EX-99 14 ex-99_1.txt CURRENT REPORT ON FORM 8-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report: February 20, 2003 EOG RESOURCES, INC. (Exact name of registrant as specified in its charter) Delaware 1-9743 47-0684736 (State or other (Commission File (I.R.S. Employer jurisdiction Number) Identification No.) of incorporation or organization) 333 Clay Street Suite 4200 Houston, Texas 77002 (Address of principal executive offices) (Zip code) 713/651-7000 (Registrant's telephone number, including area code) EOG RESOURCES, INC. Item 7. Financial Statements and Exhibits. (a) Financial Statements of EOG Resources, Inc. Financial Statements of EOG Resources, Inc. and its Consolidated Subsidiaries for the fiscal year ended December 31, 2002, including Reports of Independent Public Accountants. (b) Exhibits. 23.1 Consent of DeGolyer and MacNaughton. 23.2 Opinion of DeGolyer and MacNaughton dated January 31, 2003. 23.3 Consent of Deloitte & Touche LLP. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. EOG RESOURCES, INC. (Registrant) Date: February 20, 2003 By: /s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President, Accounting & Land Administration (Principal Accounting Officer) EOG RESOURCES, INC. TABLE OF CONTENTS Page No. Management's Discussion and Analysis of Financial Condition and Results of Operations 4 Management's Responsibility for Financial Reporting 14 Reports of Independent Public Accountants 15 Consolidated Statements of Income and Comprehensive Income for the years ended December 31, 2002, 2001 and 2000 17 Consolidated Balance Sheets, December 31, 2002 and 2001 18 Consolidated Statements of Shareholders' Equity for the years ended December 31, 2002, 2001 and 2000 19 Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000 20 Notes to Consolidated Financial Statements 21 Supplemental Information to Consolidated Financial Statements 37 Exhibits Exhibit 23.1 - Consent of DeGolyer and MacNaughton 47 Exhibit 23.2 - Opinion of DeGolyer and MacNaughton dated January 31, 2003 48 Exhibit 23.3 - Consent of Deloitte & Touche LLP 50 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Management's Discussion and Analysis of Financial Condition and Results of Operations The following review of operations for each of the three years in the period ended December 31, 2002 should be read in conjunction with the consolidated financial statements of EOG Resources, Inc. ("EOG") and notes thereto beginning with page 17. Results of Operations Net Operating Revenues. Wellhead volume and price statistics for the specified years were as follows:
Year Ended December 31, 2002 2001 2000 Natural Gas Volumes (MMcf per day)(1) United States 635 680 654 Canada 154 126 129 Trinidad 135 115 125 Total 924 921 908 Average Natural Gas Prices ($/Mcf)(2) United States $2.89 $4.26 $3.96 Canada 2.67 3.78 3.33 Trinidad 1.20 1.22 1.17 Composite 2.60 3.81 3.49 Crude Oil and Condensate Volumes (MBbl per day)(1) United States 18.8 22.0 22.8 Canada 2.1 1.7 2.1 Trinidad 2.4 2.1 2.6 Total 23.3 25.8 27.5 Average Crude Oil and Condensate Prices ($/Bbl)(2) United States $24.79 $25.06 $29.68 Canada 23.62 22.70 27.76 Trinidad 23.58 24.14 30.14 Composite 24.56 24.83 29.57 Natural Gas Liquids Volumes (MBbl per day)(1) United States 2.9 3.5 4.0 Canada 0.8 0.5 0.7 Total 3.7 4.0 4.7 Average Natural Gas Liquids Prices ($/Bbl)(2) United States $14.76 $17.17 $20.45 Canada 11.17 15.05 16.75 Composite 14.05 16.89 19.87 Natural Gas Equivalent Volumes (MMcfe per day)(3) United States 765 833 814 Canada 171 139 146 Trinidad 150 128 141 Total 1,086 1,100 1,101 Total Bcfe(3) Deliveries 396 401 403 ___________________ (1) Million cubic feet per day or thousand barrels per day, as applicable. (2) Dollars per thousand cubic feet or per barrel, as applicable. (3) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and natural gas liquids.
2002 compared to 2001. During 2002, net operating revenues decreased $560 million to $1,095 million. Total wellhead revenues of $1,105 million decreased by $435 million, or 28%, as compared to 2001. Wellhead natural gas revenues for 2002 decreased approximately $405 million primarily due to a general decline in average wellhead natural gas prices, partially offset by an increase in natural gas deliveries in Canada and Trinidad. The average wellhead price for natural gas decreased 32% to $2.60 per Mcf for the year 2002 compared to $3.81 per Mcf in 2001. Natural gas deliveries increased slightly to 924 MMcf per day for the year of 2002 compared to 921 MMcf per day for the comparable period a year ago. The overall increase in natural gas deliveries was due to an increase in Canada of 22% to 154 MMcf per day in 2002 and an increase in Trinidad of 17% to 135 MMcf per day in 2002. The higher production in 2002 was attributable to drilling activities and strategic property acquisitions in Canada, and the commencement of production from the U(a) Block in Trinidad. This increase was partially offset by the overall decrease in production in the United States Divisions of 7% or 45 MMcf per day. Wellhead crude oil and condensate revenues decreased approximately $25 million, due primarily to a decline in domestic crude oil and condensate deliveries with essentially flat wellhead crude oil and condensate prices. The average wellhead crude oil and condensate price for 2002 was $24.56 per barrel compared to $24.83 per barrel for 2001. Crude oil and condensate deliveries decreased 10% to 23.3 MBbl per day for the year of 2002 compared to 25.8 MBbl per day in 2001. The decrease in volumes was primarily due to decreased crude oil and condensate production in the Offshore, Midland and Tyler Divisions as a result of a natural decline in production. This natural decline in production was partially offset by increased production in Trinidad due to the commencement of production from the U(a) Block, and drilling activities and strategic property acquisitions in Canada. Natural gas liquids revenues were $6 million lower than a year ago primarily due to a decrease in prices of 17% and a decrease in deliveries of 8%. During 2002, EOG recognized losses on mark-to-market commodity derivative contracts of $49 million, of which $23 million were realized losses. Other marketing activities associated with sales and purchases of natural gas transactions increased net operating revenues by $37 million and $16 million in 2002 and 2001, respectively. 2001 compared to 2000. During 2001, net operating revenues increased $165 million to $1,655 million. Total wellhead revenues of $1,540 million increased by $49 million, or 3%, as compared to 2000. Average wellhead natural gas prices for 2001 were approximately 9% higher than the comparable period in 2000, increasing net operating revenues by $110 million. Average wellhead crude oil and condensate prices were 16% lower, decreasing net operating revenues by $45 million. North America wellhead natural gas deliveries were approximately 3% higher than the comparable period in 2000. The increase in volumes was primarily due to increased production in the Midland and Pittsburgh divisions, partially offset by decreased production in the Denver and Corpus Christi Divisions and the implementation of a production moderation strategy in late third quarter. Combined with reduced production in Trinidad, the overall natural gas production was 1% higher than the comparable period in 2000, increasing net operating revenues by $14 million. Wellhead crude oil and condensate volumes were 6% lower than in 2000, decreasing net operating revenues by $20 million. The decrease in wellhead crude oil and condensate volumes is primarily due to decreased deliveries worldwide. Natural gas liquids prices and deliveries were both approximately 15% lower than 2000, decreasing net operating revenues by $4 million and $5 million, respectively. During 2001, EOG recognized mark-to-market gains on commodity contracts of $98 million, of which $62 million were realized gains. Gains on sales of reserves and related assets and other, net totaled a gain of $1 million during 2001 compared to a gain of $9 million in 2000. The difference is due primarily to a $7 million gain on sales of certain North America properties in 2000. Other marketing activities associated with sales and purchases of natural gas transactions increased net operating revenues by $16 million during 2001, compared to a $10 million reduction in 2000. Operating Expenses 2002 compared to 2001. During 2002, operating expenses of $914 million were approximately $66 million lower than the $980 million incurred in 2001. Dry hole costs of $47 million decreased $25 million from 2001. Taxes other than income decreased $23 million to $72 million as compared to 2001 due to decreased wellhead revenue in North America resulting in lower production taxes and decreased ad valorem taxes. Impairments decreased $11 million to $68 million primarily as a result of improved value-to-cost relationship on a field by field basis and decreased amortization of unproved leases in 2002. Exploration costs of $60 million were $7 million lower than a year ago primarily due to decreased geological and geoscience expenditures. Lease and well expenses increased $4 million to $179 million compared to a year ago primarily due to continually expanding operations and increases in production activity in Canada, partially offset by a fewer number of workovers in the Offshore Division. Depreciation, depletion and amortization ("DD&A") expenses increased $6 million to $398 million primarily due to increased activity in Canada and the Pittsburgh Division along with higher per unit costs related to certain fields in the Denver Division, partially offset by a natural production decline in the Midland, Oklahoma City, Tyler and Offshore Divisions. General and administrative ("G&A") expenses increased $9 million to $89 million primarily due to the settlement of litigation in the second quarter, increased insurance expense and expanded operations. Interest Expense. The increase in net interest expense of $15 million for 2002 as compared to 2001 is primarily due to higher average debt balance for the year of 2002 (see Note 2 to the Consolidated Financial Statements) and the one-time close-out fees associated with the completion of the Section 29 (Tight Gas Sands Federal Income Tax Credits) financing begun in 1999. Per-Unit Costs. The following table presents the operating costs per thousand cubic feet equivalent (Mcfe) for years ended December 31, 2002 and 2001.
Year Ended December 31, 2002 2001 Lease and Well $0.45 $0.44 DD&A 1.00 0.98 G&A 0.22 0.20 Taxes Other than Income 0.18 0.24 Interest Expense 0.15 0.11 Total Per-Unit Costs $2.00 $1.97
The lower per-unit rate of taxes other than income for 2002 compared to 2001 is due primarily to decreased average wellhead natural gas prices. The higher per-unit G&A and interest expense rates for 2002 compared to 2001 are due to reasons delineated in the above G&A and interest expense discussions. Income Taxes. Income tax provision decreased approximately $200 million for 2002 as compared to 2001 primarily as a result of a lower pre-tax income in 2002 and a reduction in the overall foreign effective tax rate. 2001 compared to 2000. During 2001, operating expenses of $980 million, which includes $19 million of charges related to the bankruptcy of Enron and certain of its affiliates, were approximately $187 million higher than the $793 million incurred in 2000. Lease and well expenses increased $35 million to $175 million primarily due to higher production costs, continually expanding operations and increases in production activity in North America. Exploration expenses of $67 million remained essentially flat compared to 2000. Dry hole expenses of $71 million increased $54 million from 2000. Impairments increased $33 million to $79 million primarily as a result of write-down of assets in the United States. DD&A expenses increased $33 million to $392 million primarily due to increased DD&A rates. G&A expenses increased $13 million primarily due to expanded operations. Taxes other than income remained approximately the same as compared to 2000. Total operating costs per unit of production, which include lease and well, DD&A, G&A, taxes other than income and interest expense, increased 9% to $1.97 per Mcfe in 2001 from $1.80 in 2000. This increase is primarily due to higher per-unit rates of lease and well, DD&A and G&A expenses, partially offset by a lower per-unit rate of interest expense. During the fourth quarter of 2001, EOG recorded charges associated with the Enron bankruptcies of $19 million, of which $17 million were related to 2001 and 2002 natural gas and oil derivative contracts. Interest Expense. The decrease in net interest expense of $16 million for 2001 as compared to 2000 is primarily due to lower long-term debt levels during the year. Capital Resources and Liquidity Cash Flow. The primary sources of cash for EOG during the three-year period ended December 31, 2002 included cash generated from operations, proceeds from the sales of selected oil and gas reserves and related assets, funds from new borrowings and proceeds from stock options exercised. Primary cash outflows included funds used in operations, exploration and development expenditures, common stock repurchases and dividends paid to EOG shareholders. Net operating cash flows of $669 million in 2002 decreased approximately $529 million as compared to 2001 primarily due to lower average natural gas and liquids prices partially offset by lower cash operating expenses and lower current income taxes. Changes in working capital and other liabilities decreased operating cash flows by $145 million as compared to 2001 primarily due to changes in accounts receivable, accrued royalties payable and accrued production taxes caused by fluctuation of commodity prices at each yearend. Net investing cash outflows of $873 million in 2002 decreased by $216 million as compared to 2001 due primarily to decreased exploration and development expenditures of $292 million (including producing property acquisitions), partially offset by increased uses of working capital related to investing activities and increased equity investments. Changes in components of working capital associated with investing activities included changes in accounts payable associated with the accrual of exploration and development expenditures and changes in inventories which represent materials and equipment used in drilling and related activities. Cash provided by financing activities in 2002 was $211 million as compared to cash used of $127 million in 2001. Financing activities in 2002 included funds from new borrowings of $289 million, common stock repurchases of $63 million, dividend payments of $29 million and proceeds from stock options exercised of $17 million. New borrowings included $120 million of commercial paper borrowings and $250 million of promissory note issuances, partially offset by a decrease in uncommitted line of credit borrowings of $81 million. Net operating cash flows of $1,197 million in 2001 increased approximately $230 million as compared to 2000 primarily due to higher net operating revenues resulting from higher natural gas prices, net of increased cash operating expenses, and lower current income taxes, partially offset by a lower tax benefit from stock options exercised. Changes in working capital and other liabilities increased operating cash flows by $75 million as compared to 2000 primarily due to changes in accounts receivable, accrued royalties payable and accrued production taxes caused by fluctuation of commodity prices at each yearend. Net investing cash outflows of $1,088 million in 2001 increased by $421 million as compared to 2000 due primarily to increased exploration and development expenditures of $426 million (including producing property acquisitions) and decreased proceeds from sales of reserves and related assets, partially offset by decreased equity investments. Changes in components of working capital associated with investing activities included changes in accounts payable associated with the accrual of exploration and development expenditures and changes in inventories which represent materials and equipment used in drilling and related activities. Cash used in financing activities in 2001 was $127 million as compared to $305 million in 2000. Financing activities in 2001 included repayments of debt of $4 million, common stock repurchases of $127 million and dividend payments of $29 million, partially offset by proceeds from stock options exercised of $31 million. Exploration and Development Expenditures. The table below sets out components of exploration and development expenditures for the years ended December 31, 2002, 2001 and 2000, along with the total budgeted for 2003, excluding acquisitions.
Actual Budgeted 2003 Expenditure Category 2002 2001 2000 (excluding acquisitions) (In Millions) Capital Drilling and Facilities $ 595 $ 722 $ 443 Leasehold Acquisitions 39 76 51 Producing Property Acquisitions 71 168 102 Capitalized Interest 9 9 7 Subtotal 714 975 603 Exploration Costs 60 67 67 Dry Hole Costs 47 71 17 Subtotal 821 1,113 687 $800 - $950 Deferred Income Tax Gross Up 15 50 23 Total $ 836 $1,163 $ 710
Total exploration and development expenditures of $836 million decreased $327 million in 2002 as compared to 2001 primarily due to decreased exploration and development activities in the United States and Trinidad along with fewer strategic property acquisitions, partially offset by increased exploration and development activities in Canada. Included in the 2002 expenditures are $545 million in development, $196 million in exploration, $71 million in property acquisition, $15 million in deferred income tax gross up and $9 million in capitalized interest. Derivative Transactions. During 2002, EOG recognized losses on mark-to-market commodity derivative contracts of $49 million, which included realized losses of $21 million and a $2 million collar premium payment (see Note 11 to the Consolidated Financial Statements). Presented below is a summary of EOG's 2003 natural gas financial collar contracts and natural gas and crude oil financial price swap contracts as of February 19, 2003 with prices expressed in dollars per million British thermal units ($/MMBtu) and in dollars per barrel ($/Bbl), as applicable, and notional volumes in million British thermal units per day (MMBtud) and in barrels per day (Bbld), as applicable. EOG accounts for these collar and swap contracts using mark-to-market accounting.
Natural Gas Financial Collar Contracts Financial Price Swap Contracts Floor Price Ceiling Price Natural Gas Crude Oil Floor Weighted Ceiling Weighted Weighted Weighted Volume Range Average Range Average Volume Average Volume Average Month (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu) (Bbld) ($/Bbl) Jan 50,000 $3.87 $3.87 $6.09 $6.09 -- -- 2,000 $27.34 Feb 125,000 3.76 - 4.30 4.04 5.05 - 6.30 5.87 -- -- 2,000 26.91 Mar 125,000 3.61 - 4.20 3.93 5.00 - 6.20 5.77 100,000 $5.19 4,000 27.96 Apr 125,000 3.59 - 4.02 3.82 4.80 - 6.03 5.33 100,000 4.96 5,000 27.77 May 125,000 3.54 - 3.92 3.74 4.70 - 5.92 5.24 100,000 4.82 5,000 27.04 Jun 125,000 3.56 - 3.89 3.74 4.70 - 5.90 5.25 100,000 4.77 5,000 26.43 Jul 125,000 3.59 - 3.91 3.76 4.73 - 5.91 5.27 100,000 4.77 5,000 25.90 Aug 125,000 3.60 - 3.91 3.76 4.73 - 5.91 5.27 100,000 4.77 5,000 25.49 Sep 125,000 3.60 - 3.89 3.75 4.73 - 5.89 5.26 100,000 4.74 5,000 25.19 Oct 125,000 3.60 - 3.90 3.75 4.73 - 5.90 5.27 100,000 4.74 5,000 24.90 Nov 125,000 3.77 - 4.04 3.90 4.90 - 6.04 5.43 -- -- 5,000 24.70 Dec 125,000 3.92 - 4.18 4.04 5.05 - 6.18 5.57 -- -- 5,000 24.47
Financing. EOG's long-term debt-to-total-capitalization ratio was 40.6% as of December 31, 2002 compared to 34.3% as of December 31, 2001. During 2002, total long-term debt increased to $1,145 million primarily due to capital expenditures exceeding cash flow from operations (see Note 2 to the Consolidated Financial Statements). The estimated fair value of EOG's long-term debt at December 31, 2002 and 2001 was $1,225 million and $838 million, respectively, based upon quoted market prices and, where such prices were not available, upon interest rates currently available to EOG at yearend. EOG's debt is primarily at fixed interest rates. At December 31, 2002, a 1% decline in interest rates would result in a $59 million increase in the estimated fair value of the fixed rate obligations (see Note 11 to the Consolidated Financial Statements). The following table summarizes EOG's contractual obligations at December 31, 2002 (in thousands):
2009 & Contractual Obligations(1) Total 2003 2004 - 2006 2007 - 2008 beyond Long-Term Debt $1,145,132 $ -- $511,180 $273,952 $360,000 Non-cancelable Operating Leases 38,581 11,083 22,755 3,783 960 Drilling Rig Commitments 1,470 1,470 -- -- -- Transportation Service Commitments(2) 37,065 9,255 18,533 5,988 3,289 Total Contractual Obligations $1,222,248 $21,808 $552,468 $283,723 $364,249 (1) See Notes 2 and 7 to Consolidated Financial Statements. (2) Amounts shown are based on current transportation rates and foreign currency exchange rate at December 31, 2002. Management does not believe that any future changes in these rates before the expiration dates of these commitments will have a materially adverse effect on the financial condition or results of operations of EOG.
Shelf Registration. During the third quarter of 2000, EOG filed a shelf registration statement for the offer and sale from time to time of up to $600 million of EOG debt securities, preferred stock and/or common stock. The registration statement was declared effective by the Securities and Exchange Commission on October 27, 2000. As of February 19, 2003, EOG had sold no securities pursuant to this shelf registration. When combined with the unused portion of a previously filed registration statement declared effective in January 1998, these registration statements provide for the offer and sale from time to time of EOG debt securities, preferred stock and/or common stock by EOG in an aggregate amount up to $688 million. Outlook. Natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of future North America natural gas and crude oil price trends, and there remains a rather wide divergence in the opinions held by some in the industry. This divergence in opinion is caused by various factors including the current industrial recession and economic downturn, improvements in the technology used in drilling and completing crude oil and natural gas wells, fluctuations in the availability and utilization of natural gas storage capacity and ever-changing weather patterns. However, the increasing recognition of natural gas as a more environmentally friendly source of energy could result in increases in demand. Being primarily a natural gas producer, EOG is more significantly impacted by changes in natural gas prices than by changes in crude oil and condensate prices. Marketing companies have played an important role in the North American natural gas market. These companies aggregate natural gas supplies through purchases from producers like EOG and then resell the gas to end users, local distribution companies or other buyers. Several of the largest natural gas marketing companies have recently filed for bankruptcy or are currently in financial difficulty, and others are exiting this business. EOG does not believe that this will have a material effect on its ability to market its natural gas production. EOG continues to assess and monitor the credit worthiness of partners to whom it sells its production and where appropriate, to seek new markets. EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in North America. However, in order to diversify its overall asset portfolio and as a result of its overall success realized in Trinidad, EOG anticipates expending a portion of its available funds in the further development of opportunities outside North America. In addition, EOG expects to conduct limited exploratory activity in other areas outside of North America, including the United Kingdom North Sea, and will continue to evaluate the potential for involvement in other exploitation type opportunities. Budgeted 2003 exploration and development expenditures, excluding acquisitions, are in the range of $800 - $950 million, addressing the continuing uncertainty with regard to the future of the North America natural gas and crude oil and condensate price environment. Budgeted expenditures for 2003 are structured to maintain the flexibility necessary under EOG's strategy of funding North America exploration, exploitation, development and acquisition activities primarily from available internally generated cash flow. The level of exploration and development expenditures may vary in 2003 and will vary in future periods depending on energy market conditions and other related economic factors. Based upon existing economic and market conditions, EOG believes net operating cash flow and available financing alternatives in 2003 will be sufficient to fund its net investing cash requirements for the year. However, EOG has significant flexibility with respect to its financing alternatives and adjustment of its exploration, exploitation, development and acquisition expenditure plans if circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to operations in Trinidad, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG. Environmental Regulations. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to protection of the environment, may affect EOG's operations and costs as a result of their effect on natural gas and crude oil exploration, exploitation, development and production operations. In addition, EOG has acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under EOG's control. Under environmental laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. EOG also has acquired or merged with companies that own and operate oil and gas properties. Any obligations or liabilities of these companies under environmental laws would continue as liabilities of the acquired company, or of EOG in the event of a merger, even if the obligations or liabilities resulted from actions that took place before the acquisition or merger. Compliance with such laws and regulations has not had a material adverse effect on EOG's operations or financial condition. It is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program by reason of environmental laws and regulations. However, inasmuch as such laws and regulations are frequently changed, EOG is unable to predict the ultimate cost of compliance. EOG also could incur costs related to the clean up of sites to which it sent regulated substances for disposal and for damages to natural resources or other claims related to releases of regulated substances at such sites. In this regard, EOG has been named as a potentially responsible party in certain proceedings initiated pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act and may be named as a potentially responsible party in other similar proceedings in the future. It is not anticipated that the costs incurred by EOG in connection with the presently pending proceedings will, individually or in the aggregate, have a materially adverse effect on the financial condition or results of operations of EOG. Summary of Significant Accounting Policies Principles of Consolidation. The consolidated financial statements of EOG include the accounts of all domestic and foreign subsidiaries. Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method. All material intercompany accounts and transactions have been eliminated. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications have been made to prior period financial statements to conform with the current presentation. Beginning 2001, the "Impairment of Unproved Oil and Gas Properties" caption on the Consolidated Statements of Income was renamed "Impairments" to include the impairment of long-lived assets as described in Statement of Financial Accounting Standards ("SFAS") No. 121-"Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to Be Disposed of" ("SFAS 121 Impairments"), as superseded by SFAS No. 144-"Accounting for the Impairment or Disposal of Long-Lived Assets." As a result, EOG reclassified all prior periods to reflect such SFAS 121 Impairments in Impairments, instead of DD&A as previously reported. SFAS 121 Impairments reclassified from DD&A to Impairments was $11 million for 2000. Financial Instruments. EOG's financial instruments consist of cash and cash equivalents, marketable securities, accounts receivable, accounts payable and long-term debt. The carrying values of cash and cash equivalents, marketable securities, accounts receivable and accounts payable approximate fair value (see Note 2 to the Consolidated Financial Statements for fair value of long-term debt). Cash and Cash Equivalents. EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less. Oil and Gas Operations. EOG accounts for its natural gas and crude oil exploration and production activities under the successful efforts method of accounting. Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and crude oil, are capitalized. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. Estimated future dismantlement, restoration and abandonment costs (classified as long-term liabilities), net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis. Periodically, or when circumstances indicate that an asset may be impaired, EOG compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on EOG's estimate of future crude oil and natural gas prices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Inventories, consisting primarily of tubular goods and well equipment held for use in the exploration for, and development and production of natural gas and crude oil reserves, are carried at cost with adjustments made from time to time to recognize any reductions in value. Natural gas and liquids revenues are recorded when production is delivered. Additionally, natural gas revenues are recorded on the entitlement method based on EOG's percentage ownership of current production. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold may differ from an owner's ownership percentage. Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable is recorded when overproduction occurs. New Accounting Pronouncements. In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 143-"Accounting for Asset Retirement Obligations" effective for fiscal years beginning after June 15, 2002. SFAS No. 143 requires entities to record the fair value of a liability for legal obligations associated with the retirement of tangible long- lived assets and the associated asset retirement costs. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. Increase in the liability due to passage of time, as a result of applying an interest method of allocation to the amount of the liability at the beginning of a period, is recognized as an increase in the carrying amount of the liability and as an expense classified as an operating item in the statement of income. If the obligation is settled for other than the carrying amount of the liability, a gain or loss is recognized on settlement. EOG adopted the statement on January 1, 2003. The impact of adopting the statement results in an after-tax loss of approximately $6.5 million which will be reported as cumulative adjustment for change in accounting principle in the first quarter of 2003. In April 2002, the FASB issued SFAS No. 145-"Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" effective for financial statements issued on or after May 15, 2002. SFAS No. 145 requires gains and losses on the extinguishment of debt to be classified as income or loss from continuing operations, unless the requirements of Accounting Principles Board Opinion ("APB Opinion") No. 30-"Reporting the Results of Operations - Reporting the effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" are met, upon which the gain or loss would be considered unusual and infrequent and classified as an extraordinary item. Prior to adoption of SFAS No. 145, all gains and losses from extinguishment of debt were classified as extraordinary items. SFAS No. 145 also creates consistency between accounting for sale-leaseback transactions and certain lease modifications with economic effects similar to sale- leaseback transactions, along with various amendments which make technical corrections and clarifications. EOG adopted this statement on January 1, 2003. The adoption of SFAS No. 145 did not have any effect on its financial position or results of operations. In June 2002, the FASB issued SFAS No. 146-"Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 nullifies the guidance of the Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized only when the liability is incurred and measured initially at fair value. SFAS No. 146 is effective for exit or disposal activities initiated after December 31, 2002. EOG does not expect the impact of SFAS No. 146 to have a material effect on its financial position or results of operations. In October 2002, the FASB issued SFAS No. 147-"Acquisitions of Certain Financial Institutions", effective for acquisitions on or after October 1, 2002. The statement relates to the application of the purchase method of accounting for acquisitions of financial institutions. The statement is currently not applicable to EOG. In December 2002, the FASB issued SFAS No. 148-"Accounting for Stock-Based Compensation-Transition and Disclosure - an amendment of FASB Statement No. 123." This statement provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation, along with the requirement of disclosure in both annual and interim financial statements about the method used and effect on reported results. EOG has not decided whether it will utilize the fair value method of accounting for stock-based employee compensation and is currently evaluating the alternative methods provided by SFAS No. 148. Based on EOG's current level of stock-based employee compensation activities and its existing financial statement footnote disclosure regarding such activities, EOG does not expect the impact of implementing any of the alternative methods to be material. Accounting for Price Risk Management Activities. EOG accounts for its price risk management activities under the provisions of SFAS No. 133-"Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 137 and No. 138. The statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. During 2001 and 2002, EOG elected not to designate any of its price risk management activities as accounting hedges under SFAS No. 133, and accordingly, accounted for them using the mark-to-market accounting method. Under this accounting method, the changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. The gains or losses are recorded in Gains (Losses) on Mark-to-market Commodity Derivative Contracts in the Net Operating Revenues section of the Consolidated Statements of Income. The related cash flow impact is reflected as cash flows from operating activities in the Consolidated Statements of Cash Flows (see Note 11 to the Consolidated Financial Statements). Capitalized Interest Costs. Certain interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties. Income Taxes. EOG accounts for income taxes under the provisions of SFAS No. 109-"Accounting for Income Taxes." SFAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases (see Note 5 to the Consolidated Financial Statements). Foreign Currency Translation. For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenue and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included in Accumulated Other Comprehensive Loss in the Shareholders' Equity section of the Consolidated Balance Sheets. Accumulated translation losses were $50 million and $54 million at December 31, 2002 and 2001, respectively. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. Net Income Per Share. In accordance with the provisions of SFAS No. 128-"Earnings per Share," basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted net income per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities (see Note 8 to the Consolidated Financial Statements for additional information to reconcile the difference between the Average Number of Common Shares outstanding for basic and diluted net income per share). Stock Options. EOG accounts for stock options under the provisions and related interpretations of APB Opinion No. 25-"Accounting for Stock Issued to Employees." No compensation expense is recognized for such options. As allowed by SFAS No. 123-"Accounting for Stock-Based Compensation" issued in 1995, EOG has continued to apply APB Opinion No. 25 for purposes of determining net income and to present the pro forma disclosures required by SFAS No. 123. Information Regarding Forward-Looking Statements This Current Report on Form 8-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts, including, among others, statements regarding EOG's future financial position, business strategy, budgets, reserve information, projected levels of production, projected costs and plans and objectives of management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "strategy," "intend," "plan," "target" and "believe" or the negative of those terms or other variations of them or by comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning future operating results, the ability to replace or increase reserves or to increase production, or the ability to generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes its expectations reflected in forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will be achieved. Important factors that could cause actual results to differ materially from the expectations reflected in the forward- looking statements include, among others: the timing and extent of changes in commodity prices for crude oil, natural gas and related products and interest rates; the extent and effect of any hedging activities engaged in by EOG; the extent of EOG's success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties; the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; political developments around the world, including terrorist activities and responses to such activities; acts of war; and financial market conditions. In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements might not occur. EOG undertakes no obligations to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise. MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING The following consolidated financial statements of EOG Resources, Inc. and its subsidiaries ("EOG") were prepared by management, which is responsible for their integrity, objectivity and fair presentation. The statements have been prepared in conformity with accounting principles generally accepted in the United States and, accordingly, include some amounts that are based on the best estimates and judgments of management. Deloitte & Touche LLP, independent public accountants, was engaged to audit the consolidated financial statements of EOG and issue a report thereon. In the conduct of the audit, Deloitte & Touche LLP was given unrestricted access to all financial records and related data including minutes of all meetings of shareholders, the Board of Directors and committees of the Board. Their audit was made in accordance with auditing standards generally accepted in the United States of America and included a review of the system of internal controls to the extent considered necessary to determine the audit procedures required to support their opinion on the consolidated financial statements. Management believes that all representations made to Deloitte & Touche LLP during the audit were valid and appropriate. The system of internal controls of EOG is designed to provide reasonable assurance as to the reliability of financial statements and the protection of assets from unauthorized acquisition, use or disposition. This system includes, but is not limited to, written policies and guidelines including a published code for the conduct of business affairs, conflicts of interest and compliance with laws regarding antitrust, antiboycott and foreign corrupt practices policies, the careful selection and training of qualified personnel, and a documented organizational structure outlining the separation of responsibilities among management representatives and staff groups. The adequacy of financial controls of EOG and the accounting principles employed in financial reporting by EOG are under the general oversight of the Audit Committee of the Board of Directors. No member of this committee is an officer or employee of EOG. The independent public accountants and internal auditors have full, free, separate and direct access to the Audit Committee and meet with the committee from time to time to discuss accounting, auditing and financial reporting matters. It should be recognized that there are inherent limitations to the effectiveness of any system of internal control, including the possibility of human error and circumvention or override. Accordingly, even an effective system can provide only reasonable assurance with respect to the preparation of reliable financial statements and safeguarding of assets. Furthermore, the effectiveness of an internal control system can change with circumstances. It is management's opinion that, considering the criteria for effective internal control over financial reporting and safeguarding of assets which consists of interrelated components including the control environment, risk assessment process, control activities, information and communication systems, and monitoring, EOG maintained an effective system of internal control as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition during the year ended December 31, 2002. MARK G. PAPA EDMUND P. SEGNER, III TIMOTHY K. DRIGGERS Chairman and President and Chief of Staff Vice President, Accounting Chief Executive and Land Administration Officer Houston, Texas February 19, 2003 REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of EOG Resources, Inc. Houston, Texas We have audited the accompanying balance sheet of EOG Resources, Inc. (the "Company") as of December 31, 2002, and the related statements of income, stockholders' equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of EOG Resources, Inc. as of December 31, 2001, and for the two years then ended were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements in their report dated February 21, 2002. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Deloitte & Touche LLP February 19, 2003 REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS (Continued) EOG dismissed Arthur Andersen LLP on February 27, 2002 and subsequently engaged Deloitte & Touche LLP as its independent auditors. The predecessor auditor's report appearing below is a copy of Arthur Andersen's previously issued report dated February 21, 2002. Since EOG is unable to obtain a current manually signed audit report, a copy of Arthur Andersen's most recent signed and dated report has been included to satisfy filing requirements, as permitted under Rule 2-02(e) of Regulation S-X. To EOG Resources, Inc.: We have audited the accompanying consolidated balance sheets of EOG Resources, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income and comprehensive income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of EOG Resources, Inc. and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Houston, Texas February 21, 2002 EOG RESOURCES, INC. CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (In Thousands, Except Per Share Amounts)
Year Ended December 31, 2002 2001 2000 NET OPERATING REVENUES Natural Gas $ 915,129 $1,298,102 $1,155,804 Crude Oil, Condensate and Natural Gas Liquids 227,309 258,101 325,726 Gains (Losses) on Mark-to-market Commodity Derivative Contracts (48,508) 97,750 (1,000) Gains on Sales of Reserves and Related Assets and Other, Net 1,106 934 9,365 Total 1,095,036 1,654,887 1,489,895 OPERATING EXPENSES Lease and Well 179,429 175,446 140,915 Exploration Costs 60,228 67,467 67,196 Dry Hole Costs 46,749 71,360 17,337 Impairments 68,430 79,156 46,478 Depreciation, Depletion and Amortization 398,036 392,399 359,265 General and Administrative 88,952 79,963 66,932 Taxes Other Than Income 71,881 95,333 94,909 Charges Associated with Enron Bankruptcy -- 19,211 -- Total 913,705 980,335 793,032 OPERATING INCOME 181,331 674,552 696,863 OTHER INCOME (EXPENSE) (2,005) 2,003 (2,300) INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES 179,326 676,555 694,563 INTEREST EXPENSE Incurred 68,641 53,756 67,714 Capitalized (8,987) (8,646) (6,708) Net Interest Expense 59,654 45,110 61,006 INCOME BEFORE INCOME TAXES 119,672 631,445 633,557 INCOME TAX PROVISION 32,499 232,829 236,626 NET INCOME 87,173 398,616 396,931 PREFERRED STOCK DIVIDENDS 11,032 10,994 11,028 NET INCOME AVAILABLE TO COMMON $ 76,141 $ 387,622 $ 385,903 NET INCOME PER SHARE AVAILABLE TO COMMON Basic $ 0.66 $ 3.35 $ 3.30 Diluted $ 0.65 $ 3.30 $ 3.24 AVERAGE NUMBER OF COMMON SHARES Basic 115,335 115,765 116,934 Diluted 117,245 117,488 119,102 COMPREHENSIVE INCOME NET INCOME $ 87,173 $ 398,616 $ 396,931 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Translation Adjustment 4,315 (22,044) (12,338) Available-for-sale Security Transactions 926 (1,318) 392 COMPREHENSIVE INCOME $ 92,414 $ 375,254 $ 384,985 The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC. CONSOLIDATED BALANCE SHEETS (In Thousands) At December 31, ASSETS 2002 2001 CURRENT ASSETS Cash and Cash Equivalents $ 9,848 $ 2,512 Accounts Receivable, net 259,308 194,624 Inventories 18,928 18,871 Assets from Price Risk Management Activities -- 19,161 Federal Income Tax Receivable 50,825 19,332 Other 55,883 17,921 Total 394,792 272,421 OIL AND GAS PROPERTIES (Successful Efforts Method) 6,750,095 6,065,603 Less: Accumulated Depreciation, Depletion and Amortization (3,428,547) (3,009,693) Net Oil and Gas Properties 3,321,548 3,055,910 OTHER ASSETS 97,666 85,713 TOTAL ASSETS $3,814,006 $3,414,044 LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable $ 201,931 $ 219,561 Accrued Taxes Payable 23,170 40,219 Dividends Payable 5,007 5,045 Liabilities from Price Risk Management Activities 5,939 -- Accrued Employee Benefits 11,099 16,345 Other 29,205 29,677 Total 276,351 310,847 LONG-TERM DEBT 1,145,132 855,969 OTHER LIABILITIES 59,180 53,522 DEFERRED INCOME TAXES 660,948 551,020 SHAREHOLDERS' EQUITY Preferred Stock, $.01 Par, 10,000,000 Shares Authorized: Series B, 100,000 Shares Issued, Cumulative, $100,000,000 Liquidation Preference 98,352 98,116 Series D, 500 Shares Issued, Cumulative, $50,000,000 Liquidation Preference 49,647 49,466 Common Stock, $.01 Par, 320,000,000 Shares Authorized and 124,730,000 Shares Issued 201,247 201,247 Unearned Compensation (15,033) (14,953) Accumulated Other Comprehensive Loss (49,877) (55,118) Retained Earnings 1,723,948 1,668,708 Common Stock Held in Treasury, 10,009,740 shares at December 31, 2002 and 9,278,382 shares at December 31, 2001 (335,889) (304,780) Total Shareholders' Equity 1,672,395 1,642,686 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $3,814,006 $3,414,044 The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC. CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (In Thousands, Except Per Share Amounts) Accumulated Common
Additional Other Stock Total Preferred Common Paid In Unearned Comprehensive Retained Held In Shareholders' Stock Stock Capital Compensation Income (Loss) Earnings Treasury Equity Balance at December 31, 1999 $147,190 $201,247 $ -- $ (1,618) $(19,810) $ 930,938 $(128,336) $1,129,611 Net Income -- -- -- -- -- 396,931 -- 396,931 Amortization of Preferred Stock Discount 419 -- -- -- -- (419) -- -- Exchange Offer Fees (445) -- -- -- -- -- -- (445) Preferred Stock Dividends Paid/Declared -- -- -- -- -- (10,609) -- (10,609) Common Stock Dividends Declared, $.14 Per Share -- -- -- -- -- (15,774) -- (15,774) Translation Adjustment -- -- -- -- (12,338) -- -- (12,338) Unrealized Gain on Available- for-sale Security -- -- -- -- 392 -- -- 392 Treasury Stock Purchased -- -- -- -- -- -- (272,723) (272,723) Treasury Stock Issued Under Stock Option Plans -- -- (36,701) -- -- -- 163,350 126,649 Tax Benefits from Stock Options Exercised -- -- 41,307 -- -- -- -- 41,307 Restricted Stock and Units -- -- 2,805 (3,411) -- -- 606 -- Amortization of Unearned Compensation -- -- -- 1,273 -- -- -- 1,273 Equity Derivative Transactions -- -- (3,190) -- -- -- -- (3,190) Other -- -- -- -- -- -- (159) (159) Balance at December 31, 2000 147,164 201,247 4,221 (3,756) (31,756) 1,301,067 (237,262) 1,380,925 Net Income -- -- -- -- -- 398,616 -- 398,616 Amortization of Preferred Stock Discount 418 -- -- -- -- (418) -- -- Preferred Stock Dividends Paid/Declared -- -- -- -- -- (10,576) -- (10,576) Common Stock Dividends Declared, $.16 Per Share -- -- -- -- -- (18,523) -- (18,523) Translation Adjustment -- -- -- -- (22,044) -- -- (22,044) Unrealized Loss on Available- for-sale Security -- -- -- -- (1,318) -- -- (1,318) Treasury Stock Purchased -- -- -- -- -- -- (126,769) (126,769) Treasury Stock Issued Under Stock Option Plans -- -- (19,097) -- -- (1,458) 50,403 29,848 Treasury Stock Issued Under Employee Stock Purchase Plan -- -- (104) -- -- -- 1,061 957 Tax Benefits from Stock Options Exercised -- -- 7,332 -- -- -- -- 7,332 Restricted Stock and Units -- -- 6,583 (14,467) -- -- 7,884 -- Amortization of Unearned Compensation -- -- -- 3,270 -- -- -- 3,270 Equity Derivative Transactions -- -- 1,201 -- -- -- -- 1,201 Other -- -- (136) -- -- -- (97) (233) Balance at December 31, 2001 147,582 201,247 -- (14,953) (55,118) 1,668,708 (304,780) 1,642,686 Net Income -- -- -- -- -- 87,173 -- 87,173 Amortization of Preferred Stock Discount 417 -- -- -- -- (417) -- -- Preferred Stock Dividends Paid/Declared -- -- -- -- -- (10,615) -- (10,615) Common Stock Dividends Declared, $.16 Per Share -- -- -- -- -- (18,499) -- (18,499) Translation Adjustment -- -- -- -- 4,315 -- -- 4,315 Available-for-sale Security Transactions -- -- -- -- 926 -- -- 926 Treasury Stock Purchased -- -- -- -- -- -- (63,038) (63,038) Treasury Stock Issued Under Stock Option Plans -- -- (9,457) -- -- (2,402) 28,565 16,706 Treasury Stock Issued Under Employee Stock Purchase Plan -- -- (39) -- -- -- 2,301 2,262 Tax Benefits from Stock Options Exercised -- -- 5,167 -- -- -- -- 5,167 Restricted Stock and Units -- -- 4,329 (4,951) -- -- 622 -- Amortization of Unearned Compensation -- -- -- 4,871 -- -- -- 4,871 Other -- -- -- -- -- -- 441 441 Balance at December 31, 2002 $147,999 $201,247 $ -- $(15,033) $(49,877) $1,723,948 $(335,889) $1,672,395 The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (In Thousands)
Year Ended December 31, 2002 2001 2000 CASH FLOWS FROM OPERATING ACTIVITIES Reconciliation of Net Income to Net Operating Cash Inflows: Net Income $ 87,173 $ 398,616 $ 396,931 Items Not Requiring Cash Depreciation, Depletion and Amortization 398,036 392,399 359,265 Impairments 68,430 79,156 46,478 Deferred Income Taxes 82,179 164,945 97,729 Charges Associated with Enron Bankruptcy -- 19,211 -- Other, Net 17,333 10,423 6,693 Exploration Costs 60,228 67,467 67,196 Dry Hole Costs 46,749 71,360 17,337 Mark-to-market Commodity Derivative Contracts Total (Gains) Losses 48,508 (97,750) 1,000 Realized Gains (Losses) (21,136) 66,731 (1,438) Collar Premium (1,825) (4,621) -- Losses (Gains) on Sales of Reserves and Related Assets and Other, Net (70) 835 (5,539) Tax Benefits from Stock Options Exercised 5,168 7,332 41,307 Other, Net (1,908) (3,127) (8,935) Changes in Components of Working Capital and Other Liabilities Accounts Receivable (61,580) 146,235 (191,492) Inventories (57) (2,248) 2,345 Accounts Payable (19,012) (26,949) 97,374 Accrued Taxes Payable (84,666) (38,619) 54,556 Other Liabilities 7,816 (3,422) 348 Other, Net (5,578) (16,442) 11,378 Changes in Components of Working Capital Associated with Investing and Financing Activities 42,782 (34,105) (25,123) NET OPERATING CASH INFLOWS 668,570 1,197,427 967,410 INVESTING CASH FLOWS Additions to Oil and Gas Properties (714,127) (974,016) (602,638) Exploration Costs (60,228) (67,467) (67,196) Dry Hole Costs (46,749) (71,360) (17,337) Proceeds from Sales of Reserves and Related Assets 8,089 8,032 26,189 Changes in Components of Working Capital Associated with Investing Activities (43,246) 32,405 22,798 Other, Net (16,277) (15,649) (28,977) NET INVESTING CASH OUTFLOWS (872,538) (1,088,055) (667,161) FINANCING CASH FLOWS Long-Term Debt Borrowings (Repayments) 289,163 (4,155) (131,306) Dividends Paid (29,152) (28,580) (26,071) Treasury Stock Purchased (63,038) (126,769) (272,723) Proceeds from Stock Options Exercised 17,339 30,805 127,090 Other, Net (3,008) 1,687 (1,923) NET FINANCING CASH INFLOWS (OUTFLOWS) 211,304 (127,012) (304,933) INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 7,336 (17,640) (4,684) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 2,512 20,152 24,836 CASH AND CASH EQUIVALENTS AT END OF YEAR $ 9,848 $ 2,512 $ 20,152 The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Summary of Significant Accounting Policies Principles of Consolidation. The consolidated financial statements of EOG Resources, Inc. ("EOG"), a Delaware corporation, include the accounts of all domestic and foreign subsidiaries. Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method. All material intercompany accounts and transactions have been eliminated. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications have been made to prior period financial statements to conform with the current presentation. Beginning 2001, the "Impairment of Unproved Oil and Gas Properties" caption on the Consolidated Statements of Income was renamed "Impairments" to include the impairment of long-lived assets as described in Statement of Financial Accounting Standards ("SFAS") No. 121-"Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to Be Disposed of" ("SFAS 121 Impairments"), as superseded by SFAS No. 144-"Accounting for the Impairment or Disposal of Long-Lived Assets." As a result, EOG reclassified all prior periods to reflect such SFAS 121 Impairments in Impairments, instead of Depreciation, Depletion and Amortization ("DD&A") as previously reported. SFAS 121 Impairments reclassified from DD&A to Impairments was $11 million for 2000. Financial Instruments. EOG's financial instruments consist of cash and cash equivalents, marketable securities, accounts receivable, accounts payable and long-term debt. The carrying values of cash and cash equivalents, marketable securities, accounts receivable and accounts payable approximate fair value (see Note 2 "Long-Term Debt" for fair value of long-term debt). Cash and Cash Equivalents. EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less. Oil and Gas Operations. EOG accounts for its natural gas and crude oil exploration and production activities under the successful efforts method of accounting. Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and crude oil, are capitalized. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. Estimated future dismantlement, restoration and abandonment costs (classified as long-term liabilities), net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis. Periodically, or when circumstances indicate that an asset may be impaired, EOG compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on EOG's estimate of future crude oil and natural gas prices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Inventories, consisting primarily of tubular goods and well equipment held for use in the exploration for, and development and production of natural gas and crude oil reserves, are carried at cost with adjustments made from time to time to recognize any reductions in value. Natural gas and liquids revenues are recorded when production is delivered. Additionally, natural gas revenues are recorded on the entitlement method based on EOG's percentage ownership of current production. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold may differ from an owner's ownership percentage. Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable is recorded when overproduction occurs. New Accounting Pronouncements. In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 143-"Accounting for Asset Retirement Obligations" effective for fiscal years beginning after June 15, 2002. SFAS No. 143 requires entities to record the fair value of a liability for legal obligations associated with the retirement of tangible long- lived assets and the associated asset retirement costs. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. Increase in the liability due to passage of time, as a result of applying an interest method of allocation to the amount of the liability at the beginning of a period, is recognized as an increase in the carrying amount of the liability and as an expense classified as an operating item in the statement of income. If the obligation is settled for other than the carrying amount of the liability, a gain or loss is recognized on settlement. EOG adopted the statement on January 1, 2003. The impact of adopting the statement resulted in an after-tax loss of approximately $6.5 million which will be reported as cumulative adjustment for change in accounting principle in the first quarter of 2003. In April 2002, the FASB issued SFAS No. 145-"Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" effective for financial statements issued on or after May 15, 2002. SFAS No. 145 requires gains and losses on the extinguishment of debt to be classified as income or loss from continuing operations, unless the requirements of Accounting Principles Board Opinion ("APB Opinion") No. 30-"Reporting the Results of Operations - Reporting the effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" are met, upon which the gain or loss would be considered unusual and infrequent and classified as an extraordinary item. Prior to adoption of SFAS No. 145, all gains and losses from extinguishment of debt were classified as extraordinary items. SFAS No. 145 also creates consistency between accounting for sale-leaseback transactions and certain lease modifications with economic effects similar to sale- leaseback transactions, along with various amendments which make technical corrections and clarifications. EOG adopted this statement on January 1, 2003. The adoption of SFAS No. 145 did not have any effect on its financial position or results of operations. In June 2002, the FASB issued SFAS No. 146-"Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 nullifies the guidance of the Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized only when the liability is incurred and measured initially at fair value. SFAS No. 146 is effective for exit or disposal activities initiated after December 31, 2002. EOG does not expect the impact of SFAS No. 146 to have a material effect on its financial position or results of operations. In October 2002, the FASB issued SFAS No. 147-"Acquisitions of Certain Financial Institutions", effective for acquisitions on or after October 1, 2002. The statement relates to the application of the purchase method of accounting for acquisitions of financial institutions. The statement is currently not applicable to EOG. In December 2002, the FASB issued SFAS No. 148-"Accounting for Stock-Based Compensation-Transition and Disclosure - an amendment of FASB Statement No. 123." This statement provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation, along with the requirement of disclosure in both annual and interim financial statements about the method used and effect on reported results. EOG has not decided whether it will utilize the fair value method of accounting for stock-based employee compensation and is currently evaluating the alternative methods provided by SFAS No. 148. Based on EOG's current level of stock-based employee compensation activities and its existing financial statement footnote disclosure regarding such activities, EOG does not expect the impact of implementing any of the alternative methods to be material. Accounting for Price Risk Management Activities. EOG accounts for its price risk management activities under the provisions of SFAS No. 133-"Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 137 and No. 138. The statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. During 2001 and 2002, EOG elected not to designate any of its price risk management activities as accounting hedges under SFAS No. 133, and accordingly, accounted for them using the mark-to-market accounting method. Under this accounting method, the changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. The gains or losses are recorded in Gains (Losses) on Mark-to-market Commodity Derivative Contracts in the Net Operating Revenues section of the Consolidated Statements of Income. The related cash flow impact is reflected as cash flows from operating activities in the Consolidated Statements of Cash Flows (see Note 11 "Prices and Interest Rate Risk Management Activities"). Capitalized Interest Costs. Certain interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties. Income Taxes. EOG accounts for income taxes under the provisions of SFAS No. 109-"Accounting for Income Taxes." SFAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases (see Note 5 "Income Taxes"). Foreign Currency Translation. For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenue and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included in Accumulated Other Comprehensive Loss in the Shareholders' Equity section of the Consolidated Balance Sheets. Accumulated translation losses were $50 million and $54 million at December 31, 2002 and 2001, respectively. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. Net Income Per Share. In accordance with the provisions of SFAS No. 128-"Earnings per Share," basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted net income per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities (see Note 8 "Net Income Per Share Available to Common" for additional information to reconcile the difference between the Average Number of Common Shares outstanding for basic and diluted net income per share). Stock Options Plans. EOG accounts for stock options under the provisions and related interpretations of APB Opinion No. 25-"Accounting for Stock Issued to Employees." No compensation expense is recognized for such options. As allowed by SFAS No. 123-"Accounting for Stock-Based Compensation" issued in 1995, EOG has continued to apply APB Opinion No. 25 for purposes of determining net income and to present the pro forma disclosures required by SFAS No. 123. 2. Long-Term Debt Long-Term Debt at December 31 consisted of the following (in thousands):
2002 2001 Commercial Paper $ 120,000 $ -- Uncommitted Credit Facilities 14,310 95,147 Senior Unsecured Term Loan Facility due 2005 150,000 -- 6.50% Notes due 2004 100,000 100,000 6.70% Notes due 2006 126,870 126,870 6.50% Notes due 2007 100,000 100,000 6.00% Notes due 2008 173,952 173,952 6.65% Notes due 2028 140,000 140,000 7.00% Subsidiary Debt due 2011 220,000 120,000 Total $1,145,132 $855,969
EOG maintains two credit facilities with different expiration dates. In July 2002, the $300 million credit facility that was scheduled to expire was renewed at the same commitment level for a period of one year, which is the same period as the last renewal of this facility. Credit facility expirations are as follows: $300 million in July 2003 and $300 million in July 2004. With respect to the $300 million expiring in 2003, EOG may, at its option, extend the final maturity date of any advances made under the facility by one full year from the expiration date of the facility, effectively qualifying such debt as long term. Advances under both agreements bear interest, at the option of EOG, based upon a base rate or a Eurodollar rate. No amounts were borrowed on these committed credit facilities at December 31, 2002. On October 30, 2002, EOG entered into a Senior Unsecured Term Loan Facility (the "Facility") with a group of banks whereby the banks agreed to lend EOG $150 million with a maturity of three years. EOG used the loan proceeds under this Facility to reduce outstanding commercial paper and uncommitted bank line borrowings. This Facility calls for interest to be charged at a spread over LIBOR (London InterBank Offering Rate) or the base rate at EOG's option, and contains substantially the same covenants as those in EOG's $300 million Long-Term Revolving Credit Agreement. The applicable interest rate for this Facility was 2.35% at December 31, 2002. During 2002 and 2001, EOG utilized commercial paper and short-term funding from uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes. Commercial paper and uncommitted credit borrowings are classified as long-term debt based on EOG's intent and ability to ultimately replace such amounts with other long-term debt. The 6.00% to 6.70% Notes due 2004 to 2028 were issued through public offerings and have effective interest rates of 6.14% to 6.83%. The Subsidiary Debt due 2011 bears interest at a fixed rate of 7.00% and is guaranteed by EOG. At December 31, 2002, the aggregate annual maturities of long-term debt outstanding were none for 2003, $100 million for 2004, $150 million for 2005, $127 million in 2006 and $100 million for 2007. EOG's credit facilities contain certain restrictive covenants, including a maximum debt-to-total capitalization ratio of 65% and a minimum ratio of EBITDAX (earnings before interest, taxes, DD&A, and exploration expense) to interest expense of at least three times. Other than these covenants, EOG does not have any other financial covenants in its financing agreements. EOG continues to comply with these two covenants and does not view them as materially restrictive. Shelf Registration. During the third quarter of 2000, EOG filed a shelf registration statement for the offer and sale from time to time of up to $600 million of EOG debt securities, preferred stock and/or common stock. The registration statement was declared effective by the Securities and Exchange Commission on October 27, 2000. As of February 19, 2003, EOG had sold no securities pursuant to this shelf registration. When combined with the unused portion of a previously filed registration statement declared effective in January 1998, these registration statements provide for the offer and sale from time to time of EOG debt securities, preferred stock and/or common stock by EOG in an aggregate amount up to $688 million. Fair Value Of Long-Term Debt. At December 31, 2002 and 2001, EOG had $1,145 million and $856 million, respectively, of long-term debt which had fair values of approximately $1,225 million and $838 million, respectively. The fair value of long-term debt is the value EOG would have to pay to retire the debt, including any premium or discount to the debtholder for the differential between the stated interest rate and the year-end market rate. The fair value of long-term debt is based upon quoted market prices and, where such quotes were not available, upon interest rates available to EOG at yearend. 3. Shareholders' Equity EOG purchases its common stock from time to time in the open market to be held in treasury for the purpose of, but not limited to, fulfilling any obligations arising under EOG's stock plans and any other approved transactions or activities for which such common stock shall be required. In September 2001, the Board of Directors authorized the purchase of an aggregate maximum of 10 million shares of common stock of EOG which superseded all previous authorizations. At December 31, 2002, 6,917,000 shares remain available for repurchases under this authorization. To supplement its share repurchase program, EOG enters into equity derivative transactions from time to time. These transactions are accounted for as equity transactions with premiums received recorded to Additional Paid In Capital in the Consolidated Balance Sheets. Settlement alternatives under all circumstances are at the option of EOG and include physical share, net share and net cash settlement. During the second quarter of 2001, EOG sold put options for $1.2 million obligating EOG to purchase up to 0.6 million shares of its common stock at an average price of $33.42 per share. These options expired unexercised in December 2001. During the first half of 2000, EOG entered into a series of equity derivative transactions receiving $0.6 million. During the third quarter of 2000, EOG closed substantially all of its equity derivative contracts which were to expire in April 2001 by paying $3.75 million. EOG had one million put options which it had written which were outstanding at December 31, 2000. The strike price of these options was $18.00 per share, and they expired unexercised in April 2001. The following summarizes shares of common stock outstanding (in thousands):
Common Shares 2002 2001 2000 Outstanding at January 1 115,452 116,904 119,105 Repurchased (1,700) (3,281) (8,910) Issued Pursuant to Stock Options and Stock Plans 968 1,829 6,709 Outstanding at December 31 114,720 115,452 116,904
Series A. On December 10, 1999, EOG issued 100,000 shares of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A, with a $1,000 Liquidation Preference per share, in a private transaction. Dividends will be payable on the shares only if declared by EOG's board of directors and will be cumulative. If declared, dividends will be payable at a rate of $71.95 per share, per year on March 15, June 15, September 15, and December 15 of each year beginning March 15, 2000. EOG may redeem all or a part of the Series A preferred stock at any time beginning on December 15, 2009 at $1,000 per share, plus accrued and unpaid dividends. The shares may also be redeemable, in whole but not in part, in the event that certain amendments are made to the Dividend Received Percentage. The Series A preferred shares are not convertible into, or exchangeable for, common stock of EOG. Series C. On December 22, 1999, EOG issued 500 shares of Flexible Money Market Cumulative Preferred Stock, Series C, with a liquidation preference of $100,000 per share, in a private transaction. Dividends will be payable on the shares only if declared by EOG's board of directors and will be cumulative. The initial dividend rate on the shares will be 6.84% until December 15, 2004 (the "Initial Period-End Dividend Payment Date"). Through the Initial Period-End Dividend Payment Date dividends will be payable, if declared, on March 15, June 15, September 15, and December 15 of each year beginning March 15, 2000. The cash dividend rate for each subsequent dividend period will be determined pursuant to periodic auctions conducted in accordance with certain auction procedures. The first auction date will be December 14, 2004. After December 15, 2004 (unless EOG has elected a "Non-Call Period" for a subsequent dividend period), EOG may redeem the shares, in whole or in part, on any dividend payment date at $100,000 per share plus accumulated and unpaid dividends. The shares may also be redeemable, in whole but not in part, in the event that certain amendments are made to the Dividend Received Percentage. The Series C preferred shares are not convertible into, or exchangeable for, common stock of EOG. During the third quarter of 2000, EOG completed two exchange offers for its preferred stock whereby shares of EOG's Series A preferred stock were exchanged for shares of EOG's Series B preferred stock, and shares of EOG's Series C preferred stock were exchanged for shares of EOG's Series D preferred stock. All preferred shares were validly tendered and not withdrawn prior to expiration of the offers. EOG accepted all of the tendered shares and issued the respective series in exchange. Both exchange offers were registered under the Securities Act of 1933. The Series B preferred stock has substantially the same terms as Series A and the Series D preferred stock has substantially the same terms as Series C. On February 14, 2000, EOG's Board of Directors declared a dividend of one preferred share purchase right (a "Right," and the agreement governing the terms of such Rights, the "Rights Agreement") for each outstanding share of common stock, par value $.01 per share. The Board of Directors has adopted this Rights Agreement to protect stockholders from coercive or otherwise unfair takeover tactics. The dividend was distributed to the stockholders of record on February 24, 2000. Each Right, expiring February 24, 2010, represents a right to buy from EOG one hundredth (1/100) of a share of Series E Junior Participating Preferred Stock ("Preferred Share") for $90, once the Rights become exercisable. This portion of a Preferred Share will give the stockholder approximately the same dividend, voting, and liquidation rights as would one share of common stock. Prior to exercise, the Right does not give its holder any dividend, voting, or liquidation rights. If issued, each one hundredth (1/100) of a Preferred Share (i) will not be redeemable; (ii) will entitle holders to quarterly dividend payments of $.01 per share, or an amount equal to the dividend paid on one share of common stock, whichever is greater; (iii) will entitle holders upon liquidation either to receive $1 per share or an amount equal to the payment made on one share of common stock, whichever is greater; (iv) will have the same voting power as one share of common stock; and (v) if shares of EOG's common stock are exchanged via merger, consolidation, or a similar transaction, will entitle holders to a per share payment equal to the payment made on one share of common stock. The Rights will not be exercisable until ten days after the public announcement that a person or group has become an acquiring person ("Acquiring Person") by obtaining beneficial ownership of 10% or more of EOG's common stock, or if earlier, ten business days (or a later date determined by EOG's Board of Directors before any person or group becomes an Acquiring Person) after a person or group begins a tender or exchange offer which, if consummated, would result in that person or group becoming an Acquiring Person. On December 10, 2002, the Rights Agreement was amended to create an exception to the definition of Acquiring Person to permit a qualified institutional investor to beneficially own 10% or more but less than 15% of EOG's common stock without being deemed an Acquiring Person if the institutional investor meets the following requirements: (i) the institutional investor is described in Rule 13d-1(b)(1) promulgated under the Securities Exchange Act of 1934 and is eligible to report (and does in fact report) beneficial ownership of common stock on Schedule 13G; (ii) the institutional investor is not required to file a Schedule 13D (or any successor or comparable report) with respect to its beneficial ownership of EOG's common stock; and (iii) the institutional investor does not beneficially own 15% or more of EOG's common stock then outstanding. If a person or group becomes an Acquiring Person, all holders of Rights except the Acquiring Person may, for $90, purchase shares of EOG's common stock with a market value of $180, based on the market price of the common stock prior to such acquisition. If EOG is later acquired in a merger or similar transaction after the Rights become exercisable, all holders of Rights except the Acquiring Person may, for $90, purchase shares of the acquiring corporation with a market value of $180 based on the market price of the acquiring corporation's stock, prior to such merger. EOG's Board of Directors may redeem the Rights for $.01 per Right at any time before any person or group becomes an Acquiring Person. If the Board of Directors redeems any Rights, it must redeem all of the Rights. Once the Rights are redeemed, the only right of the holders of Rights will be to receive the redemption price of $.01 per Right. The redemption price will be adjusted if EOG has a stock split or stock dividends of EOG's common stock. After a person or group becomes an Acquiring Person, but before an Acquiring Person owns 50% or more of EOG's outstanding common stock, the Board of Directors may exchange the Rights for common stock or equivalent security at an exchange ratio of one share of common stock or an equivalent security for each such Right, other than Rights held by the Acquiring Person. 4. Enron Corp. Bankruptcy In December 2001, Enron Corp. and certain of its affiliates, including Enron North America Corp., filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code. EOG recorded $19.2 million in charges associated with the Enron bankruptcies in the fourth quarter of 2001 related to certain contracts with Enron affiliates, including 2001 and 2002 natural gas and crude oil derivative contracts. Based on EOG's review of all matters related to Enron Corp. and its affiliates, EOG believes that Enron Corp.'s Chapter 11 proceedings will not have a material adverse effect on EOG's financial position. By an order entered on June 21, 2002, the bankruptcy judge in the Enron bankruptcy case authorized the sale of 11.5 million shares of EOG common stock held by an affiliate of Enron. On November 22, 2002, the entire 11.5 million shares were sold by the Enron affiliate to an unaffiliated broker. EOG purchased one million shares of EOG common stock from the broker, and the remaining 10.5 million shares were sold by the broker to third parties. 5. Income Taxes The principal components of EOG's net deferred income tax liability at December 31, 2002 and 2001 were as follows (in thousands):
2002 2001 Deferred Income Tax Assets Non-Producing Leasehold Costs $ 29,574 $ 26,727 Seismic Costs Capitalized for Tax 18,657 17,828 Alternative Minimum Tax Credit Carryforward 20,200 -- Other 12,589 26,325 Total Deferred Income Tax Assets 81,020 70,880 Deferred Income Tax Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization 731,189 599,945 Capitalized Interest 10,779 8,373 Mark-to-market -- 10,107 Other -- 3,475 Total Deferred Income Tax Liabilities 741,968 621,900 Net Deferred Income Tax Liability $660,948 $551,020
The components of income before income taxes were as follows (in thousands):
2002 2001 2000 United States $ 37,354 $488,741 $491,823 Foreign 82,318 142,704 141,734 Total $119,672 $631,445 $633,557
Total income tax provision was as follows (in thousands):
2002 2001 2000 Current: Federal $(61,013) $ 36,737 $ 81,912 State (5,130) 5,475 7,528 Foreign 16,463 25,672 49,457 Total (49,680) 67,884 138,897 Deferred: Federal 57,232 131,127 78,833 State (358) 10,411 10,324 Foreign 25,305 23,407 8,572 Total 82,179 164,945 97,729 Income Tax Provision $ 32,499 $232,829 $236,626
The differences between taxes computed at the U.S. federal statutory tax rate and EOG's effective rate were as follows:
2002 2001 2000 Statutory Federal Income Tax Rate 35.00% 35.00% 35.00% State Income Tax, Net of Federal Benefit 0.22 1.64 1.83 Income Tax Provision Related to Foreign Operations (3.54) 0.36 1.32 Tight Gas Sands Federal Income Tax Credits (3.57) (0.83) (0.90) Other (0.95) 0.70 0.10 Effective Income Tax Rate 27.16% 36.87% 37.35%
EOG's foreign subsidiaries' undistributed earnings of approximately $543 million at December 31, 2002 are considered to be indefinitely invested outside the U.S. and, accordingly, no U.S. federal or state income taxes have been provided thereon. Upon distribution of those earnings in the form of dividends, EOG may be subject to both foreign withholding taxes and U.S. income taxes, net of allowable foreign tax credits. Determination of any potential amount of unrecognized deferred income tax liabilities is not practicable. In 1999 and 2000, EOG entered into arrangements with a third party whereby certain Section 29 credits (Tight Gas Sands Federal Income Tax Credits) were sold by EOG to the third party, and payments for such credits have been received on an as-generated basis. As a result of these transactions, for the period of 2000 through 2002, EOG recorded a deferred tax asset representing a tax gain on the sale of the Section 29 credit properties, which has reversed as the results of operations of such properties were recognized for book purposes. In January 2003, these arrangements were terminated. EOG has an alternative minimum tax ("AMT") credit carryforward of $20.2 million which can be used to offset regular income taxes payable in future years. The AMT credit carryforward has an indefinite carryforward period. 6. Employee Benefit Plans Pension Plans EOG has defined contribution pension and savings plans in place for most of its employees in the United States. EOG's contributions to these plans are based on various percentages of compensation, and in some instances, are based upon the amount of the employees' contributions to the plan. For 2002, 2001 and 2000, the cost of these plans amounted to approximately $8.0 million, $6.5 million and $5.3 million, respectively. EOG also has in effect pension and savings plans related to its Canadian and Trinidadian subsidiaries. Activity related to these plans is not material relative to EOG's operations. Postretirement Plan During 2000, EOG adopted postretirement medical and dental benefits for eligible employees and their eligible dependents. Benefits are provided under the provisions of a contributory defined dollar benefit plan. EOG accrues these postretirement benefit costs over the service lives of the employees expected to be eligible to receive such benefits. As of December 31, 2002, December 31, 2001 and December 31, 2000, the postretirement plan had a benefit obligation of $1.9 million, $2.0 million and $1.5 million, respectively. During 2002, 2001 and 2000, EOG recognized a net periodic benefit cost related to this plan of $0.3 million, $0.4 million and $0.3 million, respectively. Stock Plans EOG has various stock plans ("the Plans") under which employees and non-employee members of the Board of Directors of EOG and its subsidiaries have been or may be granted certain equity compensation. At December 31, 2002, the total number of shares authorized for grant from the Plans was 27,450,000 shares. Stock Options. Under the Plans, participants have been or may be granted rights to purchase shares of common stock of EOG at a price not less than the market price of the stock at the date of grant. Stock options granted under the plan vest either immediately at the date of grant or up to four years from the date of grant based on the nature of the grants and as defined in individual grant agreements. Terms for stock options granted under the plan have not exceeded a maximum term of 10 years. The following table sets forth the option transactions for the years ended December 31 (options in thousands):
2002 2001 2000 Average Average Average Grant Grant Grant Options Price Options Price Options Price Outstanding at January 1 7,013 $24.69 7,056 $20.70 12,667 $18.66 Granted 1,809 33.82 1,631 36.63 1,317 30.88 Exercised (868) 19.90 (1,563) 19.18 (6,726) 18.90 Forfeited (112) 27.64 (111) 23.84 (202) 19.09 Outstanding at December 31 7,842 27.31 7,013 24.69 7,056 20.70 Options Exercisable at December 31 5,041 23.96 4,034 22.04 3,845 19.83 Options Available for Future Grant 2,932 4,531 6,387 Average Fair Value of Options Granted During Year $14.79 $16.76 $12.20
The fair value of each option grant is estimated using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 2002, 2001 and 2000, respectively: (1) dividend yield of 0.4%, 0.5% and 0.6%, (2) expected volatility of 45%, 43% and 30%, (3) risk-free interest rate of 3.7%, 4.6% and 6.0% and (4) expected life of 5.3 years, 6.0 years and 6.0 years. The following table summarizes certain information for the options outstanding at December 31, 2002 (options in thousands):
Options Outstanding Options Exercisable Weighted Weighted Weighted Average Average Average Remaining Grant Grant Range of Grant Prices Options Life Price Options Price (years) $13.00 to $17.99 1,318 5 $14.64 1,306 $14.62 18.00 to 22.99 1,951 5 20.19 1,737 20.22 23.00 to 28.99 313 3 24.09 306 24.03 29.00 to 39.99 3,997 9 34.01 1,539 33.82 40.00 to 54.99 263 7 45.51 153 46.59 7,842 7 27.31 5,041 23.96
EOG's pro forma net income and net income per share of common stock for 2002, 2001 and 2000, had compensation costs been recorded in accordance with SFAS No. 123, are presented below (in millions except per share data):
2002 2001 2000 Net Income Available to Common - As Reported $ 76.1 $387.6 $385.9 Deduct: Total stock-based employee compensation expense (13.7) (11.9) (12.5) Net Income Available to Common - Pro Forma $ 62.4 $375.7 $373.4 Net Income per Share Available to Common Basic - As Reported $ 0.66 $ 3.35 $ 3.30 Basic - Pro Forma $ 0.54 $ 3.25 $ 3.19 Diluted - As Reported $ 0.65 $ 3.30 $ 3.24 Diluted - Pro Forma $ 0.53 $ 3.20 $ 3.14
The effects of applying SFAS No. 123 in this pro forma disclosure should not be interpreted as being indicative of future effects. SFAS No. 123 does not apply to awards prior to 1995, and the extent and timing of additional future awards cannot be predicted. Restricted Stock and Units. Under the Plans, employees may be granted restricted stock and/or units without cost to them. The shares and units granted vest to the employee at various times ranging from one to five years from the date of grant based on the nature of the grants and as defined in individual grant agreements. Upon vesting, restricted shares are released to the employee. Upon vesting, restricted units are converted into one share of common stock and released to the employee. The following summarizes shares of restricted stock and units granted (shares and units in thousands):
Restricted Shares and Units 2002 2001 2000 Outstanding at January 1 632 309 288 Granted 158 353 201 Released (10) (15) (178) Forfeited or Expired (5) (15) (2) Outstanding at December 31 775 632 309 Average Fair Value of Shares Granted During Year $32.56 $42.08 $16.10
The fair value of the restricted shares and units at date of grant has been recorded in shareholders' equity as unearned compensation and is being amortized over the vesting period as compensation expense. Related compensation expense for 2002, 2001 and 2000 was approximately $4.9 million, $3.3 million and $1.3 million, respectively. Employee Stock Purchase Plan. During 2001, EOG implemented an Employee Stock Purchase Plan (the "ESPP") that allows eligible employees to semiannually purchase, through payroll deductions, shares of EOG common stock at 85 percent of the fair market value at specified dates. Contributions to the ESPP are limited to 10 percent of the employees' pay (subject to certain ESPP limits) during each of the two six-month offering periods. As of December 31, 2002, 398,456 common shares remained available for issuance under the plan. During 2002, approximately 350 employees participated in the plan and 69,243 common shares were purchased at an aggregate price of approximately $2.3 million. During 2001, approximately 300 employees participated in the plan and 32,301 common shares were purchased at an aggregate price of approximately $1 million. Treasury Shares. During 2002, 2001 and 2000, EOG repurchased 1,700,000, 3,281,000 and 8,910,000 of its common shares, respectively. Approximately 968,000, 1,829,000 and 6,709,000 of these common shares were repurchased during 2002, 2001 and 2000, respectively, to offset the dilution resulting from shares issued under the EOG employee stock plans. The difference between the cost of the treasury shares and the exercise price of the options, net of federal income tax benefit of $5.2 million, $7.3 million and $41.3 million, for the years 2002, 2001 and 2000, respectively, is reflected as an adjustment to additional paid in capital to the extent EOG has accumulated additional paid in capital relating to treasury stock and retained earnings thereafter. 7. Commitments and Contingencies Letters Of Credit. At December 31, 2002 and 2001, EOG had letters of credit and guarantees outstanding totaling approximately $234 million and $136 million, respectively; however, of these amounts, $220 million and $120 million, respectively, represent guarantees of subsidiary indebtedness included under Note 2 "Long-Term Debt." Minimum Commitments. At December 31, 2002, total minimum commitments from foreign equity investments, long-term non-cancelable operating leases, drilling rig commitments and transportation service commitments, based on current transportation rates and the foreign currency exchange rate applicable to Canadian dollars at December 31, 2002, are as follows (in thousands):
Total Minimum Commitments 2003 $ 23,902 2004 - 2006 41,288 2007 - 2008 9,771 2009 and thereafter 4,249 $ 79,210
Included in the table above are leases for buildings, facilities and equipment with varying expiration dates through 2009. Rental expenses associated with these leases amounted to $21 million, $20 million and $15 million for 2002, 2001 and 2000, respectively. Contingencies. EOG and numerous other companies in the natural gas industry are named as defendants in various lawsuits alleging violations of the Civil False Claims Act. These lawsuits have been consolidated for pre-trial proceedings in the United States District Court for the District of Wyoming. The plaintiffs contend that defendants have underpaid royalties on natural gas and natural gas liquids produced on federal and Indian lands through the use of below-market prices, improper deductions, improper measurement techniques and transactions with affiliated companies. Plaintiffs allege that the royalties paid by defendants were lower than the royalties required to be paid under federal regulations and that the forms filed by defendants with the Minerals Management Service reporting these royalty payments were false, thereby violating the Civil False Claims Act. The United States has intervened in certain of the cases as to some of the defendants, but has not intervened as to EOG. The plaintiffs in one of the two lawsuits in which EOG is involved recently dismissed EOG from that case without prejudice. Based on EOG's present understanding of the remaining case in which it is a defendant, EOG believes that it has substantial defenses to the plaintiff's claims and intends to vigorously assert these defenses. However, if EOG is found to have violated the Civil False Claims Act, EOG could be subject to a variety of sanctions, including treble damages and substantial monetary fines. There are various other suits and claims against EOG that have arisen in the ordinary course of business. However, management does not believe these suits and claims will individually or in the aggregate have a material adverse effect on the financial condition or results of operations of EOG. EOG has been named as a potentially responsible party in certain Comprehensive Environmental Response Compensation and Liability Act proceedings. However, management does not believe that any potential assessments resulting from such proceedings will individually or in the aggregate have a material adverse effect on the financial condition of EOG. 8. Net Income Per Share Available to Common The following table sets forth the computation of basic and diluted earnings from net income available to common for the years ended December 31 (in thousands, except per share amounts):
2002 2001 2000 Numerator for basic and diluted earnings per share - Net income available to common $ 76,141 $387,622 $385,903 Denominator for basic earnings per share - Weighted average shares 115,335 115,765 116,934 Potential dilutive common shares - Stock options 1,633 1,453 2,038 Restricted stock and units 277 270 130 Denominator for diluted earnings per share - Adjusted weighted average shares 117,245 117,488 119,102 Net income per share of common stock Basic $ 0.66 $ 3.35 $ 3.30 Diluted $ 0.65 $ 3.30 $ 3.24
9. Supplemental Cash Flow Information Cash paid for interest and income taxes was as follows for the years ended December 31 (in thousands):
2002 2001 2000 Interest (net of amount capitalized) $ 54,432 $ 45,715 $ 61,679 Income taxes 15,946 106,312 87,285
10. Business Segment Information EOG's operations are all natural gas and crude oil exploration and production related. SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," establishes standards for reporting information about operating segments in annual financial statements and requires selected information about operating segments in interim financial reports. Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. EOG's chief operating decision making process is informal and involves the Chairman and Chief Executive Officer and other key officers. This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas in the United States and each significant international location. For segment reporting purposes, the major United States producing areas have been aggregated as one reportable segment due to similarities in their operations as allowed by SFAS No. 131. Financial information by reportable segment is presented below for the years ended December 31, or at December 31 (in thousands):
United States Canada Trinidad Other Total 2002 Net Operating Revenues $ 846,071(1) $169,365(1) $ 79,551 $ 49 $1,095,036(1) Depreciation, Depletion and Amortization 334,318 49,622 14,085 11 398,036 Operating Income (Loss) 93,681 40,846 49,450 (2,646) 181,331 Interest Income 765 229 348 -- 1,342 Other Income (Expense) (3,747) 2 394 4 (3,347) Interest Expense 53,345 6,097 211 1 59,654 Income (Loss) Before Income Taxes 37,354 34,980 49,981 (2,643) 119,672 Income Tax Provision (Benefit) (7,684) 20,359 20,974 (1,150) 32,499 Additions to Oil and Gas Properties 517,578 160,840 35,689 20 714,127 Total Assets 2,864,990 665,490 283,395 131 3,814,006 2001 Net Operating Revenues $1,394,457(1) $191,219(1) $ 69,140 $ 71 $1,654,887(1) Depreciation, Depletion and Amortization 348,539 31,821 12,031 8 392,399 Operating Income (Loss) 536,671 107,524 36,761 (6,404) 674,552 Interest Income 415 2,943 1,702 -- 5,060 Other Income (Expense) (3,284) 71 154 2 (3,057) Interest Expense 45,061 750 (701) -- 45,110 Income (Loss) Before Income Taxes 488,741 109,788 39,318 (6,402) 631,445 Income Tax Provision (Benefit) 187,285 28,438 20,166 (3,060) 232,829 Additions to Oil and Gas Properties 729,655 176,101 68,260 -- 974,016 Total Assets 2,676,160 510,476 227,229 179 3,414,044 2000 Net Operating Revenues $1,223,315(1) $184,092(1) $ 82,430 $ 58 $1,489,895(1) Depreciation, Depletion and Amortization 310,685 34,621 13,959 -- 359,265 Operating Income (Loss) 552,091 103,229 41,974 (431) 696,863 Interest Income 354 2,186 915 382 3,837 Other Income (Expense) (6,343) 302 31 (127) (6,137) Interest Expense 54,279 11,140 (4,413) -- 61,006 Income (Loss) Before Income Taxes 491,823 94,577 47,333 (176) 633,557 Income Tax Provision (Benefit) 181,506 31,159 24,076 (115) 236,626 Additions to Oil and Gas Properties 499,207 69,157 33,223 1,051 602,638 Total Assets 2,465,642 374,476 159,872 1,263 3,001,253 (1) EOG had sales activity with a certain purchaser in the United States and Canada segments in 2002 and 2001 that totaled approximately $141.9 million and $224.5 million, respectively, of the Consolidated Net Operating Revenues. Sales activity with another purchaser in the United States and Canada segments in 2000 totaled approximately $183.2 million of the Consolidated Net Operating Revenues.
11. Price and Interest Rate Risk Management Activities EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for natural gas and crude oil. EOG utilizes derivative financial instruments, primarily price swaps and collars, as the means to manage this price risk. During 2002, 2001 and 2000, EOG elected not to designate any of its derivative contracts as accounting hedges and accordingly, accounted for these derivative contracts using mark-to-market accounting. During 2002, EOG recognized mark-to-market losses on commodity contracts of $49 million, which included realized losses of $21 million and a $2 million collar premium payment. During 2001, EOG recognized mark-to-market gains on commodity contracts of $98 million, of which $62 million were realized gains. During 2000, EOG recognized and realized approximately $1 million mark-to-market losses on commodity contracts. Presented below is a summary of EOG's 2003 natural gas financial collar contracts as of December 31, 2002 with prices expressed in dollars per million British thermal units ($/MMBtu) and notional volumes in million British thermal units per day (MMBtud) and a summary of EOG's 2003 crude oil financial price swap contracts as of December 31, 2002 with prices expressed in dollars per barrel ($/Bbl) and notional volumes in barrels per day (Bbld). The fair value of the natural gas financial collar contracts and the crude oil financial price swap contracts at December 31, 2002 was negative $4.3 million and negative $1.6 million, respectively.
Natural Gas Financial Collar Contracts Crude Oil Financial Floor Price Ceiling Price Swap Contracts Weighted Weighted Weighted Volume Floor Range Average Ceiling Range Average Volume Average Month (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (Bbld) ($/Bbl) Jan 50,000 $3.87 $3.87 $6.09 $6.09 2,000 $27.34 Feb 75,000 3.76 - 4.19 3.90 5.05 - 5.98 5.67 2,000 26.91 Mar 75,000 3.61 - 4.08 3.76 5.00 - 5.83 5.55 2,000 26.57 Apr 75,000 3.59 - 3.88 3.69 4.80 - 4.97 4.91 2,000 26.16 May 75,000 3.54 - 3.78 3.62 4.70 - 4.92 4.84 2,000 25.75 Jun 75,000 3.56 - 3.78 3.63 4.70 - 4.94 4.86 2,000 25.39 Jul 75,000 3.59 - 3.79 3.66 4.73 - 4.97 4.89 2,000 25.07 Aug 75,000 3.60 - 3.79 3.66 4.73 - 4.98 4.90 2,000 24.84 Sep 75,000 3.60 - 3.77 3.65 4.73 - 4.98 4.89 2,000 24.63 Oct 75,000 3.60 - 3.77 3.65 4.73 - 4.98 4.90 2,000 24.41 Nov 75,000 3.77 - 3.91 3.81 4.90 - 5.15 5.06 2,000 24.28 Dec 75,000 3.92 - 4.04 3.96 5.05 - 5.30 5.22 2,000 24.10
Presented below is a summary of EOG's 2003 natural gas financial collar contracts and natural gas and crude oil financial price swap contracts as of February 19, 2003:
Natural Gas Financial Collar Contracts Financial Price Swap Contracts Floor Price Ceiling Price Natural Gas Crude Oil Floor Weighted Ceiling Weighted Weighted Weighted Volume Range Average Range Average Volume Average Volume Average Month (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu) (Bbld) ($/Bbl) Jan 50,000 $3.87 $3.87 $6.09 $6.09 -- -- 2,000 $27.34 Feb 125,000 3.76 - 4.30 4.04 5.05 - 6.30 5.87 -- -- 2,000 26.91 Mar 125,000 3.61 - 4.20 3.93 5.00 - 6.20 5.77 100,000 $5.19 4,000 27.96 Apr 125,000 3.59 - 4.02 3.82 4.80 - 6.03 5.33 100,000 4.96 5,000 27.77 May 125,000 3.54 - 3.92 3.74 4.70 - 5.92 5.24 100,000 4.82 5,000 27.04 Jun 125,000 3.56 - 3.89 3.74 4.70 - 5.90 5.25 100,000 4.77 5,000 26.43 Jul 125,000 3.59 - 3.91 3.76 4.73 - 5.91 5.27 100,000 4.77 5,000 25.90 Aug 125,000 3.60 - 3.91 3.76 4.73 - 5.91 5.27 100,000 4.77 5,000 25.49 Sep 125,000 3.60 - 3.89 3.75 4.73 - 5.89 5.26 100,000 4.74 5,000 25.19 Oct 125,000 3.60 - 3.90 3.75 4.73 - 5.90 5.27 100,000 4.74 5,000 24.90 Nov 125,000 3.77 - 4.04 3.90 4.90 - 6.04 5.43 -- -- 5,000 24.70 Dec 125,000 3.92 - 4.18 4.04 5.05 - 6.18 5.57 -- -- 5,000 24.47
During 2001 and 2000, EOG recognized in natural gas and crude oil and condensate revenues hedge losses of $1 million and $17 million, respectively, related to closed hedge positions. Interest Rate Swap Agreements and Foreign Currency Contracts. At December 31, 2000, a subsidiary of EOG and EOG were parties to offsetting foreign currency and interest rate swap agreements with an aggregate notional principal amount of $210 million. Such swap agreements terminated in January 2001. Presently, EOG is not a party to any foreign currency or interest rate swap agreement. The following table summarizes the estimated fair value of financial instruments and related transactions at December 31, 2002 and 2001:
2002 2001 Carrying Estimated Carrying Estimated Amount Fair Value(1) Amount Fair Value(1) (In Millions) (In Millions) Long-Term Debt(2) $1,145.1 $1,224.9 $856.0 $838.3 NYMEX-Related Commodity Market Positions (5.9) (5.9) 19.2 19.2 (1) Estimated fair values have been determined by using available market data and valuation methodologies. Judgment is necessarily required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts. (2) See Note 2 "Long-Term Debt."
Credit Risk. While notional contract amounts are used to express the magnitude of commodity price and interest rate swap agreements, the amounts potentially subject to credit risk, in the event of nonperformance by the other parties, are substantially smaller. EOG evaluates its exposure to all counterparties on an ongoing basis, including those arising from physical and financial transactions. In some instances, EOG requires collateral from its counterparties to minimize any risk, and EOG is actively considering other means of reducing its exposure to individual companies. At December 31, 2002, approximately 13% of EOG's net accounts receivable balance related to natural gas, crude oil and condensate sales was due from a major utility company. This amount was collected during early 2003. The amount due from this utility company at December 31, 2001, which approximated 11% of the net accounts receivable balance, was collected during 2002. No other individual purchaser accounted for 10% or more of the net accounts receivable balance at December 31, 2002 and 2001. At December 31, 2002, EOG had an allowance for doubtful accounts of $20.3 million, of which $19.2 million is associated with the Enron bankruptcies. 12. Concentration of Credit Risk Substantially all of EOG's accounts receivable at December 31, 2002 and 2001 result from crude oil and natural gas sales and/or joint interest billings to third party companies including foreign state-owned entities in the oil and gas industry. This concentration of customers and joint interest owners may impact EOG's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a customer or joint interest owner, EOG analyzes the entity's net worth, cash flows, earnings, and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred on receivables by EOG have been immaterial except for those associated with the Enron bankruptcies. 13. Accounting for Certain Long-Lived Assets Periodically, EOG reviews its oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. During 2002, 2001 and 2000, such reviews indicated that unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows due primarily to downward reserve revisions and lower natural gas and crude oil prices. As a result, EOG recorded in Impairments pre-tax charges of $30 million, $39 million and $11 million, respectively, for 2002, 2001 and 2000 in the United States operating segment. The carrying values for assets determined to be impaired were adjusted to estimated fair values based on projected future net cash flows discounted using EOG risk-adjusted discount rate. Amortization expenses of acquisition costs of unproved properties, including amortization of capitalized interest, were $38 million, $40 million and $35 million for 2002, 2001 and 2000, respectively. 14. Investment in Caribbean Nitrogen Company Limited and Nitrogen (2000) Unlimited EOG, through a subsidiary, owns an approximate 16% equity interest in a Trinidadian company named Caribbean Nitrogen Company Limited ("CNCL") which has constructed an ammonia plant in Pt. Lisas, Trinidad. The other shareholders in CNCL are subsidiaries of Ferrostaal AG, Duke Energy, Halliburton and CL Financial Ltd. At December 31, 2002, investment in CNCL was approximately $14 million. CNCL commenced production in June 2002 and currently produces approximately 1,850 metric tons of ammonia daily. At December 31, 2002, CNCL had a long-term debt balance of approximately $219 million, which is non-recourse to CNCL's shareholders. EOG will be liable for its share of any post-completion deficiency funds loans to fund the costs of operation, payment of principal and interest to the principal creditor and other cash deficiencies of CNCL up to $30 million, approximately $5 million of which is net to EOG's interest. The Shareholders' Agreement requires the consent of the holders of 90% or more of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOG is able to exercise significant influence over the operating and financial policies of CNCL and therefore, it accounts for the investment using the equity method. During 2002, EOG recognized equity income of $0.3 million. Secondly, EOG, through a subsidiary, owns an approximate 31% equity interest in a Trinidadian company named Nitrogen (2000) Unlimited ("N2000"). The other shareholders in N2000 are subsidiaries of Ferrostaal AG, Halliburton and CL Financial Ltd. At December 31, 2002, investment in N2000 was approximately $18 million. N2000 is constructing an ammonia plant in Trinidad, at an expected cost of approximately $320 million, and is expected to commence production in 2005. At December 31, 2002, N2000 had a long-term debt balance of approximately $7 million, which is currently recourse to N2000's shareholders. Upon receipt of an amendment to N2000's certificate of environmental clearance, this long-term debt will become non-recourse to N2000's shareholders. N2000 has applied for the amendment and believes that it will be received in the near future. EOG will be liable for its share of any pre-completion deficiency funds loans to fund plant cost overruns up to $15 million, approximately $5 million of which is net to EOG's interest. EOG will also be liable for its share of any post-completion deficiency funds loans to fund the costs of operation, payment of principal and interest to the principal creditor and other cash deficiencies of N2000 up to $30 million, approximately $9 million of which is net to EOG's interest. The Shareholders' Agreement requires the consent of the holders of 90% or more of the shares to take certain material actions. Accordingly, given its current level of equity ownership, EOG is able to exercise significant influence over the operating and financial policies of N2000 and therefore, it accounts for the investment using the equity method. In November 2002, the EOG subsidiaries along with the Ferrostaal subsidiaries entered into share purchase agreements for the sale of a portion of their shareholdings in CNCL and N2000 with a third party energy company. EOG expects the EOG subsidiaries to close these transactions during the first quarter of 2003 once certain conditions precedent have occurred. EOG does not expect these transactions to result in any gains or losses. EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (In Thousands Except Per Share Amounts Unless Otherwise Indicated) (Unaudited Except for Results of Operations for Oil and Gas Producing Activities) Oil and Gas Producing Activities The following disclosures are made in accordance with SFAS No. 69-"Disclosures about Oil and Gas Producing Activities": Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and EOG's estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause EOG's share of future production from Canadian reserves to be materially different from that presented. EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Estimates of proved and proved developed reserves at December 31, 2002, 2001 and 2000 were based on studies performed by the engineering staff of EOG for reserves in the United States, Canada and Trinidad. Opinions by DeGolyer and MacNaughton ("D&M"), independent petroleum consultants, for the years ended December 31, 2002, 2001 and 2000 covered producing areas containing 73%, 71% and 49%, respectively, of proved reserves of EOG on a net-equivalent-cubic-feet-of-gas basis. D&M's opinions indicate that the estimates of proved reserves prepared by EOG's engineering staff for the properties reviewed by D&M, when compared in total on a net-equivalent-cubic-feet-of- gas basis, do not differ materially from the estimates prepared by D&M. Such estimates by D&M in the aggregate varied by not more than 5% from those prepared by the engineering staff of EOG. All reports by D&M were developed utilizing geological and engineering data provided by EOG. No major discovery or other favorable or adverse event subsequent to December 31, 2002 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date. The following table sets forth EOG's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 2002, and the changes in the net proved reserves for each of the three years in the period then ended as estimated by the engineering staff of EOG. NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
United States Canada Trinidad TOTAL NET PROVED RESERVES Natural Gas (Bcf)(1) Net proved reserves at December 31, 1999 1,657.2 523.5 994.6 3,175.3 Revisions of previous estimates 47.2 6.4 (0.4) 53.2 Purchases in place 188.8 39.4 -- 228.2 Extensions, discoveries and other additions 255.4 23.8 65.1 344.3 Sales in place (84.2) (0.1) -- (84.3) Production (243.0) (47.3) (45.8) (336.1) Net proved reserves at December 31, 2000 1,821.4 545.7 1,013.5 3,380.6 Revisions of previous estimates 15.0 (26.8) (121.6) (133.4) Purchases in place 66.1 111.5 -- 177.6 Extensions, discoveries and other additions 358.3 59.7 295.2 713.2 Sales in place (1.0) -- -- (1.0) Production (252.5) (46.0) (42.0) (340.5) Net proved reserves at December 31, 2001 2,007.3 644.1 1,145.1 3,796.5 Revisions of previous estimates 9.4 4.7 (21.7) (7.6) Purchases in place 9.9 102.9 -- 112.8 Extensions, discoveries and other additions 217.0 83.9 232.4 533.3 Sales in place (0.8) (1.5) -- (2.3) Production (236.6) (56.2) (49.3) (342.1) Net proved reserves at December 31, 2002 2,006.2 777.9 1,306.5 4,090.6
EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
United States Canada Trinidad TOTAL Liquids (MBbl)(2) Net proved reserves at December 31, 1999 47,847 8,896 15,763 72,506 Revisions of previous estimates (1,951) 46 28 (1,877) Purchases in place 3,948 -- -- 3,948 Extensions, discoveries and other additions 12,433 404 738 13,575 Sales in place (484) (2,474) -- (2,958) Production (9,780) (1,055) (957) (11,792) Net proved reserves at December 31, 2000 52,013 5,817 15,572 73,402 Revisions of previous estimates (3,111) 1,294 (3,691) (5,508) Purchases in place 586 35 -- 621 Extensions, discoveries and other additions 12,380 361 1,967 14,708 Sales in place (192) (35) -- (227) Production (9,293) (820) (749) (10,862) Net proved reserves at December 31, 2001 52,383 6,652 13,099 72,134 Revisions of previous estimates 3,543 396 (572) 3,367 Purchases in place 624 865 -- 1,489 Extensions, discoveries and other additions 14,763 279 3,041 18,083 Sales in place (33) -- -- (33) Production (7,925) (1,026) (874) (9,825) Net proved reserves at December 31, 2002 63,355 7,166 14,694 85,215 Bcf Equivalent (Bcfe)(1) Net proved reserves at December 31, 1999 1,944.3 576.9 1,089.2 3,610.4 Revisions of previous estimates 35.5 6.8 (0.2) 42.1 Purchases in place 212.5 39.4 -- 251.9 Extensions, discoveries and other additions 330.0 26.2 69.5 425.7 Sales in place (87.1) (15.0) -- (102.1) Production (301.7) (53.7) (51.6) (407.0) Net proved reserves at December 31, 2000 2,133.5 580.6 1,106.9 3,821.0 Revisions of previous estimates (3.7) (19.1) (143.7) (166.5) Purchases in place 69.7 111.6 -- 181.3 Extensions, discoveries and other additions 432.5 62.0 307.0 801.5 Sales in place (2.2) (0.2) -- (2.4) Production (308.2) (50.9) (46.5) (405.6) Net proved reserves at December 31, 2001 2,321.6 684.0 1,223.7 4,229.3 Revisions of previous estimates 30.7 7.1 (25.1) 12.7 Purchases in place 13.6 108.1 -- 121.7 Extensions, discoveries and other additions 305.6 85.6 250.6 641.8 Sales in place (1.0) (1.5) -- (2.5) Production (284.2) (62.4) (54.5) (401.1) Net proved reserves at December 31, 2002 2,386.3 820.9 1,394.7 4,601.9
EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
United States Canada Trinidad TOTAL NET PROVED DEVELOPED RESERVES Natural Gas (Bcf)(1) December 31, 1999 1,446.5 451.1 250.2 2,147.8 December 31, 2000 1,498.6 479.4 207.0 2,185.0 December 31, 2001 1,588.4 587.6 620.6 2,796.6 December 31, 2002 1,658.7 683.3 555.2 2,897.2 Liquids (MBbl) (2) December 31, 1999 41,717 7,041 3,833 52,591 December 31, 2000 42,132 5,695 2,967 50,794 December 31, 2001 41,205 6,532 8,435 56,172 December 31, 2002 47,476 7,045 7,135 61,656 Bcf Equivalents (Bcfe)(1) December 31, 1999 1,696.8 493.3 273.2 2,463.3 December 31, 2000 1,751.4 513.6 224.8 2,489.8 December 31, 2001 1,835.7 626.8 671.1 3,133.6 December 31, 2002 1,943.6 725.5 598.0 3,267.1 ___________________________ (1) Billion cubic feet or billion cubic feet equivalent, as applicable. (2) Thousand barrels; includes crude oil, condensate and natural gas liquids.
Capitalized Costs Relating to Oil and Gas Producing Activities. The following table sets forth the capitalized costs relating to EOG's natural gas and crude oil producing activities at December 31, 2002 and 2001:
2002 2001 Proved Properties $6,527,716 $5,847,053 Unproved Properties 222,379 218,550 Total 6,750,095 6,065,603 Accumulated depreciation, depletion and amortization (3,428,547) (3,009,693) Net capitalized costs $3,321,548 $3,055,910
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19- "Financial Accounting and Reporting by Oil and Gas Producing Companies." Acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Exploration costs include exploration expenses and additions to exploration wells including those in progress. EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Development costs include additions to production facilities and equipment and additions to development wells including those in progress. The following tables set forth costs incurred related to EOG's oil and gas activities for the years ended December 31:
United States Canada Trinidad Other TOTAL 2002 Acquisition Costs of Properties Unproved $ 28,232 $ 4,754 $ 5,629 $ -- $ 38,615 Proved 22,589 48,487 -- -- 71,076 Subtotal 50,821 53,241 5,629 -- 109,691 Exploration Costs 120,058 25,866 18,117 2,384 166,425 Development Costs 423,436 107,952 13,600 -- 544,988 Subtotal 594,315 187,059 37,346 2,384 821,104 Deferred Income Tax Gross Up -- 14,938 -- -- 14,938 Total $594,315 $201,997 $37,346 $2,384 $ 836,042 2001 Acquisition Costs of Properties Unproved $ 69,308 $ 6,967 $ -- $ -- $ 76,275 Proved 95,646 72,660 -- -- 168,306 Subtotal 164,954 79,627 -- -- 244,581 Exploration Costs 163,602 16,708 13,695 8,739 202,744 Development Costs 512,175 92,374 60,969 -- 665,518 Subtotal 840,731 188,709 74,664 8,739 1,112,843 Deferred Income Tax Gross Up 19,411 30,845 -- -- 50,256 Total $860,142 $219,554 $74,664 $8,739 $1,163,099 2000 Acquisition Costs of Properties Unproved $ 45,456 $ 5,741 $ -- $ -- $ 51,197 Proved 88,473 13,965 -- -- 102,438 Subtotal 133,929 19,706 -- -- 153,635 Exploration Costs 98,654 9,711 10,849 3,581 122,795 Development Costs 335,053 46,000 29,688 -- 410,741 Subtotal 567,636 75,417 40,537 3,581 687,171 Deferred Income Tax Gross Up 18,744 3,685 -- -- 22,429 Total $586,380 $ 79,102 $40,537 $3,581 $ 709,600
EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Results of Operations for Oil and Gas Producing Activities(1). The following tables set forth results of operations for oil and gas producing activities for the years ended December 31:
United States Canada Trinidad SUBTOTAL Other(2) TOTAL 2002 Natural Gas, Crude Oil and Condensate Revenues $ 891,960 $170,875 $79,551 $1,142,386 $ 52 $1,142,438 Gains (Losses) on Sales of Reserves and Related Assets and Other, Net 2,616 (1,510) -- 1,106 -- 1,106 Total 894,576 169,365 79,551 1,143,492 52 1,143,544 Exploration Expenses, including Dry Hole 78,937 26,171 1,656 106,764 213 106,977 Production Costs 186,024 48,261 9,977 244,262 88 244,350 Impairments 65,813 2,619 -- 68,432 (2) 68,430 Depreciation, Depletion and Amortization 334,318 49,622 14,085 398,025 11 398,036 Income (Loss) before Income Taxes 229,484 42,692 53,833 326,009 (258) 325,751 Income Tax Provision (Benefit) 82,136 10,319 23,971 116,426 (90) 116,336 Results of Operations $ 147,348 $ 32,373 $29,862 $ 209,583 $ (168) $ 209,415 2001 Natural Gas, Crude Oil and Condensate Revenues $1,295,894 $191,096 $69,141 $1,556,131 $ 72 $1,556,203 Gains on Sales of Reserves and Related Assets and Other, Net 811 123 -- 934 -- 934 Total 1,296,705 191,219 69,141 1,557,065 72 1,557,137 Exploration Expenses, including Dry Hole 113,419 12,596 6,405 132,420 6,407 138,827 Production Costs 219,504 34,426 10,308 264,238 49 264,287 Impairments 76,801 2,355 -- 79,156 -- 79,156 Depreciation, Depletion and Amortization 348,397 31,821 12,031 392,249 9 392,258 Income (Loss) before Income Taxes 538,584 110,021 40,397 689,002 (6,393) 682,609 Income Tax Provision (Benefit) 198,243 32,663 22,218 253,124 (2,238) 250,886 Results of Operations $ 340,341 $ 77,358 $18,179 $ 435,878 $(4,155) $ 431,723 2000 Natural Gas, Crude Oil and Condensate Revenues $1,215,051 $183,989 $82,431 $1,481,471 $ 59 $1,481,530 Gains on Sales of Reserves and Related Assets and Other, Net 9,262 103 -- 9,365 -- 9,365 Total 1,224,313 184,092 82,431 1,490,836 59 1,490,895 Exploration Expenses, including Dry Hole 72,000 4,881 7,314 84,195 337 84,532 Production Costs 181,266 31,784 15,669 228,719 129 228,848 Impairments 39,775 6,703 -- 46,478 -- 46,478 Depreciation, Depletion and Amortization 310,612 34,621 13,959 359,192 2 359,194 Income (Loss) before Income Taxes 620,660 106,103 45,489 772,252 (409) 771,843 Income Tax Provision (Benefit) 226,657 41,274 25,019 292,950 (143) 292,807 Results of Operations $ 394,003 $ 64,829 $20,470 $ 479,302 $ (266) $ 479,036 (1) Excludes mark-to-market gains or losses on commodity derivative contracts, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2002. (2) Other includes other international operations.
EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves. The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the engineering staff of EOG. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating EOG or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG. The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's crude oil and natural gas reserves for the years ended December 31:
United States Canada Trinidad TOTAL 2002 Future cash inflows $ 9,826,571 $ 2,989,000 $2,303,930 $15,119,501 Future production costs (2,212,357) (586,166) (433,029) (3,231,552) Future development costs (359,787) (43,876) (177,275) (580,938) Future net cash flows before income taxes 7,254,427 2,358,958 1,693,626 11,307,011 Future income taxes (2,214,072) (653,425) (558,788) (3,426,285) Future net cash flows 5,040,355 1,705,533 1,134,838 7,880,726 Discount to present value at 10% annual rate (2,265,700) (766,567) (629,024) (3,661,291) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves(1) $ 2,774,655 $ 938,966 $ 505,814 $ 4,219,435 2001 Future cash inflows $ 5,677,824 $ 1,490,552 $1,472,197 $ 8,640,573 Future production costs (1,528,474) (371,124) (335,395) (2,234,993) Future development costs (387,048) (31,232) (110,331) (528,611) Future net cash flows before income taxes 3,762,302 1,088,196 1,026,471 5,876,969 Future income taxes (930,505) (295,739) (265,709) (1,491,953) Future net cash flows 2,831,797 792,457 760,762 4,385,016 Discount to present value at 10% annual rate (1,121,771) (321,980) (413,876) (1,857,627) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 1,710,026 $ 470,477 $ 346,886 $ 2,527,389 2000 Future cash inflows $18,500,822 $ 4,704,243 $1,860,366 $25,065,431 Future production costs (2,766,579) (389,819) (668,549) (3,824,947) Future development costs (279,407) (44,011) (194,741) (518,159) Future net cash flows before income taxes 15,454,836 4,270,413 997,076 20,722,325 Future income taxes (5,074,986) (1,451,776) (230,712) (6,757,474) Future net cash flows 10,379,850 2,818,637 766,364 13,964,851 Discount to present value at 10% annual rate (4,368,717) (1,304,886) (377,811) (6,051,414) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 6,011,133 $ 1,513,751 $ 388,553 $ 7,913,437 (1) Natural gas prices have changed since December 31, 2002; consequently, the discounted future net cash flows would be different if the standardized measure was calculated in the first quarter of 2003.
EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2002.
United States Canada Trinidad TOTAL December 31, 1999 $ 1,727,232 $ 377,891 $ 288,933 $ 2,394,056 Sales and transfers of oil and gas produced, net of production costs (1,048,804) (152,602) (66,761) (1,268,167) Net changes in prices and production costs 5,459,629 1,850,021 153,961 7,463,611 Extensions, discoveries, additions and improved recovery net of related costs 1,502,377 94,379 20,544 1,617,300 Development costs incurred 77,000 24,100 29,600 130,700 Revisions of estimated development costs (19,055) 39 (39,590) (58,606) Revisions of previous quantity estimates 153,862 30,376 (129) 184,109 Accretion of discount 190,045 48,912 45,192 284,149 Net change in income taxes (2,436,834) (606,556) 8,566 (3,034,824) Purchases of reserves in place 671,604 136,138 -- 807,742 Sales of reserves in place (331,960) (22,454) -- (354,414) Changes in timing and other 66,037 (266,493) (51,763) (252,219) December 31, 2000 6,011,133 1,513,751 388,553 7,913,437 Sales and transfers of oil and gas produced, net of production costs (1,060,926) (156,787) (58,832) (1,276,545) Net changes in prices and production costs (6,400,910) (1,822,229) (194,995) (8,418,134) Extensions, discoveries, additions and improved recovery net of related costs 347,088 48,271 114,871 510,230 Development costs incurred 101,900 27,500 71,088 200,488 Revisions of estimated development cost (5,296) 2,931 10,947 8,582 Revisions of previous quantity estimates (3,563) (12,536) 47,418 31,319 Accretion of discount 862,118 223,154 54,297 1,139,569 Net change in income taxes 2,313,068 592,322 15,087 2,920,477 Purchases of reserves in place 35,686 78,790 -- 114,476 Sales of reserves in place (6,165) (303) -- (6,468) Changes in timing and other (484,107) (24,387) (101,548) (610,042) December 31, 2001 1,710,026 470,477 346,886 2,527,389 Sales and transfers of oil and gas produced, net of production costs (705,938) (122,614) (69,574) (898,126) Net changes in prices and production costs 1,561,946 460,977 223,614 2,246,537 Extensions, discoveries, additions and improved recovery net of related costs 499,257 123,700 110,415 733,372 Development costs incurred 84,300 18,100 13,600 116,000 Revisions of estimated development cost 35,255 (11,418) (20,574) 3,263 Revisions of previous quantity estimates 51,227 11,470 (15,634) 47,063 Accretion of discount 200,701 59,594 48,622 308,917 Net change in income taxes (692,670) (135,888) (87,229) (915,787) Purchases of reserves in place 28,851 117,958 -- 146,809 Sales of reserves in place (715) (2,827) -- (3,542) Changes in timing and other 2,415 (50,563) (44,312) (92,460) December 31, 2002 $ 2,774,655 $ 938,966 $ 505,814 $ 4,219,435
EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded) Unaudited Quarterly Financial Information
Quarter Ended March 31 June 30 Sept. 30 Dec. 31 2002 Net Operating Revenues $186,503 $290,503 $279,869 $338,161 Operating Income (Loss) $(20,706) $ 69,640 $ 61,700 $ 70,697 Income (Loss) before Income Taxes $(35,860) $ 55,555 $ 42,866 $ 57,111 Income Tax Provision (Benefit) (11,619) 17,447 13,979 12,692 Net Income (Loss) (24,241) 38,108 28,887 44,419 Preferred Stock Dividends 2,758 2,758 2,758 2,758 Net Income (Loss) Available to Common $(26,999) $ 35,350 $ 26,129 $ 41,661 Net Income (Loss) per Share Available to Common Basic(1) $ (0.23) $ 0.31 $ 0.23 $ 0.36 Diluted(1) $ (0.23) $ 0.30 $ 0.22 $ 0.36 Average Number of Common Shares Basic 115,485 115,737 115,621 114,742 Diluted 115,485 117,689 117,078 116,908 2001 Net Operating Revenues $597,253 $466,048 $354,172 $237,414 Operating Income (Loss) $354,024 $234,239 $123,947 $(37,658) Income (Loss) before Income Taxes $340,096 $224,865 $114,977 $(48,493) Income Tax Provision (Benefit) 124,849 88,662 43,014 (23,696) Net Income (Loss) 215,247 136,203 71,963 (24,797) Preferred Stock Dividends 2,721 2,757 2,759 2,757 Net Income (Loss) Available to Common $212,526 $133,446 $ 69,204 $(27,554) Net Income (Loss) per Share Available to Common Basic(1) $ 1.83 $ 1.15 $ 0.60 $ (0.24) Diluted(1) $ 1.79 $ 1.13 $ 0.59 $ (0.24) Average Number of Common Shares Basic 116,384 115,870 115,692 115,115 Diluted 118,952 118,047 117,141 115,115 (1) The sum of quarterly net income per share available to common may not agree with total year net income per share available to common as each quarterly computation is based on the weighted average of common shares outstanding.
EXHIBIT INDEX Exhibit No. Description 23.1 Consent of DeGolyer and MacNaughton 23.2 Opinion of DeGolyer and MacNaughton dated January 31, 2003 23.3 Consent of Deloitte & Touche LLP