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Management’s Responsibility for Financial Reporting Report of Independent Registered Public Accountanting Firm Consolidated Statements of Income & Comprehensive Income Consolidated Balance Sheets Consolidated Statements of Shareholders’ Equity Consolidated Statements of Cash Flows Notes to Consolidated Financial Statements Supplemental Information to Consolidated Financial Statements Selected Financial Data Quarterly Stock Data and Related Shareholder Matters Reconciliation Schedules Certifications & Glossary of Terms Officers and Directors Shareholder Information |
RESULTS OF OPERATIONS Net Operating Revenues  2004 compared to 2003. Wellhead natural gas revenues for 2004 increased $307 million, or 20%, to $1,842 million from $1,535 million for 2003 due to increases in natural gas deliveries ($134 million) and the composite average wellhead natural gas price ($173 million). The composite average wellhead natural gas price increased 10% to $4.86 per Mcf for 2004 from $4.40 per Mcf in 2003. Natural gas deliveries increased 81 MMcf per day, or 8%, to 1,036 MMcf per day for 2004 from 955 MMcf per day in 2003, due to a 47 MMcf per day, or 28%, increase in Canada; a 34 MMcf per day, or 22%, increase in Trinidad; and a 7 MMcf per day increase in the United Kingdom due to commencement of production in August 2004, partially offset by a 7 MMcf per day, or 1% decline in the United States. The increased deliveries in Canada (47 MMcf per day) were attributable to property acquisitions completed in the fourth quarter of 2003 and additional production related to post acquisition drilling. The increase in Trinidad was attributable to the increased production from the U(a) block (22 MMcf per day), which began supplying natural gas in mid-2004 to the N2000 ammonia plant and commencement of production from the Parula wells on the SECC block in February 2004 (12 MMcf per day). Wellhead crude oil and condensate revenues increased $149 million, or 59%, to $403 million from $254 million, as compared to 2003, due to increases in both the composite average wellhead crude oil and condensate price ($103 million) and the wellhead crude oil and condensate deliveries ($46 million). The composite average wellhead crude oil and condensate price for 2004 was $40.22 per barrel, compared to $29.92 per barrel for 2003. Wellhead crude oil and condensate deliveries increased 4.2 MBbl per day, or 18%, to 27.4 MBbl per day from 23.2 MBbl per day for 2003. The increase was mainly due to production from new wells in the United States (2.6 MBbl per day) and higher production in Trinidad from the Parula wells (0.8 MBbl per day) and from the U(a) block as a result of new production (0.4 MBbl per day). Natural gas liquids revenues were $26 million higher than a year ago primarily due to increases in deliveries ($14 million) and the composite average price ($12 million). During 2004, EOG recognized losses on mark-to-market commodity derivative contracts of $33 million, which included realized losses of $82 million and collar premium payments of $1 million. During 2003, EOG recognized losses on mark-to-market commodity derivative contracts of $80 million, which included realized losses of $45 million and collar premium payments of $3 million. 2003 compared to 2002. Wellhead natural gas revenues for 2003 increased $657 million, or 75%, due to increases in the composite average wellhead natural gas price and natural gas deliveries. The composite average wellhead price for natural gas increased 69% to $4.40 per Mcf for 2003 from $2.60 per Mcf in 2002. Natural gas deliveries increased to 955 MMcf per day for 2003 from 924 MMcf per day for the comparable period in 2002. The overall increase in natural gas deliveries was primarily due to an increase in Canada of 7% to 165 MMcf per day and an increase in Trinidad of 13% to 152 MMcf per day in 2003. The 7%, or 11 MMcf per day, increase in Canada was primarily attributable to a major property acquisition in the fourth quarter. The 13%, or 17 MMcf per day, increase in Trinidad was attributable to a full year of sales to the CNCL ammonia plant versus only six months of sales in 2002. Natural gas marketing activities increased natural gas revenues by $2 million and $37 million for 2003 and 2002, respectively. Wellhead crude oil and condensate revenues increased $45 million, or 22%, due to increases in the composite average wellhead crude oil and condensate price. The composite average wellhead crude oil and condensate price for 2003 was $29.92 per barrel, compared to $24.56 per barrel for 2002. Natural gas liquids revenues were $11 million higher than a year ago primarily due to a 50% increase in the composite average price and a 3% increase in deliveries. During 2003, EOG recognized losses on mark-to-market commodity derivative contracts of $80 million, which included realized losses of $45 million and collar premium payments of $3 million. During 2002, EOG recognized losses on mark-to-market commodity derivative contracts of $49 million, which included realized losses of $21 million and a $2 million collar premium payment. Operating and Other Expenses  The higher per-unit rates of lease and well, DD&A and taxes other than income for 2004 compared to 2003 were due primarily to the reasons set forth below. Lease and well expenses of $271 million were $58 million higher than 2003 due primarily to a general increase in service costs related to increased operating activities, including an increase in the number of wells, in the United States ($18 million), Canada ($16 million), and Trinidad ($1 million); increased transportation related costs in the United States ($14 million), Canada ($2 million) and the United Kingdom ($2 million); and changes in the Canadian exchange rate ($5 million). Depreciation, depletion and amortization (DD&A) expenses of $504 million increased $63 million from 2003 due primarily to increased production in Canada ($18 million), the United States ($10 million), and Trinidad ($4 million); the commencement of production in the United Kingdom ($2 million); increased DD&A rates in the United States due to a gradual proportional increase in production from higher cost properties ($13 million); increased DD&A rates in Canada mainly from developing acquired proved reserves ($8 million); and changes in the Canadian exchange rate ($7 million). General and administrative (G&A) expenses of $115 million were $15 million higher than 2003 due primarily to expanded operations. Taxes other than income of $134 million were $48 million higher than 2003 due primarily to a decrease in credits taken against severance taxes resulting from the qualification of additional wells for a Texas high cost gas severance tax exemption ($19 million); an increase as a result of higher wellhead revenues in the United States ($13 million), Trinidad ($2 million) and Canada ($1 million); higher property taxes as a result of higher property valuation in the United States ($6 million); the results of a production tax audit lawsuit in the first quarter of 2004 ($5 million); and an increase in the number of wells and facilities in Canada ($2 million). Exploration costs of $94 million were $18 million higher than 2003 due primarily to increased geological and geophysical expenditures in the United States ($6 million), Canada ($3 million), the United Kingdom ($3 million) and Trinidad ($1 million); and increased exploration administrative expenses across EOG ($4 million). Impairments of $82 million were $8 million lower than 2003 due primarily to lower amortization of unproved leases in the United States ($10 million), partially offset by higher amortization of unproved leases in Canada ($2 million). Total impairments under Statement of Financial Accounting Standards (SFAS) No. 144 - “Accounting for the Impairment or Disposal of Long-Lived Assets” were $25 million in each of 2004 and 2003. Net interest expense of $63 million was $4 million higher than 2003 due primarily to a slightly higher average debt balance. Other Income (Expense), Net for 2004 included income from equity investments of $11 million, gains on sales of reserves and related assets of $6 million and foreign currency transaction losses of $7 million as a result of applying the changes in the Canadian exchange rate to certain intercompany short-term loans that eliminate in consolidation. Income tax provision increased $85 million to $301 million compared to 2003, primarily resulting from higher income before income taxes ($95 million) and an increase in state income taxes ($2 million), offset by lower deferred income taxes associated with the Alberta, Canada corporate tax rate ($5 million) and lower effective foreign income tax rates ($2 million). As a result of these changes, the net effective tax rate for 2004 remained unchanged from the 2003 rate of 33%. In November 2003, Canada enacted legislation reducing the Canadian federal income tax rate for companies in the resource sector from 28% to 27% for 2003, with further reductions to 21% phased in over the next four years. This legislation also made changes to the tax treatment of crown royalties and the resource allowance. Beginning in 2003, Canadian taxpayers are allowed to deduct 10% of actual provincial and other crown royalties. This percentage increases each year through 2007, at which time 100% of crown royalties will be deductible. The resource allowance, a statutory deduction calculated as 25% of adjusted resource profits, will be phased out through 2007, when the deduction will be completely eliminated. 2003 compared to 2002. During 2003, operating expenses of $1,047 million were $133 million higher than the $914 million incurred in 2002. The following table presents the costs per Mcfe for the years ended December 31:  The higher per-unit rates of lease and well, DD&A, G&A and taxes other than income for 2003, compared to 2002 were due primarily to the reasons set forth below. Lease and well expenses of $213 million were $33 million higher than 2002 due primarily to a general increase in service costs related to increased operating activities, including an increase in the number of wells, in the United States ($15 million) and Canada ($4 million); increased lease and well administrative expenses in the United States ($7 million); and changes in the Canadian exchange rate ($6 million). DD&A expenses of $442 million increased $44 million from the prior year due primarily to more relative production from higher cost properties in the United States ($20 million) and Canada ($5 million); increased production in Canada ($3 million) and Trinidad ($2 million); and changes in the Canadian exchange rate ($8 million). Also, included in DD&A expenses for 2003 was $5 million of accretion expense related to SFAS No. 143 - "Accounting for Asset Retirement Obligations." G&A expenses of $100 million were $11 million higher than the period a year ago due primarily to expanded operations ($9 million) and increased insurance expense ($5 million), partially offset by decreased legal costs ($3 million). Taxes other than income of $86 million were $14 million higher than the prior year period primarily due to an increase of approximately $35 million as a result of increased wellhead revenues as previously discussed, partially offset by $24 million of severance tax credits from the qualification of wells for a Texas high cost gas severance tax exemption. Exploration costs of $76 million were $16 million higher than a year ago due primarily to an increase in technical staff costs across EOG ($7 million) and increased geological and geophysical expenditures in the United States ($5 million) and Trinidad ($3 million). Impairments increased $21 million to $89 million compared to a year ago due to higher amortization of unproved leases in the United States ($25 million). Total impairments under SFAS No. 144 - “Accounting for the Impairment or Disposal of Long-Lived Assets” for 2003 and 2002 were $25 million and $30 million, respectively. Other Income (Expense), Net for 2003 included foreign currency transaction gains of $9 million as a result of applying the changes in the Canadian exchange rate to certain intercompany short-term loans that eliminate in consolidation and income from equity investments of $4 million. Income tax provision increased $184 million to $217 million for 2003 as compared to 2002 primarily resulting from higher income before income taxes for federal ($187 million) and state ($4 million), expiration of the tight gas sands federal income tax credit as of December 31, 2002 ($4 million), and higher effective foreign income tax rates ($4 million), primarily offset by net tax benefit associated with the Canadian tax law change ($14 million). |
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