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 24, 2004
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 of Number) Identification No.)
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, 2003, including Reports of Independent Public
Accountants.
(b) Exhibits.
23.1 Consent of DeGolyer and MacNaughton.
23.2 Opinion of DeGolyer and MacNaughton dated January 30, 2004.
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 24, 2004 By: /s/ TIMOTHY K. DRIGGERS
Timothy K. Driggers
Vice President and Chief
Accounting Officer
(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 17
Reports of Independent Public Accountants 18
Consolidated Statements of Income and Comprehensive Income
for the years ended December 31, 2003, 2002 and 2001 20
Consolidated Balance Sheets, December 31, 2003 and 2002 21
Consolidated Statements of Shareholders' Equity
for the years ended December 31, 2003, 2002 and 2001 22
Consolidated Statements of Cash Flows
for the years ended December 31, 2003, 2002 and 2001 23
Notes to Consolidated Financial Statements 24
Supplemental Information to Consolidated Financial Statements 42
Exhibits
Exhibit 23.1 - Consent of DeGolyer and MacNaughton 52
Exhibit 23.2 - Opinion of DeGolyer and MacNaughton
dated January 30, 2004 53
Exhibit 23.3 - Consent of Deloitte & Touche LLP 55
EOG RESOURCES, INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis of Financial Condition and
Results of Operations
Overview
EOG Resources, Inc. (EOG) is one of the largest independent
(non-integrated) oil and gas companies in the United States and
has substantial proved reserves in the U.S., Canada, and offshore
Trinidad, and to a lesser extent, the United Kingdom North Sea.
EOG operates under a business strategy that focuses predominantly
on three factors: achieving a strong reinvestment rate of return
on its capital program, drilling internally generated prospects
in order to find and develop low cost reserves, and maintaining a
strong balance sheet, with a below average debt-to-total
capitalization ratio.
EOG had record operating earnings in 2003. Net income
available to common for 2003 of $419.1 million, or $3.60 per
share, was up 450% over 2002, attributable primarily to higher
commodity prices. In addition, EOG substantially added to its
reserve base by replacing 249% of production at an all-in finding
cost of $1.28 per thousand cubic feet equivalent (Mcfe). From
drilling alone, EOG replaced 183% of production at a rate of
$1.21 per Mcfe.
Operations
Several important developments have occurred since January 1,
2003.
North America. EOG closed the largest property acquisition
in its history on October 1, 2003, with the purchase of natural
gas properties in the Wintering Hills, Drumheller East and
Twining areas of southeast Alberta, Canada, from a subsidiary of
Husky Energy Inc. for approximately US $320 million. This
transaction increases EOG's drilling inventory in Canada,
primarily in the footprint of its very successful shallow natural
gas program in southern Alberta. It also complements EOG's
existing Canadian assets by providing incremental reserve
potential and significantly increasing EOG's coal bed methane
acreage position in the Twining Field.
EOG's effort to identify plays with larger reserve potential
has proven a successful supplement to its base development and
exploitation program in North America. EOG plans to continue to
drill smaller wells in large acreage plays, which in the
aggregate, will contribute substantially to EOG's crude oil and
natural gas production. EOG has several larger potential plays
underway in Wyoming, Utah and Texas, including the Barnett Shale,
from which more information will become known during 2004.
International. In 2003, Trinidad had its first full year of
sales to the Caribbean Nitrogen Company Limited (CNCL) ammonia
plant versus only six months of sales in 2002. Also in Trinidad
in 2003, construction progressed on the Nitro 2000 ammonia plant,
which is scheduled to start up in the second half of 2004. EOG
will supply 60 million cubic feet per day (MMcfd), gross, and
based on current price assumptions, expects to supply 47 MMcfd,
net, of natural gas to this facility under a fifteen-year
contract. Additionally in Trinidad, EOG signed a fifteen-year
contract to supply a portion of the natural gas requirements of
the M5000 methanol plant. Currently under construction, start-up
of the M5000 facility is planned for mid-2005. When the plant is
running at its design capacity, EOG anticipates supplying
approximately 95 MMcfd, gross, of natural gas during the first
four years and approximately 125 MMcfd, gross, during the
remaining eleven years of the contract. Based on current price
assumptions, the company expects to supply an average 67 MMcfd,
net, during the first four years and 87 MMcfd, net, during the
remaining eleven years. The wellhead price will be linked to
Caribbean methanol prices but with a floor price. With this new
contract, EOG anticipates another significant increase in its
Trinidad production next year. In addition, EOG believes that
there are additional exploration opportunities in its existing
acreage position in Trinidad and continues to pursue additional
acreage.
Although EOG continues to focus on North American natural
gas, EOG sees an increasing linkage between North American
natural gas demand and Trinidadian natural gas supply. For
example, liquefied natural gas (LNG) imports from existing and
planned facilities in Trinidad are serious contenders to meet
increasing U.S. demand. In addition, ammonia, methanol and
chemical production has been relocating from North America to
Trinidad, driven by attractive natural gas feedstock prices in
the island nation. EOG anticipates that its existing position
with the supply contracts to the two ammonia plants and the new
methanol plant, discussed above, will continue to give its
portfolio an even broader exposure to North American natural gas
fundamentals.
Also in 2003, EOG established a new venue outside of North
America with two natural gas discoveries in the Southern Gas
Basin of the United Kingdom North Sea. The wells were farm-in
opportunities from major oil companies. Production of
approximately 40 MMcfd, net, is expected by year-end 2004. EOG
is reviewing additional farm-in opportunities in this area and
expects to participate in several exploration wells in 2004.
Capital Structure
As noted, one of management's key strategies is to keep a
strong balance sheet with a consistently below average debt-to-
total capitalization ratio. At December 31, 2003, its debt-to-
total capitalization ratio was 33.3%, down from 40.6% at year-end
2002. With the net cash provided from operating activities, EOG
funded its entire $917 million capital program, paid down $36
million of debt, closed $405 million of acquisitions and, in May
2003, increased the dividend paid to common shareholders by 25%.
As management currently assesses price forecast and demand trends
for 2004, EOG believes that operations and capital expenditure
activity can essentially be funded by cash from operations.
For 2004, EOG's estimated capital expenditure budget is
approximately $1.1 billion, excluding acquisitions. EOG plans to
spend about 5% of this estimated capital expenditure budget to
drill new, internally generated, bigger target ideas. North
American natural gas continues to be a key component of this
effort. When it fits EOG's strategy, EOG will make acquisitions
that bolster existing drilling programs or offer EOG incremental
exploration and/or production opportunities. Management believes
EOG has one of the strongest prospect inventories in EOG's
history.
Finding Costs and Reserve Replacement
During 2003, EOG replaced 249% of its production at an all-
in $1.28 per Mcfe finding cost. In North America, EOG had 259%
reserve replacement at $1.36 per Mcfe. EOG replaced 189% of
production at a $0.63 per Mcfe finding costs in its Trinidad and
United Kingdom activities. An external review of approximately
70% of EOG's reserves was conducted by the independent reserve
engineering firm of DeGolyer and MacNaughton (D&M). For the
sixteenth consecutive year, D&M reported no material differences
overall between their independent estimates and EOG's internal
estimates.
The following review of operations for each of the three
years in the period ended December 31, 2003 should be read in
conjunction with the consolidated financial statements of EOG and
notes thereto beginning with page 20.
Results of Operations
Net Operating Revenue
During 2003, net operating revenues increased $650 million
to $1,745 million. Total wellhead revenues increased 65% to
$1,818 million as compared to 2002. Wellhead volume and price
statistics for the specified years were as follows:
Year Ended December 31,
2003 2002 2001
Natural Gas Volumes (MMcf per day) (1)
United States 638 635 680
Canada 165 154 126
Trinidad 152 135 115
Total 955 924 921
Average Natural Gas Prices ($/Mcf) (2)
United States $5.06 $2.89 $4.26
Canada 4.66 2.67 3.78
Trinidad 1.35 1.20 1.22
Composite 4.40 2.60 3.81
Crude Oil and Condensate Volumes (MBbl per day) (1)
United States 18.5 18.8 22.0
Canada 2.3 2.1 1.7
Trinidad 2.4 2.4 2.1
Total 23.2 23.3 25.8
Average Crude Oil and Condensate Prices ($/Bbl) (2)
United States $30.24 $24.79 $25.06
Canada 28.54 23.62 22.70
Trinidad 28.88 23.58 24.14
Composite 29.92 24.56 24.83
Natural Gas Liquids Volumes (MBbl per day) (1)
United States 3.2 2.9 3.5
Canada 0.6 0.8 0.5
Total 3.8 3.7 4.0
Average Natural Gas Liquids Prices ($/Bbl) (2)
United States $21.53 $14.76 $17.17
Canada 19.13 11.17 15.05
Composite 21.13 14.05 16.89
Natural Gas Equivalent Volumes (MMcfe per day) (3)
United States 768 765 833
Canada 183 171 139
Trinidad 166 150 128
Total 1,117 1,086 1,100
Total Bcfe (3) Deliveries 408 396 401
(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.
2003 compared to 2002. Wellhead natural gas revenues for
2003 increased $657 million, or 75%, due to increases in the
composite average wellhead natural gas price and natural gas
deliveries. The composite average wellhead price for natural gas
increased 69% to $4.40 per Mcf for 2003 from $2.60 per Mcf in
2002.
Natural gas deliveries increased to 955 MMcf per day for
2003 from 924 MMcf per day for the comparable period a year ago.
The overall increase in natural gas deliveries was primarily due
to an increase in Canada of 7% to 165 MMcf per day and an
increase in Trinidad of 13% to 152 MMcf per day in 2003. The 7%
or 11 MMcf per day increase in Canada was primarily attributable
to a major property acquisition in the fourth quarter. The 13%
or 17 MMcf per day increase in Trinidad was attributable to a
full year of sales to the CNCL ammonia plant versus only six
months of sales in 2002.
Wellhead crude oil and condensate revenues increased $45
million, or 22%, due to increases in the composite average
wellhead crude oil and condensate price. The composite average
wellhead crude oil and condensate price for 2003 was $29.92 per
barrel compared to $24.56 per barrel for 2002.
Natural gas liquids revenues were $11 million higher than a
year ago primarily due to a 50% increase in the composite average
price and a 3% increase in deliveries.
During 2003, EOG recognized losses on mark-to-market
commodity derivative contracts of $80 million, which included
realized losses of $45 million and collar premium payments of $3
million. During 2002, EOG recognized losses on mark-to-market
commodity derivative contracts of $49 million, which included
realized losses of $21 million and a $2 million collar premium
payment.
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
the composite average wellhead natural gas price, partially
offset by an increase in natural gas deliveries in Canada and
Trinidad. The composite average wellhead price for natural gas
decreased 32% to $2.60 per Mcf for 2002 compared to $3.81 per Mcf
in 2001.
Natural gas deliveries increased slightly to 924 MMcf per
day for 2002 compared to 921 MMcf per day for 2001. 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 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 composite 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 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 certain areas in the United States 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 in 2002
than in 2001 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, which included
realized losses of $21 million and a $2 million collar premium
payment. During 2001, EOG recognized gains on mark-to-market
commodity derivative contracts of $98 million, of which $67
million were realized gains which were netted against a $5
million collar premium payment.
Other marketing activities associated with sales and
purchases of natural gas increased net operating revenues by $37
million and $16 million in 2002 and 2001, respectively.
Operating and Other Expenses
2003 compared to 2002. During 2003, operating expenses of
$1,047 million were $133 million higher than the $914 million
incurred in 2002. The following table presents the costs per
Mcfe for the years ended December 31, 2003 and 2002:
Year Ended December 31,
2003 2002
Lease and Well $0.52 $0.45
DD&A 1.08 1.00
G&A 0.25 0.22
Taxes Other than Income 0.21 0.18
Interest Expense, Net 0.14 0.15
Total Per-Unit Costs $2.20 $2.00
The higher per-unit rates of lease and well, DD&A, G&A and
taxes other than income for 2003 compared to 2002 were due
primarily to the reasons set forth below.
Lease and well expenses of $213 million were $33 million
higher than 2002 due primarily to a general increase in service
costs related to operating activities in the United States ($15
million) and Canada ($4 million), increased lease and well
administrative expenses in the United States ($7 million) and
changes in the Canadian exchange rate ($6 million).
Depreciation, depletion and amortization (DD&A) expenses of
$442 million increased $44 million from the prior year due
primarily to more relative production from higher cost properties
in the United States ($20 million) and Canada ($5 million),
increased production in Canada ($3 million) and Trinidad ($2
million), and changes in the Canadian exchange rate ($8 million).
Also, included in DD&A expenses for 2003 was $5 million of
accretion expense related to Statement of Financial Accounting
Standards (SFAS) No. 143 - "Accounting for Asset Retirement
Obligations."
General and administrative (G&A) expenses of $100 million
were $11 million higher than the period a year ago due primarily
to expanded operations ($9 million) and increased insurance
expense ($5 million), partially offset by decreases in legal
costs ($3 million).
Taxes other than income of $86 million were $14 million
higher than the prior year period primarily due to an increase of
approximately $35 million as a result of increased wellhead
revenue as previously discussed, partially offset by $24 million
of severance tax credits from the qualification of wells for a
Texas high cost gas severance tax exemption.
Exploration costs of $76 million were $16 million higher
than a year ago due primarily to an increase in technical staff
costs across EOG ($7 million) and increased geological and
geoscience expenditures in the United States ($5 million) and
Trinidad ($3 million).
Impairments increased $21 million to $89 million compared to
a year ago due to higher amortization of unproved leases in the
United States ($25 million). Total impairments under SFAS No.
144 - "Accounting for the Impairment or Disposal of Long-Lived
Assets" for 2003 and 2002 were $25 million and $30 million,
respectively.
Other Income (Expense), Net for 2003 included foreign
currency transaction gains of $9 million as a result of applying
the changes in the Canadian exchange rate to certain intercompany
short-term loans that eliminate in consolidation.
Income tax provision increased $184 million to $217 million
for 2003 as compared to 2002 primarily resulting from higher
income before income taxes for federal ($187 million) and state
($4 million), expiration of the tight gas sands federal income
tax credit as of December 31, 2002 ($4 million), higher effective
foreign income tax rates ($4 million), offset by net tax benefit
associated with the Canadian tax law change ($14 million).
In November 2003, Canada enacted legislation reducing the
Canadian federal income tax rate for companies in the resource
sector from 28% to 27% for 2003, with further reductions to 21%
phased in over the next four years. This legislation also made
changes to the tax treatment of crown royalties and the resource
allowance. Beginning in 2003, Canadian taxpayers are allowed to
deduct 10% of actual provincial and other crown royalties. This
percentage increases each year through 2007, at which time 100%
of crown royalties will be deductible. The resource allowance, a
statutory deduction calculated as 25% of adjusted resource
profits, will be phased out through 2007, when the deduction will
be completely eliminated.
2002 compared to 2001. During 2002, operating expenses of
$914 million were approximately $66 million lower than the $980
million incurred in 2001. The following table presents the costs
per Mcfe for the 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, Net 0.15 0.11
Total Per-Unit Costs $2.00 $1.97
The changes in per-unit lease and well, DD&A, G&A, taxes
other than income and net interest expense rates for 2002
compared to 2001 are due primarily to the reasons set forth
below.
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 fewer workovers in the Gulf of Mexico.
DD&A expenses increased $6 million to $398 million primarily
due to increased activity in Canada and higher per unit costs
related to certain fields in the United States.
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.
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.
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 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.
Exploration costs of $60 million were $7 million lower than
a year ago primarily due to decreased geological and geoscience
expenditures.
Dry hole costs of $47 million decreased $25 million from
2001.
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.
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.
Capital Resources and Liquidity
Cash Flow
The primary sources of cash for EOG during the three-year
period ended December 31, 2003 included funds generated from
operations and funds from new borrowings. Primary cash outflows
included funds used in operations, exploration and development
expenditures, oil and gas property acquisitions, repayment of
debt, common stock repurchases and dividends.
2003 compared to 2002. Net operating cash inflows of $1,320
million in 2003 increased approximately $652 million as compared
to 2002 primarily reflecting an increase in operating revenues of
$650 million and favorable changes in working capital and other
liabilities of $115 million, partially offset by an increase in
cash operating expenses of $132 million.
Net investing cash outflows of approximately $1,269 million
in 2003 increased by $396 million as compared to 2002 due
primarily to increased exploration and development expenditures
of $501 million, which includes $366 million related to two
Canadian asset purchases as mentioned below in the Capital
Expenditures discussion, partially offset by favorable changes in
working capital of $81 million related to investing activities
and a decrease in equity investment of $15 million. Changes in
Components of Working Capital Associated with Investing
Activities included changes in accounts payable associated with
the accrual of exploration and development expenditures and
changes in inventories which represent material and equipment
used in drilling and related activities.
Cash used by financing activities was $57 million in 2003
versus cash provided of $211 million in 2002. Financing
activities for 2003 included repayment of the outstanding
balances of commercial paper borrowings and the uncommitted line
of credit of $22 million and $14 million, respectively,
repurchases of EOG's common stock of $21 million, cash dividend
payments of $31 million and proceeds of $35 million from sales of
treasury stock attributable to employee stock option exercises
and the employee stock purchase plan.
2002 compared to 2001. 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.
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.
Exploration and Development Expenditures
The table below sets out components of exploration and
development expenditures for the years ended December 31, 2003,
2002 and 2001, along with the total budgeted for 2004, excluding
acquisitions (in millions):
Actual Budgeted 2004
2003 2002 2001 (excluding acquisitions)
Expenditure Category
Capital
Drilling and Facilities $ 731 $ 595 $ 722
Leasehold Acquisitions 59 39 76
Producing Property Acquisitions 405 71 168
Capitalized Interest 9 9 9
Subtotal 1,204 714 975
Exploration Costs 76 60 67
Dry Hole Costs 41 47 71
Subtotal 1,321 821 1,113 Approximately $1,100
Asset Retirement Costs (1) 12 -- --
Deferred Income Tax Gross Up -- 15 50
Total (2) $1,333 $ 836 $1,163
(1) 2003 Asset Retirement Costs does not include the cumulative
effect of adoption and is netted with gains recognized upon
settlement of asset retirement obligations of $1 million.
(2) Pro forma total expenditures for 2002 and 2001 are not
presented since the pro forma application of SFAS No. 143 to
the prior periods would not result in pro forma total
expenditures materially different from the actual amounts
reported.
Total exploration and development expenditures of $1,333
million increased $497 million in 2003 as compared to 2002 due
primarily to the two property acquisitions by a Canadian
subsidiary of EOG, as described below, and increased exploration
and development activities across EOG. Included in 2003
expenditures are $652 million in development, $405 million in
property acquisitions and $266 million in exploration.
On October 1, 2003, a Canadian subsidiary of EOG closed an
asset purchase of natural gas properties in the Wintering Hills,
Drumheller East and Twining areas of southeast Alberta from a
subsidiary of Husky Energy Inc. for approximately US $320
million. These properties are essentially adjacent to existing
EOG operations or are properties in which EOG already had a
working interest. The transaction was partially funded by
commercial paper borrowings of US $140.5 million on October 1,
2003. The remainder of the purchase price, US $179.5 million,
was funded by EOG's available cash balance. Subsequent to the
closing, the purchase price was reduced by exercised preferential
rights on the properties which totaled approximately US $5
million. In late December 2003, a Canadian subsidiary of EOG
closed another property acquisition for US $46 million.
Derivative Transactions
During 2003, EOG recognized losses on mark-to-market
commodity derivative contracts of $80 million, which included
realized losses of $45 million and collar premium payments of $3
million. During 2002, EOG recognized losses on mark-to-market
commodity derivative contracts of $49 million, which included
realized losses of $21 million and a $2 million collar premium
payment. (See Note 12 to the Consolidated Financial Statements.)
Presented below is a summary of EOG's 2004 natural gas
financial collar contracts and natural gas and crude oil
financial price swap contracts as of February 24, 2004, with
prices expressed in dollars per million British thermal units
($/MMBtu) and in dollars per barrel ($/Bbl), as applicable, and
notional volumes in million British thermal units per day
(MMBtud) and in barrels per day (Bbld), as applicable. EOG has
not entered into any additional natural gas financial collar
contracts or natural gas or crude oil financial price swap
contracts since December 31, 2003. EOG accounts for these collar
and swap contracts using mark-to-market accounting.
Natural Gas Financial Collar Contracts Financial Price Swap Contracts
Floor Price Ceiling Price Natural Gas Crude Oil
Floor Weighted Ceiling Weighted Weighted Weighted
Volume Range Average Range Average Volume Average Volume Average
Month(1) (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu) (Bbld) ($/Bbl)
Jan 330,000 $5.06 - 5.88 $5.38 $5.86 - 6.69 $6.29 30,000 $5.57 4,000 $30.61
Feb 330,000 5.02 - 5.78 5.31 5.82 - 6.62 6.24 30,000 5.50 4,000 30.12
Mar 330,000 4.93 - 5.53 5.16 5.73 - 6.40 6.10 30,000 5.37 4,000 29.58
Apr 375,000 4.47 - 4.71 4.59 4.93 - 5.30 5.13 30,000 4.89 4,000 29.08
May 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 4,000 28.66
Jun 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 4,000 28.27
Jul 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 3,000 27.91
Aug 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 2,000 28.11
Sep 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.78 -- --
Oct 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 -- --
(1) The collar contracts for January 2004 to March 2004 were
purchased at a total premium of $3 million or $0.10 per MMBtu.
The collar contracts for April 2004 to October 2004 were
purchased without a premium.
Financing
EOG's long-term debt-to-total capitalization ratio was 33.3%
as of December 31, 2003 compared to 40.6% as of December 31, 2002.
During 2003, total long-term debt decreased $36 million to
$1,109 million (see Note 2 to the Consolidated Financial
Statements). The estimated fair value of EOG's long-term debt at
December 31, 2003 and 2002 was $1,175 million and $1,225 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, 2003, a 1% decline in interest
rates would result in a $51 million increase in the estimated
fair value of the fixed rate obligations (see Note 12 to the
Consolidated Financial Statements).
During 2003 and 2002, EOG utilized primarily commercial
paper and committed bank loans to fund its operations. These
loans are more fully described in Note 2 to the Consolidated
Financial Statements. While EOG maintains a $600 million
commercial paper program, the maximum outstanding at any time
during 2003 was $244 million, and the amount outstanding at
yearend was $98 million. EOG considers this excess availability,
which is contractually backed by the $600 million Revolving
Credit Agreement with domestic and foreign lenders described in
Note 2, combined with the $688 million of availability under its
shelf registration described below, to be ample to meet its
ongoing operating needs.
Contractual Obligations
The following table summarizes EOG's contractual obligations
at December 31, 2003 (in thousands):
2010 &
Contractual Obligations (1) Total 2004 2005 - 2007 2008 - 2009 beyond
Long-Term Debt (2) $1,108,872 $198,050 $376,870 $173,952 $360,000
Non-cancelable Operating Leases 54,650 18,187 25,954 3,898 6,611
Drilling Rig Commitments 2,364 1,033 998 333 --
Pipeline Transportation Service
Commitments (3) 45,702 13,615 25,811 3,666 2,610
Total Contractual Obligations $1,211,588 $230,885 $429,633 $181,849 $369,221
(1) See Notes 2 and 8 to Consolidated Financial Statements.
(2) Commercial paper and the 6.50% Notes due 2004 are
classified as long-term debt on the Consolidated Balance
Sheets based on EOG's intent and ability to ultimately replace
such amounts with other long-term debt. See Note 2 to the
Consolidated Financial Statements.
(3) Amounts shown are based on current pipeline
transportation rates and the Canadian foreign currency
exchange rate at December 31, 2003. Management does not
believe that any future changes in these rates before the
expiration dates of these commitments will have a materially
adverse effect on the financial condition or results of
operations of EOG.
Shelf Registration
As of February 24, 2004, the amount available under various
filed registration statements with the Securities and Exchange
Commission for the offer and sale from time to time of EOG debt
securities, preferred stock and/or common stock totaled $688
million.
Off-Balance Sheet Arrangements
EOG does not participate in financial transactions that generate
relationships with unconsolidated entities or financial
partnerships. Such entities, often referred to as variable
interest entities (VIE) or special purpose entities (SPE), are
generally established for the purpose of facilitating off-balance
sheet arrangements or other contractually narrow or limited
purposes. EOG was not involved in any unconsolidated VIE or SPE
financial transactions during any of the reporting periods in this
document and has no intention to participate in such transactions
in the foreseeable future.
Foreign Currency Exchange Rate Risk
During 2003, EOG was exposed to foreign currency exchange
rate risk inherent in its operations in foreign countries,
including Canada, Trinidad and the United Kingdom. The foreign
currency most significant to EOG's operations during 2003 was the
Canadian Dollar. While the strengthening of the Canadian Dollar
in 2003 impacted both the revenues and expenses recorded on the
income statements of EOG's Canadian subsidiaries, its impacts on
these items were not to the same extent. Since the Canadian
natural gas prices are largely correlated to United States
prices, the changes in the Canadian currency exchange rate have
less of an impact on the Canadian revenues than the Canadian
expenses. EOG continues to monitor the foreign currency exchange
rates of countries in which it is currently conducting business
and will implement measures to protect against the foreign
currency exchange rate risk if needed.
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
current economic conditions, 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. Longer term
natural gas prices will be determined by the natural rate of
production decline in North America, the level of North American
rig activity and the level of LNG imports as well as prices of
competing fuels, including oil.
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. In recent years, several of the
largest natural gas marketing companies have filed for bankruptcy
or are having financial difficulty, and others are exiting this
business. EOG does not believe that this will have a material
effect on its ability to market its natural gas production. EOG
continues to assess and monitor the credit worthiness of partners
to whom it sells its production and where appropriate, to seek
new markets.
EOG plans to continue to focus a substantial portion of its
exploration and development expenditures in its major producing
areas in 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
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 2004 exploration and development
expenditures, excluding acquisitions, are approximately $1.1
billion, 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 2004 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 2004 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 2004
will be sufficient to fund its net investing cash requirements
for the year. However, EOG has significant flexibility with
respect to its financing alternatives and adjustment of its
exploration, exploitation, development and acquisition
expenditure plans if circumstances warrant. While EOG has
certain continuing commitments associated with expenditure plans
related to operations in the United States, Canada, Trinidad and
the United Kingdom, such commitments are not expected to be
material when considered in relation to the total financial
capacity of EOG.
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 or to which it
sent equipment for cleaning, and for damages to natural resources
or other claims related to releases of regulated substances at
such sites. In this regard, EOG has been named as a potentially
responsible party in certain proceedings initiated pursuant to
the Comprehensive Environmental Response, Compensation, and
Liability Act and may be named as a potentially responsible party
in other similar proceedings in the future. It is not
anticipated that the costs incurred by EOG in connection with the
presently pending proceedings will, individually or in the
aggregate, have a materially adverse effect on the financial
condition or results of operations of EOG.
Summary of Critical Accounting Policies
EOG prepares its financial statements and the accompanying
notes in conformity with accounting principles generally accepted
in the United States of America, which requires management to
make estimates and assumptions about future events that affect
the reported amounts in the financial statements and the
accompanying notes. EOG identifies certain accounting policies
as critical based on, among other things, their impact on the
portrayal of EOG's financial condition, results of operations or
liquidity, and the degree of difficulty, subjectivity and
complexity in their deployment. Critical accounting policies
cover accounting matters that are inherently uncertain because
the future resolution of such matters is unknown. Management
routinely discusses the development, selection and disclosure of
each of the critical accounting policies. Following is a
discussion of EOG's most critical accounting policies:
Proved Oil and Gas Reserves
EOG's engineers, with secondary verification from third-
party experts (D&M), estimate proved oil and gas reserves, which
directly impact financial accounting estimates, including
depreciation, depletion and amortization. Proved reserves
represent estimated quantities of natural gas, crude oil,
condensate, and natural gas liquids that geological and
engineering data demonstrate, with reasonable certainty, to be
recoverable in future years from known reservoirs under economic
and operating conditions existing at the time the estimates were
made. The process of estimating quantities of proved oil and gas
reserves is very complex, requiring significant subjective
decisions in the evaluation of all available geological,
engineering and economic data for each reservoir. The data for a
given reservoir may also change substantially over time as a
result of numerous factors including, but not limited to,
additional development activity, evolving production history and
continual reassessment of the viability of production under
varying economic conditions. Consequently, material revisions
(upward or downward) to existing reserve estimates may occur from
time to time.
Impairments
Oil and gas lease acquisition costs are capitalized when
incurred. Unproved properties with individually significant
acquisition costs are assessed quarterly on a
property-by-property basis, and any impairment in value is
recognized. Unproved properties with acquisition costs that are
not individually significant are aggregated, and the portion of
such costs estimated to be nonproductive, based on historical
experience, is amortized over the average holding period. If the
unproved properties are determined to be productive, the
appropriate related costs are transferred to proved oil and gas
properties. Lease rentals are expensed as incurred.
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,
operating costs, anticipated production from proved reserves and
other relevant data, are lower than the unamortized capitalized
cost, the capitalized cost is reduced to fair value. Fair value
is calculated by discounting the future cash flows at an
appropriate risk-adjusted discount rate.
Depreciation, Depletion and Amortization for Oil and Gas Properties
The quantities of estimated proved oil and gas reserves are
a significant component of our calculation of depletion expense
and revisions in such estimates may alter the rate of future
expense. Holding all other factors constant, if reserves were
revised upward or downward, earnings would increase or decrease
respectively.
Stock Options
EOG accounts for stock options under the provisions and
related interpretations of Accounting Principles Board (APB)
Opinion No. 25 - "Accounting for Stock Issued to Employees." No
compensation expense is recognized for such options. As allowed
by SFAS No. 123 - "Accounting for Stock-Based Compensation"
issued in 1995, EOG has continued to apply APB Opinion No. 25 for
purposes of determining net income and to present the pro forma
disclosures required by SFAS No. 123.
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, foreign currency exchange rates and interest
rates; the timing and impact of liquefied natural gas imports and
changes in demand or prices for ammonia or methanol; the extent
and effect of any hedging activities engaged in by EOG; the
extent of EOG's success in discovering, developing, marketing and
producing reserves and in acquiring oil and gas properties; the
accuracy of reserve estimates, which by their nature involve the
exercise of professional judgment and may therefore be imprecise;
political developments around the world; acts of war and
terrorism and responses to these acts; and financial market
conditions. In light of these risks, uncertainties and
assumptions, the events anticipated by EOG's forward-looking
statements might not occur. EOG undertakes no obligations to
update or revise its forward-looking statements, whether as a
result of new information, future events or otherwise.
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, 2003.
MARK G. PAPA EDMUND P. SEGNER, III TIMOTHY K. DRIGGERS
Chairman of the Board President and Chief Vice President and Chief
and Chief Executive of Staff Accounting Officer
Officer
Houston, Texas
February 23, 2004
REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
EOG Resources, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets
of EOG Resources, Inc. (the "Company") as of December 31, 2003
and 2002, and the related consolidated statements of income,
stockholders' equity, and cash flows for the years then ended.
These consolidated financial statements are the responsibility of
the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our
audits. The consolidated financial statements of EOG Resources,
Inc. for the year ended December 31, 2001, were audited by other
auditors who have ceased operations. Those auditors expressed
an unqualified opinion on those consolidated financial statements
in their report dated February 21, 2002.
We conducted our audits 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 audits provide a reasonable
basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of the
Company as of December 31, 2003 and 2002, and the results of its
operations and its cash flows for the years then ended in
conformity with accounting principles generally accepted in the
United States of America.
As discussed in Note 14 to the consolidated financial
statements, the Company adopted Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations,"
on January 1, 2003.
Deloitte & Touche LLP
February 23, 2004
REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS (Concluded)
EOG dismissed Arthur Andersen LLP on February 27, 2002 and
subsequently engaged Deloitte & Touche LLP as its independent
auditors. The predecessor auditor's report appearing below is a
copy of Arthur Andersen's previously issued report dated February
21, 2002. Since EOG is unable to obtain a current manually
signed audit report, a copy of Arthur Andersen's most recent
signed and dated report has been included to satisfy filing
requirements, as permitted under Rule 2-02(e) of Regulation S-X.
The only information in the financial statements and the related
footnotes included in this Current Report on Form 8-K that is
referred to in the report of Arthur Andersen LLP is the
information included in the accompanying Consolidated Statements
of Income and Consolidated Statements of Cash Flows and the
related footnotes for the year ended December 31, 2001.
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,
2003 2002 2001
NET OPERATING REVENUES
Natural Gas $1,537,352 $ 915,129 $1,298,102
Crude Oil, Condensate and Natural Gas Liquids 283,042 227,309 258,101
Gains (Losses) on Mark-to-Market Commodity
Derivative Contracts (80,414) (48,508) 97,750
Other, Net 4,695 752 1,769
TOTAL 1,744,675 1,094,682 1,655,722
OPERATING EXPENSES
Lease and Well 212,601 179,429 175,446
Exploration Costs 76,358 60,228 67,467
Dry Hole Costs 41,156 46,749 71,360
Impairments 89,133 68,430 79,156
Depreciation, Depletion and Amortization 441,843 398,036 392,399
General and Administrative 100,403 88,952 79,963
Taxes Other Than Income 85,867 71,881 95,333
Charges Associated with Enron Bankruptcy - - 19,211
TOTAL 1,047,361 913,705 980,335
OPERATING INCOME 697,314 180,977 675,387
OTHER INCOME (EXPENSE), NET 15,273 (1,651) 1,168
INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES 712,587 179,326 676,555
INTEREST EXPENSE
Incurred 67,252 68,641 53,756
Capitalized (8,541) (8,987) (8,646)
Net Interest Expense 58,711 59,654 45,110
INCOME BEFORE INCOME TAXES 653,876 119,672 631,445
INCOME TAX PROVISION 216,600 32,499 232,829
NET INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 437,276 87,173 398,616
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAX (7,131) - -
NET INCOME 430,145 87,173 398,616
PREFERRED STOCK DIVIDENDS 11,032 11,032 10,994
NET INCOME AVAILABLE TO COMMON $ 419,113 $ 76,141 $ 387,622
NET INCOME PER SHARE AVAILABLE TO COMMON
Basic
Net Income Available to Common Before
Cumulative Effect of Change in Accounting
Principle $ 3.72 $ 0.66 $ 3.35
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax (0.06) - -
Net Income Available to Common $ 3.66 $ 0.66 $ 3.35
Diluted
Net Income Available to Common Before
Cumulative Effect of Change in Accounting
Principle $ 3.66 $ 0.65 $ 3.30
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax (0.06) - -
Net Income Available to Common $ 3.60 $ 0.65 $ 3.30
AVERAGE NUMBER OF COMMON SHARES
Basic 114,597 115,335 115,765
Diluted 116,519 117,245 117,488
COMPREHENSIVE INCOME
NET INCOME $ 430,145 $ 87,173 $ 398,616
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Translation Adjustment 123,811 4,315 (22,044)
Available-for-Sale Security Transactions - 926 (1,318)
COMPREHENSIVE INCOME $ 553,956 $ 92,414 $ 375,254
The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
At December 31,
2003 2002
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 4,443 $ 9,848
Accounts Receivable, net 295,118 259,308
Inventories 21,922 18,928
Income Taxes Receivable 7,976 67,090
Deferred Income Taxes 31,548 12,925
Other 35,007 26,255
TOTAL 396,014 394,354
OIL AND GAS PROPERTIES (SUCCESSFUL EFFORTS METHOD) 8,189,062 6,750,095
Less: Accumulated Depreciation, Depletion
and Amortization (3,940,145) (3,428,547)
Net Oil and Gas Properties 4,248,917 3,321,548
OTHER ASSETS 104,084 97,666
TOTAL ASSETS $ 4,749,015 $ 3,813,568
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable $ 282,379 $ 201,931
Accrued Taxes Payable 33,276 22,732
Dividends Payable 6,175 5,007
Liabilities from Price Risk Management Activities 37,779 5,939
Deferred Income Taxes 73,611 39,634
Other 43,299 40,304
TOTAL 476,519 315,547
LONG-TERM DEBT 1,108,872 1,145,132
OTHER LIABILITIES 171,115 59,180
DEFERRED INCOME TAXES 769,128 621,314
SHAREHOLDERS' EQUITY
Preferred Stock, $.01 Par, 10,000,000 Shares
Authorized:
Series B, 100,000 Shares Issued, Cumulative,
$100,000,000 Liquidation Preference 98,589 98,352
Series D, 500 Shares Issued, Cumulative,
$50,000,000 Liquidation Preference 49,827 49,647
Common Stock, $.01 Par, 320,000,000 Shares
Authorized and 124,730,000 Shares Issued 201,247 201,247
Additional Paid in Capital 1,625 -
Unearned Compensation (23,473) (15,033)
Accumulated Other Comprehensive Income (Loss) 73,934 (49,877)
Retained Earnings 2,121,214 1,723,948
Common Stock Held in Treasury, 8,819,600
shares at December 31, 2003 and 10,009,740
shares at December 31, 2002 (299,582) (335,889)
TOTAL SHAREHOLDERS' EQUITY 2,223,381 1,672,395
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 4,749,015 $ 3,813,568
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, 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
Net Income -- -- -- -- -- 430,145 -- 430,145
Amortization of Preferred
Stock Discount 417 -- -- -- -- (417) -- --
Preferred Stock Dividends
Paid/Declared -- -- -- -- -- (10,615) -- (10,615)
Common Stock Dividends
Declared, $.20 Per Share -- -- -- -- -- (21,847) -- (21,847)
Translation Adjustment -- -- -- -- 123,811 -- -- 123,811
Treasury Stock Purchased -- -- -- -- -- -- (21,295) (21,295)
Treasury Stock Issued Under
Stock Option Plans -- -- (16,522) -- -- -- 46,379 29,857
Treasury Stock Issued Under
Employee Stock Purchase Plan -- -- 84 -- -- -- 2,515 2,599
Tax Benefits from Stock
Options Exercised -- -- 11,926 -- -- -- -- 11,926
Restricted Stock and Units -- -- 6,084 (14,467) -- -- 8,383 --
Amortization of Unearned
Compensation -- -- -- 6,027 -- -- -- 6,027
Other -- -- 53 -- -- -- 325 378
Balance at December 31, 2003 $148,416 $201,247 $ 1,625 $(23,473) $ 73,934 $2,121,214 $(299,582) $2,223,381
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,
2003 2002 2001
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of Net Income to Net
Operating Cash Inflows:
Net Income $ 430,145 $ 87,173 $ 398,616
Items Not Requiring Cash
Depreciation, Depletion and Amortization 441,843 398,036 392,399
Impairments 89,133 68,430 79,156
Deferred Income Taxes 191,726 82,179 164,945
Charges Associated with Enron Bankruptcy - - 19,211
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax 7,131 - -
Other, Net 1,033 17,333 10,423
Exploration Costs 76,358 60,228 67,467
Dry Hole Costs 41,156 46,749 71,360
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses 80,414 48,508 (97,750)
Realized Gains (Losses) (44,870) (21,136) 66,731
Collar Premium (3,003) (1,825) (4,621)
Tax Benefits from Stock Options Exercised 11,926 5,168 7,332
Other, Net 2,141 (1,978) (2,292)
Changes in Components of Working Capital
and Other Liabilities
Accounts Receivable (36,156) (61,580) 146,235
Inventories (2,994) (57) (2,248)
Accounts Payable 79,748 (19,012) (26,949)
Accrued Taxes Payable 8,285 (84,666) (38,619)
Other Liabilities (3,387) 7,816 (3,422)
Other, Net (14,400) (5,578) (16,442)
Changes in Components of Working Capital
Associated with Investing and Financing
Activities (35,928) 42,782 (34,105)
NET OPERATING CASH INFLOWS 1,320,301 668,570 1,197,427
INVESTING CASH FLOWS
Additions to Oil and Gas Properties (1,204,383) (714,127) (974,016)
Exploration Costs (76,358) (60,228) (67,467)
Dry Hole Costs (41,156) (46,749) (71,360)
Proceeds from Sales of Assets 13,480 8,089 8,032
Changes in Components of Working Capital
Associated with Investing Activities 37,475 (43,246) 32,405
Other, Net 2,432 (16,277) (15,649)
NET INVESTING CASH OUTFLOWS (1,268,510) (872,538) (1,088,055)
FINANCING CASH FLOWS
Long-Term Debt Borrowings (Repayments) (36,260) 289,163 (4,155)
Dividends Paid (31,294) (29,152) (28,580)
Treasury Stock Purchased (21,295) (63,038) (126,769)
Proceeds from Stock Options Exercised 35,138 17,339 30,805
Other, Net (3,485) (3,008) 1,687
NET FINANCING CASH INFLOWS (OUTFLOWS) (57,196) 211,304 (127,012)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (5,405) 7,336 (17,640)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 9,848 2,512 20,152
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 4,443 $ 9,848 $ 2,512
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) include the accounts of
all domestic and foreign subsidiaries. Investments in
unconsolidated affiliates, in which EOG is able to exercise
significant influence, are accounted for using the equity method.
All material intercompany accounts and transactions have been
eliminated.
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenue and
expenses during the reporting period. Actual results could
differ from those estimates.
Certain reclassifications have been made to prior period
financial statements to conform with the current presentation.
Financial Instruments. EOG's financial instruments consist
of cash and cash equivalents, marketable securities, commodity
derivative contracts, accounts receivable, accounts payable and
long-term debt. The carrying values of cash and cash
equivalents, marketable securities, commodity derivative
contracts, accounts receivable and accounts payable approximate
fair value (see Note 2 for fair value of long-term debt).
Cash and Cash Equivalents. EOG records as cash equivalents
all highly liquid short-term investments with original maturities
of three months or less.
Oil and Gas Operations. EOG accounts for its natural gas
and crude oil exploration and production activities under the
successful efforts method of accounting.
Oil and gas lease acquisition costs are capitalized when
incurred. Unproved properties with individually significant
acquisition costs are assessed quarterly on a
property-by-property basis, and any impairment in value is
recognized. Unproved properties with acquisition costs that are
not individually significant are aggregated, and the portion of
such costs estimated to be nonproductive, based on historical
experience, is amortized over the average holding period. If the
unproved properties are determined to be productive, the
appropriate related costs are transferred to proved oil and gas
properties. Lease rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of
drilling exploratory wells, are charged to expense as incurred.
The costs of drilling exploratory wells are capitalized pending
determination of whether they have discovered proved commercial
reserves. 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, net of salvage values, are
taken into account. Certain other assets are depreciated on a
straight-line basis.
EOG accounts for impairments under the provisions of
Statement of Financial Accounting Standards (SFAS) No. 144 -
"Accounting for the Impairment or Disposal of Long-Lived Assets."
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, operating
costs, anticipated production from proved reserves and other
relevant data, are lower than the unamortized capitalized cost,
the capitalized cost is reduced to fair value. Fair value is
calculated by discounting the future cash flows at an appropriate
risk-adjusted discount rate.
Inventories, consisting primarily of tubular goods and well
equipment held for use in the exploration for, and development
and production of natural gas and crude oil reserves, are carried
at cost with adjustments made from time to time to recognize any
reductions in value.
Natural gas and liquids revenues are recorded when
production is delivered. Revenues are recorded on the
entitlement method based on EOG's percentage ownership of current
production. Each working interest owner in a well generally has
the right to a specific percentage of production, although actual
production sold on that owner's behalf may differ from that
owner's ownership percentage. Under entitlement accounting, a
receivable is recorded when underproduction occurs and a payable
is recorded when overproduction occurs.
Capitalized Interest Costs. Interest capitalization is
required for those properties if its effect, compared with the
effect of expensing interest, is material. Accordingly, certain
interest costs have been capitalized as a part of the historical
cost of unproved oil and gas properties. The amount capitalized
is an allocation of the interest cost incurred during the
reporting period. The interest rate used for capitalization
purposes is based on the interest rates on EOG's outstanding
borrowings.
Accounting for Price Risk Management Activities. EOG
accounts for its price risk management activities under the
provisions of SFAS No. 133 - "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS Nos. 137,
138 and 149. The statement establishes accounting and reporting
standards requiring that every derivative instrument be recorded
in the balance sheet as either an asset or liability measured at
its fair value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. During 2001,
2002 and 2003, EOG elected not to designate any of its price risk
management activities as accounting hedges under SFAS No. 133,
and accordingly, accounted for them using the mark-to-market
accounting method. Under this accounting method, the changes in
the market value of outstanding financial instruments are
recognized as gains or losses in the period of change. The gains
or losses are recorded in Gains (Losses) on Mark-to-Market
Commodity Derivative Contracts. The related cash flow impact is
reflected as cash flows from operating activities (see Note 12).
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 6).
Foreign Currency Translation. For subsidiaries whose
functional currency is deemed to be other than the United States
dollar, asset and liability accounts are translated at year-end
exchange rates and revenue and expenses are translated at average
exchange rates prevailing during the year. Translation
adjustments are included in Accumulated Other Comprehensive
Income (Loss). Any gains or losses on transactions or monetary
assets or liabilities in currencies other than the functional
currency are included in net income in the current period.
Net Income Per Share. In accordance with the provisions of
SFAS No. 128 - "Earnings per Share," basic net income per share
is computed on the basis of the weighted-average number of common
shares outstanding during the periods. Diluted net income per
share is computed based upon the weighted-average number of
common shares plus the assumed issuance of common shares for all
potentially dilutive securities (see Note 9 for additional
information to reconcile the difference between the Average
Number of Common Shares outstanding for basic and diluted net
income per share).
Stock Options. EOG accounts for stock options under the
provisions and related interpretations of Accounting Principles
Board (APB) Opinion No. 25 - "Accounting for Stock Issued to
Employees." No compensation expense is recognized for such
options. As allowed by SFAS No. 123 - "Accounting for Stock-
Based Compensation" issued in 1995, EOG has continued to apply
APB Opinion No. 25 for purposes of determining net income and to
present the pro forma disclosures required by SFAS No. 123 (see
Note 7).
New Accounting Pronouncements. In June 2001, the Financial
Accounting Standards Board (FASB) issued SFAS No. 143 -
"Accounting for Asset Retirement Obligations" effective for
fiscal years beginning after June 15, 2002. SFAS No. 143
essentially requires entities to record the fair value of a
liability for legal obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement
costs. EOG adopted the statement on January 1, 2003. The impact
of adopting the statement results in an after-tax charge of $7.1
million, which was reported in the first quarter of 2003 as
cumulative effect of change in accounting principle.
In November 2002, the FASB released its Interpretation No.
45 - "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Others" (FIN 45). FIN 45 requires a company, when serving as a
guarantor, to disclose its obligations and/or recognize the
liability associated with the guarantee. The initial recognition
and measurement provisions of this Interpretation are applicable
to guarantees issued or modified after December 31, 2002 on a
prospective basis. Disclosure is effective for financial
statements of interim or annual periods ending after December 15,
2002. EOG has identified one instance where it acts as a co-
guarantor in a loan agreement between a bank and a school in
Trinidad. The maximum exposure for EOG is US $1 million. EOG
deems the amount immaterial. The guarantee does not require
measurement and recognition under FIN 45.
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 (see Note 7). Subsequently, at the
April 22, 2003 FASB meeting, the FASB decided to require all
companies to expense the value of employee stock options.
Companies will be required to measure the cost according to the
fair value of the options under a method yet to be determined.
On October 1, 2003, the FASB set a goal of completing its
deliberations and issuing a final statement in the second half of
2004. EOG continues to monitor the developments in this area as
details of the implementation of the decision emerge.
In January 2003, the FASB released its Interpretation No. 46 -
"Consolidation of Variable Interest Entities, an Interpretation
of Accounting Research Bulletin no. 51" (FIN 46). FIN 46
requires a company to consolidate a variable interest entity
(VIE) if the company has a variable interest (or combination of
variable interests) that will absorb a majority of the entity's
expected losses if they occur, receive a majority of the entity's
expected residual returns if they occur, or both. Since EOG does
not own any interest in a VIE, the release of FIN 46 does not
have any effect on its financial position or results of
operations.
During the third quarter of 2003, the Securities and
Exchange Commission (SEC) has made comments to other registrants
that oil and gas mineral rights acquired should be classified as
an intangible asset pursuant to SFAS No. 141 - "Business
Combinations," and SFAS No. 142 - "Goodwill and Other Intangible
Assets." However, the SEC is not requiring all oil and gas
producing companies to apply this classification or the
disclosure requirements of intangible assets. Currently, EOG
classifies the cost of oil and gas mineral rights as oil and gas
properties and believes that this is consistent with oil and gas
accounting and industry practice. The FASB has been asked to
address this issue. If the FASB determines that the
reclassification is required, EOG would reclassify these costs
from oil and gas properties to intangible assets on the balance
sheet. There would be no effect on the statement of income or
cash flows.
In December 2003, the FASB issued a revision to SFAS No. 132 -
"Employers' Disclosures about Pensions and Other Postretirement
Benefits." The revised SFAS No. 132 retains the disclosures
required by the original SFAS No. 132 and requires additional
disclosures on the types of plan assets, investment strategy,
measurement dates, plan obligations, cash flows and components of
net periodic benefit cost recognized during interim periods.
This revision to SFAS No. 132 does not have any effect on EOG's
financial position or results of operations. EOG has modified
its existing disclosure on benefit plans to incorporate this
revision (see Note 7).
In January 2004, the FASB released its FASB Staff Position
No. 106-1 - "Accounting and Disclosure Requirements related to
the Medicare Prescription Drug, Improvement and Modernization Act
of 2003" (FSP 106-1), which allows a company to make a one-time
election to defer accounting for the effects of the Medicare
Prescription Drug Improvement Act of 2003 (Act). While EOG is
aware of the Act, any measures of the Accounting for
Postretirement Benefits Other than Pensions or net periodic
postretirement benefit cost in the financial statements and
accompanying Footnote 7 below, do not reflect the effects of the
Act on the plan. Specific authoritative guidance on the
accounting for the federal subsidy is pending and that guidance,
when issued, could require the company to change previously
reported information.
2. Long-Term Debt
Long-Term Debt at December 31 consisted of the following (in
thousands):
2003 2002
Commercial Paper $ 98,050 $ 120,000
Uncommitted Credit Facilities -- 14,310
Senior Unsecured Term Loan Facility due 2005 150,000 150,000
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 220,000 220,000
Total $1,108,872 $1,145,132
During 2003 and 2002, 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.
On July 23, 2003, EOG entered into a new three-year
Revolving Credit Agreement (Agreement) with domestic and foreign
lenders which provides for $600 million in long-term committed
credit, and concurrently cancelled the existing $300 million 364-
day credit facility and $300 million five-year credit facility
scheduled to expire in July 2003 and July 2004, respectively.
Advances under the Agreement bear interest based upon a base rate
or a Eurodollar rate at the option of EOG. The Agreement also
provides for the allocation, at the option of EOG, of up to $75
million of the $600 million to its Canadian subsidiary. Advances
to the Canadian subsidiary, should they occur, would be
guaranteed by EOG and would bear interest at the option of the
Canadian subsidiary based upon a Canadian prime rate or a
Canadian banker's acceptance rate. EOG also has the option to
issue up to $100 million in letters of credit as part of this
Agreement. No amounts were borrowed under this Agreement at
December 31, 2003.
EOG maintains a three-year Senior Unsecured Term Loan
Facility (Facility) with a group of banks whereby the banks lent
EOG $150 million with a maturity date of October 30, 2005. This
Facility calls for interest to be charged at a spread over LIBOR
(London InterBank Offering Rate) or the base rate at EOG's
option, and contains substantially the same covenants as those in
EOG's $600 million Long-Term Revolving Credit Agreement. The
applicable interest rate for this Facility was 1.88% at December
31, 2003.
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. The weighted
average interest rate for the commercial paper was 1.28% for
2003.
At December 31, 2003, the aggregate annual maturities of
long-term debt were $100 million for 2004, $150 million for 2005,
$127 million in 2006, $100 million for 2007 and $174 million for
2008. The 6.50% Notes due 2004 are classified as long-term debt
based on EOG's intent and ability to ultimately refinance such
amounts with other long-term debt.
Both EOG's credit Agreement and Facility contain certain
restrictive covenants, including a maximum debt-to-total
capitalization ratio of 65% and a minimum ratio of EBITDAX
(earnings before interest, taxes, DD&A, and exploration expense)
to interest expense of at least three times. Other than these
covenants, EOG does not have any other financial covenants in its
financing agreements. EOG continues to comply with these two
covenants and does not view them as materially restrictive.
Shelf Registration. As of February 24, 2004, the amount
available under various filed registration statements with the
SEC for the offer and sale from time to time of EOG debt
securities, preferred stock and/or common stock totaled $688
million.
Fair Value Of Long-Term Debt. At December 31, 2003 and
2002, EOG had $1,109 million and $1,145 million, respectively, of
long-term debt, which had fair values of approximately
$1,175 million and $1,225 million, respectively. The fair value
of long-term debt is the value EOG would have to pay to retire
the debt, including any premium or discount to the debt-holder
for the differential between the stated interest rate and the
year-end market rate. The fair value of long-term debt is based
upon quoted market prices and, where such quotes were not
available, upon interest rates available to EOG at yearend.
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, 2003, 6,386,200 shares
remain available for repurchases under this authorization.
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. 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
2003 2002 2001
Outstanding at January 1 114,720 115,452 116,904
Repurchased (531) (1,700) (3,281)
Issued Pursuant to Stock Options
and Stock Plans 1,721 968 1,829
Outstanding at December 31 115,910 114,720 115,452
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 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.
5. Other Income (Expense), Net
Other Income (Expense), Net for 2003 included foreign
currency transaction gains of $9 million as a result of applying
the changes in the Canadian exchange rate to certain intercompany
short-term loans that eliminate in consolidation.
6. Income Taxes
The principal components of EOG's net deferred income tax
liability at December 31, 2003 and 2002 were as follows (in
thousands):
2003 2002
Current Deferred Income Tax Assets
Commodity Hedging Contracts $ 9,739 $ (1,688)
Deferred Compensation Plans 4,994 3,801
Net Operating Loss 5,225 --
Other 11,590 10,812
Total Current Deferred Income Tax Assets 31,548 12,925
Current Deferred Income Tax Liabilities
Timing Differences Associated With Different
Yearends In Foreign Jurisdictions 73,611 39,634
Total Net Current Deferred Income Tax Liability $ 42,063 $ 26,709
Noncurrent Deferred Income Tax Assets
(included in Other Assets)
Foreign Net Operating Loss Carryforward $ 3,688 $ --
Noncurrent Deferred Income Tax Assets
Non-Producing Leasehold Costs $ 36,154 $ 29,574
Seismic Costs Capitalized for Tax 21,365 18,657
Alternative Minimum Tax Credit Carryforward 3,869 20,200
Other 20,124 12,589
Total Noncurrent Deferred Income Tax Assets 81,512 81,020
Noncurrent Deferred Income Tax Liabilities
Oil and Gas Exploration and Development Costs
Deducted for Tax Over Book Depreciation,
Depletion and Amortization 837,189 691,555
Capitalized Interest 13,451 10,779
Total Noncurrent Deferred Income Tax Liabilities 850,640 702,334
Total Net Noncurrent Deferred Income Tax Liability $769,128 $621,314
Total Net Deferred Income Tax Liability $807,503 $648,023
The components of income before income taxes were as follows
(in thousands):
2003 2002 2001
United States $442,109 $ 37,354 $488,741
Foreign 211,767 82,318 142,704
Total $653,876 $119,672 $631,445
Total income tax provision was as follows (in thousands):
2003 2002 2001
Current:
Federal $ 3,844 $(61,013) $ 36,737
State 880 (5,130) 5,475
Foreign 20,150 16,463 25,672
Total 24,874 (49,680) 67,884
Deferred:
Federal 151,389 57,232 131,127
State 4,052 (358) 10,411
Foreign 36,285 25,305 23,407
Total 191,726 82,179 164,945
Income Tax Provision $216,600 $ 32,499 $232,829
The differences between taxes computed at the U.S. federal
statutory tax rate and EOG's effective rate were as follows:
2003 2002 2001
Statutory Federal Income Tax Rate 35.00% 35.00% 35.00%
State Income Tax, Net of Federal Benefit 0.73 0.22 1.64
Income Tax Provision Related to Foreign
Operations (0.05) (3.54) 0.36
Change in Canadian Federal Tax Rate (2.16) -- --
Tight Gas Sands Federal Income Tax Credits -- (3.57) (0.83)
Other (0.40) (0.95) 0.70
Effective Income Tax Rate 33.12% 27.16% 36.87%
EOG's foreign subsidiaries' undistributed earnings of
approximately $722 million at December 31, 2003 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.
EOG incurred a tax net operating loss of $191 million in
2002. During 2003, EOG utilized $176 million of the 2002 net
operating loss. The remaining net operating loss of $15 million
will not expire until 2022. EOG expects the entire remaining net
operating loss to be utilized in 2004.
A foreign net operating loss of $9 million was incurred
during 2003. These losses will be carried forward indefinitely
until they are utilized.
EOG has an alternative minimum tax (AMT) credit carryforward
of $4 million which can be used to offset regular income taxes
payable in future years. The AMT credit carryforward has an
indefinite carryforward period.
7. 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 2003, 2002 and
2001, the contributions to these plans amounted to approximately
$8.2 million, $8.0 million and $6.5 million, respectively.
In addition, EOG's Canadian subsidiary maintains a non-
contributory defined contribution pension plan and a matched
savings plan and EOG's Trinidadian subsidiary maintains a
contributory defined benefit pension plan and a matched savings
plan. These plans are available to most employees of the
Canadian and Trinidadian subsidiaries and activity related to
these plans was less than $1 million combined for 2003, which is
deemed immaterial 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. The following table
summarizes EOG's postretirement benefit plan (in thousands):
As of December 31,
2003 2002 2001
Change in Benefit Obligation
Benefit Obligation at Beginning of Year $ 1,875 $ 2,021 $ 1,526
Service Cost 175 139 192
Interest Cost 131 115 134
Plan Participants' Contributions 64 58 34
Amendments 773 -- --
Benefits Paid (102) (95) (63)
Actuarial (Gain) Loss 95 (363) 198
Benefit Obligation at Yearend $ 3,011 $ 1,875 $ 2,021
Change in Plan Asset
Fair Value of Plan Asset at Beginning of Year $ -- $ -- $ --
Employer Contributions 38 37 29
Plan Participants Contributions 64 58 34
Benefits Paid (102) (95) (63)
Fair Value of Plan Asset at End of Year $ -- $ -- $ --
Reconciliation of Funded Status to Balance Sheet
Funded Status $ 3,011 $ 1,875 $ 2,021
Unrecognized Net Actuarial Gain (Loss) (64) 35 (327)
Unrecognized Prior Service (Cost) Benefit (1,647) (948) (1,024)
Accrued Benefit Cost at Yearend $ 1,300 $ 962 $ 670
Components of Net Periodic Benefit Cost
Service Cost $ 175 $ 139 $ 192
Interest Cost 131 115 134
Amortization of Prior Service Cost 75 75 75
Recognized Net Actuarial Loss (Gain) -- (1) 8
Net Periodic Benefit Cost $ 381 $ 328 $ 409
Weighted-average discount rate assumptions used in the
determination of benefit obligations at December 31, 2003, 2002
and 2001 were 6.15%, 6.40% and 7.00%, respectively. Weighted-
average discount rate assumptions used in the determination of
net periodic benefit cost for years ended December 31, 2003, 2002
and 2001 were 6.40%, 7.00% and 7.25%, respectively.
Estimated Future Employer-Paid Benefits. The following
benefits, which reflect expected future service, as appropriate,
are expected to be paid by EOG in the next 10 years (in
thousands):
Postretirement
Employer-Paid Benefits
2004 $ 57
2005 68
2006 81
2007 92
2008 104
2009 - 2013 855
Postretirement health care trend rates have zero effect on
the amounts reported for the postretirement health care plan for
both 2003 and 2002. A one-percentage point increase or decrease
in EOG's healthcare cost trend rates would have zero impact on
the postretirement benefit obligation, as any increase or
decrease in healthcare costs would be borne by the employee.
Stock Plans
EOG has various stock plans (Plans) under which employees
and non-employee members of the Board of Directors of EOG and its
subsidiaries have been or may be granted certain equity
compensation. At December 31, 2003, the total number of shares
authorized for grant from the Plans was 27,445,000 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 Plans vest either
immediately at the date of grant or up to four years from the
date of grant based on the nature of the grants and as defined in
individual grant agreements. Terms for stock options granted
under the Plans have not exceeded a maximum term of 10 years.
The following table sets forth the option transactions for
the years ended December 31 (options in thousands):
2003 2002 2001
Average Average Average
Grant Grant Grant
Options Price Options Price Options Price
Outstanding at January 1 7,842 $27.31 7,013 $24.69 7,056 $20.70
Granted 1,515 39.13 1,809 33.82 1,631 36.63
Exercised (1,485) 22.73 (868) 19.90 (1,563) 19.18
Forfeited (121) 34.74 (112) 27.64 (111) 23.84
Outstanding at December 31 7,751 30.38 7,842 27.31 7,013 24.69
Options Exercisable at December 31 4,933 27.03 5,041 23.96 4,034 22.04
Available for Future Grant 1,178 2,932 4,531
Average Fair Value of Options
Granted During Year $16.55 $14.79 $16.76
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 2003, 2002 and
2001, respectively: (1) dividend yield of 0.4%, 0.4% and 0.5%,
(2) expected volatility of 43%, 45% and 43%, (3) risk-free
interest rate of 3.4%, 3.7% and 4.6% and (4) expected life of 5.2
years, 5.3 years and 6.0 years.
The following table summarizes certain information for the
options outstanding at December 31, 2003 (options in thousands):
Options Outstanding Options Exercisable
Weighted Weighted Weighted
Average Average Average
Remaining Grant Grant
Range of Grant Prices Options Life (Years) Price Options Price
$13.00 to $17.99 892 4 $14.59 887 $14.58
18.00 to 22.99 1,370 4 20.06 1,369 20.06
23.00 to 28.99 198 3 24.33 195 24.27
29.00 to 33.99 2,351 8 33.25 1,276 33.04
34.00 to 39.99 2,568 9 37.27 929 36.37
40.00 to 54.99 372 7 43.86 277 44.19
7,751 7 30.38 4,933 27.03
EOG's pro forma net income and net income per share of
common stock for 2003, 2002 and 2001, had compensation costs been
recorded in accordance with SFAS No. 123, are presented below (in
millions, except per share data):
Year Ended December 31,
2003 2002 2001
Net Income Available to Common - As Reported $419.1 $ 76.1 $387.6
Deduct: Total stock-based employee
compensation expense (13.9) (13.7) (11.9)
Net Income Available to Common - Pro Forma $405.2 $ 62.4 $375.7
Net Income per Share Available to Common
Basic - As Reported $ 3.66 $ 0.66 $ 3.35
Basic - Pro Forma $ 3.54 $ 0.54 $ 3.25
Diluted - As Reported $ 3.60 $ 0.65 $ 3.30
Diluted - Pro Forma $ 3.48 $ 0.53 $ 3.20
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
2003 2002 2001
Outstanding at January 1 775 632 309
Granted 372 158 353
Released (103) (10) (15)
Forfeited or Expired (18) (5) (15)
Outstanding at December 31 1,026 775 632
Average Fair Value of Shares Granted During Year $40.43 $32.56 $42.08
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 2003,
2002 and 2001 was $6.0 million, $4.9 million and $3.3 million,
respectively.
Employee Stock Purchase Plan. During 2001, EOG implemented
an Employee Stock Purchase Plan (ESPP) that allows eligible
employees to semi-annually purchase, through payroll deductions,
shares of EOG common stock at 85 percent of the fair market value
at specified dates. Contributions to the ESPP are limited to 10
percent of the employees' pay (subject to certain ESPP limits)
during each of the two six-month offering periods. As of
December 31, 2003, 324,362 common shares remained available for
issuance under the plan. During 2003, approximately 410
employees participated in the plan and 74,094 common shares were
purchased at an aggregate price of $2.6 million. During 2002,
approximately 350 employees participated in the plan and 69,243
common shares were purchased at an aggregate price of $2.3
million. During 2001, approximately 300 employees participated
in the plan and 32,301 common shares were purchased at an
aggregate price of $1.0 million.
Treasury Shares. During 2003, 2002 and 2001, EOG
repurchased 531,000, 1,700,000 and 3,281,000 of its common
shares, respectively. Approximately 531,000, 968,000 and
1,829,000 of these common shares were repurchased during 2003,
2002 and 2001, 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 $11.9 million, $5.2 million and $7.3 million, for the years
2003, 2002 and 2001, 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.
8. Commitments and Contingencies
Letters Of Credit. At December 31, 2003 and 2002, EOG had
standby letters of credit and guarantees outstanding totaling
approximately $266 million and $234 million, respectively;
however, of these amounts, $220 million represents guarantees of
subsidiary indebtedness included under Note 2 "Long-Term Debt."
Minimum Commitments. At December 31, 2003, total minimum
commitments from long-term non-cancelable operating leases,
drilling rig commitments and pipeline transportation service
commitments, based on current transportation rates and the
Canadian currency exchange rate at December 31, 2003, are as
follows (in thousands):
Total Minimum
Commitments
2004 $ 32,835
2005 - 2007 52,763
2008 - 2009 7,897
2010 and beyond 9,221
$102,716
Included in the table above are leases for buildings,
facilities and equipment with varying expiration dates through
2012. Rental expenses associated with these leases amounted to
$22 million, $21 million and $20 million for 2003, 2002 and 2001,
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
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.
9. Net Income Per Share Available to Common
The following table sets forth the computation of net income
per share available to common for the years ended December 31 (in
thousands, except per share amounts):
2003 2002 2001
Numerator for basic and diluted earnings
per share -
Net income available to common $419,113 $ 76,141 $387,622
Denominator for basic earnings per share -
Weighted average shares 114,597 115,335 115,765
Potential dilutive common shares -
Stock options 1,584 1,633 1,453
Restricted stock and units 338 277 270
Denominator for diluted earnings per share -
Adjusted weighted average shares 116,519 117,245 117,488
Net income per share of common stock
Basic $ 3.66 $ 0.66 $ 3.35
Diluted $ 3.60 $ 0.65 $ 3.30
10. Supplemental Cash Flow Information
Cash paid for interest and income taxes was as follows for
the years ended December 31 (in thousands):
2003 2002 2001
Interest (net of amount capitalized) $ 62,472 $ 54,432 $ 45,715
Income taxes 26,330 15,946 106,312
11. 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 United
States Canada Trinidad Kingdom Other Total
2003
Net Operating Revenues $1,335,145(1) $ 309,418(1) $100,112 $ -- $ -- $1,744,675(1)
Depreciation, Depletion and Amortization 359,439 66,334 16,070 -- -- 441,843
Operating Income (Loss) 487,133 163,783 55,433 (9,195) 160 697,314
Interest Income 1,385 950 454 -- -- 2,789
Other Income (Expense) 2,777 6,354 3,418 (71) 6 12,484
Interest Expense 43,421 14,618 670 -- 2 58,711
Income (Loss) Before Income Taxes 447,874 156,469 58,635 (9,266) 164 653,876
Income Tax Provision (Benefit) 163,359 36,190 20,671 (3,486) (134) 216,600
Additions to Oil and Gas Properties 605,667 552,164 31,942 14,610 -- 1,204,383
Total Assets 3,119,474 1,302,753 309,727 17,061 -- 4,749,015
2002
Net Operating Revenues $ 846,007(2) $ 169,106(2) $ 79,551 $ -- $ 18 $1,094,682(2)
Depreciation, Depletion and Amortization 334,318 49,622 14,085 -- 11 398,036
Operating Income (Loss) 93,600 40,587 49,450 (250) (2,410) 180,977
Interest Income 765 229 348 -- -- 1,342
Other Income (Expense) (3,652) 261 394 -- 4 (2,993)
Interest Expense 45,907 13,534 211 -- 2 59,654
Income (Loss) Before Income Taxes 44,806 27,543 49,981 (250) (2,408) 119,672
Income Tax Provision (Benefit) (7,684) 20,359 20,974 300 (1,450) 32,499
Additions to Oil and Gas Properties 517,598 160,840 35,689 -- -- 714,127
Total Assets 2,864,862 665,202 283,395 66 43 3,813,568
2001
Net Operating Revenues $1,395,349(2) $ 191,213(2) $ 69,140 $ -- $ 20 $1,655,722(2)
Depreciation, Depletion and Amortization 348,539 31,821 12,031 -- 8 392,399
Operating Income (Loss) 537,549 107,518 36,761 (40) (6,401) 675,387
Interest Income 1,117 2,244 1,699 -- -- 5,060
Other Income (Expense) (4,123) 77 154 -- -- (3,892)
Interest Expense 45,064 (280) 326 -- -- 45,110
Income (Loss) Before Income Taxes 489,479 110,119 38,288 (40) (6,401) 631,445
Income Tax Provision (Benefit) 187,265 28,438 20,166 432 (3,472) 232,829
Additions to Oil and Gas Properties 729,655 176,101 68,260 -- -- 974,016
Total Assets 2,676,182 510,476 227,229 36 121 3,414,044
(1) EOG had sales activity with two significant purchasers, one
totaled $222 million and the other totaled $182 million, of
Consolidated Net Operating Revenues in the United States and Canada
segments in 2003.
(2) EOG had sales activity with a single significant purchaser in the
United States and Canada segments in 2002 and 2001 that totaled $163
million and $225 million, respectively, of the Consolidated Net
Operating Revenues.
12. Price, Interest Rate and Credit Risk Management Activities
Price and Interest Rate Risks. EOG engages in price risk
management activities from time to time. These activities are
intended to manage EOG's exposure to fluctuations in commodity
prices for natural gas and crude oil. EOG utilizes derivative
financial instruments, primarily price swaps and collars, as the
means to manage this price risk. In addition to these financial
transactions, EOG is a party to various physical commodity
contracts for the sale of hydrocarbons that cover varying periods
of time and have varying pricing provisions. Under SFAS No. 133 -
"Accounting for Derivative Instruments and Hedging Activities,"
as amended by SFAS Nos. 137, 138 and 149, these various physical
commodity contracts qualify for the normal purchases and normal
sales exception and therefore, are not subject to hedge
accounting or mark-to-market accounting. The financial impact of
these various physical commodity contracts is included in
revenues at the time of settlement, which in turn affects average
realized hydrocarbon prices.
During 2003, 2002 and 2001, EOG elected not to designate any
of its derivative financial contracts as accounting hedges and
accordingly, accounted for these derivative financial contracts
using mark-to-market accounting. During 2003, EOG recognized
losses on mark-to-market commodity derivative contracts of $80
million, which included realized losses of $45 million and collar
premium payments of $3 million. During 2002, EOG recognized
losses on mark-to-market commodity derivative contracts of $49
million, which included realized losses of $21 million and a $2
million collar premium payment. During 2001, EOG recognized
gains on mark-to-market commodity derivative contracts of $98
million, of which $67 million were realized gains which were
netted against a $5 million collar premium payment.
Presented below is a summary of EOG's 2004 natural gas
financial collar contracts and natural gas and crude oil
financial price swap contracts as of December 31, 2003 with
prices expressed in dollars per million British thermal units
($/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. The total fair value of the natural gas financial
collar contracts and natural gas and crude oil financial price
swap contracts at December 31, 2003 was a negative $38 million.
Natural Gas Financial Collar Contracts Financial Price Swap Contracts
Floor Price Ceiling Price Natural Gas Crude Oil
Floor Weighted Ceiling Weighted Weighted Weighted
Volume Range Average Range Average Volume Average Volume Average
Month(1) (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu) (Bbld) ($/Bbl)
Jan 330,000 $5.06 - 5.88 $5.38 $5.86 - 6.69 $6.29 30,000 $5.57 4,000 $30.61
Feb 330,000 5.02 - 5.78 5.31 5.82 - 6.62 6.24 30,000 5.50 4,000 30.12
Mar 330,000 4.93 - 5.53 5.16 5.73 - 6.40 6.10 30,000 5.37 4,000 29.58
Apr 375,000 4.47 - 4.71 4.59 4.93 - 5.30 5.13 30,000 4.89 4,000 29.08
May 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 4,000 28.66
Jun 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 4,000 28.27
Jul 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 3,000 27.91
Aug 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 2,000 28.11
Sep 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.78 -- --
Oct 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 -- --
(1) The collar contracts for January 2004 to March 2004 were
purchased at a total premium of $3 million or $0.10 per
MMBtu. The collar contracts for April 2004 to October 2004
were purchased without a premium.
The following table summarizes the estimated fair value of
financial instruments and related transactions at December 31,
2003 and 2002 (in millions):
2003 2002
Carrying Estimated Carrying Estimated
Amount Fair Value(1) Amount Fair Value(1)
Long-Term Debt(2) $1,109 $1,175 $1,145 $1,225
NYMEX-Related Commodity Market Positions (38) (38) (6) (6)
(1) Estimated fair values have been determined by using
available market data and valuation methodologies. Judgment is
necessarily required in interpreting market data and the use
of different market assumptions or estimation methodologies
may affect the estimated fair value amounts.
(2) See Note 2 "Long-Term Debt."
Credit Risk. While notional contract amounts are used to
express the magnitude of commodity price and interest rate swap
agreements, the amounts potentially subject to credit risk, in
the event of nonperformance by the other parties, are
substantially smaller. EOG evaluates its exposure to all
counterparties on an ongoing basis, including those arising from
physical and financial transactions. In some instances, EOG
requires collateral, parent guarantees or letters of credit to
minimize credit risk. At December 31, 2003, EOG's net accounts
receivable balance related to North American natural gas, crude
oil and condensate sales included receivables from a major
integrated oil and gas company and a major utility company,
which constituted 14% and 11%, respectively, of the total
balance. The related amounts were collected during early 2004.
The amount due from the major utility company at December 31,
2002, which approximated 13% of the North American net accounts
receivable balance, was collected during early 2003. No other
individual purchaser accounted for 10% or more of the North
American net accounts receivable balance at December 31, 2003 and
2002. At December 31, 2003, EOG had an allowance for doubtful
accounts of $21 million, of which $19 million is associated with
the Enron bankruptcies recorded in December 2001.
Substantially all of EOG's accounts receivable at
December 31, 2003 and 2002 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 or other credit enhancements from a
customer or joint interest owner, EOG analyzes the entity's net
worth, cash flows, earnings, and credit ratings. Receivables are
generally not collateralized. Historical credit losses incurred
on receivables by EOG have been immaterial except for those
associated with the Enron bankruptcies which were recorded in
December 2001.
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 2003, 2002 and 2001, such
reviews indicated that unamortized capitalized costs of certain
properties were higher than their expected undiscounted future
cash flows due primarily to downward reserve revisions for
certain producing fields. As a result, during 2003, EOG recorded
in Impairments pre-tax charges of $21 million and $4 million in
the United States and Canada operating segments, respectively.
During 2002 and 2001, EOG recorded in Impairments pre-tax charges
of $30 million and $39 million, respectively, 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's
risk-adjusted discount rate. Amortization expenses of
acquisition costs of unproved properties, including amortization
of capitalized interest, were $64 million, $38 million and $40
million for 2003, 2002 and 2001, respectively.
14. Accounting for Asset Retirement Obligations
EOG adopted SFAS No. 143 - "Accounting for Asset Retirement
Obligations" on January 1, 2003. The impact of adopting the
statement resulted in an after-tax charge of $7.1 million, which
was reported in the first quarter of 2003 as cumulative effect of
change in accounting principle. The following table presents the
reconciliation of the beginning and ending aggregate carrying
amount of short-term and long-term legal obligations associated
with the retirement of oil and gas properties pursuant to SFAS
No. 143 for 2003 (in thousands):
Asset Retirement Obligations
Short-Term Long-Term Total
Balance at December 31, 2002 $ - $ - $ -
Carrying Amount at Adoption 6,384 92,097 98,481
Liabilities Incurred 1,364 11,295 12,659
Liabilities Settled (2,699) (1,144) (3,843)
Accretion 140 4,740 4,880
Foreign Currency Translation 131 2,128 2,259
Balance at December 31, 2003 $5,320 $109,116 $114,436
Pro forma net income and earnings per share are not
presented for the comparable period in 2002 because the pro forma
application of SFAS No. 143 to the prior period would not result
in pro forma net income and earnings per share materially
different from the actual amounts reported for the period in the
accompanying Consolidated Statements of Income.
15. Investment in Caribbean Nitrogen Company Limited and
Nitrogen (2000) Unlimited
EOG, through certain wholly-owned subsidiaries, owns equity
interests in two Trinidadian companies: Caribbean Nitrogen
Company Limited (CNCL) and Nitrogen (2000) Unlimited (N2000).
During the first quarter of 2003, EOG completed separate share
sale agreements whereby a portion of the EOG subsidiaries'
shareholdings in CNCL and N2000 was sold to a third party energy
company. The sale left EOG with equity interests of
approximately 12% in CNCL and 27% in N2000 and did not result in
any gain or loss.
The other shareholders in CNCL are subsidiaries of
Ferrostaal AG, Duke Energy, Halliburton, Koch Industries, Inc.
and CL Financial Ltd. At December 31, 2003, investment in CNCL
was approximately $14 million. CNCL commenced production in June
2002, and at December 31, 2003, was producing approximately 1,950
metric tons of ammonia daily. At December 31, 2003, CNCL had a
long-term debt balance of approximately $218 million, which is
non-recourse to CNCL's shareholders. EOG will be liable for its
share of any post-completion deficiency funds loans to fund the
costs of operation, payment of principal and interest to the
principal creditor and other cash deficiencies of CNCL up to $30
million, approximately $4 million of which is net to EOG's
interest. The Shareholders' Agreement requires the consent of
the holders of 90% or more of the shares to take certain material
actions. Accordingly, given its current level of equity
ownership, EOG is able to exercise significant influence over the
operating and financial policies of CNCL and therefore, it
accounts for the investment using the equity method. During
2003, EOG recognized equity income of $3.7 million.
The other shareholders in N2000 are subsidiaries of
Ferrostaal AG, Halliburton, Koch Industries, Inc. and CL
Financial Ltd. At December 31, 2003, investment in N2000 was
approximately $20 million. N2000 is constructing an ammonia
plant in Trinidad, at an expected cost of approximately $320
million, and is expected to commence production in the third
quarter 2004. At December 31, 2003, N2000 had a long-term debt
balance of approximately $172 million, which is non-recourse to
N2000's shareholders. EOG will be liable for its share of any pre-
completion deficiency funds loans to fund plant cost overruns up
to $15 million, approximately $4 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
$8 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.
16. Property Acquisitions
On October 1, 2003, a Canadian subsidiary of EOG closed an
asset purchase of natural gas properties in the Wintering Hills,
Drumheller East and Twining areas of southeast Alberta from a
subsidiary of Husky Energy Inc. for approximately US $320
million. These properties are essentially adjacent to existing
EOG operations or are properties in which EOG already has a
working interest. The transaction was partially funded by
commercial paper borrowings of US $140.5 million on October 1,
2003. The remainder of the purchase price, US $179.5 million,
was funded by EOG's available cash balance. Subsequent to the
closing, the purchase price was reduced by exercised preferential
rights on the properties which totaled approximately US $5
million. In late December 2003, a Canadian subsidiary of EOG
closed another property acquisition for US $46 million.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(In Thousands Except Per Share Amounts Unless Otherwise Indicated)
(Unaudited Except for Results of Operations for Oil and Gas
Producing Activities)
Oil and Gas Producing Activities
The following disclosures are made in accordance with SFAS
No. 69 - "Disclosures about Oil and Gas Producing Activities":
Oil and Gas Reserves. Users of this information should be
aware that the process of estimating quantities of "proved,"
"proved developed" and "proved undeveloped" crude oil and natural
gas reserves is very complex, requiring significant subjective
decisions in the evaluation of all available geological,
engineering and economic data for each reservoir. The data for a
given reservoir may also change substantially over time as a
result of numerous factors including, but not limited to,
additional development activity, evolving production history, and
continual reassessment of the viability of production under
varying economic conditions. Consequently, material revisions
(upward or downward) to existing reserve estimates may occur from
time to time. Although every reasonable effort is made to ensure
that reserve estimates reported represent the most accurate
assessments possible, the significance of the subjective
decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other
estimates presented in connection with financial statement
disclosures.
Proved reserves represent estimated quantities of natural
gas, crude oil, condensate, and natural gas liquids that
geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known
reservoirs under economic and operating conditions existing at
the time the estimates were made.
Proved developed reserves are proved reserves expected to be
recovered, through wells and equipment in place and under
operating methods being utilized at the time the estimates were
made.
Proved undeveloped reserves are reserves that are expected
to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required
for completion. Reserves on undrilled acreage are limited to
those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be
demonstrated with certainty that there is continuity of
production from the existing productive formation. Estimates for
proved undeveloped reserves are not attributed to any acreage for
which an application of fluid injection or other improved
recovery technique is contemplated, unless such techniques have
been proved effective by actual tests in the area and in the same
reservoir.
Canadian provincial royalties are determined based on a
graduated percentage scale which varies with prices and
production volumes. Canadian reserves, as presented on a net
basis, assume prices and royalty rates in existence at the time
the estimates were made, and EOG's estimate of future production
volumes. Future fluctuations in prices, production rates, or
changes in political or regulatory environments could cause EOG's
share of future production from Canadian reserves to be
materially different from that presented.
Estimates of proved and proved developed reserves at
December 31, 2003, 2002 and 2001 were based on studies performed
by the engineering staff of EOG for reserves in the United
States, Canada, Trinidad and the United Kingdom. Opinions by
DeGolyer and MacNaughton (D&M), independent petroleum
consultants, for the years ended December 31, 2003, 2002 and 2001
covered producing areas containing 72%, 73% and 71%,
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, 2003 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, 2003, and the changes in the net
proved reserves for each of the three years in the period then
ended as estimated by the engineering staff of EOG.
NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
United United
States Canada Trinidad Kingdom TOTAL
NET PROVED RESERVES
Natural Gas (Bcf)(1)
Net proved reserves at December 31, 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
Revisions of previous estimates (24.9) (18.5) (74.9) -- (118.3)
Purchases in place 43.9 361.0 -- -- 404.9
Extensions, discoveries and other additions 345.5 118.3 129.3 59.2 652.3
Sales in place (30.8) -- -- -- (30.8)
Production (238.3) (60.2) (55.4) -- (353.9)
Net proved reserves at December 31, 2003 2,101.6 1,178.5 1,305.5 59.2 4,644.8
United United
States Canada Trinidad Kingdom TOTAL
Liquids (MBbl)(2)
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
Revisions of previous estimates 1,487 214 (1,120) -- 581
Purchases in place 738 1,379 -- -- 2,117
Extensions, discoveries and other additions 15,669 598 1,212 84 17,563
Sales in place (344) -- -- -- (344)
Production (7,897) (1,091) (881) -- (9,869)
Net proved reserves at December 31, 2003 73,008 8,266 13,905 84 95,263
Bcf Equivalent (Bcfe)(1)
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
Revisions of previous estimates (15.9) (17.2) (81.7) -- (114.8)
Purchases in place 48.3 369.3 -- -- 417.6
Extensions, discoveries and other additions 439.6 121.8 136.5 59.7 757.6
Sales in place (32.9) -- -- -- (32.9)
Production (285.7) (66.7) (60.7) -- (413.1)
Net proved reserves at December 31, 2003 2,539.7 1,228.1 1,388.8 59.7 5,216.3
United
States Canada Trinidad TOTAL
NET PROVED DEVELOPED RESERVES
Natural Gas (Bcf) (1)
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
December 31, 2003 1,749.3 889.2 429.9 3,068.4
Liquids (MBbl) (2)
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
December 31, 2003 56,321 7,995 5,229 69,545
Bcf Equivalents (Bcfe) (1)
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
December 31, 2003 2,087.3 937.2 461.2 3,485.7
(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, 2003 and 2002:
2003 2002
Proved properties (1) $ 7,990,675 $ 6,527,716
Unproved properties 198,387 222,379
Total 8,189,062 6,750,095
Accumulated depreciation, depletion
and amortization (3,940,145) (3,428,547)
Net capitalized costs $ 4,248,917 $ 3,321,548
(1) The 2003 proved properties amount includes asset
retirement obligations of $85 million as a result of the
adoption of SFAS No. 143 - "Accounting for Asset Retirement
Obligations" on January 1, 2003.
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 additions to exploration wells
including those in progress and exploration expenses.
Development costs include additions to production facilities and
equipment and additions to development wells including those in
progress.
The following tables set forth costs incurred related to EOG's oil
and gas activities for the years ended December 31:
United United
States Canada Trinidad Kingdom Other TOTAL
2003
Acquisition Costs of Properties
Unproved $ 43,890 $ 14,536 $ 172 $ -- $ -- $ 58,598
Proved 18,347 386,532 -- -- -- 404,879
Subtotal 62,237 401,068 172 -- -- 463,477
Exploration Costs 145,104 15,429 20,517 20,958 4,664 206,672
Development Costs 480,257 145,539 23,140 2,812 -- 651,748
Subtotal 687,598 562,036 43,829 23,770 4,664 1,321,897
Asset Retirement Costs (1) 8,167 3,552 -- -- -- 11,719
Total $695,765 $565,588 $43,829 $23,770 $4,664 $1,333,616
2002
Acquisition Costs of Properties
Unproved $ 28,232 $ 4,754 $ 5,629 $ -- $ -- $ 38,615
Proved 22,589 48,487 -- -- -- 71,076
Subtotal 50,821 53,241 5,629 -- -- 109,691
Exploration Costs 120,058 25,866 18,117 -- 2,384 166,425
Development Costs 423,436 107,952 13,600 -- -- 544,988
Subtotal 594,315 187,059 37,346 -- 2,384 821,104
Deferred Income Tax Gross Up -- 14,938 -- -- -- 14,938
Total (2) $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 (2) $860,142 $219,554 $74,664 $ -- $8,739 $1,163,099
(1) Asset Retirement Costs do not include the cumulative effect of
adoption. The Asset Retirement Costs for the United States are netted
with gains recognized upon settlement of asset retirement obligations
of $1 million.
(2) Pro forma total expenditures for 2002 and 2001 are not presented as
the pro forma application of SFAS No. 143 to the prior periods would
not result in pro forma total expenditures materially different from
the actual amounts reported.
Results of Operations for Oil and Gas Producing Activities(1). The
following tables set forth results of operations for oil and gas
producing activities for the years ended December 31:
United United
States Canada Trinidad Kingdom Other(2) TOTAL
2003
Natural Gas, Crude Oil
and Condensate Revenues $1,410,946 $309,336 $100,112 $ -- $ -- $1,820,394
Other, Net 4,613 82 -- -- -- 4,695
Total 1,415,559 309,418 100,112 -- -- 1,825,089
Exploration Expenses 65,885 5,726 3,997 739 11 76,358
Dry Hole Expenses 20,706 4,139 7,890 8,421 -- 41,156
Production Costs 219,447 58,249 11,363 51 2 289,112
Impairments 81,661 7,473 -- -- (1) 89,133
Depreciation, Depletion and Amortization 359,439 66,334 16,070 -- -- 441,843
Income (Loss) before Income Taxes 668,421 167,497 60,792 (9,211) (12) 887,487
Income Tax Provision (Benefit) 239,534 61,928 24,661 (3,673) (5) 322,445
Results of Operations $ 428,887 $105,569 $ 36,131 $(5,538) $ (7) $ 565,042
2002
Natural Gas, Crude Oil
and Condensate Revenues $ 891,991 $170,875 $ 79,551 $ -- $ 21 $1,142,438
Other, Net 2,521 (1,769) -- -- -- 752
Total 894,512 169,106 79,551 -- 21 1,143,190
Exploration Expenses 52,830 5,529 1,656 152 61 60,228
Dry Hole Expenses 26,107 20,642 -- -- -- 46,749
Production Costs 186,041 48,261 9,977 64 7 244,350
Impairments 65,813 2,619 -- -- (2) 68,430
Depreciation, Depletion and Amortization 334,318 49,622 14,085 -- 11 398,036
Income (Loss) before Income Taxes 229,403 42,433 53,833 (216) (56) 325,397
Income Tax Provision (Benefit) 82,136 10,319 23,971 (70) (20) 116,336
Results of Operations $ 147,267 $ 32,114 $ 29,862 $ (146) $ (36) $ 209,061
2001
Natural Gas, Crude Oil
and Condensate Revenues $1,295,945 $191,096 $ 69,141 $ -- $ 21 $1,556,203
Other, Net 1,652 117 -- -- -- 1,769
Total 1,297,597 191,213 69,141 -- 21 1,557,972
Exploration Expenses 57,602 6,101 3,577 -- 187 67,467
Dry Hole Expenses 55,817 6,495 2,828 -- 6,220 71,360
Production Costs 219,518 34,426 10,308 35 -- 264,287
Impairments 76,801 2,355 -- -- -- 79,156
Depreciation, Depletion and Amortization 348,397 31,821 12,031 -- 9 392,258
Income (Loss) before Income Taxes 539,462 110,015 40,397 (35) (6,395) 683,444
Income Tax Provision (Benefit) 198,243 32,663 22,218 -- (2,238) 250,886
Results of Operations $ 341,219 $ 77,352 $ 18,179 $ (35) $(4,157) $ 432,558
(1) Excludes gains or losses on mark-to-market commodity derivative
contracts, interest charges and general corporate expenses for each of
the three years in the period ended December 31, 2003.
(2) Other includes other international operations.
Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves. The following information has been
developed utilizing procedures prescribed by SFAS No. 69 and based on
crude oil and natural gas reserve and production volumes estimated by
the engineering staff of EOG. It may be useful for certain comparison
purposes, but should not be solely relied upon in evaluating EOG or its
performance. Further, information contained in the following table
should not be considered as representative of realistic assessments of
future cash flows, nor should the Standardized Measure of Discounted
Future Net Cash Flows be viewed as representative of the current value
of EOG.
The future cash flows presented below are based on sales prices,
cost rates, and statutory income tax rates in existence as of the date
of the projections. It is expected that material revisions to some
estimates of crude oil and natural gas reserves may occur in the future,
development and production of the reserves may occur in periods other
than those assumed, and actual prices realized and costs incurred may
vary significantly from those used.
Management does not rely upon the following information in making
investment and operating decisions. Such decisions are based upon a
wide range of factors, including estimates of probable as well as proved
reserves, and varying price and cost assumptions considered more
representative of a range of possible economic conditions that may be
anticipated.
The following table sets forth the standardized measure of
discounted future net cash flows from projected production of EOG's
crude oil and natural gas reserves for the years ended December 31:
United United
States Canada Trinidad Kingdom TOTAL
2003
Future cash inflows $14,030,539 $ 6,221,171 $2,995,951 $320,427 $23,568,088
Future production costs (3,026,650) (1,289,592) (449,200) (47,524) (4,812,966)
Future development costs (524,401) (200,324) (228,504) (21,289) (974,518)
Future net cash flows before income taxes 10,479,488 4,731,255 2,318,247 251,614 17,780,604
Future income taxes (3,382,125) (1,376,955) (786,418) (96,896) (5,642,394)
Future net cash flows 7,097,363 3,354,300 1,531,829 154,718 12,138,210
Discount to present value at 10% annual rate (3,393,605) (1,610,085) (778,985) (41,420) (5,824,095)
Standardized measure of discounted
future net cash flows relating
to proved oil and gas reserves $ 3,703,758 $ 1,744,215 $ 752,844 $113,298 $ 6,314,115
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 $ 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
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, 2003:
United United
States Canada Trinidad Kingdom TOTAL
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
Sales and transfers of oil
and gas produced, net of
production costs (1,191,450) (251,070) (88,749) -- (1,531,269)
Net changes in prices and
production costs 1,334,817 422,754 294,570 -- 2,052,141
Extensions, discoveries,
additions and improved
recovery net of related costs 916,653 227,632 93,754 182,581 1,420,620
Development costs incurred 103,200 22,600 23,100 -- 148,900
Revisions of estimated
development cost (34,688) (45,591) (29,415) -- (109,694)
Revisions of previous quantity
estimates (35,537) (34,700) (65,239) -- (135,476)
Accretion of discount 376,431 120,032 73,237 -- 569,700
Net change in income taxes (520,575) (240,253) (145,698) (69,283) (975,809)
Purchases of reserves in place 94,482 547,011 -- -- 641,493
Sales of reserves in place (63,136) -- -- -- (63,136)
Changes in timing and other (51,094) 36,834 91,470 -- 77,210
December 31, 2003 $3,703,758 $1,744,215 $752,844 $113,298 $6,314,115
Unaudited Quarterly Financial Information
Quarter Ended
Mar 31 Jun 30 Sep 30 Dec 31
2003
Net Operating Revenues $464,669 $424,754 $458,724 $396,528
Operating Income $226,129 $176,868 $193,312 $101,005
Income Before Income Taxes $210,963 $165,741 $179,604 $ 97,568
Income Tax Provision 74,407 56,950 62,185 23,058
Net Income Before Cumulative Effect
of Change in Accounting Principle 136,556 108,791 117,419 74,510
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax (7,131) - - -
Net Income 129,425 108,791 117,419 74,510
Preferred Stock Dividends 2,758 2,758 2,758 2,758
Net Income Available to Common $126,667 $106,033 $114,661 $ 71,752
Net Income per Share
Basic (1)
Net Income Available to Common Before
Cumulative Effect of Change in
Accounting Principle $ 1.17 $ 0.93 $ 1.00 $ 0.62
Cumulative Effect of Change in
Accounting Principle, Net of Income Tax (0.06) - - -
Net Income Available to Common $ 1.11 $ 0.93 $ 1.00 $ 0.62
Diluted (1)
Net Income Available to Common Before
Cumulative Effect of Change in
Accounting Principle $ 1.15 $ 0.91 $ 0.99 $ 0.61
Cumulative Effect of Change in
Accounting Principle, Net of Income Tax (0.06) - - -
Net Income Available to Common $ 1.09 $ 0.91 $ 0.99 $ 0.61
Average Number of Common Shares
Basic 114,441 114,382 114,616 114,893
Diluted 116,224 116,131 116,370 117,209
2002
Net Operating Revenues $186,563 $290,163 $279,879 $338,077
Operating Income (Loss) $(20,646) $ 69,300 $ 61,710 $ 70,613
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
(1) The sum of quarterly net income (loss) 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 30, 2004
23.3 Consent of Deloitte & Touche LLP