8-K 1 h84540e8-k.txt EOG RESOURCES, INC. DATED 2/26/01 1 ================================================================================ 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 26, 2001 ---------- EOG RESOURCES, INC. (Exact name of registrant as specified in its charter) DELAWARE 1-9743 47-0684736 (State or other jurisdiction (Commission File (I.R.S. Employer of incorporation or organization) Number) Identification No.) 1200 SMITH STREET SUITE 300 HOUSTON, TEXAS 77002 (Address of principal executive offices) (Zip code) 713/651-7000 (Registrant's telephone number, including area code) ================================================================================ 2 EOG RESOURCES, INC. ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS. (a) Financial Statements of EOG Resources, Inc. Financial Statements of EOG Resources, Inc. and its Consolidated Subsidiaries for the fiscal year ended December 31, 2000, including Report of Arthur Andersen LLP, Independent Public Accountants. (b) Exhibits. 23.1 Consent of DeGolyer and MacNaughton. 23.2 Opinion of DeGolyer and MacNaughton dated February 8, 2001. 23.3 Consent of Arthur Andersen LLP. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. EOG RESOURCES, INC. (Registrant) Date: February 26, 2001 By: /s/ TIMOTHY K. DRIGGERS ------------------------------ Timothy K. Driggers Vice President, Accounting & Land Administration (Principal Accounting Officer) 2 3 EOG RESOURCES, INC. TABLE OF CONTENTS
PAGE NO. Management's Discussion and Analysis of Financial Condition and Results of Operations............................................ 4 Management's Responsibility for Financial Reporting....................... 10 Report of Independent Public Accountants.................................. 11 Consolidated Statements of Income and Comprehensive Income for the years ended December 31, 2000, 1999 and 1998................. 12 Consolidated Balance Sheets, December 31, 2000 and 1999................... 13 Consolidated Statements of Shareholders' Equity for the years ended December 31, 2000, 1999 and 1998.......... 14 Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998.............................................. 15 Notes to Consolidated Financial Statements................................ 16 Supplemental Information to Consolidated Financial Statements............. 30 Exhibits Exhibit 23.1 - Consent of DeGolyer and MacNaughton................... 39 Exhibit 23.2 - Opinion of DeGolyer and MacNaughton dated February 8, 2001................................................ 40 Exhibit 23.3 - Consent of Arthur Andersen LLP........................ 42
3 4 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following review of operations for each of the three years in the period ended December 31, 2000 should be read in conjunction with the consolidated financial statements of EOG Resources, Inc. ("EOG") and notes thereto beginning with page 12. As a result of the consensus of Emerging Issues Task Force Issue 00-10, "Accounting for Shipping and Handling Fees and Costs," EOG reclassified all prior periods to reflect certain transportation expenses incurred as lease and well expenses, instead of deductions from revenues as previously reported. RESULTS OF OPERATIONS Net Operating Revenues. Wellhead volume and price statistics for the specified years were as follows:
YEAR ENDED DECEMBER 31, --------------------------------- 2000 1999 1998 --------- --------- --------- NATURAL GAS VOLUMES (MMcf PER DAY) United States ...................................... 654 654 671(1) Canada ............................................. 129 115 105 Trinidad ........................................... 125 123 139 India(2) ........................................... -- 46 56 --------- --------- --------- TOTAL ........................................ 908 938 971 ========= ========= ========= AVERAGE NATURAL GAS PRICES ($/Mcf) United States ...................................... $ 3.96 $ 2.20 $ 2.01(3) Canada ............................................. 3.33 1.88 1.48 Trinidad ........................................... 1.17 1.08 1.06 India(2) ........................................... -- 2.09 2.57 COMPOSITE .................................... 3.49 2.01 1.85 CRUDE OIL AND CONDENSATE VOLUMES (MBbl PER DAY) United States ...................................... 22.8 14.4 14.0 Canada ............................................. 2.1 2.6 2.6 Trinidad ........................................... 2.6 2.4 3.0 India(2) ........................................... -- 4.1 5.1 --------- --------- --------- TOTAL ........................................ 27.5 23.5 24.7 ========= ========= ========= AVERAGE CRUDE OIL AND CONDENSATE PRICES ($/Bbl) United States ...................................... $ 29.68 $ 18.55 $ 12.89 Canada ............................................. 27.76 16.77 11.82 Trinidad ........................................... 30.14 16.21 12.26 India(2) ........................................... -- 12.80 12.86 COMPOSITE .................................... 29.57 17.12 12.69 NATURAL GAS LIQUIDS VOLUMES (MBbl PER DAY) United States ...................................... 4.0 2.6 2.9 Canada ............................................. 0.7 0.8 1.0 --------- --------- --------- TOTAL ........................................ 4.7 3.4 3.9 ========= ========= ========= AVERAGE NATURAL GAS LIQUIDS PRICES ($/Bbl) United States ...................................... $ 20.45 $ 13.41 $ 9.50 Canada ............................................. 16.75 8.23 5.32 COMPOSITE .................................... 19.87 12.24 8.38 NATURAL GAS EQUIVALENT VOLUMES (MMcfe PER DAY)(4) United States ...................................... 814 757 771 Canada ............................................. 146 134 128 Trinidad ........................................... 141 138 157 India(2) ........................................... -- 70 86 --------- --------- --------- TOTAL ........................................ 1,101 1,099 1,142 ========= ========= ========= TOTAL Bcfe DELIVERIES ................................. 403 401 417
---------- (1) Includes 48 MMcf per day delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. Delivery obligations were terminated in December 1998. (2) See Note 4 to the Consolidated Financial Statements regarding the Share Exchange Agreement with Enron Corp. (3) Includes an average equivalent wellhead value of $1.88 per Mcf for the volumes detailed in note (1). (4) Includes natural gas, crude oil, condensate and natural gas liquids. 4 5 2000 compared to 1999. During 2000, net operating revenues increased $648 million to $1,490 million. Total wellhead revenues of $1,491 million increased by $641 million, or 75%, as compared to 1999. Average wellhead natural gas prices for 2000 were approximately 74% higher than the comparable period in 1999, increasing net operating revenues by $491 million. Average wellhead crude oil and condensate prices were up by 73%, increasing net operating revenues by $125 million. Wellhead natural gas volumes were approximately 3% lower than the comparable period in 1999, decreasing net operating revenues by $20 million. The decrease in wellhead natural gas volumes is primarily due to the transfer of producing properties in connection with the Share Exchange Agreement ("Share Exchange") described in Note 4 to the Consolidated Financial Statements, partially offset by increased deliveries in Canada and Trinidad. Wellhead crude oil and condensate volumes were 17% higher than in 1999, increasing net operating revenues by $26 million. The increase in wellhead crude oil and condensate volumes is primarily due to increased deliveries in the United States and Trinidad, partially offset by the transfer of producing properties in the Share Exchange and decreased deliveries in Canada. Natural gas liquids prices and deliveries were approximately 62% and 39% higher than 1999, increasing net operating revenues by $13 million and $6 million, respectively. Gains (losses) on sales of reserves and related assets and other, net totaled a gain of $8 million during 2000 compared to a loss of nearly $1 million in 1999. The difference is due primarily to a $7 million gain on sales of certain North America properties in 2000. Other marketing activities associated with sales and purchases of natural gas, and natural gas and crude oil price hedging and trading transactions decreased net operating revenue by $10 million during 2000, compared to a $7 million reduction in 1999. 1999 compared to 1998. During 1999, net operating revenues increased $34 million to $842 million. Total wellhead revenues of $850 million increased by $69 million, or 9%, as compared to 1998. Average wellhead natural gas prices for 1999 were approximately 9% higher than the comparable period in 1998 increasing net operating revenues by approximately $56 million. Average wellhead crude oil and condensate prices were up by 35% increasing net operating revenues by $38 million. Revenues from the sale of natural gas liquids increased $3 million primarily due to higher wellhead prices. Wellhead natural gas volumes were approximately 3% lower than the comparable period in 1998 decreasing net operating revenues by nearly $22 million. The decrease in volumes is primarily due to the transfer of producing properties in the Share Exchange and decreased deliveries in Trinidad. Production in Trinidad decreased 16 MMcf per day due primarily to decreased nominations and the temporary shut-in of a well in accordance with the terms of a field allocation agreement. North America wellhead natural gas production was approximately 1% lower than the comparable period in 1998. Wellhead crude oil and condensate volumes were 5% lower than in 1998 decreasing net operating revenues by $6 million. The decrease is primarily attributable to the Share Exchange and decreased deliveries in Trinidad. Gains (losses) on sales of reserves and related assets and other, net totaled a loss of $1 million during 1999 compared to a net gain of $18 million in 1998. The difference is due primarily to an $8 million loss in 1999 related to the anticipated disposition of certain international assets compared to a $27 million gain on sale of certain South Texas properties, partially offset by a $14 million provision for loss on certain physical natural gas contracts in 1998. Other marketing activities associated with sales and purchases of natural gas, natural gas and crude oil price hedging and trading transactions, and margins related to the volumetric production payment (in 1998) decreased net operating revenue by $7 million during 1999, compared to a $9 million addition in 1998. Operating Expenses 2000 compared to 1999. During 2000, operating expenses of $793 million were approximately $31 million lower than the $824 million incurred in 1999. Lease and well expenses increased $9 million to $141 million primarily due to continually expanding operations and increases in production activity in North America. Exploration expenses of $67 million and dry hole expenses of $17 million increased $14 million and $5 million, respectively, from 1999 due to increased exploratory drilling activities. Impairment of unproved oil and gas properties increased $4 million to $36 million as a result of increased acquisition of unproved leases in North America. Depreciation, depletion and amortization ("DD&A") expense decreased $90 million primarily due to charges of $15 million pursuant to a change in EOG's strategy related to certain offshore operations in the second quarter of 1999, the impairment of various North America properties in the fourth quarter of 1999, and non-recurring charges of $114 million related primarily to assets determined no longer central to EOG's business in the third quarter of 1999. General and 5 6 administrative ("G&A") expenses decreased $16 million primarily due to non-recurring costs in 1999 of $14 million related to the Share Exchange, the potential sale of EOG and personnel expenses partially offset by savings resulting from the discontinuance of the India and China operations as a result of the Share Exchange. Taxes other than income increased $42 million reflecting higher state severance taxes associated with higher taxable wellhead revenues resulting from higher average prices. Total operating costs per unit of production, which include lease and well, DD&A, G&A, taxes other than income and interest expense, decreased 7% to $1.82 per thousand cubic feet equivalent ("Mcfe") in 2000 from $1.97 in 1999. This decrease is primarily due to lower per unit rates of DD&A and G&A, partially offset by higher per unit rates of taxes other than income and lease and well. Excluding the aforementioned 1999 charges of $15 million and $114 million in DD&A and $14 million in G&A, the per unit operating costs for EOG were $1.61 per Mcfe in 1999. The per unit operating costs in 2000 of $1.82 was $.21 higher than this adjusted per unit operating costs of 1999 primarily due to a higher per unit rate of DD&A, taxes other than income and lease and well expense. 1999 compared to 1998. During 1999, operating expenses of $824 million were approximately $129 million higher than the $695 million incurred in 1998. Lease and well expenses decreased $6 million to $132 million primarily due to the effects of the Share Exchange, fewer workovers, the effects of a warm winter and a continuing focus on controlling operating costs in all areas of EOG operations. Exploration expenses of $53 million and dry hole expenses of $12 million decreased $13 million and $11 million, respectively, from 1998 primarily due to implementation of cost provisions of certain new service agreements in North America. Impairment of unproved oil and gas properties of $32 million remained essentially flat compared to 1998. DD&A expense increased approximately $145 million to $460 million in 1999 primarily due to charges of $15 million pursuant to a change in EOG's strategy related to certain offshore operations in the second quarter and an impairment of various North America properties in the fourth quarter, and non-recurring charges of $114 million related primarily to assets determined no longer central to EOG's business in the third quarter. G&A expenses were $14 million higher than in 1998 due to non-recurring costs of $5 million related to the potential sale of EOG, $4 million related to personnel expenses and $9 million related to the completion of the Share Exchange partially offset by a reduction of $4 million resulting from the discontinuance of the India and China operations as a result of the Share Exchange. Total operating costs per unit of production, which include lease and well, DD&A, G&A, taxes other than income and interest expense, increased 32% to $1.97 per Mcfe in 1999 from $1.49 per Mcfe in 1998. This increase is primarily due to a higher per unit rate of DD&A, G&A and interest expense. Excluding the aforementioned charges of $15 million and $114 million in DD&A and $14 million in G&A, the per unit operating costs for EOG were $1.61 per Mcfe. The adjusted per unit operating costs were $0.12 higher compared to $1.49 per Mcfe for the comparable period in 1998 primarily due to a higher per unit rate of interest as a result of higher debt levels and a higher per unit rate of DD&A expense. Other Income (Expense). Other income of $611 million for 1999 included a $575 million net gain from the Share Exchange, a $59.6 million gain on the sale of 3.2 million options owned by EOG to purchase Enron Corp. common stock, and a $19.4 million charge for estimated exit costs related to EOG's decision to dispose of certain international assets. Interest Expense. The increase in net interest expense of $13 million from 1998 to 1999 primarily reflects a higher level of debt outstanding due to expanded worldwide operations and common stock repurchases (See Note 2 to the Consolidated Financial Statements). Income Taxes. Income tax provision increased approximately $238 million for 2000 as compared to 1999 as a result of a higher pre-tax income year to year after removing the non-taxable gain on the Share Exchange in 1999. Income tax provision decreased approximately $5 million for 1999 as compared to 1998 primarily due to lower pre-tax income year to year after removing the non-taxable gain on the Share Exchange in 1999. CAPITAL RESOURCES AND LIQUIDITY Cash Flow. The primary sources of cash for EOG during the three-year period ended December 31, 2000 included funds generated from operations, proceeds from the sales of other assets, selected oil and gas reserves and related assets, funds from new borrowings and proceeds from equity offerings. Primary cash outflows included funds used in operations, exploration and development expenditures, common stock repurchases, dividends paid to EOG shareholders, repayments of debt and cash contributed to transferred subsidiaries in the Share Exchange. 6 7 Net operating cash flows of $967 million in 2000 increased approximately $524 million as compared to 1999 due to higher net operating revenues resulting from higher prices, net of cash operating expenses, and higher tax benefits from stock options exercised partially offset by higher current income taxes. Changes in working capital and other liabilities decreased operating cash flows by $16 million as compared to 1999 primarily due to changes in accounts receivable, accrued royalties payable and accrued production taxes caused by fluctuation of commodity prices at each yearend. Net investing cash outflows of $667 million in 2000 increased by $304 million as compared to 1999 due primarily to increased exploration and development expenditures of $231 million (including producing property acquisitions), increased equity investments, and the non-recurrence of proceeds from sales of Enron Corp. options in 1999, partially offset by increased proceeds from sales of reserves and related assets. Changes in components of working capital associated with investing activities included changes in accounts payable associated with the accrual of exploration and development expenditures and changes in inventories which represent materials and equipment used in drilling and related activities. Cash used in financing activities in 2000 was $305 million as compared to $62 million in 1999. Financing activities in 2000 included repayments of debt of $131 million, common stock repurchases of $273 million and dividend payments of $26 million, partially offset by proceeds from sales of treasury stock of $127 million. Net operating cash flows of $444 million in 1999 increased approximately $40 million as compared to 1998 due to higher net operating revenues resulting from higher prices, net of cash operating expenses, and lower current income taxes. Changes in working capital and other liabilities decreased operating cash flows by $18 million as compared to 1998 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 $363 million in 1999 decreased by $396 million as compared to 1998 due primarily to decreased exploration and development expenditures of $312 million (including producing property acquisitions) and higher proceeds from sales of other assets of $83 million partially offset by lower proceeds from sales of reserves and related assets of $51 million. Changes in components of working capital associated with investing activities included for all periods changes in accounts payable related to 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 1999 was $62 million as compared to cash provided by financing activities of $353 million in 1998. Financing activities in 1999 included funds used in the Share Exchange of $609 million, dividend payments of $17 million, transaction fees of $19 million associated with the Share Exchange and other financing transactions, and net repayment of $152 million of long-term debt, partially offset by net proceeds from common and preferred equity offerings of $725 million and proceeds from sales of treasury stock of $13 million. Discretionary cash flow available to common, a frequently used measure of performance for exploration and production companies, is generally derived by adjusting net income to include tax benefits on stock options exercised and to eliminate the effects of depreciation, depletion and amortization, impairment of unproved oil and gas properties, deferred income taxes, gains on sales of oil and gas reserves and related assets, certain other non-cash amounts, except for amortization of deferred revenue and exploration and dry hole costs. EOG generated discretionary cash flow available to common of approximately $1,007 million in 2000, $477 million in 1999 and $463 million in 1998. Discretionary cash flow available to common should not be considered as an alternative to income from operations or to cash flows from operating activities (as determined in accordance with accounting principles generally accepted in the United States) and should not be construed as an indication of a company's operating performance or as a measure of liquidity. Exploration and Development Expenditures. The table below sets out components of actual exploration and development expenditures for the years ended December 31, 2000, 1999 and 1998, along with the total budgeted for 2001, excluding acquisitions.
EXCLUDING INDIA AND BUDGETED 2001 ACTUAL CHINA OPERATIONS (EXCLUDING ACQUISITIONS) ------------------------ ------------------- ------------------------ EXPENDITURE CATEGORY 2000 1999 1998 1999 1998 -------------------- ------ ------ ------ ------- --------- (IN MILLIONS) Capital Drilling and Facilities ............. $ 443 $ 319 $ 420 $ 293 $ 373 Leasehold Acquisitions .............. 51 21 36 21 36 Producing Property Acquisitions ..... 102 45 211 43 211 Capitalized Interest ................ 7 11 13 8 9 ------ ------ ------ ------ ------ Subtotal ......................... 603 396 680 365 629 Exploration Costs ...................... 67 53 66 51 64 Dry Hole Costs ......................... 17 12 23 12 23 ------ ------ ------ ------ ------ Total .................................. $ 687 $ 461 $ 769 $ 428 $ 716 $700 - $800 ====== ====== ====== ====== ====== ===========
7 8 Exploration and development expenditures increased $226 million in 2000 as compared to 1999 primarily due to increased exploration and development activities in the United States and Trinidad, and acquisitions of oil and gas properties in North America, partially offset by the Share Exchange and the acquisition of producing properties in the Big Piney area in the first quarter of 1999. Hedging Transactions. EOG's 2000 NYMEX-related natural gas and crude oil commodity price swaps decreased net operating revenues by $11 million and $6 million, respectively. At December 31, 2000, there were open crude oil commodity price swaps for 2001 covering approximately 0.7 MMBbl of crude oil at a weighted average price of $26.25 per barrel. There were no open natural gas commodity price swaps. Financing. EOG's long-term debt-to-total-capital ratio was 38% as of December 31, 2000 compared to 47% as of December 31, 1999. During 2000, total long-term debt decreased $131 million to $859 million primarily due to higher cash flow from operations primarily resulting from higher oil and gas prices, partially offset by additions to oil and gas properties and significant share repurchases of common stock. (See Note 2 to the Consolidated Financial Statements). The estimated fair value of EOG's long-term debt at December 31, 2000 and 1999 was $831 million and $933 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, 2000, a 1% change in interest rates would result in a $44 million change in the estimated fair value of the fixed rate obligations. (See Note 12 to the Consolidated Financial Statements). 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. Such registration statement was declared effective by the Securities and Exchange Commission on October 27, 2000. As of February 15, 2001, 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, such 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 improvements in the technology used in drilling and completing crude oil and natural gas wells, improvements being realized in the availability and utilization of natural gas storage capacity and colder weather experienced in the latter part of 2000. However, the increasing recognition of natural gas as a more environmentally friendly source of energy along with the availability of significant domestically sourced supplies should result in further increases in demand. Being primarily a natural gas producer, EOG is more significantly impacted by changes in natural gas prices than by changes in crude oil and condensate prices. At December 31, 2000, based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2001 for which prices have not, in effect, been hedged using NYMEX-related commodity market transactions and long-term marketing contracts, EOG's price sensitivity for each $.10 per Mcf change in average wellhead natural gas prices is $19 million (or $0.16 per share) for net income and $19 million for current operating cash flow. EOG is not impacted as significantly by changing crude oil prices for those volumes not otherwise hedged. EOG's price sensitivity for each $1.00 per barrel change in average wellhead crude oil prices is $6 million (or $0.05 per share) for net income and $6 million for current operating cash flow. EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in North America. However, in order to diversify its overall asset portfolio and as a result of its overall success realized in Trinidad, EOG anticipates expending a portion of its available funds in the further development of opportunities outside North America. In addition, EOG expects to conduct limited exploratory activity in other areas outside of North America and will continue to evaluate the potential for involvement in other exploitation type opportunities. Budgeted 2001 expenditures, excluding acquisitions, are in the range of $700 - $800 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 2001 are structured to maintain the flexibility necessary under EOG's continuing strategy of funding North America exploration, exploitation, development and acquisition activities primarily from available internally generated cash flow. The level of exploration and development expenditures may vary in 2001 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 2001 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 8 9 its exploration, exploitation, development and acquisition expenditure plans if circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to operations in Trinidad, such commitments are not anticipated to be material when considered in relation to the total financial capacity of EOG. Environmental Regulations. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to protection of the environment, may affect EOG's operations and costs as a result of their effect on natural gas and crude oil exploration, exploitation, development and production operations. 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. NEW ACCOUNTING PRONOUNCEMENT--SFAS NO. 133 In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133--"Accounting for Derivative Instruments and Hedging Activities" effective for fiscal years beginning after June 15, 1999. In June 1999, the FASB issued SFAS No. 137, which delayed the effective date of SFAS No. 133 for one year, to fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, which amends the accounting and reporting standards of SFAS No. 133 for certain derivative instruments and certain hedging activities. SFAS No. 133, as amended by SFAS No. 137 and No. 138, cannot be applied retroactively and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after a transition date to be selected by EOG of either December 31, 1997 or December 31, 1998. The statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the statements of income and requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. EOG adopted SFAS No. 133, as amended by SFAS No. 137 and No. 138, on January 1, 2001 for the accounting periods which begin thereafter. The adoption of SFAS No. 133 did not have a material impact on EOG's financial statements. 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" 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 or the ability to increase reserves or 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: timing and extent of changes in commodity prices for crude oil, natural gas and related products and interest rates; extent of EOG's success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties; political developments around the world; 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. 9 10 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING The following consolidated financial statements of EOG Resources, Inc. and its subsidiaries ("EOG") were prepared by management, which is responsible for their integrity, objectivity and fair presentation. The statements have been prepared in conformity with accounting principles generally accepted in the United States and, accordingly, include some amounts that are based on the best estimates and judgments of management. Arthur Andersen LLP, independent public accountants, was engaged to audit the consolidated financial statements of EOG and issue a report thereon. In the conduct of the audit, Arthur Andersen LLP was given unrestricted access to all financial records and related data including minutes of all meetings of shareholders, the Board of Directors and committees of the Board. Management believes that all representations made to Arthur Andersen LLP during the audit were valid and appropriate. The system of internal controls of EOG is designed to provide reasonable assurance as to the reliability of financial statements and the protection of assets from unauthorized acquisition, use or disposition. This system includes, but is not limited to, written policies and guidelines including a published code for the conduct of business affairs, conflicts of interest and compliance with laws regarding antitrust, antiboycott and foreign corrupt practices policies, the careful selection and training of qualified personnel, and a documented organizational structure outlining the separation of responsibilities among management representatives and staff groups. The adequacy of financial controls of EOG and the accounting principles employed in financial reporting by EOG are under the general oversight of the Audit Committee of the Board of Directors. No member of this committee is an officer or employee of EOG. The independent public accountants and internal auditors have 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, 2000.
TIMOTHY K. DRIGGERS EDMUND P. SEGNER, III MARK G. PAPA Vice President, Accounting President and Chief of Staff Chairman and and Land Administration Chief Executive Officer
Houston, Texas February 15, 2001 10 11 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To EOG Resources, Inc.: We have audited the accompanying consolidated balance sheets of EOG Resources, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2000 and 1999, 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, 2000. 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, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Houston, Texas February 15, 2001 11 12 EOG RESOURCES, INC. CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31, ----------------------------------------- 2000 1999 1998 ----------- ----------- ----------- NET OPERATING REVENUES Natural Gas ............................................................... $ 1,155,804 $ 683,469 $ 658,949 Crude Oil, Condensate and Natural Gas Liquids ............................. 325,726 159,373 131,052 Gains (Losses) on Sales of Reserves and Related Assets and Other, Net...... 8,365 (743) 18,251 ----------- ----------- ----------- Total .................................................................. 1,489,895 842,099 808,252 OPERATING EXPENSES Lease and Well ............................................................ 140,915 132,233 137,932 Exploration Costs ......................................................... 67,196 52,773 65,940 Dry Hole Costs ............................................................ 17,337 11,893 22,751 Impairment of Unproved Oil and Gas Properties ............................. 35,717 31,608 32,076 Depreciation, Depletion and Amortization .................................. 370,026 459,877 315,106 General and Administrative ................................................ 66,932 82,857 69,010 Taxes Other Than Income ................................................... 94,909 52,670 51,776 ----------- ----------- ----------- Total .................................................................. 793,032 823,911 694,591 ----------- ----------- ----------- OPERATING INCOME ............................................................. 696,863 18,188 113,661 OTHER INCOME (EXPENSE) Gain on Share Exchange .................................................... -- 575,151 -- Other, Net ................................................................ (2,300) 36,192 (4,800) ----------- ----------- ----------- Total .................................................................. (2,300) 611,343 (4,800) ----------- ----------- ----------- INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES .............................. 694,563 629,531 108,861 INTEREST EXPENSE Incurred .................................................................. 67,714 72,413 61,290 Capitalized ............................................................... (6,708) (10,594) (12,711) ----------- ----------- ----------- Net Interest Expense ................................................... 61,006 61,819 48,579 ----------- ----------- ----------- INCOME BEFORE INCOME TAXES ................................................... 633,557 567,712 60,282 INCOME TAX PROVISION (BENEFIT) ............................................... 236,626 (1,382) 4,111 ----------- ----------- ----------- NET INCOME ................................................................... 396,931 569,094 56,171 PREFERRED STOCK DIVIDENDS .................................................... (11,028) (535) -- ----------- ----------- ----------- NET INCOME AVAILABLE TO COMMON ............................................... $ 385,903 $ 568,559 $ 56,171 =========== =========== =========== EARNINGS PER SHARE AVAILABLE TO COMMON Basic .................................................................. $ 3.30 $ 4.04 $ 0.36 =========== =========== =========== Diluted ................................................................ $ 3.24 $ 4.01 $ 0.36 =========== =========== =========== AVERAGE NUMBER OF COMMON SHARES Basic .................................................................. 116,934 140,648 154,002 =========== =========== =========== Diluted ................................................................ 119,102 141,627 154,573 =========== =========== =========== NET INCOME ................................................................... $ 396,931 $ 569,094 $ 56,171 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Translation Adjustment ................................... (12,338) 16,038 (16,077) Unrealized Gain on Available-for-Sale Security, Net of Tax of $211 ........................................... 392 -- -- ----------- ----------- ----------- COMPREHENSIVE INCOME ......................................................... $ 384,985 $ 585,132 $ 40,094 =========== =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. 12 13 EOG RESOURCES, INC. CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
AT DECEMBER 31, -------------------------- ASSETS 2000 1999 ----------- ----------- CURRENT ASSETS Cash and Cash Equivalents .......................................... $ 20,152 $ 24,836 Accounts Receivable ................................................ 342,579 148,189 Inventories ........................................................ 16,623 18,816 Other .............................................................. 15,073 8,660 ----------- ----------- Total ........................................................ 394,427 200,501 OIL AND GAS PROPERTIES (Successful Efforts Method) ................... 5,122,728 4,602,740 Less: Accumulated Depreciation, Depletion and Amortization ........ (2,597,721) (2,267,812) ----------- ----------- Net Oil and Gas Properties ................................... 2,525,007 2,334,928 OTHER ASSETS ......................................................... 81,381 75,364 ----------- ----------- TOTAL ASSETS ....................................................... $ 3,000,815 $ 2,610,793 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable ................................................... $ 246,030 $ 172,780 Accrued Taxes Payable .............................................. 78,838 19,648 Dividends Payable .................................................. 4,525 4,227 Other .............................................................. 40,285 21,963 ----------- ----------- Total ........................................................ 369,678 218,618 LONG-TERM DEBT ........................................................ 859,000 990,306 OTHER LIABILITIES ..................................................... 51,133 46,306 DEFERRED INCOME TAXES ................................................. 340,079 225,952 SHAREHOLDERS' EQUITY Preferred Stock, $.01 Par, 10,000,000 Shares Authorized: Series B, 100,000 shares Issued, Cumulative, $100,000,000 Liquidation Preference ......................... 97,879 97,909 Series D, 500 shares Issued, Cumulative, $50,000,000 Liquidation Preference .......................... 49,285 49,281 Common Stock, $.01 Par, 320,000,000 shares Authorized and 124,730,000 shares Issued ....................................... 201,247 201,247 Additional Paid In Capital ......................................... 4,221 -- Unearned Compensation .............................................. (3,756) (1,618) Accumulated Other Comprehensive Income ............................. (31,756) (19,810) Retained Earnings .................................................. 1,301,067 930,938 Common Stock Held in Treasury, 7,825,708 shares at December 31, 2000 and 5,625,446 shares at December 31, 1999 ................. (237,262) (128,336) ----------- ----------- Total Shareholders' Equity ......................................... 1,380,925 1,129,611 ----------- ----------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ......................... $ 3,000,815 $ 2,610,793 =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. 13 14 EOG RESOURCES, INC. CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
ACCUMULATED ADDITIONAL OTHER PREFERRED COMMON PAID IN UNEARNED COMPREHENSIVE RETAINED STOCK STOCK CAPITAL COMPENSATION INCOME EARNINGS --------- ----------- ----------- ------------ ------------- ----------- Balance at December 31, 1997 $ -- $ 201,600 $ 402,877 $ (4,694) $ (19,771) $ 800,709 Net Income -- -- -- -- -- 56,171 Dividends Paid/Declared, $.12 Per Share -- -- -- -- -- (18,509) Translation Adjustment -- -- -- -- (16,077) -- Treasury Stock Purchased -- -- -- -- -- -- Treasury Stock Issued Under Stock Option Plans -- -- (762) (1,709) -- -- Tax Benefits from Stock Options Exercised -- -- 270 -- -- -- Amortization of Unearned Compensation -- -- -- 1,503 -- -- Other -- -- (861) -- -- -- ----------- ----------- ----------- ----------- ----------- ----------- Balance at December 31, 1998 -- 201,600 401,524 (4,900) (35,848) 838,371 Net Income -- -- -- -- -- 569,094 Preferred Stock Issued 147,175 -- -- -- -- -- Amortization of Preferred Stock Discount 15 -- -- -- -- -- Common Stock Issued -- 270 577,662 -- -- -- Preferred Stock Dividends Paid/Declared -- -- -- -- -- (535) Common Stock Dividends Paid/ Declared, $.12 Per Share -- -- -- -- -- (16,377) Translation Adjustment -- -- -- -- 16,038 -- Treasury Stock Purchased -- -- -- -- -- -- Treasury Stock Received in Share Exchange -- -- -- -- -- -- Common Stock Retired -- (623) (978,224) -- -- (458,033) Treasury Stock Issued Under Stock Option Plans -- -- (2,274) 136 -- (1,582) Tax Benefits from Stock Options Exercised -- -- 1,387 -- -- -- Amortization of Unearned Compensation -- -- -- 3,146 -- -- Other -- -- (75) -- -- -- ----------- ----------- ----------- ----------- ----------- ----------- Balance at December 31, 1999 147,190 201,247 -- (1,618) (19,810) 930,938 Net Income -- -- -- -- -- 396,931 Amortization of Preferred Stock Discount 419 -- -- -- -- (419) Exchange Offer Fees (445) -- -- -- -- -- Preferred Stock Dividends Paid/Declared -- -- -- -- -- (10,609) Common Stock Dividends Paid/ Declared, $.14 Per Share -- -- -- -- -- (15,774) Translation Adjustment -- -- -- -- (12,338) -- Unrealized Gain on Available- for-Sale Security -- -- -- -- 392 -- Treasury Stock Purchased -- -- -- -- -- -- Treasury Stock Issued Under Stock Option Plans -- -- (36,701) -- -- -- Tax Benefits from Stock Options Exercised -- -- 41,307 -- -- -- Restricted Stock and Units -- -- 2,805 (3,411) -- -- Amortization of Unearned Compensation -- -- -- 1,273 -- -- Equity Derivative Transactions -- -- (3,190) -- -- -- Other -- -- -- -- -- -- ----------- ----------- ----------- ----------- ----------- ----------- Balance at December 31, 2000 $ 147,164 $ 201,247 $ 4,221 $ (3,756) $ (31,756) $ 1,301,067 =========== =========== =========== =========== =========== =========== COMMON STOCK TOTAL HELD IN SHAREHOLDERS' TREASURY EQUITY ----------- ------------- Balance at December 31, 1997 $ (99,672) $ 1,281,049 Net Income -- 56,171 Dividends Paid/Declared, $.12 Per Share -- (18,509) Translation Adjustment -- (16,077) Treasury Stock Purchased (25,875) (25,875) Treasury Stock Issued Under Stock Option Plans 5,104 2,633 Tax Benefits from Stock Options Exercised -- 270 Amortization of Unearned Compensation -- 1,503 Other -- (861) ----------- ----------- Balance at December 31, 1998 (120,443) 1,280,304 Net Income -- 569,094 Preferred Stock Issued -- 147,175 Amortization of Preferred Stock Discount -- 15 Common Stock Issued -- 577,932 Preferred Stock Dividends Paid/Declared -- (535) Common Stock Dividends Paid/ Declared, $.12 Per Share -- (16,377) Translation Adjustment -- 16,038 Treasury Stock Purchased (2,143) (2,143) Treasury Stock Received in Share Exchange (1,459,484) (1,459,484) Common Stock Retired 1,436,880 -- Treasury Stock Issued Under Stock Option Plans 16,854 13,134 Tax Benefits from Stock Options Exercised -- 1,387 Amortization of Unearned Compensation -- 3,146 Other -- (75) ----------- ----------- Balance at December 31, 1999 (128,336) 1,129,611 Net Income -- 396,931 Amortization of Preferred Stock Discount -- -- Exchange Offer Fees -- (445) Preferred Stock Dividends Paid/Declared -- (10,609) Common Stock Dividends Paid/ Declared, $.14 Per Share -- (15,774) Translation Adjustment -- (12,338) Unrealized Gain on Available- for-Sale Security -- 392 Treasury Stock Purchased (272,723) (272,723) Treasury Stock Issued Under Stock Option Plans 163,350 126,649 Tax Benefits from Stock Options Exercised -- 41,307 Restricted Stock and Units 606 -- Amortization of Unearned Compensation -- 1,273 Equity Derivative Transactions -- (3,190) Other (159) (159) ----------- ----------- Balance at December 31, 2000 $ (237,262) $ 1,380,925 =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. 14 15 EOG RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, ----------------------------------- 2000 1999 1998 --------- --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES Reconciliation of Net Income to Net Operating Cash Inflows: Net Income ................................................................ $ 396,931 $ 569,094 $ 56,171 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization ................................ 370,026 459,877 315,106 Impairment of Unproved Oil and Gas Properties ........................... 35,717 31,608 32,076 Deferred Income Taxes ................................................... 97,729 (26,252) (26,794) Other, Net .............................................................. 6,693 25,583 7,761 Exploration Costs ......................................................... 67,196 52,773 65,940 Dry Hole Costs ............................................................ 17,337 11,893 22,751 Losses (Gains) On Sales of Reserves and Related Assets and Other, Net...... (5,977) 5,602 (11,191) Gains on Sales of Other Assets ............................................ -- (59,647) -- Gain on Share Exchange .................................................... -- (575,151) -- Tax Benefits from Stock Options Exercised ................................. 41,307 1,387 270 Other, Net ................................................................ (8,935) (19,081) 1,116 Changes in Components of Working Capital and Other Liabilities Accounts Receivable ..................................................... (191,492) (12,914) 36,363 Inventories ............................................................. 2,345 5,180 (7,541) Accounts Payable ........................................................ 97,374 4,395 (65,249) Accrued Taxes Payable ................................................... 54,556 2,449 (8,754) Other Liabilities ....................................................... 348 (15,438) 2,324 Other, Net .............................................................. 11,378 (9,960) (3,620) Amortization of Deferred Revenue .......................................... -- -- (43,344) Changes in Components of Working Capital Associated with Investing and Financing Activities ...................... (25,123) (7,879) 30,491 --------- --------- --------- NET OPERATING CASH INFLOWS ................................................... 967,410 443,519 403,876 INVESTING CASH FLOWS Additions to Oil and Gas Properties ....................................... (602,638) (396,450) (680,520) Exploration Costs ......................................................... (67,196) (52,773) (65,940) Dry Hole Costs ............................................................ (17,337) (11,893) (22,751) Proceeds from Sales of Reserves and Related Assets ........................ 26,189 10,934 61,858 Proceeds from Sales of Other Assets ....................................... -- 82,965 -- Changes in Components of Working Capital Associated with Investing Activities .................................... 22,798 7,909 (30,173) Other, Net ................................................................ (28,977) (4,057) (22,094) --------- --------- --------- NET INVESTING CASH OUTFLOWS .................................................. (667,161) (363,365) (759,620) FINANCING CASH FLOWS Long-Term Debt Trade ................................................................... (131,306) 47,527 394,004 Affiliate ............................................................... -- (200,000) 7,500 Proceeds from Preferred Stock Issued ...................................... -- 147,175 -- Proceeds from Common Stock Issued ......................................... -- 577,932 -- Dividends Paid ............................................................ (26,071) (17,395) (18,504) Treasury Stock Purchased .................................................. (272,723) (2,143) (25,875) Proceeds from Sales of Treasury Stock ..................................... 127,090 13,341 2,613 Equity Contribution to Transferred Subsidiaries ........................... -- (608,750) -- Other, Net ................................................................ (1,923) (19,308) (7,021) --------- --------- --------- NET FINANCING CASH INFLOWS (OUTFLOWS) ........................................ (304,933) (61,621) 352,717 --------- --------- --------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ............................. (4,684) 18,533 (3,027) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR ............................... 24,836 6,303 9,330 --------- --------- --------- CASH AND CASH EQUIVALENTS AT END OF YEAR ..................................... $ 20,152 $ 24,836 $ 6,303 ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. 15 16 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED) 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. All material intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to the consolidated financial statements for prior years to conform with the current presentation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. 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. Amortization of any remaining costs of such leases begins at a point prior to the end of the lease term depending upon the length of such term. 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 changes in value. Natural gas revenues are recorded on the entitlement method based on EOG's percentage ownership of current production. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold may differ from an owner's ownership percentage. Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable when overproduction occurs. 16 17 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Gains and losses associated with the sale of in place natural gas and crude oil reserves and related assets are classified as net operating revenues in the consolidated statements of income and comprehensive income based on EOG's strategy of continuing such sales in order to maximize the economic value of its assets. New Accounting Pronouncements in 2000. In July 2000, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board reached a consensus on EITF Issue 00-15, "Classification in the Statement of Cash Flows of the Income Tax Benefit Received by a Company upon Exercise of a Nonqualified Employee Stock Option." Pursuant to the consensus, reduction of income taxes paid as a result of the deduction triggered by employee exercise of stock options should be classified as an operating cash inflow. In accordance with EITF Issue 00-15, EOG reported tax benefits from stock options exercised as an operating cash inflow for the year 2000 and reclassified the amounts in the prior periods on the consolidated statements of cash flows to conform with the current year classification. In September 2000, the EITF reached a consensus on EITF Issue 00-10, "Accounting for Shipping and Handling Fees and Costs." Pursuant to the consensus, amounts paid related to certain transportation must be reported as an expense on the income statement rather than reporting revenues net of transportation as has been industry practice. In addition, pertinent amounts in financial statements for prior periods should be reclassified to reflect the same accounting treatment. In accordance with EITF Issue 00-10, EOG recorded transportation related amounts of $29.4 million, $40.7 million and $39.1 million in lease and well expense with a corresponding increase to revenues for 2000, 1999 and 1998, respectively, in the consolidated statements of income and comprehensive income. Accounting for Price Risk Management Activities. EOG engages in price risk management activities from time to time primarily for non-trading and to a lesser extent for trading purposes. Derivative financial instruments (primarily price swaps and costless collars) are utilized selectively for non-trading purposes to hedge the impact of market fluctuations on natural gas and crude oil market prices. Hedge accounting is utilized in non-trading activities when there is a high degree of correlation between price movements in the derivative and the item designated as being hedged. Gains and losses on derivative financial instruments used for hedging purposes are recognized as revenue in the same period as the hedged item. Gains and losses on hedging instruments that are closed prior to maturity are deferred in the consolidated balance sheets and recognized as revenue in the same period as the hedged item. In instances where the anticipated correlation of price movements does not occur, hedge accounting is terminated and future changes in the value of the derivative are recognized as gains or losses using the mark-to-market method of accounting. Derivative and other financial instruments utilized in connection with trading activities, primarily price swaps and call options, are accounted for using the mark-to-market method, under which changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. The cash flow impact of derivative and other financial instruments used for non-trading and trading purposes is reflected as cash flows from operating activities in the consolidated statements of cash flows. (See Notes 12 and 15 for new accounting pronouncement related to accounting for price risk management activities.) Capitalized Interest Costs. Certain interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties and in work in progress for development drilling and related facilities with significant cash outlays. Income Taxes. EOG accounts for income taxes under the provisions of Statement of Financial Accounting Standards ("SFAS") No. 109--"Accounting for Income Taxes." SFAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases (see Note 5 "Income Taxes"). Foreign Currency Translation. For subsidiaries whose functional currency is deemed to be other than the U.S. dollar, asset and liability accounts are translated at year-end exchange rates and revenue and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included as a separate component of shareholders' equity. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. Net Income Per Share. In accordance with the provisions of SFAS No. 128--"Earnings per Share," basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted net income per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities (See Note 8 "Net Income Per Share Available to Common" for additional information to reconcile the difference between the Average Number of Common Shares outstanding for basic and diluted net income per share). 17 18 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 2. LONG-TERM DEBT Long-Term Debt at December 31 consisted of the following (in thousands):
2000 1999 -------- -------- Commercial Paper...................................... $ -- $123,186 Uncommitted Credit Facilities......................... 38,800 87,000 6.50% Notes due 2004.................................. 100,000 100,000 6.70% Notes due 2006.................................. 150,000 150,000 6.50% Notes due 2007.................................. 100,000 100,000 6.00% Notes due 2008.................................. 175,000 175,000 6.65% Notes due 2028.................................. 150,000 150,000 Subsidiary Debt due 2001.............................. 105,000 105,000 Subsidiary Debt due 2002.............................. 40,200 -- Other................................................. -- 120 -------- -------- Total........................................ $859,000 $990,306 ======== ========
EOG maintains two credit facilities with different expiration dates. On July 26, 2000, the $400 million credit facility that was scheduled to expire was renewed for $375 million, thereby reducing aggregate long-term committed credit from $800 million at December 31, 1999 to $775 million. Credit facility expirations are as follows: $375 million in 2001 and $400 million in 2004. With respect to the $375 million expiring in 2001, 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. At December 31, 2000, there were no advances outstanding under either of these agreements. Commercial paper and short-term funding from uncommitted credit facilities provide financing for various corporate purposes and bear interest based upon market rates. 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 2001 was fully paid in January 2001 by increased borrowings from commercial paper and uncommitted credit facilities. The Subsidiary Debt due 2002 bears interest at variable market-based rates. At December 31, 2000, the aggregate annual maturities of long-term debt outstanding were $105 million for 2001, $40 million for 2002, none for 2003, $100 million for 2004 and none for 2005. 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. Such registration statement was declared effective by the Securities and Exchange Commission on October 27, 2000. As of February 15, 2001, 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, such 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, 2000 and 1999, EOG had $859 million and $990 million, respectively, of long-term debt which had fair values of approximately $831 million and $933 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. 18 19 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 3. SHAREHOLDERS' EQUITY In February 1998, the Board of Directors authorized the purchase of an aggregate maximum of 10 million shares of common stock of EOG 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 option plans and any other approved transactions or activities for which such common stock shall be required. In February 2000, as amended in December 2000, the Board of Directors authorized the purchase of an aggregate maximum of 15 million shares of common stock of EOG which replaced the remaining authorization from February 1998. At December 31, 2000 and 1999, 7,825,708 shares and 5,625,446 shares, respectively, were held in treasury under these authorizations. During the first half of 2000, to supplement its share repurchase program, EOG entered into a series of equity derivative transactions. Settlement alternatives for these equity derivative contracts under all circumstances are at the option of EOG and include physical share, net share and net cash settlement. The transactions were accounted for as equity transactions with premium received recorded to additional paid in capital in the consolidated balance sheets. 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 still outstanding at December 31, 2000. The strike price of these options is $18.00 per share, and they expire in April 2001. At December 31, 1999, there were no put options outstanding. At December 31, 1998, there were put options outstanding for 175,000 shares of common stock. On July 23, 1999, EOG filed a registration statement with the Securities and Exchange Commission for the public offering of 27,000,000 shares of EOG's common stock. The public offering was completed on August 16, 1999, and the net proceeds were used to repay short-term borrowings used to fund a significant portion of the cash capital contribution in connection with the Share Exchange Agreement ("Share Exchange") described in Note 4 "Transactions with Enron Corp. and Related Parties." As a result of the public offering and the retirement of the 62,270,000 shares of EOG's common stock received from Enron Corp. in the Share Exchange transaction, the number of shares of EOG's common stock issued was reduced to 124,730,000 from 160,000,000 prior to the Share Exchange. The following summarizes shares of common stock outstanding (in thousands):
COMMON SHARES ------------------------------------------ 2000 1999 1998 ------- ------- ------- Outstanding at January 1......................................... 119,105 153,724 155,064 Repurchased................................................... (8,910) (130) (1,590) Issued Pursuant to Stock Options and Stock Plans.............. 6,709 781 250 Retired....................................................... -- (62,270) -- Public Offering............................................... -- 27,000 -- ------- ------- ------- Outstanding at December 31....................................... 116,904 119,105 153,724 ======= ======= =======
In December 1999, EOG issued the following two series of preferred stock: 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. The dividend rate may only be adjusted in the event that certain amendments are made to the Dividend Received Percentage, as defined, within the first 18 months of the issuance date. 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. 19 20 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 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" or "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 15% 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. The Board of Directors may reduce the threshold at which a person or a group becomes an Acquiring Person from 15% to not less than 10% of the outstanding common stock. If a person or group becomes an Acquiring Person, all holders of Rights except the Acquiring Person may, for $90, purchase shares of our 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. 20 21 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 4. TRANSACTIONS WITH ENRON CORP. AND RELATED PARTIES Share Exchange. On August 16, 1999, EOG and Enron Corp. completed the Share Exchange whereby EOG received 62,270,000 shares of EOG's common stock out of 82,270,000 shares owned by Enron Corp. in exchange for all the stock of EOG's subsidiary, EOGI-India, Inc. Prior to the Share Exchange, EOG made an indirect capital contribution of approximately $600 million in cash, plus certain intercompany receivables, to EOGI-India, Inc. At the time of completion of this transaction, this subsidiary owned, through subsidiaries, all of EOG's assets and operations in India and China. EOG recognized a $575 million tax-free gain on the Share Exchange based on the fair value of the shares received, net of transaction fees of $14 million. Immediately following the Share Exchange, EOG retired the 62,270,000 shares of EOG's common stock received in the transaction. The weighted average basis in the treasury shares retired was first deducted from and fully eliminated existing additional paid in capital with the remaining value deducted from retained earnings. This transaction is a tax-free exchange to EOG. On August 30, 1999, EOG changed its corporate name to "EOG Resources, Inc." from "Enron Oil & Gas Company" and has since made similar changes to its subsidiaries' names. Immediately prior to the closing of the Share Exchange, Enron Corp. owned 82,270,000 shares of EOG's common stock, representing approximately 53.5 percent of all of the shares of EOG's common stock that were issued and outstanding. As a result of the closing of the Share Exchange, the sale by Enron Corp. of 8,500,000 shares of EOG's common stock as a selling stockholder in the public offering referred to above, and the completion on August 17, 1999 and August 20, 1999 of the offering of Enron Corp. notes mandatorily exchangeable at maturity into up to 11,500,000 shares of EOG's common stock, Enron Corp's maximum remaining interest in EOG after the automatic conversion of its notes on July 31, 2002, will be under two percent (assuming the notes are exchanged for less than the 11,500,000 shares of EOG's common stock). Effective as of August 16, 1999, the closing date of the Share Exchange, the members of the board of directors of EOG who were officers or directors of Enron Corp. resigned their positions as directors of EOG. Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues. Prior to the Share Exchange, Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues included revenues from and associated costs paid to various subsidiaries and affiliates of Enron Corp. pursuant to contracts which, in the opinion of management, were no less favorable than could be obtained from third parties. Revenues from sales to Enron Corp. and its affiliates totaled $57.3 million in 1999 prior to the Share Exchange and $72.2 million in 1998. Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues also included certain commodity price swap and NYMEX-related commodity transactions with Enron Corp. affiliated companies, which in the opinion of management, were no less favorable than could be received from third parties. (See Note 12 "Price and Interest Rate Risk Management"). General and Administrative Expenses. Prior to the Share Exchange, EOG was charged by Enron Corp. for all direct costs associated with its operations. Such direct charges, excluding benefit plan charges (See Note 6 "Employee Benefit Plans"), totaled $10.6 million and $14.2 million for the years ended December 31, 1999 and 1998, respectively. Additionally, certain administrative costs not directly charged to any Enron Corp. operations or business segments were allocated to the entities of the consolidated group. Approximately $3.4 million and $5.1 million was incurred by EOG for indirect general and administrative expenses for 1999 and 1998, respectively. Management believes that these charges were reasonable. Sale of Enron Corp. Options. In December 1997, EOG and Enron Corp. entered into an Equity Participation and Business Opportunity Agreement. Under the agreement, among other things, Enron Corp. granted EOG options to purchase 3.2 million shares of Enron Corp. During 1999, EOG sold the 3.2 million options and recognized a pre-tax gain of $59.6 million. The gain on sale of the options is included in other income (expense) - other, net in the consolidated statements of income and comprehensive income. 21 22 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 5. INCOME TAXES The principal components of EOG's net deferred income tax liability at December 31, 2000 and 1999 were as follows (in thousands):
2000 1999 -------- -------- Deferred Income Tax Assets Non-Producing Leasehold Costs ...................................... $ 22,623 $ 25,199 Seismic Costs Capitalized for Tax .................................. 15,536 9,912 Alternative Minimum Tax Credit Carryforward ........................ -- 21,772 Trading Activity ................................................... 4,420 1,426 Section 29 Credit Monetization ..................................... 12,774 15,657 Other .............................................................. 16,743 13,993 -------- -------- Total Deferred Income Tax Assets .......................... 72,096 87,959 Deferred Income Tax Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization ......... 403,808 299,704 Capitalized Interest ............................................... 5,697 11,986 Other .............................................................. 2,670 2,221 -------- -------- Total Deferred Income Tax Liabilities ..................... 412,175 313,911 -------- -------- Net Deferred Income Tax Liability ......................... $340,079 $225,952 ======== ========
The components of income (loss) before income taxes were as follows (in thousands):
2000 1999 1998 -------- -------- -------- United States ........................................................... $491,417 $561,841 $ (3,297) Foreign ................................................................. 142,140 5,871 63,579 -------- -------- -------- Total ............................................................ $633,557 $567,712 $ 60,282 ======== ======== ========
Total income tax provision (benefit) was as follows (in thousands):
2000 1999 1998 -------- -------- -------- Current: Federal ............................................................ $ 81,912 $ 5,510 $ 10,496 State .............................................................. 7,528 3,234 1,474 Foreign ............................................................ 49,457 16,126 18,935 -------- -------- -------- Total ............................................................ 138,897 24,870 30,905 Deferred: Federal ............................................................ 78,833 (49,474) (31,279) State .............................................................. 10,324 (502) (4,589) Foreign ............................................................ 8,572 23,724 9,074 -------- -------- -------- Total ............................................................ 97,729 (26,252) (26,794) -------- -------- -------- Income Tax Provision (Benefit) .......................................... $236,626 $ (1,382) $ 4,111 ======== ======== ========
The differences between taxes computed at the U.S. federal statutory tax rate and EOG's effective rate were as follows:
2000 1999 1998 -------- -------- -------- Statutory Federal Income Tax Rate ....................................... 35.00% 35.00% 35.00% State Income Tax, Net of Federal Benefit ................................ 1.83 0.31 (3.36) Income Tax Related to Foreign Operations ................................ 1.32 1.60 4.76 Tight Gas Sand Federal Income Tax Credits ............................... -- (1.45) (17.36) Revision of Prior Years' Tax Estimates .................................. 0.16 (0.21) (10.78) Share Exchange .......................................................... -- (35.46) -- Other ................................................................... (.96) (.03) (1.45) ----- ----- ----- Effective Income Tax Rate ........................................ 37.35% (0.24)% 6.81% ===== ===== =====
22 23 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) EOG's foreign subsidiaries' undistributed earnings of approximately $380 million at December 31, 2000 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 2000, EOG fully utilized an alternative minimum tax credit carryforward of approximately $22 million to offset regular income taxes payable. In 1999 and 2000, EOG entered into arrangements with a third party whereby certain Section 29 credits were sold by EOG to the third party, and payments for such credits will be received on an as-generated basis. As a result of these transactions, EOG recorded a deferred tax asset representing a tax gain on the sale of the Section 29 credit properties, which will reverse as the results of operations of such properties are recognized for book purposes. 6. EMPLOYEE BENEFIT PLANS Employees of EOG were covered by various retirement, stock purchase and other benefit plans of Enron Corp. through August 1999. During each of the years ended December 31, 1999 and 1998, EOG was charged $4.4 million and $6.4 million, respectively, for all such benefits, including pension expense totaling $0.9 million and $1.3 million, respectively, by Enron Corp. Pension and Postretirement Plans Since August 1999, EOG has adopted defined contribution pension plans for most of its employees in the United States. EOG's contributions to these plans are based on various percentages of compensation, and in some instances, are based upon the amount of the employees' contributions to the plan. From August 31, 1999 to December 31, 1999 the cost of these plans amounted to approximately $1.2 million. For 2000, the cost of these plans amounted to approximately $3.1 million. EOG also has in effect pension and savings plans related to its Canadian and Trinidadian subsidiaries. Activity related to these plans is not material relative to EOG's operations. 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, 2000, the postretirement plan had a benefit obligation of $1.5 million and during 2000, EOG recognized a $0.3 million net periodic benefit cost related to this plan. Stock Plans Stock Options. EOG has various stock plans ("the Plans") under which employees of EOG and its subsidiaries and nonemployee members of the Board of Directors have been or may be granted rights to purchase shares of common stock of EOG at a price not less than the market price of the stock at the date of grant. Stock options granted under the Plans vest over a period of time based on the nature of the grants and as defined in the individual grant agreements. Terms for stock options granted under the Plans have not exceeded a maximum term of 10 years. EOG accounts for the stock options under the provisions and related interpretations of Accounting Principles Board Opinion No. 25 ("APB 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 No. 25 for purposes of determining net income and to present the pro forma disclosures required by SFAS No. 123. 23 24 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following table sets forth the option transactions under the Plans for the years ended December 31 (options in thousands):
2000 1999 1998 ---------------------- ---------------------- ---------------------- AVERAGE AVERAGE AVERAGE GRANT GRANT GRANT OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE --------- --------- --------- --------- --------- --------- Outstanding at January 1 ............... 12,667 $ 18.66 15,036 $ 18.35 9,735 $ 19.99 Granted ........................... 1,317 30.88 1,280 19.88 5,949 15.76 Exercised ......................... (6,726) 18.90 (822) 16.22 (172) 15.14 Forfeited ......................... (202) 19.09 (2,827) 18.26 (476) 20.62 --------- --------- --------- Outstanding at December 31 ............. 7,056 20.70 12,667 18.66 15,036 18.35 ========= ========= ========= Options Exercisable at December 31 ..... 3,845 19.83 8,118 19.23 7,703 19.38 ========= ========= ========= Options Available for Future Grant ..... 6,387 5,564 3,098 ========= ========= ========= Average Fair Value of Options Granted During Year ............... $ 12.20 $ 7.43 $ 4.75 ========= ========= =========
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 2000, 1999, and 1998, respectively: (1) dividend yield of 0.6%, 0.6% and 0.6%, (2) expected volatility of 30%, 28%, and 26%, (3) risk-free interest rate of 6.0%, 5.9%, and 5.1%, and (4) expected life of 6.0 years, 6.0 years and 4.9 years. The following table summarizes certain information for the options outstanding at December 31, 2000 (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) $ 9.00 to $12.99.................... 24 1 $ 9.45 24 $ 9.45 13.00 to 17.99.................... 2,137 8 14.72 979 15.24 18.00 to 22.99.................... 3,271 6 20.09 2,161 20.02 23.00 to 28.99.................... 560 5 23.93 505 23.74 29.00 to 39.99.................... 1,047 10 32.93 173 32.84 40.00 to 50.00.................... 17 10 47.11 3 47.11 ------ ------ 7,056 7 20.70 3,845 19.83 ====== ======
24 25 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) EOG's pro forma net income and net income per share of common stock for 2000, 1999 and 1998, had compensation costs been recorded in accordance with SFAS No. 123, are presented below (in millions except per share data):
2000 1999 1998 ------------------- ---------------------- ----------------------- AS AS AS REPORTED PRO FORMA REPORTED PRO FORMA REPORTED PRO FORMA -------- --------- -------- --------- -------- --------- Net Income Available to Common.............. $ 385.9 $ 373.4 $ 568.6 $ 565.7 $ 56.2 $ 47.3 Net Income per Share Available to Common Basic.................................... $ 3.30 $ 3.19 $ 4.04 $ 4.02 $ .36 $ .31 ======== ======== ======== ========== ======== ======= Diluted.................................. $ 3.24 $ 3.14 $ 4.01 $ 3.99 $ .36 $ .31 ======== ======== ======== ========== ======== =======
The effects of applying SFAS No. 123 in this pro forma disclosure should not be interpreted as being indicative of future effects. SFAS No. 123 does not apply to awards prior to 1995, and the extent and timing of additional future awards cannot be predicted. The Black-Scholes model used by EOG to calculate option values, as well as other currently accepted option valuation models, were developed to estimate the fair value of freely tradable, fully transferable options without vesting and/or trading restrictions, which significantly differ from EOG's stock option awards. These models also require highly subjective assumptions, including future stock price volatility and expected time until exercise, which significantly affect the calculated values. Accordingly, management does not believe that this model provides a reliable single measure of the fair value of EOG's stock option awards. Restricted Stock and Units. Under the Plans, participants may be granted restricted stock and/or units without cost to the participant. The shares and units granted vest to the participant at various times ranging from one to seven years. Upon vesting, the restricted shares are released to the participants and the restricted units released to the participants are converted into one share of common stock. The following summarizes shares of restricted stock and units granted:
RESTRICTED SHARES AND UNITS ------------------------------- 2000 1999 1998 --------- -------- -------- Outstanding at January 1.............................................. 265,168 345,334 284,000 Granted........................................................... 200,566 23,000 108,500 Released to Participants.......................................... (171,502) (37,166) (14,166) Forfeited or Expired.............................................. (2,661) (66,000) (33,000) --------- -------- -------- Outstanding at December 31............................................ 291,571 265,168 345,334 --------- -------- -------- Average Fair Value of Shares Granted During Year...................... $ 16.10 $ 21.43 $ 20.11 ========= ======== ========
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 2000, 1999 and 1998 was approximately $1.3 million, $3.1 million and $1.5 million, respectively. Treasury Shares. During 2000, 1999 and 1998, EOG purchased 6,709,138, 130,000, and 249,788 of its common shares, respectively, to offset the dilution resulting from shares issued under the EOG employee stock plans. The difference between the cost of the treasury shares and the exercise price of the options, net of federal income tax benefit of $41.3 million, $1.4 million and $.3 million for the years 2000, 1999 and 1998, 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, 2000 and 1999, EOG had letters of credit and guaranties outstanding totaling approximately $122 million and $118 million, respectively. 25 26 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Contingencies. On July 21, 1999, two stockholders of EOG filed separate lawsuits purportedly on behalf of EOG against Enron Corp. and those individuals who were then directors of EOG, alleging that Enron Corp. and those directors breached their fiduciary duties of good faith and loyalty in approving the Share Exchange. The lawsuits seek to rescind the transaction or to receive monetary damages and costs and expenses, including reasonable attorneys' and experts' fees. EOG, Enron Corp. and the individual defendants believe the lawsuits are without merit and intend to vigorously contest them. EOG is engaged in arbitration hearings to settle a disagreement over the timing of the conversion of a 5% overriding royalty interest held by a third party in EOG's Trinidad SECC block to a 15% working interest. EOG does not expect the outcome to have a material adverse effect on EOG's financial position or results of operations. There are various other suits and claims against EOG that have arisen in the ordinary course of business. However, management does not believe these suits and claims will individually or in the aggregate have a material adverse effect on the financial condition or results of operations of EOG. EOG has been named as a potentially responsible party in certain Comprehensive Environmental Response Compensation and Liability Act proceedings. However, management does not believe that any potential assessments resulting from such proceedings will individually or in the aggregate have a materially adverse effect on the financial condition or results of operations of EOG. 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):
2000 1999 1998 -------- -------- -------- Numerator for basic and diluted earnings per share - Net income available to common ...................... $385,903 $568,559 $ 56,171 ======== ======== ======== Denominator for basic earnings per share - Weighted average shares ............................. 116,934 140,648 154,002 Potential dilutive common shares - Stock options ....................................... 2,038 964 461 Restricted stock and units .......................... 130 15 110 -------- -------- -------- Denominator for diluted earnings per share - Adjusted weighted average shares .................... 119,102 141,627 154,573 ======== ======== ======== Net income per share of common stock Basic ............................................... $ 3.30 $ 4.04 $ 0.36 ======== ======== ======== Diluted ............................................. $ 3.24 $ 4.01 $ 0.36 ======== ======== ========
9. SUPPLEMENTAL CASH FLOW INFORMATION On August 16, 1999, EOG and Enron Corp. completed the Share Exchange whereby EOG received 62,270,000 shares of EOG's common stock out of 82,270,000 shares owned by Enron Corp. in exchange for all the stock of EOG's subsidiary, EOGI-India, Inc (see Note 4 "Transactions with Enron Corp. and Related Parties"). Prior to the Share Exchange, EOG made an indirect capital contribution of approximately $600 million in cash, plus certain intercompany receivables, to EOGI-India, Inc. At the time of completion of this transaction, EOG's net investment in EOGI-India, Inc. was $870 million. Cash paid for interest and income taxes was as follows for the years ended December 31:
2000 1999 1998 -------- --------- ------ Interest (net of amount capitalized)............................ $ 61,679 $ 67,965 $ 51,166 Income taxes.................................................... 87,285 19,810 38,551
26 27 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 10. BUSINESS SEGMENT INFORMATION EOG's operations are all natural gas and crude oil exploration and production related. SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," establishes standards for reporting information about operating segments in annual financial statements and requires selected information about operating segments in interim financial reports. Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. EOG's chief operating decision making group is the Executive Committee, which consists of the Chairman and Chief Executive Officer and other key officers. This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas in the United States and each significant international location. For segment reporting purposes, the major U.S. producing areas have been aggregated as one reportable segment due to similarities in their operations as allowed by SFAS No. 131. Financial information by reportable segment is presented below for the years ended December 31, or at December 31 (in thousands):
UNITED STATES CANADA TRINIDAD INDIA(1) OTHER(2) TOTAL --------------- ---------- -------- -------- -------- ------------ 2000 Net Operating Revenues ....................... $1,223,315(3)(4) $184,092(3) $ 82,430 $ -- $ 58 $1,489,895(3) Depreciation, Depletion and Amortization ..... 316,814 39,253 13,959 -- -- 370,026 Operating Income (Loss) ...................... 552,091 103,229 41,974 -- (431) 696,863 Interest Income .............................. 522 2,186 915 -- 214 3,837 Other Income (Expense) ....................... (6,344) 302 31 -- (126) (6,137) Interest Expense ............................. 59,841 7,550 323 -- -- 67,714 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 ................................. 2,465,204 374,476 159,872 -- 1,263 3,000,815 1999 Net Operating Revenues ....................... $ 635,587(3)(4) $ 97,817(3) $ 62,689 $ 53,897 $ (7,891) $ 842,099(3) Depreciation, Depletion and Amortization ..... 371,606 29,826 12,787 7,223 38,435 459,877 Operating Income (Loss) ...................... (7,714) 33,941 32,643 22,699 (63,381) 18,188 Interest Income .............................. 113 184 626 51 63 1,037 Other Income (Expense) ....................... 630,872 112 128 (992) (19,814) 610,306 Interest Expense ............................. 64,875 7,215 323 -- -- 72,413 Income Tax Provision (Benefit) ............... (4,200) 4,637 18,484 8,858 (29,161) (1,382) Additions to Oil and Gas Properties .......... 292,970 63,783 7,361 23,281 9,055 396,450 Total Assets ................................. 2,118,843 344,465 145,186 -- 2,299 2,610,793 1998 Net Operating Revenues ....................... $ 597,215(4) $ 71,680 $ 66,967 $ 75,995 $ (3,605) $ 808,252 Depreciation, Depletion and Amortization ..... 265,738 25,972 12,867 8,456 2,073 315,106 Operating Income (Loss) ...................... 54,272 11,908 42,094 41,718 (36,331) 113,661 Interest Income .............................. 216 88 507 205 131 1,147 Other Expense ................................ (559) -- (150) (1,761) (3,477) (5,947) Interest Expense ............................. 53,773 6,558 859 100 -- 61,290 Income Tax Provision (Benefit) ............... (6,214) (1,112) 21,517 13,401 (23,481) 4,111 Additions to Oil and Gas Properties .......... 539,978 48,898 19,214 46,479 25,951 680,520 Total Assets ................................. 2,238,969 277,861 131,964 289,596 79,705 3,018,095
(1) See Note 4 "Transactions with Enron Corp. and Related Parties." (2) Other includes China operations in 1999 and 1998. See Note 4 "Transactions with Enron Corp. and Related Parties." (3) Sales activities with a certain purchaser in the United States and Canada segments totaled approximately $183.2 million and $98.1 million of the consolidated Net Operating Revenues for 2000 and 1999, respectively. (4) Net Operating Revenues for the United States segment are net of costs related to natural gas marketing activities of $49.0 million, $44.6 million and $83.1 million for 2000, 1999 and 1998, respectively. 27 28 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 11. OTHER INCOME (EXPENSE), NET Other income (expense) other, net for the year ended December 31, 1999, included the gain of $59.6 million on the sale of 3.2 million shares of Enron Corp. options granted to EOG under the 1997 Equity Participation and Business Opportunity Agreement with Enron Corp., and $19.4 million loss relating to anticipated costs of abandonment of certain international activities. 12. PRICE AND INTEREST RATE RISK MANAGEMENT ACTIVITIES Periodically, EOG enters into certain trading and non-trading activities including NYMEX-related commodity market transactions and other contracts. The non-trading portions of these activities have been designated to hedge the impact of market price fluctuations on anticipated commodity delivery volumes or other contractual commitments. Trading Activities. At December 31, 2000, EOG had outstanding swap contracts covering notional volumes of approximately 0.7 million barrels ("MMBbl") of crude oil and condensate for 2001. EOG elected not to designate these crude oil swap contracts as a hedge of its 2001 crude oil production, and accordingly, is accounting for these swap contracts under mark-to-market accounting. At December 31, 2000, the fair value of these swap contracts was $0.4 million. During 1999, EOG did not enter into derivative contracts that were accounted for as trading activities. Trading activities in 1998 included a revenue increase of $1.1 million related to the change in market value of natural gas price swap options exercisable by a counterparty and partially offsetting "buy" price swap positions. Hedging Transactions. At December 31, 2000, EOG had closed positions covering notional volumes of approximately 4 trillion British thermal units of natural gas for each of the years 2001 through 2005. At December 31, 2000, the aggregate deferred revenue reduction for 2001, 2002 and thereafter was approximately $1.2 million, $1.0 million and $3.8 million, respectively, and is classified as "Other Assets." During 2000, natural gas and crude oil and condensate revenues included a $17 million loss related to closed hedge positions. Interest Rate Swap Agreements and Foreign Currency Contracts. At December 31, 2000 and 1999, a subsidiary of EOG and EOG are 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. In November 1998, EOG entered into two interest rate swap agreements having notional values of $100 million each. The agreements were entered into to hedge the base variable interest rates of EOG's commercial paper, uncommitted credit facilities and affiliated borrowings. These agreements terminated in November 2000. The following table summarizes the estimated fair value of financial instruments and related transactions for non-trading activities at December 31, 2000 and 1999:
2000 1999 ------------------------------ ----------------------------- CARRYING ESTIMATED CARRYING ESTIMATED AMOUNT FAIR VALUE(1) AMOUNT FAIR VALUE(1) ---------- ------------- ---------- ------------- (IN MILLIONS) (IN MILLIONS) Long-Term Debt(2)...................................... $ 859.0 $ 831.1 $ 990.3 $ 933.0 NYMEX-Related Commodity Market Positions............... (5.6) (5.6) (18.0) (20.3)
(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 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 does not anticipate nonperformance by the other parties. 28 29 EOG RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONCLUDED) 13. CONCENTRATION OF CREDIT RISK Substantially all of EOG's accounts receivable at December 31, 2000 and 1999 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. 14. ACCOUNTING FOR CERTAIN LONG-LIVED ASSETS In 1999, as a result of the change to EOG's portfolio of assets brought about by the Share Exchange (see Note 5 "Transactions with Enron Corp. and Related Parties"), EOG conducted a re-evaluation of its overall business. As a result of this re-evaluation, some of EOG's projects were no longer deemed central to its business. EOG recorded non-cash charges in connection with the impairment and/or EOG's decision to dispose of such projects of $133 million pre-tax ($89 million after-tax). In addition, EOG recorded charges of $15 million pre-tax ($10 million after-tax) pursuant to a change in EOG's strategy related to certain offshore operations in the second quarter and an impairment of various North America properties in the fourth quarter of 1999 to depreciation, depletion and amortization expense. In the United States operating segment, a pre-tax impairment charge of $85 million was recorded to depreciation, depletion and amortization expense. The carrying values for assets determined to be impaired were adjusted to estimated fair values based on projected future discounted net cash flows for such assets. In the Other operating segment, a pre-tax charge of $36 million was recorded to depreciation, depletion and amortization expense to fully write-off EOG's basis and a pre-tax charge of $19 million was recorded to other income (expense)--other, net for the estimated exit costs related to EOG's decision to dispose of certain international operations. Net loss for the Other operating segment operations for 1999, excluding these charges, was approximately $3 million. 15. NEW ACCOUNTING PRONOUNCEMENT--SFAS NO. 133 In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133--"Accounting for Derivative Instruments and Hedging Activities" effective for fiscal years beginning after June 15, 1999. In June 1999, the FASB issued SFAS No. 137, which delays the effective date of SFAS No. 133 for one year, to fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, which amends the accounting and reporting standards of SFAS No. 133 for certain derivative instruments and certain hedging activities. SFAS No. 133, as amended by SFAS No. 137 and No. 138, cannot be applied retroactively and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after a transition date to be selected by EOG of either December 31, 1997 or December 31, 1998. The statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the statements of income and requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. EOG adopted SFAS No. 133, as amended by SFAS No. 137 and No. 138, on January 1, 2001 for the accounting periods which begin thereafter. The adoption of SFAS No. 133 did not have a material impact on EOG's financial statements. 29 30 EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (IN THOUSANDS EXCEPT PER SHARE AMOUNTS UNLESS OTHERWISE INDICATED) (UNAUDITED EXCEPT FOR RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES) OIL AND GAS PRODUCING ACTIVITIES The following disclosures are made in accordance with SFAS No. 69--"Disclosures about Oil and Gas Producing Activities": Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and EOG's estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause EOG's share of future production from Canadian reserves to be materially different from that presented. As a result of the re-evaluation of EOG's portfolio of assets following the Share Exchange, on November 12, 1999 senior management proposed to the Board of Directors ("the Board") of EOG to defer the development of the Big Piney Madison deep Paleozoic formation methane reserves in Wyoming for the foreseeable future. The Board approved the recommendation. As a result, the 1.2 trillion cubic feet of methane reserves in the formation, which are located on acreage owned by EOG and held by production for the foreseeable future, and which were classified as proved undeveloped reserves at December 31, 1998, were removed as a revision during 1999. At December 31, 1998, these reserves represented approximately $100 million or 5% of EOG's Standardized Measure of Discounted Future Net Cash Flows as adjusted for the sale of the India and China reserves as a result of the Share Exchange. At December 31, 2000, EOG had no plan to develop these reserves for the foreseeable future. 30 31 EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Estimates of proved and proved developed reserves at December 31, 2000, 1999 and 1998 were based on studies performed by the engineering staff of EOG for reserves in the United States, Canada, Trinidad, India and China (See Note 4 to the Consolidated Financial Statements regarding operations transferred under the Share Exchange). Opinions by DeGolyer and MacNaughton ("D&M"), independent petroleum consultants, for the years ended December 31, 2000, 1999, and 1998 covered producing areas containing 49%, 52% and 39%, respectively, of proved reserves, excluding deep Paleozoic methane reserves in 1998 and 1997, 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. The deep Paleozoic methane reserves were covered by the opinion of D&M for the year ended December 31, 1995. 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, 2000 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, 2000, and the changes in the net proved reserves for each of the three years in the period then ended as estimated by the engineering staff of EOG. NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
UNITED STATES CANADA TRINIDAD SUBTOTAL INDIA(2) ------------- ------ -------- -------- -------- NATURAL GAS (Bcf)(1) Net proved reserves at December 31, 1997 .............. 2,784.8 (4) 387.4 328.8 3,501.0 471.6 Revisions of previous estimates ..................... (55.9) (2.5) 4.7 (53.7) 32.3 Purchases in place .................................. 123.0 54.9 -- 177.9 -- Extensions, discoveries and other additions ......... 272.8 62.9 693.8 1,029.5 340.9 Sales in place ...................................... (37.5) -- -- (37.5) -- Production .......................................... (233.8) (38.5) (50.9) (323.2) (20.2) ------- ------- ------- ------- ------- Net proved reserves at December 31, 1998 .............. 2,853.4 (4) 464.2 976.4 4,294.0 824.6 Revisions of previous estimates ..................... (1,199.1)(5) (1.3) 4.5 (1,195.9) -- Purchases in place .................................. 108.5 34.0 -- 142.5 -- Extensions, discoveries and other additions ......... 208.2 69.8 51.0 329.0 -- Sales in place ...................................... (70.9) (1.4) -- (72.3) (807.9) Production .......................................... (242.9) (41.8) (37.3) (322.0) (16.7) ------- ------- ------- ------- ------- 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 -- ======= ======= ======= ======= ======= OTHER(3) TOTAL -------- ----- NATURAL GAS (Bcf)(1) Net proved reserves at December 31, 1997 .............. 7.7 3,980.3 Revisions of previous estimates ..................... (0.4) (21.8) Purchases in place .................................. -- 177.9 Extensions, discoveries and other additions ......... 103.0 1,473.4 Sales in place ...................................... -- (37.5) Production .......................................... -- (343.4) ------- ------- Net proved reserves at December 31, 1998 .............. 110.3 5,228.9 Revisions of previous estimates ..................... -- (1,195.9) Purchases in place .................................. -- 142.5 Extensions, discoveries and other additions ......... -- 329.0 Sales in place ...................................... (110.3) (990.5) Production .......................................... -- (338.7) ------- ------- Net proved reserves at December 31, 1999 .............. -- 3,175.3 Revisions of previous estimates ..................... -- 53.2 Purchases in place .................................. -- 228.2 Extensions, discoveries and other additions ......... -- 344.3 Sales in place ...................................... -- (84.3) Production .......................................... -- (336.1) ------- ------- Net proved reserves at December 31, 2000 .............. -- 3,380.6 ======= =======
31 32 EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
UNITED STATES CANADA TRINIDAD SUBTOTAL INDIA(2) ------------- ------ -------- -------- -------- LIQUIDS (MBbl)(6)(7) Net proved reserves at December 31, 1997 .............. 31,649 9,006 6,901 47,556 30,095 Revisions of previous estimates ..................... (152) (504) (1,049) (1,705) 3,063 Purchases in place .................................. 3,104 -- -- 3,104 -- Extensions, discoveries and other additions ......... 9,396 448 11,429 21,273 11,501 Sales in place ...................................... (1,039) -- -- (1,039) -- Production .......................................... (6,131) (1,358) (1,077) (8,566) (1,874) -------- -------- -------- -------- -------- Net proved reserves at December 31, 1998 .............. 36,827 7,592 16,204 60,623 42,785 Revisions of previous estimates ..................... 5,085 117 (72) 5,130 -- Purchases in place .................................. 2,753 39 -- 2,792 -- Extensions, discoveries and other additions ......... 9,520 2,416 509 12,445 -- Sales in place(2) ................................... (121) (37) -- (158) (41,306) Production .......................................... (6,217) (1,231) (878) (8,326) (1,479) -------- -------- -------- -------- -------- 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 -- ======== ======== ======== ======== ======== Bcf EQUIVALENT (Bcfe)(1) Net proved reserves at December 31, 1997 .............. 2,975.0 (4) 441.3 370.2 3,786.5 652.0 Revisions of previous estimates ..................... (57.0) (5.5) (1.7) (64.2) 50.8 Purchases in place .................................. 141.6 54.9 -- 196.5 -- Extensions, discoveries and other additions ......... 329.2 65.6 762.4 1,157.2 409.9 Sales in place ...................................... (43.7) -- -- (43.7) -- Production .......................................... (270.6) (46.6) (57.3) (374.5) (31.4) -------- -------- -------- -------- -------- Net proved reserves at December 31, 1998 .............. 3,074.5 (4) 509.7 1,073.6 4,657.8 1,081.3 Revisions of previous estimates ..................... (1,168.8)(5) (0.6) 4.1 (1,165.3) -- Purchases in place .................................. 125.1 34.3 -- 159.4 -- Extensions, discoveries and other additions ......... 265.3 84.3 54.0 403.6 -- Sales in place(2) ................................... (71.6) (1.6) -- (73.2) (1,055.7) Production .......................................... (280.2) (49.2) (42.5) (371.9) (25.6) -------- -------- -------- -------- -------- 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 -- ======== ======== ======== ======== ======== OTHER(3) TOTAL -------- --------- LIQUIDS (MBbl)(6)(7) Net proved reserves at December 31, 1997 .............. -- 77,651 Revisions of previous estimates ..................... 73 1,431 Purchases in place .................................. -- 3,104 Extensions, discoveries and other additions ......... 1,089 33,863 Sales in place ...................................... -- (1,039) Production .......................................... -- (10,440) -------- -------- Net proved reserves at December 31, 1998 .............. 1,162 104,570 Revisions of previous estimates ..................... -- 5,130 Purchases in place .................................. -- 2,792 Extensions, discoveries and other additions ......... -- 12,445 Sales in place(2) ................................... (1,162) (42,626) Production .......................................... -- (9,805) -------- -------- Net proved reserves at December 31, 1999 .............. -- 72,506 Revisions of previous estimates ..................... -- (1,877) Purchases in place .................................. -- 3,948 Extensions, discoveries and other additions ......... -- 13,575 Sales in place ...................................... -- (2,958) Production .......................................... -- (11,792) -------- -------- Net proved reserves at December 31, 2000 .............. -- 73,402 ======== ======== Bcf EQUIVALENT (Bcfe)(1) Net proved reserves at December 31, 1997 .............. 7.7 4,446.2 Revisions of previous estimates ..................... -- (13.4) Purchases in place .................................. -- 196.5 Extensions, discoveries and other additions ......... 109.5 1,676.6 Sales in place ...................................... -- (43.7) Production .......................................... -- (405.9) -------- -------- Net proved reserves at December 31, 1998 .............. 117.2 5,856.3 Revisions of previous estimates ..................... -- (1,165.3) Purchases in place .................................. -- 159.4 Extensions, discoveries and other additions ......... -- 403.6 Sales in place(2) ................................... (117.2) (1,246.1) Production .......................................... -- (397.5) -------- -------- Net proved reserves at December 31, 1999 .............. -- 3,610.4 Revisions of previous estimates ..................... -- 42.1 Purchases in place .................................. -- 251.9 Extensions, discoveries and other additions ......... -- 425.7 Sales in place ...................................... -- (102.1) Production .......................................... -- (407.0) -------- -------- Net proved reserves at December 31, 2000 .............. -- 3,821.0 ======== ========
32 33 EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
UNITED STATES CANADA TRINIDAD SUBTOTAL INDIA(2) TOTAL ------------- ------ -------- -------- -------- ----- NET PROVED DEVELOPED RESERVES AT NATURAL GAS (Bcf)(1) December 31, 1997........... 1,349.0 370.9 328.8 2,048.7 286.6 2,335.3 December 31, 1998........... 1,429.7 387.4 283.0 2,100.1 407.4 2,507.5 December 31, 1999........... 1,446.5 451.1 250.2 2,147.8 -- 2,147.8 December 31, 2000........... 1,498.6 479.4 207.0 2,185.0 -- 2,185.0 LIQUIDS (MBbl)(6)(7) December 31, 1997........... 27,707 8,885 6,901 43,493 23,322 66,815 December 31, 1998........... 33,045 7,465 4,782 45,292 33,472 78,764 December 31, 1999........... 41,717 7,041 3,833 52,591 -- 52,591 December 31, 2000........... 42,132 5,695 2,967 50,794 -- 50,794 Bcf EQUIVALENTS December 31, 1997........... 1,515.3 424.2 370.2 2,309.7 426.5 2,736.2 December 31, 1998........... 1,628.0 432.1 311.7 2,371.8 608.2 2,980.0 December 31, 1999........... 1,696.8 493.3 273.2 2,463.3 -- 2,463.3 December 31, 2000........... 1,751.4 513.6 224.8 2,489.8 -- 2,489.8
------------------- (1) Billion cubic feet or billion cubic feet equivalent, as applicable. (2) See Note 4 "Transactions with Enron Corp. and Related Parties." (3) Other includes China operations only. See Note 4 "Transactions with Enron Corp. and Related Parties." (4) Includes 1,180 Bcf of proved undeveloped methane reserves contained, along with high concentrations of carbon dioxide and other gases, in deep Paleozoic (Madison) formations in the Big Piney area of Wyoming. (5) Includes reduction of the 1,180 Bcf of proved undeveloped methane reserves mentioned in (4) as a result of EOG's decision to defer the development of the Big Piney Madison deep Paleozoic formation methane reserves in Wyoming for the foreseeable future. (6) Thousand barrels. (7) 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, 2000 and 1999:
2000 1999 ----------- ----------- Proved Properties ........................... $ 4,966,667 $ 4,459,727 Unproved Properties ......................... 156,061 143,013 ----------- ----------- Total ............................ 5,122,728 4,602,740 Accumulated depreciation, depletion and amortization ......................... (2,597,721) (2,267,812) ----------- ----------- Net capitalized costs ....................... $ 2,525,007 $ 2,334,928 =========== ===========
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19--"Financial Accounting and Reporting by Oil and Gas Producing Companies." Acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Exploration costs include exploration expenses, additions to exploration wells including those in progress, and depreciation of support equipment used in exploration activities. 33 34 EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Development costs include additions to production facilities and equipment, additions to development wells including those in progress and depreciation of support equipment and related facilities used in development activities. The following tables set forth costs incurred related to EOG's oil and gas activities for the years ended December 31:
UNITED STATES CANADA TRINIDAD OTHER SUBTOTAL INDIA(1) ------------- ------ -------- ----- -------- -------- 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 Taxes ....................... 18,744 3,685 -- -- 22,429 -- -------- ------- ------- ------- -------- ------- Total ............................... $586,380 $79,102 $40,537 $ 3,581 $709,600 $ -- ======== ======= ======= ======= ======== ======= 1999 Acquisition Costs of Properties Unproved .................................. $ 18,964 $ 2,276 $ -- $ -- $ 21,240 $ -- Proved .................................... 22,092 20,838 -- -- 42,930 -- -------- ------- ------- ------- -------- ------- Subtotal ............................ 41,056 23,114 -- -- 64,170 -- Exploration Costs ........................... 65,070 6,516 8,425 4,350 84,361 1,083 Development Costs ........................... 234,900 39,544 4,801 20 279,265 23,281 -------- ------- ------- ------- -------- ------- Subtotal ............................ 341,026 69,174 13,226 4,370 427,796 24,364 Deferred Income Taxes ....................... -- -- -- -- -- -- -------- ------- ------- ------- -------- ------- Total ............................... $341,026 $69,174 $13,226 $ 4,370 $427,796 $24,364 ======== ======= ======= ======= ======== ======= 1998 Acquisition Costs of Properties Unproved .................................. $ 32,925 $ 3,545 $ -- $ -- $ 36,470 $ -- Proved .................................... 198,006 12,896 -- -- 210,902 -- -------- ------- ------- ------- -------- ------- Subtotal ............................ 230,931 16,441 -- -- 247,372 -- Exploration Costs ........................... 82,248 12,375 15,217 24,183 134,023 1,278 Development Costs ........................... 290,673 27,578 6,024 10,206 334,481 46,479 -------- ------- ------- ------- -------- ------- Subtotal ............................ 603,852 56,394 21,241 34,389 715,876 47,757 Deferred Income Taxes ....................... -- -- -- -- -- -- -------- ------- ------- ------- -------- ------- Total ............................... $603,852 $56,394 $21,241 $34,389 $715,876 $47,757 ======== ======= ======= ======= ======== ======= CHINA(1) TOTAL -------- ----- 2000 Acquisition Costs of Properties Unproved .................................. $ -- $ 51,197 Proved .................................... -- 102,438 ------ -------- Subtotal ............................ -- 153,635 Exploration Costs ........................... -- 122,795 Development Costs ........................... -- 410,741 ------ -------- Subtotal ............................ -- 687,171 Deferred Income Taxes ....................... -- 22,429 ------ -------- Total ............................... $ -- $709,600 ====== ======== 1999 Acquisition Costs of Properties Unproved .................................. $ -- $ 21,240 Proved .................................... -- 42,930 ------ -------- Subtotal ............................ -- 64,170 Exploration Costs ........................... 1,014 86,458 Development Costs ........................... 7,942 310,488 ------ -------- Subtotal ............................ 8,956 461,116 Deferred Income Taxes ....................... -- -- ------ -------- Total ............................... 8,956 $461,116 ====== ======== 1998 Acquisition Costs of Properties Unproved .................................. $ -- $ 36,470 Proved .................................... -- 210,902 ------ -------- Subtotal ............................ -- 247,372 Exploration Costs ........................... 1,282 136,583 Development Costs ........................... 4,296 385,256 ------ -------- Subtotal ............................ 5,578 769,211 Deferred Income Taxes ....................... -- -- ------ -------- Total ............................... $5,578 $769,211 ====== ========
(1) See Note 4 "Transactions with Enron Corp. and Related Parties." 34 35 EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Results of Operations for Oil and Gas Producing Activities(1). The following tables set forth results of operations for oil and gas producing activities for the years ended December 31:
UNITED STATES CANADA TRINIDAD SUBTOTAL INDIA(2) ------ ------ -------- -------- -------- 2000 Operating Revenues Trade ........................................ $1,118,434 $ 184,386 $82,430 $1,385,250 $ -- Associated Companies ......................... 102,834 -- -- 102,834 -- Gains (Losses) on Sales of Reserves and Related Assets ............................. 5,833 (294) -- 5,539 -- ---------- --------- ------- ---------- ------- Total ...................................... 1,227,101 184,092 82,430 1,493,623 -- Exploration Expenses, including Dry Hole ......... 72,000 4,881 7,314 84,195 -- Production Costs ................................. 172,464 31,785 15,669 219,918 -- Impairment of Unproved Oil and Gas Properties ................................. 33,647 2,070 -- 35,717 -- Depreciation, Depletion and Amortization ......... 315,746 39,253 13,959 368,958 -- ---------- --------- ------- ---------- ------- Income (Loss) before Income Taxes ................ 633,244 106,103 45,488 784,835 -- Income Tax Provision (Benefit) ................... 231,182 41,274 25,018 297,474 -- ---------- --------- ------- ---------- ------- Results of Operations ............................ $ 402,062 $ 64,829 $20,470 $ 487,361 $ -- ========== ========= ======= ========== ======= 1999 Operating Revenues Trade ........................................ $ 510,567 $ 86,581 $55,900 $ 653,048 $53,897 Associated Companies ......................... 125,204 11,161 -- 136,365 -- Gains (Losses) on Sales of Reserves and Related Assets ............................. 2,254 75 -- 2,329 -- ---------- --------- ------- ---------- ------- Total ...................................... 638,025 97,817 55,900 791,742 53,897 Exploration Expenses, including Dry Hole ......... 49,181 5,122 5,865 60,168 1,083 Production Costs ................................. 114,810 24,698 8,322 147,830 13,413 Impairment of Unproved Oil and Gas Properties ..................................... 29,384 2,224 -- 31,608 -- Depreciation, Depletion and Amortization ......... 370,536 29,826 12,787 413,149 7,223 ---------- --------- ------- ---------- ------- Income (Loss) before Income Taxes ................ 74,114 35,947 28,926 138,987 32,178 Income Tax Provision (Benefit) ................... 21,283 12,259 15,909 49,451 15,445 ---------- --------- ------- ---------- ------- Results of Operations ............................ $ 52,831 $ 23,688 $13,017 $ 89,536 $16,733 ========== ========= ======= ========== ======= 1998 Operating Revenues Trade ........................................ $ 448,653 $ 56,543 $66,967 $ 572,163 $75,995 Associated Companies ......................... 121,112 15,132 -- 136,244 -- Gains (Losses) on Sales of Reserves and Related Assets ............................. 29,268 (15) -- 29,253 -- ---------- --------- ------- ---------- ------- Total ...................................... 599,033 71,660 66,967 737,660 75,995 Exploration Expenses, including Dry Hole ......... 63,875 7,496 2,027 73,398 1,278 Production Costs ................................. 119,012 22,773 7,361 149,146 16,786 Impairment of Unproved Oil and Gas Properties ................................. 29,952 2,124 -- 32,076 -- Depreciation, Depletion and Amortization ......... 264,927 25,972 12,867 303,766 8,456 ---------- --------- ------- ---------- ------- Income (Loss) before Income Taxes ................ 121,267 13,295 44,712 179,274 49,475 Income Tax Provision (Benefit) ................... 22,944 3,840 24,592 51,376 23,748 ---------- --------- ------- ---------- ------- Results of Operations ............................ $ 98,323 $ 9,455 $20,120 $ 127,898 $25,727 ========== ========= ======= ========== ======= OTHER(3) TOTAL -------- ----- 2000 Operating Revenues Trade ........................................ $ 59 $ 1,385,309 Associated Companies ......................... -- 102,834 Gains (Losses) on Sales of Reserves and Related Assets ............................. -- 5,539 ----------- ----------- Total ...................................... 59 1,493,682 Exploration Expenses, including Dry Hole ......... 337 84,532 Production Costs ................................. 129 220,047 Impairment of Unproved Oil and Gas Properties ................................. -- 35,717 Depreciation, Depletion and Amortization ......... 2 368,960 ----------- ----------- Income (Loss) before Income Taxes ................ (409) 784,426 Income Tax Provision (Benefit) ................... (144) 297,330 ----------- ----------- Results of Operations ............................ $ (265) $ 487,096 =========== =========== 1999 Operating Revenues Trade ........................................ $ 39 $ 706,984 Associated Companies ......................... -- 136,365 Gains (Losses) on Sales of Reserves and Related Assets ............................. (7,931) (5,602) ----------- ----------- Total ...................................... (7,892) 837,747 Exploration Expenses, including Dry Hole ......... 3,415 64,666 Production Costs ................................. 2,334 163,577 Impairment of Unproved Oil and Gas Properties ..................................... -- 31,608 Depreciation, Depletion and Amortization ......... 38,436 458,808 ----------- ----------- Income (Loss) before Income Taxes ................ (52,077) 119,088 Income Tax Provision (Benefit) ................... (18,227) 46,669 ----------- ----------- Results of Operations ............................ $ (33,850) $ 72,419 =========== =========== 1998 Operating Revenues Trade ........................................ $ 52 $ 648,210 Associated Companies ......................... -- 136,244 Gains (Losses) on Sales of Reserves and Related Assets ............................. (3,658) 25,595 ----------- ----------- Total ...................................... (3,606) 810,049 Exploration Expenses, including Dry Hole ......... 14,015 88,691 Production Costs ................................. 3,666 169,598 Impairment of Unproved Oil and Gas Properties ................................. -- 32,076 Depreciation, Depletion and Amortization ......... 2,073 314,295 ----------- ----------- Income (Loss) before Income Taxes ................ (23,360) 205,389 Income Tax Provision (Benefit) ................... (7,370) 67,754 ----------- ----------- Results of Operations ............................ $ (15,990) $ 137,635 =========== ===========
(1) Excludes net revenues associated with other marketing activities, interest charges, general corporate expenses and certain gathering and handling fees for each of the three years in the period ended December 31, 2000. The gathering and handling fees and other marketing net revenues are directly associated with oil and gas operations with regard to segment reporting as defined in SFAS No. 131--"Disclosures about Segments of an Enterprise and Related Information," but are not part of Disclosures about Oil and Gas Producing Activities as defined in SFAS No. 69. (2) See Note 4 "Transactions with Enron Corp. and Related Parties." (3) Other includes China (in 1999 and 1998) and other international operations. See Note 4 "Transactions with Enron Corp. and Related Parties." 35 36 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 SUBTOTAL INDIA(1) ------ ------ -------- -------- -------- 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(3)....... $ 6,011,133 $ 1,513,751 $ 388,553 $ 7,913,437 $ -- ============ =========== =========== ============ =========== 1999 Future cash inflows ...................... $ 4,653,014 $ 1,159,024 $ 1,455,951 $ 7,267,989 $ -- Future production costs .................. (1,277,485) (300,332) (486,902) (2,064,719) -- Future development costs ................. (175,039) (46,966) (158,778) (380,783) -- ------------ ----------- ----------- ------------ ----------- Future net cash flows before income taxes ........................... 3,200,490 811,726 810,271 4,822,487 -- Future income taxes ...................... (630,876) (226,118) (253,373) (1,110,367) -- ------------ ----------- ----------- ------------ ----------- Future net cash flows .................... 2,569,614 585,608 556,898 3,712,120 -- Discount to present value at 10% annual rate ........................ (842,382) (207,717) (267,965) (1,318,064) -- ------------ ----------- ----------- ------------ ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves ......... $ 1,727,232 $ 377,891 $ 288,933 $ 2,394,056 $ -- ============ =========== =========== ============ =========== 1998 Future cash inflows ...................... $ 5,471,121 $ 827,416 $ 1,210,060 $ 7,508,597 $ 2,384,459 Future production costs .................. (1,280,875) (200,492) (347,431) (1,828,798) (556,609) Future development costs ................. (316,175) (38,963) (161,424) (516,562) (392,546) ------------ ----------- ----------- ------------ ----------- Future net cash flows before income taxes ........................... 3,874,071 587,961 701,205 5,163,237 1,435,304 Future income taxes ...................... (903,983) (119,655) (229,281) (1,252,919) (614,297) ------------ ----------- ----------- ------------ ----------- Future net cash flows .................... 2,970,088 468,306 471,924 3,910,318 821,007 Discount to present value at 10% annual rate ............................ (1,399,541) (161,988) (234,129) (1,795,658) (434,714) ------------ ----------- ----------- ------------ ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves ......... $ 1,570,547 $ 306,318 $ 237,795 $ 2,114,660 $ 386,293 ============ =========== =========== ============ =========== OTHER(2) TOTAL -------- ----- 2000 Future cash inflows ...................... $ -- $ 25,065,431 Future production costs .................. -- (3,824,947) Future development costs ................. -- (518,159) ------------ ------------ Future net cash flows before income taxes ........................... -- 20,722,325 Future income taxes ...................... -- (6,757,474) ------------ ------------ Future net cash flows .................... -- 13,964,851 Discount to present value at 10% annual rate ............................ -- (6,051,414) ------------ ------------ Standardized measure of discounted future net cash flows relating to proved oil and gas reserves ......... $ -- $ 7,913,437 ============ ============ 1999 Future cash inflows ...................... $ -- $ 7,267,989 Future production costs .................. -- (2,064,719) Future development costs ................. -- (380,783) ------------ ------------ Future net cash flows before income taxes ........................... -- 4,822,487 Future income taxes ...................... -- (1,110,367) ------------ ------------ Future net cash flows .................... -- 3,712,120 Discount to present value at 10% annual rate ........................ -- (1,318,064) ------------ ------------ Standardized measure of discounted future net cash flows relating to proved oil and gas reserves ......... $ -- $ 2,394,056 ============ ============ 1998 Future cash inflows ...................... $ 179,329 $ 10,072,385 Future production costs .................. (127,039) (2,512,446) Future development costs ................. (11,325) (920,433) ------------ ------------ Future net cash flows before income taxes ........................... 40,965 6,639,506 Future income taxes ...................... (7,111) (1,874,327) ------------ ------------ Future net cash flows .................... 33,854 4,765,179 Discount to present value at 10% annual rate ............................ (13,893) (2,244,265) ------------ ------------ Standardized measure of discounted future net cash flows relating to proved oil and gas reserves ......... $ 19,961 $ 2,520,914 ============ ============
(1) See Note 4 "Transactions with Enron Corp. and Related Parties." (2) Other includes China operations only. See Note 4 "Transactions with Enron Corp. and Related Parties." (3) Natural gas prices have declined significantly since December 31, 2000; consequently, the discounted future net cash flows would be significantly reduced if the standardized measure was calculated in the first quarter of 2001. 36 37 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, 2000.
UNITED STATES CANADA TRINIDAD SUBTOTAL INDIA (1) ------------- ------ -------- -------- --------- DECEMBER 31, 1997 ......................... $ 1,549,719(3) $ 277,312 $ 147,919 $ 1,974,950 $ 319,728 Sales and transfers of oil and gas produced, net of production costs ...................... (423,733) (48,902) (59,606) (532,241) (59,209) Net changes in prices and production costs ...................... (33,809) 10,445 (36,730) (60,094) (103,097) Extensions, discoveries, additions and improved recovery net of related costs ......... 325,308 43,686 159,497 528,491 218,168 Development costs incurred .............. 59,600 2,900 6,000 68,500 43,400 Revisions of estimated development costs ..................... (26,611) 3,584 (11,410) (34,437) (66,128) Revisions of previous quantity estimates ............................. (35,216) (4,109) (1,142) (40,467) 36,877 Accretion of discount ................... 174,102 30,332 28,791 233,225 53,296 Net change in income taxes .............. 47,745 (5,822) (122) 41,801 212 Purchases of reserves in place .......... 156,818 20,131 -- 176,949 -- Sales of reserves in place .............. (33,549) -- -- (33,549) -- Changes in timing and other ............. (189,827) (23,239) 4,598 (208,468) (56,954) ----------- ----------- ----------- ----------- --------- DECEMBER 31, 1998 ......................... 1,570,547(3) 306,318 237,795 2,114,660 386,293 Sales and transfers of oil and gas produced, net of production costs ...................... (520,961) (73,044) (47,578) (641,583) (40,484) Net changes in prices and production costs ...................... 265,946 77,195 76,381 419,522 -- Extensions, discoveries, additions and improved recovery net of related costs ......... 310,470 68,396 8,523 387,389 -- Development costs incurred .............. 42,500 16,100 -- 58,600 23,820 Revisions of estimated development costs ..................... 133,741 687 8,178 142,606 -- Revisions of previous quantity estimates ............................. (163,423)(4) (505) 2,051 (161,877) -- Accretion of discount ................... 171,588 33,815 37,790 243,193 -- Net change in income taxes .............. (27,883) (79,397) (22,874) (130,154) -- Purchases of reserves in place .......... 102,086 18,769 -- 120,855 -- Sales of reserves in place .............. (81,607) (1,276) -- (82,883) (369,629) Changes in timing and other ............. (75,772) 10,833 (11,333) (76,272) -- ----------- ----------- ----------- ----------- --------- 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 estimates 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 $ -- =========== =========== ========= =========== ========= OTHER (2) TOTAL --------- ----- DECEMBER 31, 1997 ......................... $ 5,776 $ 2,300,454 Sales and transfers of oil and gas produced, net of production costs ...................... 3,664 (587,786) Net changes in prices and production costs ...................... (6,961) (170,152) Extensions, discoveries, additions and improved recovery net of related costs ......... 18,894 765,553 Development costs incurred .............. 4,300 116,200 Revisions of estimated development costs ..................... (3,233) (103,798) Revisions of previous quantity estimates ............................. -- (3,590) Accretion of discount ................... 562 287,083 Net change in income taxes .............. (428) 41,585 Purchases of reserves in place .......... -- 176,949 Sales of reserves in place .............. -- (33,549) Changes in timing and other ............. (2,613) (268,035) ------- ----------- DECEMBER 31, 1998 ......................... 19,961 2,520,914 Sales and transfers of oil and gas produced, net of production costs ...................... 2,334 (679,733) Net changes in prices and production costs ...................... -- 419,522 Extensions, discoveries, additions and improved recovery net of related costs ......... -- 387,389 Development costs incurred .............. 8,010 90,430 Revisions of estimated development costs ..................... -- 142,606 Revisions of previous quantity estimates ............................. -- (161,877) Accretion of discount ................... -- 243,193 Net change in income taxes .............. -- (130,154) Purchases of reserves in place .......... -- 120,855 Sales of reserves in place .............. (30,305) (482,817) Changes in timing and other ............. -- (76,272) ------- ----------- DECEMBER 31, 1999 ......................... -- 2,394,056 Sales and transfers of oil and gas produced, net of production costs ...................... -- (1,268,167) Net changes in prices and production costs ...................... -- 7,463,611 Extensions, discoveries, additions and improved recovery net of related costs ......... -- 1,617,300 Development costs incurred .............. -- 130,700 Revisions of estimates development costs ..................... -- (58,606) Revisions of previous quantity estimates ............................. -- 184,109 Accretion of discount ................... -- 284,149 Net change in income taxes .............. -- (3,034,824) Purchases of reserves in place .......... -- 807,742 Sales of reserves in place .............. -- (354,414) Changes in timing and other ............. -- (252,219) ------- ----------- DECEMBER 31, 2000 ......................... $ -- $ 7,913,437 ======= ===========
(1) See Note 4 "Transactions with Enron Corp. and Related Parties." (2) Other includes China operations only. See Note 4 "Transactions with Enron Corp. and Related Parties." (3) Includes approximately $55,316 and $100,284 in 1997 and 1998, respectively, related to the reserves in the Big Piney deep Paleozoic formations. (4) Includes reserves reduction of approximately $172,057, discounted before income taxes, related to the reserves in the Big Piney deep Paleozoic formations. 37 38 EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (CONCLUDED) UNAUDITED QUARTERLY FINANCIAL INFORMATION
QUARTER ENDED ------------------------------------------------ MARCH 31 JUNE 30 SEPT. 30 DEC. 31 --------- --------- --------- --------- 2000 Net Operating Revenues ................... $ 259,897 $ 322,725 $ 402,152 $ 505,121 ========= ========= ========= ========= Operating Income ......................... $ 80,210 $ 139,235 $ 203,658 $ 273,760 ========= ========= ========= ========= Income before Income Taxes ............... $ 65,659 $ 124,417 $ 188,943 $ 254,538 Income Tax Provision ..................... 24,169 46,900 72,466 93,091 --------- --------- --------- --------- Net Income ............................... 41,490 77,517 116,477 161,447 Preferred Stock Dividends ................ (2,654) (2,860) (2,755) (2,759) --------- --------- --------- --------- Net Income Available to Common ........... $ 38,836 $ 74,657 $ 113,722 $ 158,688 ========= ========= ========= ========= Net Income per Share Available to Common Basic(1) ............................. $ 0.33 $ 0.64 $ 0.98 $ 1.36 ========= ========= ========= ========= Diluted(1) ........................... $ 0.33 $ 0.63 $ 0.95 $ 1.33 ========= ========= ========= ========= Average Number of Common Shares Basic ................................. 117,827 116,666 116,559 116,684 ========= ========= ========= ========= Diluted ............................... 118,273 119,179 119,262 119,582 ========= ========= ========= ========= 1999 Net Operating Revenues ................... $ 169,561 $ 198,208 $ 236,887 $ 237,443 ========= ========= ========= ========= Operating Income (Loss) .................. $ (9,604) $ 15,695 $ (53,229) $ 65,326 ========= ========= ========= ========= Income before Income Taxes ............... $ 3,067 $ 32,273 $ 484,281 $ 48,091 Income Tax Provision (Benefit) ........... (1,999) 11,635 (28,640) 17,622 --------- --------- --------- --------- Net Income ............................... 5,066 20,638 512,921 30,469 Preferred Stock Dividends ................ -- -- -- (535) --------- --------- --------- --------- Net Income Available to Common ........... $ 5,066 $ 20,638 $ 512,921 $ 29,934 ========= ========= ========= ========= Net Income per Share Available to Common Basic(1) .............................. $ .03 $ .13 $ 3.75 $ .25 ========= ========= ========= ========= Diluted(1) ............................ $ .03 $ .13 $ 3.71 $ .25 ========= ========= ========= ========= Average Number of Common Shares Basic ................................. 153,388 153,484 136,662 119,059 ========= ========= ========= ========= Diluted ............................... 154,048 154,540 138,271 119,778 ========= ========= ========= =========
(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. 38 39 EXHIBIT INDEX
EXHBIT NUMBER DESCRIPTION ------ ----------- 23.1 Consent of DeGolyer and MacNaughton. 23.2 Opinion of DeGolyer and MacNaughton dated February 8, 2001. 23.3 Consent of Arthur Andersen LLP.