designed to
provide reasonable assurance as to the reliability of financial
statements and the protection of assets from unauthorized
acquisition, use or disposition. This system includes, but is not
limited to, written policies and guidelines including a published
code for the conduct of business affairs, conflicts of interest
and compliance with laws regarding antitrust, antiboycott and
foreign corrupt practices policies, the careful selection and
training of qualified personnel, and a documented organizational
structure outlining the separation of responsibilities among
management representatives and staff groups.
The adequacy of financial controls of EOG and the accounting
principles employed in financial reporting by EOG are under the
general oversight of the Audit Committee of the Board of
Directors. No member of this committee is an officer or employee
of EOG. The independent public accountants and internal auditors
have full, free, separate and direct access to the Audit
Committee and meet with the committee from time to time to
discuss accounting, auditing and financial reporting matters. It
should be recognized that there are inherent limitations to the
effectiveness of any system of internal control, including the
possibility of human error and circumvention or override.
Accordingly, even an effective system can provide only reasonable
assurance with respect to the preparation of reliable financial
statements and safeguarding of assets. Furthermore, the
effectiveness of an internal control system can change with
circumstances.
It is management's opinion that, considering the criteria
for effective internal control over financial reporting and
safeguarding of assets which consists of interrelated components
including the control environment, risk assessment process,
control activities, information and communication systems, and
monitoring, EOG maintained an effective system of internal
control as to the reliability of financial statements and the
protection of assets against unauthorized acquisition, use or
disposition during the year ended December 31, 2002.
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 19, 2003
REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
EOG Resources, Inc.
Houston, Texas
We have audited the accompanying balance sheet of EOG
Resources, Inc. (the "Company") as of December 31, 2002, and the
related statements of income, stockholders' equity, and cash
flows for the year then ended. 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 audit. The financial statements of EOG
Resources, Inc. as of December 31, 2001, and for the two years
then ended were audited by other auditors who have ceased
operations. Those auditors expressed an unqualified opinion on
those financial statements in their report dated February 21,
2002.
We conducted our audit in accordance with auditing standards
generally accepted in the United States of America. Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation. We believe that our audit provides a reasonable
basis for our opinion.
In our opinion, such financial statements present fairly, in
all material respects, the financial position of the Company as
of December 31, 2002, and the results of its operations and its
cash flows for the year then ended in conformity with accounting
principles generally accepted in the United States of America.
Deloitte & Touche LLP
February 19, 2003
REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS (Continued)
EOG dismissed Arthur Andersen LLP on February 27, 2002 and
subsequently engaged Deloitte & Touche LLP as its independent
auditors. The predecessor auditor's report appearing below is a
copy of Arthur Andersen's previously issued report dated February
21, 2002. Since EOG is unable to obtain a current manually
signed audit report, a copy of Arthur Andersen's most recent
signed and dated report has been included to satisfy filing
requirements, as permitted under Rule 2-02(e) of Regulation S-X.
To EOG Resources, Inc.:
We have audited the accompanying consolidated balance sheets
of EOG Resources, Inc. (a Delaware corporation) and subsidiaries
as of December 31, 2001 and 2000, and the related consolidated
statements of income and comprehensive income, shareholders'
equity and cash flows for each of the three years in the period
ended December 31, 2001. These financial statements are the
responsibility of the Company's management. Our responsibility is
to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with auditing
standards generally accepted in the United States. Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of EOG Resources, Inc. and subsidiaries as of December 31, 2001
and 2000, and the results of their operations and their cash
flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
February 21, 2002
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(In Thousands, Except Per Share Amounts)
Year Ended December 31,
2002 2001 2000
NET OPERATING REVENUES
Natural Gas $ 915,129 $1,298,102 $1,155,804
Crude Oil, Condensate and Natural
Gas Liquids 227,309 258,101 325,726
Gains (Losses) on Mark-to-market
Commodity Derivative Contracts (48,508) 97,750 (1,000)
Gains on Sales of Reserves and Related
Assets and Other, Net 1,106 934 9,365
Total 1,095,036 1,654,887 1,489,895
OPERATING EXPENSES
Lease and Well 179,429 175,446 140,915
Exploration Costs 60,228 67,467 67,196
Dry Hole Costs 46,749 71,360 17,337
Impairments 68,430 79,156 46,478
Depreciation, Depletion and Amortization 398,036 392,399 359,265
General and Administrative 88,952 79,963 66,932
Taxes Other Than Income 71,881 95,333 94,909
Charges Associated with Enron Bankruptcy -- 19,211 --
Total 913,705 980,335 793,032
OPERATING INCOME 181,331 674,552 696,863
OTHER INCOME (EXPENSE) (2,005) 2,003 (2,300)
INCOME BEFORE INTEREST EXPENSE AND
INCOME TAXES 179,326 676,555 694,563
INTEREST EXPENSE
Incurred 68,641 53,756 67,714
Capitalized (8,987) (8,646) (6,708)
Net Interest Expense 59,654 45,110 61,006
INCOME BEFORE INCOME TAXES 119,672 631,445 633,557
INCOME TAX PROVISION 32,499 232,829 236,626
NET INCOME 87,173 398,616 396,931
PREFERRED STOCK DIVIDENDS 11,032 10,994 11,028
NET INCOME AVAILABLE TO COMMON $ 76,141 $ 387,622 $ 385,903
NET INCOME PER SHARE AVAILABLE TO COMMON
Basic $ 0.66 $ 3.35 $ 3.30
Diluted $ 0.65 $ 3.30 $ 3.24
AVERAGE NUMBER OF COMMON SHARES
Basic 115,335 115,765 116,934
Diluted 117,245 117,488 119,102
COMPREHENSIVE INCOME
NET INCOME $ 87,173 $ 398,616 $ 396,931
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Translation Adjustment 4,315 (22,044) (12,338)
Available-for-sale Security Transactions 926 (1,318) 392
COMPREHENSIVE INCOME $ 92,414 $ 375,254 $ 384,985
The accompanying notes are an integral part of these consolidated
financial statements.
EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands)
At December 31,
ASSETS 2002 2001
CURRENT ASSETS
Cash and Cash Equivalents $ 9,848 $ 2,512
Accounts Receivable, net 259,308 194,624
Inventories 18,928 18,871
Assets from Price Risk Management Activities -- 19,161
Federal Income Tax Receivable 50,825 19,332
Other 55,883 17,921
Total 394,792 272,421
OIL AND GAS PROPERTIES (Successful Efforts Method) 6,750,095 6,065,603
Less: Accumulated Depreciation, Depletion
and Amortization (3,428,547) (3,009,693)
Net Oil and Gas Properties 3,321,548 3,055,910
OTHER ASSETS 97,666 85,713
TOTAL ASSETS $3,814,006 $3,414,044
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable $ 201,931 $ 219,561
Accrued Taxes Payable 23,170 40,219
Dividends Payable 5,007 5,045
Liabilities from Price Risk Management Activities 5,939 --
Accrued Employee Benefits 11,099 16,345
Other 29,205 29,677
Total 276,351 310,847
LONG-TERM DEBT 1,145,132 855,969
OTHER LIABILITIES 59,180 53,522
DEFERRED INCOME TAXES 660,948 551,020
SHAREHOLDERS' EQUITY
Preferred Stock, $.01 Par, 10,000,000 Shares
Authorized:
Series B, 100,000 Shares Issued, Cumulative,
$100,000,000 Liquidation Preference 98,352 98,116
Series D, 500 Shares Issued, Cumulative,
$50,000,000 Liquidation Preference 49,647 49,466
Common Stock, $.01 Par, 320,000,000 Shares
Authorized and 124,730,000 Shares Issued 201,247 201,247
Unearned Compensation (15,033) (14,953)
Accumulated Other Comprehensive Loss (49,877) (55,118)
Retained Earnings 1,723,948 1,668,708
Common Stock Held in Treasury, 10,009,740 shares
at December 31, 2002 and 9,278,382 shares at
December 31, 2001 (335,889) (304,780)
Total Shareholders' Equity 1,672,395 1,642,686
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $3,814,006 $3,414,044
The accompanying notes are an integral part of these consolidated
financial statements.
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(In Thousands, Except Per Share Amounts)
Accumulated Common
Additional Other Stock Total
Preferred Common Paid In Unearned Comprehensive Retained Held In Shareholders'
Stock Stock Capital Compensation Income (Loss) Earnings Treasury Equity
Balance at December 31, 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
Net Income -- -- -- -- -- 87,173 -- 87,173
Amortization of Preferred
Stock Discount 417 -- -- -- -- (417) -- --
Preferred Stock Dividends
Paid/Declared -- -- -- -- -- (10,615) -- (10,615)
Common Stock Dividends
Declared, $.16 Per Share -- -- -- -- -- (18,499) -- (18,499)
Translation Adjustment -- -- -- -- 4,315 -- -- 4,315
Available-for-sale Security
Transactions -- -- -- -- 926 -- -- 926
Treasury Stock Purchased -- -- -- -- -- -- (63,038) (63,038)
Treasury Stock Issued Under
Stock Option Plans -- -- (9,457) -- -- (2,402) 28,565 16,706
Treasury Stock Issued Under
Employee Stock Purchase Plan -- -- (39) -- -- -- 2,301 2,262
Tax Benefits from Stock
Options Exercised -- -- 5,167 -- -- -- -- 5,167
Restricted Stock and Units -- -- 4,329 (4,951) -- -- 622 --
Amortization of Unearned
Compensation -- -- -- 4,871 -- -- -- 4,871
Other -- -- -- -- -- -- 441 441
Balance at December 31, 2002 $147,999 $201,247 $ -- $(15,033) $(49,877) $1,723,948 $(335,889) $1,672,395
The accompanying notes are an integral part of these consolidated financial
statements.
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
Year Ended December 31,
2002 2001 2000
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of Net Income to Net
Operating Cash Inflows:
Net Income $ 87,173 $ 398,616 $ 396,931
Items Not Requiring Cash
Depreciation, Depletion and Amortization 398,036 392,399 359,265
Impairments 68,430 79,156 46,478
Deferred Income Taxes 82,179 164,945 97,729
Charges Associated with Enron Bankruptcy -- 19,211 --
Other, Net 17,333 10,423 6,693
Exploration Costs 60,228 67,467 67,196
Dry Hole Costs 46,749 71,360 17,337
Mark-to-market Commodity Derivative Contracts
Total (Gains) Losses 48,508 (97,750) 1,000
Realized Gains (Losses) (21,136) 66,731 (1,438)
Collar Premium (1,825) (4,621) --
Losses (Gains) on Sales of Reserves
and Related Assets and Other, Net (70) 835 (5,539)
Tax Benefits from Stock Options Exercised 5,168 7,332 41,307
Other, Net (1,908) (3,127) (8,935)
Changes in Components of Working Capital
and Other Liabilities
Accounts Receivable (61,580) 146,235 (191,492)
Inventories (57) (2,248) 2,345
Accounts Payable (19,012) (26,949) 97,374
Accrued Taxes Payable (84,666) (38,619) 54,556
Other Liabilities 7,816 (3,422) 348
Other, Net (5,578) (16,442) 11,378
Changes in Components of Working Capital
Associated with Investing and
Financing Activities 42,782 (34,105) (25,123)
NET OPERATING CASH INFLOWS 668,570 1,197,427 967,410
INVESTING CASH FLOWS
Additions to Oil and Gas Properties (714,127) (974,016) (602,638)
Exploration Costs (60,228) (67,467) (67,196)
Dry Hole Costs (46,749) (71,360) (17,337)
Proceeds from Sales of Reserves and
Related Assets 8,089 8,032 26,189
Changes in Components of Working Capital
Associated with Investing Activities (43,246) 32,405 22,798
Other, Net (16,277) (15,649) (28,977)
NET INVESTING CASH OUTFLOWS (872,538) (1,088,055) (667,161)
FINANCING CASH FLOWS
Long-Term Debt Borrowings (Repayments) 289,163 (4,155) (131,306)
Dividends Paid (29,152) (28,580) (26,071)
Treasury Stock Purchased (63,038) (126,769) (272,723)
Proceeds from Stock Options Exercised 17,339 30,805 127,090
Other, Net (3,008) 1,687 (1,923)
NET FINANCING CASH INFLOWS (OUTFLOWS) 211,304 (127,012) (304,933)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 7,336 (17,640) (4,684)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 2,512 20,152 24,836
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 9,848 $ 2,512 $ 20,152
The accompanying notes are an integral part of these consolidated
financial statements.
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial
statements of EOG Resources, Inc. ("EOG"), 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 of
America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenue and
expenses during the reporting period. Actual results could differ
from those estimates.
Certain reclassifications have been made to prior period
financial statements to conform with the current presentation.
Beginning 2001, the "Impairment of Unproved Oil and Gas
Properties" caption on the Consolidated Statements of Income was
renamed "Impairments" to include the impairment 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 superseded by SFAS No. 144-"Accounting for
the Impairment or Disposal of Long-Lived Assets." 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 was $11 million
for 2000.
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.
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
is recorded when overproduction occurs.
New Accounting Pronouncements. In June 2001, the Financial
Accounting Standards Board ("FASB") issued SFAS No.
143-"Accounting for Asset Retirement Obligations" effective for
fiscal years beginning after June 15, 2002. SFAS No. 143
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. Increase in the
liability due to passage of time, as a result of applying an
interest method of allocation to the amount of the liability at
the beginning of a period, is recognized as an increase in the
carrying amount of the liability and as an expense classified as
an operating item in the statement of income. If the obligation
is settled for other than the carrying amount of the liability, a
gain or loss is recognized on settlement. EOG adopted the
statement on January 1, 2003. The impact of adopting the
statement resulted in an after-tax loss of approximately $6.5
million which will be reported as cumulative adjustment for
change in accounting principle in the first quarter of 2003.
In April 2002, the FASB issued SFAS No. 145-"Rescission of
FASB Statements No. 4, 44, and 64, Amendment of FASB Statement
No. 13, and Technical Corrections" effective for financial
statements issued on or after May 15, 2002. SFAS No. 145
requires gains and losses on the extinguishment of debt to be
classified as income or loss from continuing operations, unless
the requirements of Accounting Principles Board Opinion ("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" are met, upon which the gain or loss would be
considered unusual and infrequent and classified as an
extraordinary item. Prior to adoption of SFAS No. 145, all gains
and losses from extinguishment of debt were classified as
extraordinary items. SFAS No. 145 also creates consistency
between accounting for sale-leaseback transactions and certain
lease modifications with economic effects similar to sale-
leaseback transactions, along with various amendments which make
technical corrections and clarifications. EOG adopted this
statement on January 1, 2003. The adoption of SFAS No. 145 did
not have any effect on its financial position or results of
operations.
In June 2002, the FASB issued SFAS No. 146-"Accounting for
Costs Associated with Exit or Disposal Activities." SFAS No. 146
nullifies the guidance of the Emerging Issues Task Force (EITF)
Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." SFAS No.
146 requires that a liability for a cost associated with an exit
or disposal activity be recognized only when the liability is
incurred and measured initially at fair value. SFAS No. 146 is
effective for exit or disposal activities initiated after
December 31, 2002. EOG does not expect the impact of SFAS No.
146 to have a material effect on its financial position or
results of operations.
In October 2002, the FASB issued SFAS No. 147-"Acquisitions
of Certain Financial Institutions", effective for acquisitions on
or after October 1, 2002. The statement relates to the
application of the purchase method of accounting for acquisitions
of financial institutions. The statement is currently not
applicable to EOG.
In December 2002, the FASB issued SFAS No. 148-"Accounting
for Stock-Based Compensation-Transition and Disclosure - an
amendment of FASB Statement No. 123." This statement provides
alternative methods of transition for a voluntary change to the
fair value based method of accounting for stock-based employee
compensation, along with the requirement of disclosure in both
annual and interim financial statements about the method used and
effect on reported results. EOG has not decided whether it will
utilize the fair value method of accounting for stock-based
employee compensation and is currently evaluating the alternative
methods provided by SFAS No. 148. Based on EOG's current level
of stock-based employee compensation activities and its existing
financial statement footnote disclosure regarding such
activities, EOG does not expect the impact of implementing any of
the alternative methods to be material.
Accounting for Price Risk Management Activities. EOG
accounts for its price risk management activities under the
provisions of SFAS No. 133-"Accounting for Derivative Instruments
and Hedging Activities," as amended by SFAS No. 137 and No. 138.
The statement establishes accounting and reporting standards
requiring that every derivative instrument be recorded in the
balance sheet as either an asset or liability measured at its
fair value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. During 2001
and 2002, EOG elected not to designate any of its price risk
management activities as accounting hedges under SFAS No. 133,
and accordingly, accounted for them using the mark-to-market
accounting method. Under this accounting method, the changes in
the market value of outstanding financial instruments are
recognized as gains or losses in the period of change. The gains
or losses are recorded in Gains (Losses) on Mark-to-market
Commodity Derivative Contracts 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
11 "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.
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 United States
dollar, asset and liability accounts are translated at year-end
exchange rates and revenue and expenses are translated at average
exchange rates prevailing during the year. Translation adjustments
are included in Accumulated Other Comprehensive Loss in the
Shareholders' Equity section of the Consolidated Balance Sheets.
Accumulated translation losses were $50 million and $54 million
at December 31, 2002 and 2001, respectively. 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):
2002 2001
Commercial Paper $ 120,000 $ --
Uncommitted Credit Facilities 14,310 95,147
Senior Unsecured Term Loan Facility due 2005 150,000 --
6.50% Notes due 2004 100,000 100,000
6.70% Notes due 2006 126,870 126,870
6.50% Notes due 2007 100,000 100,000
6.00% Notes due 2008 173,952 173,952
6.65% Notes due 2028 140,000 140,000
7.00% Subsidiary Debt due 2011 220,000 120,000
Total $1,145,132 $855,969
EOG maintains two credit facilities with different
expiration dates. In July 2002, the $300 million credit facility
that was scheduled to expire was renewed at the same commitment
level for a period of one year, which is the same period as the
last renewal of this facility. Credit facility expirations are
as follows: $300 million in July 2003 and $300 million in July
2004. With respect to the $300 million expiring in 2003, 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, 2002.
On October 30, 2002, EOG entered into a Senior Unsecured
Term Loan Facility (the "Facility") with a group of banks whereby
the banks agreed to lend EOG $150 million with a maturity of
three years. EOG used the loan proceeds under this Facility to
reduce outstanding commercial paper and uncommitted bank line
borrowings. This Facility calls for interest to be charged at a
spread over LIBOR (London InterBank Offering Rate) or the base
rate at EOG's option, and contains substantially the same
covenants as those in EOG's $300 million Long-Term Revolving
Credit Agreement. The applicable interest rate for this Facility
was 2.35% at December 31, 2002.
During 2002 and 2001, 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 Debt due 2011 bears interest at a
fixed rate of 7.00% and is guaranteed by EOG.
At December 31, 2002, the aggregate annual maturities of
long-term debt outstanding were none for 2003, $100 million for
2004, $150 million for 2005, $127 million in 2006 and $100
million for 2007.
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 19, 2003, 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, 2002 and
2001, EOG had $1,145 million and $856 million, respectively, of
long-term debt which had fair values of approximately
$1,225 million and $838 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 its common stock from time to time in the open
market to be held in treasury for the purpose of, but not limited
to, fulfilling any obligations arising under EOG's stock plans
and any other approved transactions or activities for which such
common stock shall be required. In September 2001, the Board of
Directors authorized the purchase of an aggregate maximum of 10
million shares of common stock of EOG which superseded all
previous authorizations. At December 31, 2002, 6,917,000 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 which were outstanding
at December 31, 2000. The strike price of these options was
$18.00 per share, and they expired unexercised in April 2001.
The following summarizes shares of common stock outstanding
(in thousands):
Common Shares
2002 2001 2000
Outstanding at January 1 115,452 116,904 119,105
Repurchased (1,700) (3,281) (8,910)
Issued Pursuant to Stock Options
and Stock Plans 968 1,829 6,709
Outstanding at December 31 114,720 115,452 116,904
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 stock. Prior to
exercise, the Right does not give its holder any dividend,
voting, or liquidation rights. If issued, each one hundredth
(1/100) of a Preferred Share (i) will not be redeemable;
(ii) will entitle holders to quarterly dividend payments of $.01
per share, or an amount equal to the dividend paid on one share
of common stock, whichever is greater; (iii) will entitle holders
upon liquidation either to receive $1 per share or an amount
equal to the payment made on one share of common stock, whichever
is greater; (iv) will have the same voting power as one share of
common stock; and (v) if shares of EOG's common stock are
exchanged via merger, consolidation, or a similar transaction,
will entitle holders to a per share payment equal to the payment
made on one share of common stock.
The Rights will not be exercisable until ten days after the
public announcement that a person or group has become an
acquiring person ("Acquiring Person") by obtaining beneficial
ownership of 10% or more of EOG's common stock, or if earlier,
ten business days (or a later date determined by EOG's Board of
Directors before any person or group becomes an Acquiring Person)
after a person or group begins a tender or exchange offer which,
if consummated, would result in that person or group becoming an
Acquiring Person. On December 10, 2002, the Rights Agreement was
amended to create an exception to the definition of Acquiring
Person to permit a qualified institutional investor to
beneficially own 10% or more but less than 15% of EOG's common
stock without being deemed an Acquiring Person if the
institutional investor meets the following requirements: (i) the
institutional investor is described in Rule 13d-1(b)(1)
promulgated under the Securities Exchange Act of 1934 and is
eligible to report (and does in fact report) beneficial ownership
of common stock on Schedule 13G; (ii) the institutional investor
is not required to file a Schedule 13D (or any successor or
comparable report) with respect to its beneficial ownership of
EOG's common stock; and (iii) the institutional investor does not
beneficially own 15% or more of EOG's common stock then
outstanding.
If a person or group becomes an Acquiring Person, all
holders of Rights except the Acquiring Person may, for $90,
purchase shares of EOG's common stock with a market value of
$180, based on the market price of the common stock prior to such
acquisition. If EOG is later acquired in a merger or similar
transaction after the Rights become exercisable, all holders of
Rights except the Acquiring Person may, for $90, purchase shares
of the acquiring corporation with a market value of $180 based on
the market price of the acquiring corporation's stock, prior to
such merger.
EOG's Board of Directors may redeem the Rights for $.01 per
Right at any time before any person or group becomes an Acquiring
Person. If the Board of Directors redeems any Rights, it must
redeem all of the Rights. Once the Rights are redeemed, the only
right of the holders of Rights will be to receive the redemption
price of $.01 per Right. The redemption price will be adjusted if
EOG has a stock split or stock dividends of EOG's common stock.
After a person or group becomes an Acquiring Person, but before
an Acquiring Person owns 50% or more of EOG's outstanding common
stock, the Board of Directors may exchange the Rights for common
stock or equivalent security at an exchange ratio of one share of
common stock or an equivalent security for each such Right, other
than Rights held by the Acquiring Person.
4. Enron Corp. Bankruptcy
In December 2001, Enron Corp. and certain of its affiliates,
including Enron North America Corp., filed voluntary petitions
for reorganization under Chapter 11 of the United States
Bankruptcy Code. EOG recorded $19.2 million in charges
associated with the Enron bankruptcies in the fourth quarter of
2001 related to certain contracts with Enron affiliates,
including 2001 and 2002 natural gas and crude oil derivative
contracts. Based on EOG's review of all matters related to Enron
Corp. and its affiliates, EOG believes that Enron Corp.'s Chapter
11 proceedings will not have a material adverse effect on EOG's
financial position.
By an order entered on June 21, 2002, the bankruptcy judge
in the Enron bankruptcy case authorized the sale of 11.5 million
shares of EOG common stock held by an affiliate of Enron. On
November 22, 2002, the entire 11.5 million shares were sold by
the Enron affiliate to an unaffiliated broker. EOG purchased one
million shares of EOG common stock from the broker, and the
remaining 10.5 million shares were sold by the broker to third
parties.
5. Income Taxes
The principal components of EOG's net deferred income tax
liability at December 31, 2002 and 2001 were as follows (in
thousands):
2002 2001
Deferred Income Tax Assets
Non-Producing Leasehold Costs $ 29,574 $ 26,727
Seismic Costs Capitalized for Tax 18,657 17,828
Alternative Minimum Tax Credit Carryforward 20,200 --
Other 12,589 26,325
Total Deferred Income Tax Assets 81,020 70,880
Deferred Income Tax Liabilities
Oil and Gas Exploration and Development
Costs Deducted for Tax Over Book Depreciation,
Depletion and Amortization 731,189 599,945
Capitalized Interest 10,779 8,373
Mark-to-market -- 10,107
Other -- 3,475
Total Deferred Income Tax Liabilities 741,968 621,900
Net Deferred Income Tax Liability $660,948 $551,020
The components of income before income taxes were as follows
(in thousands):
2002 2001 2000
United States $ 37,354 $488,741 $491,823
Foreign 82,318 142,704 141,734
Total $119,672 $631,445 $633,557
Total income tax provision was as follows (in thousands):
2002 2001 2000
Current:
Federal $(61,013) $ 36,737 $ 81,912
State (5,130) 5,475 7,528
Foreign 16,463 25,672 49,457
Total (49,680) 67,884 138,897
Deferred:
Federal 57,232 131,127 78,833
State (358) 10,411 10,324
Foreign 25,305 23,407 8,572
Total 82,179 164,945 97,729
Income Tax Provision $ 32,499 $232,829 $236,626
The differences between taxes computed at the U.S. federal
statutory tax rate and EOG's effective rate were as follows:
2002 2001 2000
Statutory Federal Income Tax Rate 35.00% 35.00% 35.00%
State Income Tax, Net of Federal Benefit 0.22 1.64 1.83
Income Tax Provision Related to
Foreign Operations (3.54) 0.36 1.32
Tight Gas Sands Federal Income Tax Credits (3.57) (0.83) (0.90)
Other (0.95) 0.70 0.10
Effective Income Tax Rate 27.16% 36.87% 37.35%
EOG's foreign subsidiaries' undistributed earnings of
approximately $543 million at December 31, 2002 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 have been received on an as-generated
basis. As a result of these transactions, for the period of 2000
through 2002, EOG recorded a deferred tax asset representing a
tax gain on the sale of the Section 29 credit properties, which
has reversed as the results of operations of such properties were
recognized for book purposes. In January 2003, these
arrangements were terminated.
EOG has an alternative minimum tax ("AMT") credit
carryforward of $20.2 million which can be used to offset regular
income taxes payable in future years. The AMT credit
carryforward has an indefinite carryforward period.
6. Employee Benefit Plans
Pension Plans
EOG has defined contribution pension and savings plans in
place for most of its employees in the United States. EOG's
contributions to these plans are based on various percentages of
compensation, and in some instances, are based upon the amount of
the employees' contributions to the plan. For 2002, 2001 and
2000, the cost of these plans amounted to approximately $8.0
million, $6.5 million and $5.3 million, respectively.
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, 2002,
December 31, 2001 and December 31, 2000, the postretirement plan
had a benefit obligation of $1.9 million, $2.0 million and $1.5
million, respectively. During 2002, 2001 and 2000, EOG
recognized a net periodic benefit cost related to this plan of
$0.3 million, $0.4 million and $0.3 million, respectively.
Stock Plans
EOG has various stock plans ("the Plans") under which
employees and non-employee members of the Board of Directors of
EOG and its subsidiaries have been or may be granted certain
equity compensation. At December 31, 2002, the total number of
shares authorized for grant from the Plans was 27,450,000 shares.
Stock Options. Under the Plans, participants have been or
may be granted rights to purchase shares of common stock of EOG
at a price not less than the market price of the stock at the
date of grant. Stock options granted under the plan vest either
immediately at the date of grant or up to four years from the
date of grant based on the nature of the grants and as defined in
individual grant agreements. Terms for stock options granted
under the plan have not exceeded a maximum term of 10 years.
The following table sets forth the option transactions for
the years ended December 31 (options in thousands):
2002 2001 2000
Average Average Average
Grant Grant Grant
Options Price Options Price Options Price
Outstanding at January 1 7,013 $24.69 7,056 $20.70 12,667 $18.66
Granted 1,809 33.82 1,631 36.63 1,317 30.88
Exercised (868) 19.90 (1,563) 19.18 (6,726) 18.90
Forfeited (112) 27.64 (111) 23.84 (202) 19.09
Outstanding at December 31 7,842 27.31 7,013 24.69 7,056 20.70
Options Exercisable at December 31 5,041 23.96 4,034 22.04 3,845 19.83
Options Available for Future Grant 2,932 4,531 6,387
Average Fair Value of Options
Granted During Year $14.79 $16.76 $12.20
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 2002, 2001 and
2000, respectively: (1) dividend yield of 0.4%, 0.5% and 0.6%,
(2) expected volatility of 45%, 43% and 30%, (3) risk-free
interest rate of 3.7%, 4.6% and 6.0% and (4) expected life of 5.3
years, 6.0 years and 6.0 years.
The following table summarizes certain information for the
options outstanding at December 31, 2002 (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 1,318 5 $14.64 1,306 $14.62
18.00 to 22.99 1,951 5 20.19 1,737 20.22
23.00 to 28.99 313 3 24.09 306 24.03
29.00 to 39.99 3,997 9 34.01 1,539 33.82
40.00 to 54.99 263 7 45.51 153 46.59
7,842 7 27.31 5,041 23.96
EOG's pro forma net income and net income per share of
common stock for 2002, 2001 and 2000, had compensation costs been
recorded in accordance with SFAS No. 123, are presented below (in
millions except per share data):
2002 2001 2000
Net Income Available to Common - As Reported $ 76.1 $387.6 $385.9
Deduct: Total stock-based employee
compensation expense (13.7) (11.9) (12.5)
Net Income Available to Common - Pro Forma $ 62.4 $375.7 $373.4
Net Income per Share Available to Common
Basic - As Reported $ 0.66 $ 3.35 $ 3.30
Basic - Pro Forma $ 0.54 $ 3.25 $ 3.19
Diluted - As Reported $ 0.65 $ 3.30 $ 3.24
Diluted - Pro Forma $ 0.53 $ 3.20 $ 3.14
The effects of applying SFAS No. 123 in this pro forma
disclosure should not be interpreted as being indicative of
future effects. SFAS No. 123 does not apply to awards prior to
1995, and the extent and timing of additional future awards
cannot be predicted.
Restricted Stock and Units. Under the Plans, employees may
be granted restricted stock and/or units without cost to them.
The shares and units granted vest to the employee at various
times ranging from one to five years from the date of grant based
on the nature of the grants and as defined in individual grant
agreements. Upon vesting, restricted shares are released to the
employee. Upon vesting, restricted units are converted into one
share of common stock and released to the employee. The
following summarizes shares of restricted stock and units granted
(shares and units in thousands):
Restricted Shares and Units
2002 2001 2000
Outstanding at January 1 632 309 288
Granted 158 353 201
Released (10) (15) (178)
Forfeited or Expired (5) (15) (2)
Outstanding at December 31 775 632 309
Average Fair Value of Shares Granted
During Year $32.56 $42.08 $16.10
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 2002, 2001
and 2000 was approximately $4.9 million, $3.3 million and
$1.3 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, 2002, 398,456 common shares remained available for
issuance under the plan. During 2002, approximately 350
employees participated in the plan and 69,243 common shares were
purchased at an aggregate price of approximately $2.3 million.
During 2001, approximately 300 employees participated in the plan
and 32,301 common shares were purchased at an aggregate price of
approximately $1 million.
Treasury Shares. During 2002, 2001 and 2000, EOG
repurchased 1,700,000, 3,281,000 and 8,910,000 of its common
shares, respectively. Approximately 968,000, 1,829,000 and
6,709,000 of these common shares were repurchased during 2002,
2001 and 2000, 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 $5.2 million, $7.3 million and $41.3 million, for the years
2002, 2001 and 2000, 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.
7. Commitments and Contingencies
Letters Of Credit. At December 31, 2002 and 2001, EOG had
letters of credit and guarantees outstanding totaling
approximately $234 million and $136 million, respectively;
however, of these amounts, $220 million and $120 million,
respectively, represent guarantees of subsidiary indebtedness
included under Note 2 "Long-Term Debt."
Minimum Commitments. At December 31, 2002, total minimum
commitments from foreign equity investments, long-term
non-cancelable operating leases, drilling rig commitments
and transportation service commitments, based on current
transportation rates and the foreign currency exchange rate
applicable to Canadian dollars at December 31, 2002, are as
follows (in thousands):
Total Minimum
Commitments
2003 $ 23,902
2004 - 2006 41,288
2007 - 2008 9,771
2009 and thereafter 4,249
$ 79,210
Included in the table above are leases for buildings,
facilities and equipment with varying expiration dates through
2009. Rental expenses associated with these leases amounted to
$21 million, $20 million and $15 million for 2002, 2001 and 2000,
respectively.
Contingencies. EOG and numerous other companies in the
natural gas industry are named as defendants in various lawsuits
alleging violations of the Civil False Claims Act. These lawsuits
have been consolidated for pre-trial proceedings in the United
States District Court for the District of Wyoming. The plaintiffs
contend that defendants have underpaid royalties on natural gas
and natural gas liquids produced on federal and Indian lands
through the use of below-market prices, improper deductions,
improper measurement techniques and transactions with affiliated
companies. Plaintiffs allege that the royalties paid by
defendants were lower than the royalties required to be paid
under federal regulations and that the forms filed by defendants
with the Minerals Management Service reporting these royalty
payments were false, thereby violating the Civil False Claims
Act. The United States has intervened in certain of the cases as
to some of the defendants, but has not intervened as to EOG. The
plaintiffs in one of the two lawsuits in which EOG is involved
recently dismissed EOG from that case without prejudice. Based
on EOG's present understanding of the remaining case in which it
is a defendant, EOG believes that it has substantial defenses to
the plaintiff's claims and intends to vigorously assert these
defenses. However, if EOG is found to have violated the Civil
False Claims Act, EOG could be subject to a variety of sanctions,
including treble damages and substantial monetary fines.
There are various other suits and claims against EOG that
have arisen in the ordinary course of business. However,
management does not believe these suits and claims will
individually or in the aggregate have a material adverse effect
on the financial condition or results of operations of EOG. EOG
has been named as a potentially responsible party in certain
Comprehensive Environmental Response Compensation and Liability
Act proceedings. However, management does not believe that any
potential assessments resulting from such proceedings will
individually or in the aggregate have a material adverse effect
on the financial condition of EOG.
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):
2002 2001 2000
Numerator for basic and diluted earnings per share -
Net income available to common $ 76,141 $387,622 $385,903
Denominator for basic earnings per share -
Weighted average shares 115,335 115,765 116,934
Potential dilutive common shares -
Stock options 1,633 1,453 2,038
Restricted stock and units 277 270 130
Denominator for diluted earnings per share -
Adjusted weighted average shares 117,245 117,488 119,102
Net income per share of common stock
Basic $ 0.66 $ 3.35 $ 3.30
Diluted $ 0.65 $ 3.30 $ 3.24
9. Supplemental Cash Flow Information
Cash paid for interest and income taxes was as follows for
the years ended December 31 (in thousands):
2002 2001 2000
Interest (net of amount capitalized) $ 54,432 $ 45,715 $ 61,679
Income taxes 15,946 106,312 87,285
10. Business Segment Information
EOG's operations are all natural gas and crude oil
exploration and production related. SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information,"
establishes standards for reporting information about operating
segments in annual financial statements and requires selected
information about operating segments in interim financial
reports. Operating segments are defined as components of an
enterprise about which separate financial information is
available and evaluated regularly by the chief operating decision
maker, or decision making group, in deciding how to allocate
resources and in assessing performance. EOG's chief operating
decision making process is informal and involves the Chairman and
Chief Executive Officer and other key officers. This group
routinely reviews and makes operating decisions related to
significant issues associated with each of EOG's major producing
areas in the United States and each significant international
location. For segment reporting purposes, the major United States
producing areas have been aggregated as one reportable segment
due to similarities in their operations as allowed by SFAS
No. 131. Financial information by reportable segment is
presented below for the years ended December 31, or at
December 31 (in thousands):
United States Canada Trinidad Other Total
2002
Net Operating Revenues $ 846,071(1) $169,365(1) $ 79,551 $ 49 $1,095,036(1)
Depreciation, Depletion and Amortization 334,318 49,622 14,085 11 398,036
Operating Income (Loss) 93,681 40,846 49,450 (2,646) 181,331
Interest Income 765 229 348 -- 1,342
Other Income (Expense) (3,747) 2 394 4 (3,347)
Interest Expense 53,345 6,097 211 1 59,654
Income (Loss) Before Income Taxes 37,354 34,980 49,981 (2,643) 119,672
Income Tax Provision (Benefit) (7,684) 20,359 20,974 (1,150) 32,499
Additions to Oil and Gas Properties 517,578 160,840 35,689 20 714,127
Total Assets 2,864,990 665,490 283,395 131 3,814,006
2001
Net Operating Revenues $1,394,457(1) $191,219(1) $ 69,140 $ 71 $1,654,887(1)
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(1) $184,092(1) $ 82,430 $ 58 $1,489,895(1)
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
(1) EOG had sales activity with a certain purchaser in the
United States and Canada segments in 2002 and 2001 that
totaled approximately $141.9 million and $224.5 million,
respectively, of the Consolidated Net Operating Revenues.
Sales activity with another purchaser in the United States and
Canada segments in 2000 totaled approximately $183.2 million
of the Consolidated Net Operating Revenues.
11. 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 collars, as the means to manage this price risk.
During 2002, 2001 and 2000, EOG elected not to designate any
of its derivative contracts as accounting hedges and accordingly,
accounted for these derivative contracts using mark-to-market
accounting. During 2002, EOG recognized mark-to-market losses on
commodity contracts of $49 million, which included realized
losses of $21 million and a $2 million collar premium payment.
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 $1
million mark-to-market losses on commodity contracts.
Presented below is a summary of EOG's 2003 natural gas
financial collar contracts as of December 31, 2002 with prices
expressed in dollars per million British thermal units ($/MMBtu)
and notional volumes in million British thermal units per day
(MMBtud) and a summary of EOG's 2003 crude oil financial price
swap contracts as of December 31, 2002 with prices expressed in
dollars per barrel ($/Bbl) and notional volumes in barrels per
day (Bbld). The fair value of the natural gas financial collar
contracts and the crude oil financial price swap contracts at
December 31, 2002 was negative $4.3 million and negative $1.6
million, respectively.
Natural Gas Financial Collar Contracts Crude Oil Financial
Floor Price Ceiling Price Swap Contracts
Weighted Weighted Weighted
Volume Floor Range Average Ceiling Range Average Volume Average
Month (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (Bbld) ($/Bbl)
Jan 50,000 $3.87 $3.87 $6.09 $6.09 2,000 $27.34
Feb 75,000 3.76 - 4.19 3.90 5.05 - 5.98 5.67 2,000 26.91
Mar 75,000 3.61 - 4.08 3.76 5.00 - 5.83 5.55 2,000 26.57
Apr 75,000 3.59 - 3.88 3.69 4.80 - 4.97 4.91 2,000 26.16
May 75,000 3.54 - 3.78 3.62 4.70 - 4.92 4.84 2,000 25.75
Jun 75,000 3.56 - 3.78 3.63 4.70 - 4.94 4.86 2,000 25.39
Jul 75,000 3.59 - 3.79 3.66 4.73 - 4.97 4.89 2,000 25.07
Aug 75,000 3.60 - 3.79 3.66 4.73 - 4.98 4.90 2,000 24.84
Sep 75,000 3.60 - 3.77 3.65 4.73 - 4.98 4.89 2,000 24.63
Oct 75,000 3.60 - 3.77 3.65 4.73 - 4.98 4.90 2,000 24.41
Nov 75,000 3.77 - 3.91 3.81 4.90 - 5.15 5.06 2,000 24.28
Dec 75,000 3.92 - 4.04 3.96 5.05 - 5.30 5.22 2,000 24.10
Presented below is a summary of EOG's 2003 natural gas
financial collar contracts and natural gas and crude oil
financial price swap contracts as of February 19, 2003:
Natural Gas Financial Collar Contracts Financial Price Swap Contracts
Floor Price Ceiling Price Natural Gas Crude Oil
Floor Weighted Ceiling Weighted Weighted Weighted
Volume Range Average Range Average Volume Average Volume Average
Month (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu) (Bbld) ($/Bbl)
Jan 50,000 $3.87 $3.87 $6.09 $6.09 -- -- 2,000 $27.34
Feb 125,000 3.76 - 4.30 4.04 5.05 - 6.30 5.87 -- -- 2,000 26.91
Mar 125,000 3.61 - 4.20 3.93 5.00 - 6.20 5.77 100,000 $5.19 4,000 27.96
Apr 125,000 3.59 - 4.02 3.82 4.80 - 6.03 5.33 100,000 4.96 5,000 27.77
May 125,000 3.54 - 3.92 3.74 4.70 - 5.92 5.24 100,000 4.82 5,000 27.04
Jun 125,000 3.56 - 3.89 3.74 4.70 - 5.90 5.25 100,000 4.77 5,000 26.43
Jul 125,000 3.59 - 3.91 3.76 4.73 - 5.91 5.27 100,000 4.77 5,000 25.90
Aug 125,000 3.60 - 3.91 3.76 4.73 - 5.91 5.27 100,000 4.77 5,000 25.49
Sep 125,000 3.60 - 3.89 3.75 4.73 - 5.89 5.26 100,000 4.74 5,000 25.19
Oct 125,000 3.60 - 3.90 3.75 4.73 - 5.90 5.27 100,000 4.74 5,000 24.90
Nov 125,000 3.77 - 4.04 3.90 4.90 - 6.04 5.43 -- -- 5,000 24.70
Dec 125,000 3.92 - 4.18 4.04 5.05 - 6.18 5.57 -- -- 5,000 24.47
During 2001 and 2000, EOG recognized in natural gas and
crude oil and condensate revenues hedge losses of $1 million and
$17 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,
2002 and 2001:
2002 2001
Carrying Estimated Carrying Estimated
Amount Fair Value(1) Amount Fair Value(1)
(In Millions) (In Millions)
Long-Term Debt(2) $1,145.1 $1,224.9 $856.0 $838.3
NYMEX-Related Commodity Market Positions (5.9) (5.9) 19.2 19.2
(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, 2002,
approximately 13% of EOG's net accounts receivable balance
related to natural gas, crude oil and condensate sales was due
from a major utility company. This amount was collected during
early 2003. The amount due from this utility company at December
31, 2001, which approximated 11% of the net accounts receivable
balance, was collected during 2002. No other individual
purchaser accounted for 10% or more of the net accounts
receivable balance at December 31, 2002 and 2001. At December
31, 2002, EOG had an allowance for doubtful accounts of $20.3
million, of which $19.2 million is associated with the Enron
bankruptcies.
12. Concentration of Credit Risk
Substantially all of EOG's accounts receivable at
December 31, 2002 and 2001 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.
13. Accounting for Certain Long-Lived Assets
Periodically, EOG reviews its oil and gas properties for
impairment purposes by comparing the expected undiscounted future
cash flows at a producing field level to the unamortized
capitalized cost of the asset. During 2002, 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 $30 million, $39 million and $11
million, respectively, for 2002, 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. Amortization expenses of
acquisition costs of unproved properties, including amortization
of capitalized interest, were $38 million, $40 million and $35
million for 2002, 2001 and 2000, respectively.
14. Investment in Caribbean Nitrogen Company Limited and
Nitrogen (2000) Unlimited
EOG, through a subsidiary, owns an approximate 16% equity
interest in a Trinidadian company named Caribbean Nitrogen
Company Limited ("CNCL") which has constructed an ammonia plant
in Pt. Lisas, Trinidad. The other shareholders in CNCL are
subsidiaries of Ferrostaal AG, Duke Energy, Halliburton and CL
Financial Ltd. At December 31, 2002, investment in CNCL was
approximately $14 million. CNCL commenced production in June
2002 and currently produces approximately 1,850 metric tons of
ammonia daily. At December 31, 2002, CNCL had a long-term debt
balance of approximately $219 million, which is non-recourse to
CNCL's shareholders. EOG will be liable for its share of any
post-completion deficiency funds loans to fund the costs of
operation, payment of principal and interest to the principal
creditor and other cash deficiencies of CNCL up to $30 million,
approximately $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. During 2002, EOG recognized
equity income of $0.3 million.
Secondly, EOG, through a subsidiary, owns an approximate 31%
equity interest in a Trinidadian company named Nitrogen (2000)
Unlimited ("N2000"). The other shareholders in N2000
are subsidiaries of Ferrostaal AG, Halliburton and CL Financial Ltd.
At December 31, 2002, investment in N2000 was approximately $18
million. N2000 is constructing an ammonia plant in Trinidad, at an
expected cost of approximately $320 million, and is expected to
commence production in 2005. At December 31, 2002, N2000 had a
long-term debt balance of approximately $7 million, which is
currently recourse to N2000's shareholders. Upon receipt of an
amendment to N2000's certificate of environmental clearance, this
long-term debt will become non-recourse to N2000's shareholders.
N2000 has applied for the amendment and believes that it will be
received in the near future. EOG will be liable for its share of
any pre-completion deficiency funds loans to fund plant cost
overruns up to $15 million, approximately $5 million of which
is net to EOG's interest. EOG will also be liable for its share
of any post-completion deficiency funds loans to fund the costs
of operation, payment of principal and interest to the principal
creditor and other cash deficiencies of N2000 up to $30 million,
approximately $9 million of which is net to EOG's interest. The
Shareholders' Agreement requires the consent of the holders of 90%
or more of the shares to take certain material actions. Accordingly,
given its current level of equity ownership, EOG is able to exercise
significant influence over the operating and financial policies
of N2000 and therefore, it accounts for the investment using the
equity method.
In November 2002, the EOG subsidiaries along with the
Ferrostaal subsidiaries entered into share purchase agreements
for the sale of a portion of their shareholdings in CNCL and
N2000 with a third party energy company. EOG expects the EOG
subsidiaries to close these transactions during the first quarter
of 2003 once certain conditions precedent have occurred. EOG does
not expect these transactions to result in any gains or losses.
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 completion. Reserves on undrilled acreage are limited to
those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be
demonstrated with certainty that there is continuity of
production from the existing productive formation. Estimates for
proved undeveloped reserves are not attributed to any acreage for
which an application of fluid injection or other improved
recovery technique is contemplated, unless such techniques have
been proved effective by actual tests in the area and in the same
reservoir.
Canadian provincial royalties are determined based on a
graduated percentage scale which varies with prices and
production volumes. Canadian reserves, as presented on a net
basis, assume prices and royalty rates in existence at the time
the estimates were made, and EOG's estimate of future production
volumes. Future fluctuations in prices, production rates, or
changes in political or regulatory environments could cause EOG's
share of future production from Canadian reserves to be
materially different from that presented.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Estimates of proved and proved developed reserves at
December 31, 2002, 2001 and 2000 were based on studies performed
by the engineering staff of EOG for reserves in the United
States, Canada and Trinidad. Opinions by DeGolyer and
MacNaughton ("D&M"), independent petroleum consultants, for the
years ended December 31, 2002, 2001 and 2000 covered producing
areas containing 73%, 71% and 49%, 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, 2002 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, 2002, 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 TOTAL
NET PROVED RESERVES
Natural Gas (Bcf)(1)
Net proved reserves at December 31, 1999 1,657.2 523.5 994.6 3,175.3
Revisions of previous estimates 47.2 6.4 (0.4) 53.2
Purchases in place 188.8 39.4 -- 228.2
Extensions, discoveries and other additions 255.4 23.8 65.1 344.3
Sales in place (84.2) (0.1) -- (84.3)
Production (243.0) (47.3) (45.8) (336.1)
Net proved reserves at December 31, 2000 1,821.4 545.7 1,013.5 3,380.6
Revisions of previous estimates 15.0 (26.8) (121.6) (133.4)
Purchases in place 66.1 111.5 -- 177.6
Extensions, discoveries and other additions 358.3 59.7 295.2 713.2
Sales in place (1.0) -- -- (1.0)
Production (252.5) (46.0) (42.0) (340.5)
Net proved reserves at December 31, 2001 2,007.3 644.1 1,145.1 3,796.5
Revisions of previous estimates 9.4 4.7 (21.7) (7.6)
Purchases in place 9.9 102.9 -- 112.8
Extensions, discoveries and other additions 217.0 83.9 232.4 533.3
Sales in place (0.8) (1.5) -- (2.3)
Production (236.6) (56.2) (49.3) (342.1)
Net proved reserves at December 31, 2002 2,006.2 777.9 1,306.5 4,090.6
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
United States Canada Trinidad TOTAL
Liquids (MBbl)(2)
Net proved reserves at December 31, 1999 47,847 8,896 15,763 72,506
Revisions of previous estimates (1,951) 46 28 (1,877)
Purchases in place 3,948 -- -- 3,948
Extensions, discoveries and other additions 12,433 404 738 13,575
Sales in place (484) (2,474) -- (2,958)
Production (9,780) (1,055) (957) (11,792)
Net proved reserves at December 31, 2000 52,013 5,817 15,572 73,402
Revisions of previous estimates (3,111) 1,294 (3,691) (5,508)
Purchases in place 586 35 -- 621
Extensions, discoveries and other additions 12,380 361 1,967 14,708
Sales in place (192) (35) -- (227)
Production (9,293) (820) (749) (10,862)
Net proved reserves at December 31, 2001 52,383 6,652 13,099 72,134
Revisions of previous estimates 3,543 396 (572) 3,367
Purchases in place 624 865 -- 1,489
Extensions, discoveries and other additions 14,763 279 3,041 18,083
Sales in place (33) -- -- (33)
Production (7,925) (1,026) (874) (9,825)
Net proved reserves at December 31, 2002 63,355 7,166 14,694 85,215
Bcf Equivalent (Bcfe)(1)
Net proved reserves at December 31, 1999 1,944.3 576.9 1,089.2 3,610.4
Revisions of previous estimates 35.5 6.8 (0.2) 42.1
Purchases in place 212.5 39.4 -- 251.9
Extensions, discoveries and other additions 330.0 26.2 69.5 425.7
Sales in place (87.1) (15.0) -- (102.1)
Production (301.7) (53.7) (51.6) (407.0)
Net proved reserves at December 31, 2000 2,133.5 580.6 1,106.9 3,821.0
Revisions of previous estimates (3.7) (19.1) (143.7) (166.5)
Purchases in place 69.7 111.6 -- 181.3
Extensions, discoveries and other additions 432.5 62.0 307.0 801.5
Sales in place (2.2) (0.2) -- (2.4)
Production (308.2) (50.9) (46.5) (405.6)
Net proved reserves at December 31, 2001 2,321.6 684.0 1,223.7 4,229.3
Revisions of previous estimates 30.7 7.1 (25.1) 12.7
Purchases in place 13.6 108.1 -- 121.7
Extensions, discoveries and other additions 305.6 85.6 250.6 641.8
Sales in place (1.0) (1.5) -- (2.5)
Production (284.2) (62.4) (54.5) (401.1)
Net proved reserves at December 31, 2002 2,386.3 820.9 1,394.7 4,601.9
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
United States Canada Trinidad TOTAL
NET PROVED DEVELOPED RESERVES
Natural Gas (Bcf)(1)
December 31, 1999 1,446.5 451.1 250.2 2,147.8
December 31, 2000 1,498.6 479.4 207.0 2,185.0
December 31, 2001 1,588.4 587.6 620.6 2,796.6
December 31, 2002 1,658.7 683.3 555.2 2,897.2
Liquids (MBbl) (2)
December 31, 1999 41,717 7,041 3,833 52,591
December 31, 2000 42,132 5,695 2,967 50,794
December 31, 2001 41,205 6,532 8,435 56,172
December 31, 2002 47,476 7,045 7,135 61,656
Bcf Equivalents (Bcfe)(1)
December 31, 1999 1,696.8 493.3 273.2 2,463.3
December 31, 2000 1,751.4 513.6 224.8 2,489.8
December 31, 2001 1,835.7 626.8 671.1 3,133.6
December 31, 2002 1,943.6 725.5 598.0 3,267.1
___________________________
(1) Billion cubic feet or billion cubic feet equivalent, as
applicable.
(2) Thousand barrels; includes crude oil, condensate and
natural gas liquids.
Capitalized Costs Relating to Oil and Gas Producing
Activities. The following table sets forth the capitalized costs
relating to EOG's natural gas and crude oil producing activities
at December 31, 2002 and 2001:
2002 2001
Proved Properties $6,527,716 $5,847,053
Unproved Properties 222,379 218,550
Total 6,750,095 6,065,603
Accumulated depreciation, depletion
and amortization (3,428,547) (3,009,693)
Net capitalized costs $3,321,548 $3,055,910
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 and additions
to exploration wells including those in progress.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Development costs include additions to production facilities
and equipment and additions to development wells including those
in progress.
The following tables set forth costs incurred related to
EOG's oil and gas activities for the years ended December 31:
United States Canada Trinidad Other TOTAL
2002
Acquisition Costs of Properties
Unproved $ 28,232 $ 4,754 $ 5,629 $ -- $ 38,615
Proved 22,589 48,487 -- -- 71,076
Subtotal 50,821 53,241 5,629 -- 109,691
Exploration Costs 120,058 25,866 18,117 2,384 166,425
Development Costs 423,436 107,952 13,600 -- 544,988
Subtotal 594,315 187,059 37,346 2,384 821,104
Deferred Income Tax Gross Up -- 14,938 -- -- 14,938
Total $594,315 $201,997 $37,346 $2,384 $ 836,042
2001
Acquisition Costs of Properties
Unproved $ 69,308 $ 6,967 $ -- $ -- $ 76,275
Proved 95,646 72,660 -- -- 168,306
Subtotal 164,954 79,627 -- -- 244,581
Exploration Costs 163,602 16,708 13,695 8,739 202,744
Development Costs 512,175 92,374 60,969 -- 665,518
Subtotal 840,731 188,709 74,664 8,739 1,112,843
Deferred Income Tax Gross Up 19,411 30,845 -- -- 50,256
Total $860,142 $219,554 $74,664 $8,739 $1,163,099
2000
Acquisition Costs of Properties
Unproved $ 45,456 $ 5,741 $ -- $ -- $ 51,197
Proved 88,473 13,965 -- -- 102,438
Subtotal 133,929 19,706 -- -- 153,635
Exploration Costs 98,654 9,711 10,849 3,581 122,795
Development Costs 335,053 46,000 29,688 -- 410,741
Subtotal 567,636 75,417 40,537 3,581 687,171
Deferred Income Tax Gross Up 18,744 3,685 -- -- 22,429
Total $586,380 $ 79,102 $40,537 $3,581 $ 709,600
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 Other(2) TOTAL
2002
Natural Gas, Crude Oil
and Condensate Revenues $ 891,960 $170,875 $79,551 $1,142,386 $ 52 $1,142,438
Gains (Losses) on Sales of
Reserves and Related Assets
and Other, Net 2,616 (1,510) -- 1,106 -- 1,106
Total 894,576 169,365 79,551 1,143,492 52 1,143,544
Exploration Expenses, including Dry Hole 78,937 26,171 1,656 106,764 213 106,977
Production Costs 186,024 48,261 9,977 244,262 88 244,350
Impairments 65,813 2,619 -- 68,432 (2) 68,430
Depreciation, Depletion and Amortization 334,318 49,622 14,085 398,025 11 398,036
Income (Loss) before Income Taxes 229,484 42,692 53,833 326,009 (258) 325,751
Income Tax Provision (Benefit) 82,136 10,319 23,971 116,426 (90) 116,336
Results of Operations $ 147,348 $ 32,373 $29,862 $ 209,583 $ (168) $ 209,415
2001
Natural Gas, Crude Oil
and Condensate Revenues $1,295,894 $191,096 $69,141 $1,556,131 $ 72 $1,556,203
Gains 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 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
(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, 2002.
(2) Other includes other international operations.
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
2002
Future cash inflows $ 9,826,571 $ 2,989,000 $2,303,930 $15,119,501
Future production costs (2,212,357) (586,166) (433,029) (3,231,552)
Future development costs (359,787) (43,876) (177,275) (580,938)
Future net cash flows before
income taxes 7,254,427 2,358,958 1,693,626 11,307,011
Future income taxes (2,214,072) (653,425) (558,788) (3,426,285)
Future net cash flows 5,040,355 1,705,533 1,134,838 7,880,726
Discount to present value at
10% annual rate (2,265,700) (766,567) (629,024) (3,661,291)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves(1) $ 2,774,655 $ 938,966 $ 505,814 $ 4,219,435
2001
Future cash inflows $ 5,677,824 $ 1,490,552 $1,472,197 $ 8,640,573
Future production costs (1,528,474) (371,124) (335,395) (2,234,993)
Future development costs (387,048) (31,232) (110,331) (528,611)
Future net cash flows before
income taxes 3,762,302 1,088,196 1,026,471 5,876,969
Future income taxes (930,505) (295,739) (265,709) (1,491,953)
Future net cash flows 2,831,797 792,457 760,762 4,385,016
Discount to present value at
10% annual rate (1,121,771) (321,980) (413,876) (1,857,627)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves $ 1,710,026 $ 470,477 $ 346,886 $ 2,527,389
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
(1) Natural gas prices have changed since December 31, 2002;
consequently, the discounted future net cash flows would be
different if the standardized measure was calculated in the
first quarter of 2003.
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, 2002.
United States Canada Trinidad TOTAL
December 31, 1999 $ 1,727,232 $ 377,891 $ 288,933 $ 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)
Net changes in prices and
production costs 5,459,629 1,850,021 153,961 7,463,611
Extensions, discoveries,
additions and improved
recovery net of related costs 1,502,377 94,379 20,544 1,617,300
Development costs incurred 77,000 24,100 29,600 130,700
Revisions of estimated
development costs (19,055) 39 (39,590) (58,606)
Revisions of previous quantity
estimates 153,862 30,376 (129) 184,109
Accretion of discount 190,045 48,912 45,192 284,149
Net change in income taxes (2,436,834) (606,556) 8,566 (3,034,824)
Purchases of reserves in place 671,604 136,138 -- 807,742
Sales of reserves in place (331,960) (22,454) -- (354,414)
Changes in timing and other 66,037 (266,493) (51,763) (252,219)
December 31, 2000 6,011,133 1,513,751 388,553 7,913,437
Sales and transfers of oil
and gas produced, net of
production costs (1,060,926) (156,787) (58,832) (1,276,545)
Net changes in prices and
production costs (6,400,910) (1,822,229) (194,995) (8,418,134)
Extensions, discoveries,
additions and improved
recovery net of related costs 347,088 48,271 114,871 510,230
Development costs incurred 101,900 27,500 71,088 200,488
Revisions of estimated
development cost (5,296) 2,931 10,947 8,582
Revisions of previous quantity
estimates (3,563) (12,536) 47,418 31,319
Accretion of discount 862,118 223,154 54,297 1,139,569
Net change in income taxes 2,313,068 592,322 15,087 2,920,477
Purchases of reserves in place 35,686 78,790 -- 114,476
Sales of reserves in place (6,165) (303) -- (6,468)
Changes in timing and other (484,107) (24,387) (101,548) (610,042)
December 31, 2001 1,710,026 470,477 346,886 2,527,389
Sales and transfers of oil
and gas produced, net of
production costs (705,938) (122,614) (69,574) (898,126)
Net changes in prices and
production costs 1,561,946 460,977 223,614 2,246,537
Extensions, discoveries,
additions and improved
recovery net of related costs 499,257 123,700 110,415 733,372
Development costs incurred 84,300 18,100 13,600 116,000
Revisions of estimated
development cost 35,255 (11,418) (20,574) 3,263
Revisions of previous quantity
estimates 51,227 11,470 (15,634) 47,063
Accretion of discount 200,701 59,594 48,622 308,917
Net change in income taxes (692,670) (135,888) (87,229) (915,787)
Purchases of reserves in place 28,851 117,958 -- 146,809
Sales of reserves in place (715) (2,827) -- (3,542)
Changes in timing and other 2,415 (50,563) (44,312) (92,460)
December 31, 2002 $ 2,774,655 $ 938,966 $ 505,814 $ 4,219,435
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Concluded)
Unaudited Quarterly Financial Information
Quarter Ended
March 31 June 30 Sept. 30 Dec. 31
2002
Net Operating Revenues $186,503 $290,503 $279,869 $338,161
Operating Income (Loss) $(20,706) $ 69,640 $ 61,700 $ 70,697
Income (Loss) before Income Taxes $(35,860) $ 55,555 $ 42,866 $ 57,111
Income Tax Provision (Benefit) (11,619) 17,447 13,979 12,692
Net Income (Loss) (24,241) 38,108 28,887 44,419
Preferred Stock Dividends 2,758 2,758 2,758 2,758
Net Income (Loss) Available to Common $(26,999) $ 35,350 $ 26,129 $ 41,661
Net Income (Loss) per Share
Available to Common
Basic(1) $ (0.23) $ 0.31 $ 0.23 $ 0.36
Diluted(1) $ (0.23) $ 0.30 $ 0.22 $ 0.36
Average Number of Common Shares
Basic 115,485 115,737 115,621 114,742
Diluted 115,485 117,689 117,078 116,908
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
(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.
EXHIBIT INDEX
Exhibit No. Description
23.1 Consent of DeGolyer and MacNaughton
23.2 Opinion of DeGolyer and MacNaughton dated January 31, 2003
23.3 Consent of Deloitte & Touche LLP