10-Q 1 d10q.txt FORM 10-Q FOR PERIOD ENDING JUNE 30, 2002 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT UNDER SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarterly Period Ended June 30, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition Period from ____________to____________. Commission File No. 1-12905 EEX CORPORATION (Exact name of Registrant as specified in its charter) Texas 75-2421863 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 2500 CityWest Blvd. Suite 1400 Houston, Texas 77042 (Address of principal executive office) (Zip Code) (713) 243-3100 (Registrant's telephone number, including Area Code) Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Number of shares of Common Stock of Registrant outstanding as of July 31, 2002: 42,556,914 PART I. FINANCIAL INFORMATION Item 1. Financial Statements EEX CORPORATION CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (UNAUDITED)

Three Months Ended ~~Nine~~Six Months Ended ~~September~~June 30 ~~September~~June 30 ----------------------------~~-----~~ ----------------------------~~---~~ 2002 2001 ~~2000~~2002 2001 ~~2000~~ -------------- -------------- -------------- ------------- (In thousands, except per share amounts) Revenues: Natural gas~~.............................................~~ $ 3235,~~580~~100 $44 33,~~021~~051 $~~105~~ 71,~~117~~431 $~~122~~ 72,~~216~~537 Oil, condensate and natural gas liquids~~.................~~ 142,~~239~~369 192,~~940~~931 484,~~206~~452 596,~~420~~196 Cogeneration operations~~.................................~~ 827 1,~~306~~843 1,~~664~~966 53,~~194~~888 ~~5,915~~ Other~~...................................................~~ ~~365~~346 ~~358~~223 1,~~392~~304 1,~~579~~027 ---------~~-----~~ ---------~~-----~~ ---------~~-----~~ ---------~~---~~ Total~~................................................~~ 4838,~~490~~642 6538,~~983~~048 ~~159~~79,~~909~~153 ~~189~~83,~~130~~648 ---------~~-----~~ ---------~~-----~~ ---------~~-----~~ ---------~~---~~ Costs and Expenses: Production and operating~~................................~~ 85,~~547~~728 105,~~076~~445 2511,~~958~~966 2910,~~402~~387 Exploration~~.............................................~~ 8,~~662~~940 78,~~880~~060 3714,~~068~~664 2227,~~134~~771 Depletion, depreciation and amortization~~................~~ 1711,~~633~~956 2411,~~608~~548 5024,~~227~~086 7022,~~857~~988 ~~Impairment of producing oil and gas properties.......... -- -- -- 12,200~~ (Gain) Loss on sales of property, plant and equipment~~...~~ (~~29,176~~156) ~~1,389~~33 (~~28,841~~173) ~~3,678~~335 Cogeneration operations~~.................................~~ ~~992~~1,041 1,~~405~~593 41,~~460~~842 43,~~793~~468 General, administrative and other~~.......................~~ 24,~~956~~906 43,~~638~~187 9,~~457~~289 156,~~554~~500 Taxes, other than income~~................................~~ 23,~~300~~789 34,~~412~~121 115,~~966~~646 79,~~403~~666 ---------~~-----~~ ---------~~-----~~ ---------~~-----~~ ---------~~---~~ Total~~................................................~~ 1136,~~914~~204 5333,~~408~~987 ~~110~~67,~~295~~320 ~~166~~81,~~021~~115 ---------~~-----~~ ---------~~-----~~ ---------~~-----~~ ---------~~---~~ Operating Income~~..........................................~~ 36from Continuing Operations 2,~~576~~438 124,~~575~~061 4911,~~614~~833 232,~~109~~533 Other Income--Net~~.........................................~~ 1965 4749 9093 ~~168~~51 Interest Income~~...........................................~~ ~~183~~338 ~~384~~205 ~~784~~867 ~~725~~601 Interest and Other Financing Costs~~........................~~ (76,~~519~~649) (87,~~861~~765) (2312,~~096~~811) (2415,~~819~~577) --------- --------- --------- --------- Income (Loss) from Continuing Operations Before Income Taxes (3,808) (3,450) (18) (12,392) Income Taxes -- -- -- -- --------- --------- --------- --------- Income (Loss) ~~Before~~from ~~Income~~Continuing ~~Taxes.........................~~Operations 29(3,~~259~~808) 4(3,~~145~~450) ~~27,392~~(18) (~~817~~12,392) Discontinued Operations: Income ~~Taxes..............................................~~(Loss) ~~9,281~~from ~~800~~Discontinued 9Operations,~~281~~ ~~3,100~~Net ~~Minority~~of ~~Interest~~Income ~~Third~~Taxes ~~Party.............................~~(241) --5,832 12,~~674~~460 ~~-- 3~~10,~~062~~525 ---------~~-----~~ ---------~~-----~~ ---------~~-----~~ ---------~~---~~ Net Income (Loss)~~.........................................~~ 19(4,~~978~~049) 12,~~671~~382 182,~~111~~442 (61,~~979~~867) Preferred Stock Dividends~~.................................~~ 3,~~652~~875 3,~~373~~579 107,~~741~~674 97,~~923~~089 ---------~~-----~~ ---------~~-----~~ ---------~~-----~~ ---------~~---~~ Net ~~Income~~ (Loss) Applicable to Common Shareholders~~.......~~ $ 16(7,~~326~~924) $ (1,~~702~~197) $ 7(5,~~370~~232) $ (168,~~902~~956) =========~~=====~~ =========~~=====~~ =========~~=====~~ =========~~===~~ ~~Net~~Basic ~~Income~~and ~~(Loss)~~Diluted Earnings Per Share: ~~Available~~Net to(Loss) ~~Common~~from ~~Shareholders:~~Continuing ~~Basic...................................................~~Operations $ (0.3918) $ (0.0417) $ (0.18) $ (0.4047) =========~~=====~~ =========~~=====~~ =========~~=====~~ ============ ~~Diluted.................................................~~Net Income (Loss) from Discontinued Operations $ (0.2901) $ (0.~~04)~~14 $ 0.1806 $ (0.~~40)~~26 =========~~=====~~ =========~~=====~~ =========~~=====~~ =========~~===~~ ~~Weighted~~Net ~~Average~~(Loss) ~~Shares~~Applicable ~~Outstanding:~~to ~~Basic~~Common Shareholders $ (0.19) $ (0.~~.................................................~~03) ~~41,723~~$ ~~41,929~~(0.12) ~~41,695~~$ ~~42,110~~(0.21) =========~~=====~~ =========~~=====~~ =========~~=====~~ =========~~===~~ Weighted Average Shares Outstanding: Basic and Diluted~~.................................................~~ 6941,~~863~~903 41,~~929~~664 41,~~798~~881 4241,~~110 ============== ============== ============== ============~~656

See accompanying notes. 2 EEX CORPORATION CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED)

~~September~~June 30 December 31 2002 2001 ~~2000~~ --------------- --------------- (In thousands) ASSETS ~~------~~ Current Assets: Cash and cash equivalents~~....................................................~~ $ 517,~~965~~441 $ 19136,~~791~~618 Accounts receivable--trade (net of allowance of $2,~~329~~781 and $2,~~270~~780)~~...........~~ 6223,~~222~~100 5729,~~539~~651 ~~Other........................................................................~~Natural 20gas hedging derivatives -- 23,~~924~~203 22Assets held for sale (net of allowance of $0 and $1,~~478~~650) -- 13,174 Other 3,472 1,871 ----------- ------------ Total current assets~~.....................................................~~ 8944,~~111~~013 99204,~~808~~517 ------------ ------------ Property, Plant and Equipment (at cost): Oil and gas properties (successful efforts method)~~...........................~~ 1903,~~013,523~~101 ~~955~~873,~~263~~008 Other~~........................................................................~~ 8,~~617~~582 8,~~160~~668 ------------ ------------ Total~~....................................................................~~ 1911,~~022,140~~683 ~~963~~881,~~423~~676 Less accumulated depletion, depreciation and amortization~~....................~~ ~~335~~386,~~454~~238 ~~323~~362,~~875~~128 ------------ ------------ Net property, plant and equipment~~........................................~~ ~~686~~525,~~686~~445 ~~639~~519,548 ------------ ------------ ~~Deferred~~Net ~~Income~~property, ~~Tax~~plant ~~Assets......................................................~~and ~~10,565~~equipment 19held for sale -- 18,~~846~~107 Other Assets~~....................................................................~~ 184,~~200~~528 47,~~866~~946 ------------ ------------ Total~~....................................................................~~ $ ~~804~~573,~~562~~986 $ ~~764~~750,~~068~~118 ============ ============ LIABILITIES AND SHAREHOLDERS' EQUITY ~~------------------------------------~~ Current Liabilities: Accounts payable--trade~~......................................................~~ $ 5536,~~902~~048 $ 7642,~~999~~443 Bank revolving credit agreement~~..............................................~~ ~~180~~221,000 --325,000 ~~Capital~~Secured ~~lease~~notes ~~obligations....................................................~~payable --14,642 13,~~351~~579 ~~Secured~~Liabilities ~~notes~~held ~~payable........................................................~~for ~~16,278~~sale --75 6,132 Other~~........................................................................~~ 64,~~398~~174 57,~~993~~118 ------------ ------------ Total current liabilities~~................................................~~ ~~258~~275,~~578~~939 96394,~~343~~272 ------------ ------------ ~~Bank Revolving Credit Agreement................................................. -- 75,000 Capital Lease Obligations....................................................... -- 192,283~~ Secured Notes Payable~~...........................................................~~ ~~120~~86,~~795~~122 --100,764 Gas Sales Obligation~~............................................................~~ 6346,~~191~~957 8359,~~490~~937 Other Liabilities~~...............................................................~~ 1013,~~336~~457 229,~~351~~357 Minority Interest Third Party~~...................................................~~ 5,000 5,000 Shareholders' Equity: Preferred stock (10,000 shares authorized; 1,~~862~~976 and 1,~~755~~899 shares issued; Liquidation preference of $~~186~~197,~~222~~620 and $~~175~~189,~~481~~946)~~.........................~~ 20 19 18 Common stock ($0.01 par value; 150,000 shares authorized; 42,~~497~~558 and 42,~~256~~496 shares issued)~~....................................................~~ 433 432 ~~429~~ Paid in capital~~..............................................................~~ ~~756~~768,~~761~~331 ~~744~~760,~~782~~484 Retained (deficit)~~...........................................................~~ (~~437~~610,~~796~~844) (~~445~~605,~~166~~612) Unamortized restricted stock compensation~~....................................~~ (1,~~712~~124) (1,~~067~~403) ~~Unearned compensation........................................................ -- (349)~~ Other comprehensive income~~...................................................~~ 38(1,~~029~~188) --35,954 Treasury stock, at cost (~~817~~843 and ~~808~~817 shares)~~.................................~~ (9,~~071~~117) (9,~~046~~086) ------------ ------------ Total shareholders' equity~~...............................................~~ ~~346~~146,~~662~~511 ~~289~~180,~~601~~788 ------------ ------------ Total~~....................................................................~~ $ ~~804~~573,~~562~~986 $ ~~764~~750,~~068~~118 ============ ============

See accompanying notes. 3 EEX CORPORATION CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

~~Nine~~Six Months Ended ~~September~~June 30 -------------------------------~~-----~~ 2002 2001 ~~2000~~ --------------- --------------- (In thousands) OPERATING ACTIVITIES Net Income (Loss)~~.........................................................~~ $ 182,~~111~~442 $ (61,~~979~~867) ~~Dry~~Less: ~~hole~~Income ~~cost.............................................................~~from discontinued operations 2,~~945~~460 10,525 ---------- ---------- Income (~~328~~Loss) ~~Depletion,~~from ~~depreciation~~continuing ~~and~~operations ~~amortization..................................~~(18) 50(12,~~227~~392) ~~70,857~~Adjustments ~~Impairment~~to ofreconcile ~~producing~~net ~~oil~~income ~~and~~to ~~gas~~net ~~properties............................~~cash --provided ~~12,200~~by ~~Impairment~~operating ofactivities: ~~undeveloped~~Dry ~~leasehold.......................................~~hole 5cost 23 853 Depletion,~~896~~ 4depreciation and amortization 24,~~793~~086 ~~Deferred~~22,988 ~~income~~Impairment ~~taxes.....................................................~~of 9undeveloped leasehold 4,~~281~~852 3,~~100~~900 (Gain) Loss on sales of property, plant and equipment~~.....................~~ (~~28,841~~173) ~~3,678~~335 Other~~.....................................................................~~ (133,~~826~~739) (1811,~~954~~119) Changes in current operating assets and liabilities: Accounts receivable~~......................................................~~ ~~22,591~~ (183,~~493~~213) 8,075 Other current assets~~.....................................................~~ ~~1,554~~ (1,~~768~~601) 5,523 Accounts payable~~.........................................................~~ (211,~~820~~876) (614,~~155~~128) Other current liabilities~~................................................~~ ~~405~~(2,944) 3(1,~~224~~483) ----------~~-----~~ ----------~~-----~~ Net cash flows provided by operating activities~~........................~~ 4615,~~523~~397 452,~~175~~552 ----------~~-----~~ ----------~~-----~~ INVESTING ACTIVITIES Additions of property, plant and equipment~~................................~~ (~~136~~34,~~657~~703) (~~127~~95,~~422~~729) Proceeds from dispositions of property, plant and equipment~~...............~~ 5910,~~470~~866 ~~11,760~~184 Other (changes in accruals)~~...............................................~~ ~~723~~ (177,~~937~~682) 3,332 ----------~~-----~~ ----------~~-----~~ Net cash flows used in investing activities~~............................~~ (7631,~~464~~519) (~~133~~92,~~599~~213) ----------~~-----~~ ----------~~-----~~ FINANCING ACTIVITIES Borrowings under bank revolving credit agreement~~..........................~~ ~~185~~225,000 ~~200~~145,000 Repayment of borrowings under bank revolving credit agreement~~.............~~ (80329,000) (8613,000) ~~Borrowings under short-term financing agreement........................... -- 45,000 Repayment of borrowings under short-term financing agreement.............. -- (45,000)~~ Deliveries under the gas sales obligation~~.................................~~ (2012,~~299~~980) (1614,~~047~~084) Proceeds from hedge settlements 96 -- Purchase of treasury stock~~................................................~~ (2531) (~~3,723~~6) Purchase of lessor's equity interest in capital lease~~.....................~~ -- (54,416) ~~-- Minority interest third party............................................. -- 3,062~~ Payments of secured notes payable~~.........................................~~ (613,~~340~~579) -- Payments of capital lease obligations~~.....................................~~ -- (7,805) ~~(16,810)~~ ----------~~-----~~ ----------~~-----~~ Net cash flows (used in) provided by financing activities~~........................~~ 16(130,~~115~~494) 8055,~~482~~689 ----------~~-----~~ ----------~~-----~~ Cash Provided By Discontinued Operations 27,419 16,383 Net Decrease in Cash and Cash Equivalents~~...................................~~ (13119,~~826~~197) (717,~~942~~589) Cash and Cash Equivalents at Beginning of Period~~............................~~ 136,638 19,791 ~~15,053~~ ---------- ---------- Cash and Cash Equivalents at End of Period 17,441 2,202 Less: Cash and Cash Equivalents of Discontinued Operations -- 20 ---------- ---------- Cash and Cash Equivalents atfrom ~~End~~Continuing ofOperations ~~Period..................................~~ $ 517,~~965~~441 $ 72,~~111~~182 ==========~~=====~~ ==========~~===== Non-Cash Items: Conversion of forward purchase facilities to treasury stock............... $ -- $ 5,000~~

See accompanying notes. 4 EEX CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 1. The accompanying unaudited consolidated financial statements present the financial position, results of operations and cash flows of EEX Corporation and its subsidiaries ("EEX" or the "Company"). These consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission governing interim financial disclosures. These consolidated financial statements reflect all adjustments (consisting of only normal recurring adjustments) that, in the opinion of management, are necessary to fairly present the Company's financial position as of June 30, 2002 and December 31, 2001, and the results of operations and cash flows for the six months ended June 30, 2002 and 2001. Operating results for the six months ended June 30, 2002 are not necessarily indicative of the results that may be expected for the year ending December 31, 2002. Up to the end of 2001, EEX reported its business operations in four segments: Onshore, Deepwater Operations, Deepwater FPS and Pipelines and International. See Note 23 to the Consolidated Financial Statements in Item 8 of EEX's Annual Report on Form 10-K and Note 9, below. In the fourth quarter of 2001, the Company began marketing all of its Indonesian assets. As a result, the results of operations of the Indonesian subsidiaries (International segment) are presented as a discontinued operation in accordance with Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"). The historical financial statements have been restated to give effect to this treatment. During the second quarter of 2002, the Company closed the sale of all of the shares of a subsidiary that owns a 25% interest in the Tuban Concession to PT Medco Energi Internasional. The sale of the other Indonesian subsidiary has not closed. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and accompanying notes included in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. 2. The Company's consolidated financial statements have been presented on the basis that it is a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. The Company has incurred recurring net losses and there are uncertainties relating to the Company's ability to meet future expenditures and cash flow requirements. These conditions raise substantial doubt about the Company's ability to continue as a going concern. The financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of these uncertainties. 3. On May 28, 2002, EEX Operating, L.P. ("EEX Operating") and EEX entered into a new revolving credit facility with a group of banks. The maximum credit amount under the new credit agreement is $240 million, with a $10 million sublimit for letters of credit, and an additional $10 million available only for letters of credit to support surety bond obligations of EEX. As of June 30, 2002, the outstanding balance is $221 million and is classified as a current liability on the balance sheet. The new credit agreement matures March 31, 2003, unless earlier terminated upon the occurrence of certain specified events. The interest rate for (i) base rate loans is the higher of the federal funds rate plus 1/2 of 1% or the Administrative Agent's prime rate plus 2.75% and (ii) Eurodollar loans, is LIBOR plus 4.0%. The interest rates increase 0.5% per quarter beginning June 30, 2002. Loans are guaranteed by all of EEX's domestic subsidiaries other than EEX Reserves Funding LLC and its subsidiaries and secured by security interests in the equity and ownership interests of EEX's domestic subsidiaries (other than the subsidiaries of EEX Reserves Funding LLC); other material tangible and intangible assets of EEX Operating, EEX and its subsidiaries; and mortgages on substantially all of the oil and gas properties of EEX Operating and EEX. Covenants of the new credit agreement limit additional borrowings, repayment of existing debt, capital expenditures, dividends, distributions and redemptions, investments, loans and advances, liens, gas imbalances, take-or-pay obligations, mergers, property transfers and the sale of oil and gas properties; restrict the restructuring of the gas sales obligation and hedging agreements; and include other customary negative covenants. EEX may not use borrowed funds to pay the scheduled principal and interest payment due January 2, 2003 on the secured notes. The new credit agreement requires, on a quarterly basis, that: (i) EEX's ratio of total debt (as defined) to EBITDAX (as defined) for the four most recent quarters may not be greater than 4.0 to 1.0; (ii) commencing April 1, 2002, EEX's ratio of EBITDAX to fixed charges (as defined) may not be less than 1.0 to 1.0; and (iii) EEX's proved oil and natural gas reserves must be at least 375 billion cubic feet equivalent, and the present value, using the lenders' price deck and discount rate (currently 9%), of EEX's proved developed producing reserves must be at least 70% of the present value of EEX's total proved reserves. 5 EEX CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 4. On January 1, 2002, the Company adopted SFAS No. 144. Consequently, the Indonesian operations are held for sale and presented as discontinued operations. The assets and liabilities specifically related to this segment are classified as held for sale in the accompanying consolidated balance sheets, which include working capital and fixed assets. These assets have been recorded at their estimated fair market values and the effect of any adjustments have been reflected in the net income from discontinued operations. In the fourth quarter of 2001, the Company began marketing all of its Indonesian assets. In March 2002, the Company negotiated and signed two stock purchase agreements subject to certain conditions to closing. On April 26, 2002, the Company closed the sale of all of the shares of a subsidiary that owns a 25% interest in the Tuban Concession, onshore Java, to PT Medco Energi Internasional and received approximately $26 million. The sale of this subsidiary was recorded during the second quarter 2002. The sale of the other Indonesian subsidiary that owns a 15% interest in the Asahan Concession, offshore Sumatra, has not closed. An impairment of approximately $0.5 million was recorded in the second quarter of 2002 to reflect the impact of a disputed drilling cost overrun. Refer to Note 9 - Segment Information - International segment for results of operations for the quarter ended and the six months ended June 30, 2002 compared to June 30, 2001. 5. The preferred stock has a stated value of $100 and a current dividend rate of 8% per year, payable quarterly. The 8% dividend rate will be adjusted to a market rate, not to exceed 18%, in January 2006 or upon the earlier occurrence of certain events, including a change of control. Prior to any such adjustment of the dividend rate, EEX may, at its option, accrue dividends or pay them in cash, shares of preferred stock or shares of common stock. After any adjustment of the dividend rate, dividends must be paid in cash. The following table shows the dividends in-kind paid on, and the liquidation preference of, the preferred stock as of the dates shown:

~~Three~~Amount ~~Months~~of ~~Ended~~Dividends ~~Nine~~Number ~~Months~~of ~~Ended~~Preferred ~~September~~Liquidation 30Preference ~~September~~Date ~~30 -------------------------------- -------------------------------- 2001 2000 2001 2000 -------------- -------------- -------------- --------------~~ (In ~~thousands, except per share amounts~~millions) ~~Net~~Shares ~~income~~Issued (~~loss)~~In ~~from continuing operations............... $ 16,326 $(1,702~~millions) ~~$ 7,370 $(16,902) Effect of dilutive securities: Preferred stock dividends................................ 3,652~~ -- -- -- ~~Stock options............................................ 44~~ -- -- -- ---~~----------~~ -------------- -----~~---------~~ -------------- Net income (loss) from continuing operations applicable to common shareholders for diluted earnings per share.... $ 20,022 $(1,702) $ 7,370 $(16,902) ============= ============== ============== ============== Basic weighted average shares outstanding.................. 41,723 41,929 41,695 42,110 Effect of dilutive securities: Preferred stock.......................................... 27,907 -- -- -- ~~Stock options............................................ 233~~ -- ~~103~~ -- ------------- -----~~---------~~ ~~--------------~~June ~~-------------- Diluted weighted average shares outstanding................ 69~~30,~~863~~ ~~41,929~~2002 ~~41,798 42,110 ============= ============== ============== ============== Net income (loss) per share available to common shareholders: Basic....................................................~~ $ 03.399 $38,749 ~~(0.04)~~ $ 0197.186 $March ~~(0.40)~~31, ~~==============~~2002 ~~============== ============== ============== Diluted..................................................~~ $ 03.298 $37,990 ~~(0.04)~~ $ 0193.~~18 $ (0.40) ============== ============== ============== ==============~~7

6. Payments under the gas sales obligation are amortized using the interest method through final pay out using an interest rate of 9.5%. Payments related to this obligation made during the second quarter of 2002 were $6 million, and during the first quarter of 2002, $7 million. 7. The Statement of Cash Flows for the six months ended June 30, 2002 reflects $3 million related to the early settlement of several hedges as a non-cash transaction. This amount was reclassified from other comprehensive income and recognized as revenues to match the underlying sales transaction being hedged. In addition, the Statement of Cash Flows also reflects the net change in the fair value of derivative financial instruments which results in a non-cash decrease of $34 million to shareholders' equity. 8. EEX is involved in a number of legal and administrative proceedings incident to the ordinary course of its business. In the opinion of management, based on the advice of counsel and current assessment, any liability to EEX relative to these ordinary course proceedings will not have a material adverse effect on EEX's operations or financial condition. The operations and financial position of EEX continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and gas production, imports and exports, natural gas regulation, tax increases, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on EEX vary greatly and are not predictable. EEX has taken and will continue to take into account uncertainties and potential exposures in legal and administrative proceedings in periodically establishing accounting reserves. 6 EEX CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 9. Segment information has been prepared in accordance with Statement of Financial Accounting Standards No. 131, Disclosures About Segments of an Enterprise and Related Information. EEX has determined that its reportable segments are those that are based on the Company's method of internal reporting. EEX has four reportable segments, which are primarily in the business of natural gas and crude oil exploration and production: Onshore, Deepwater Operations, Deepwater FPS/Pipelines, and International. The accounting policies of the segments are the same as those described in the summary of significant accounting policies (See Note 3 to the Consolidated Financial Statements in Item 8 of EEX's 2001 Annual Report on Form 10-K). EEX's reportable segments are managed separately because of their geographic locations. In the fourth quarter of 2001, the Company began marketing all of its Indonesian assets. In accordance with SFAS No. 144, the results of operations of the Indonesian subsidiaries (International segment) are presented as a discontinued operation. Historical segment information has been restated to give effect to this treatment. During the second quarter 2002, the Company closed and recorded the sale of all of the shares of the subsidiary that owns a 25% interest in the Tuban Concession. The sale of the other Indonesian subsidiary has not closed. Financial information by operating segment is presented below (in thousands):

Deepwater Continuing Discontinued ------------------------------ Operations ~~FPS/Pipelines~~Operations - Onshore~~/Shelf~~ ~~International~~Operations FPS/Pipelines Other(a) Total International ---------- ------------- -------------- ---------- --- ---------- ------------- Three months ended ~~September~~June 30, ~~2001~~2002: ~~-------------------------------------~~ Total ~~Revenues.............................~~revenues $ --36,184 $ -- $ ~~32,015~~-- $ 112,~~643~~458 $ 438,~~832~~642 $ ~~48,490~~-- Production and operating costs~~.............~~ ~~-- 306~~ 4,~~980~~934 ~~3,261~~400 394 -- 85,~~547~~728 -- Exploration costs~~..........................~~ ~~940~~2,947 5,993 -- ~~7,236 486~~ -- 8,~~662~~940 -- Depletion, depreciation and amortization~~...~~ 10,522 -- 21,~~271~~059 ~~10,473~~375 411,~~424~~956 ~~465~~-- ~~17,633~~Impairment ~~Other~~of ~~costs................................~~oil and gas properties as required per SFAS 144 -- -- 2-- -- -- 451 Other costs 3,~~297~~552 (b) -- ~~(25~~-- 6,~~225)~~028 ~~(22~~9,~~928~~580 (245) ---------- -------~~------~~ ---------~~----~~ --------~~-----~~ --------- -------- Operating Income (Loss)~~....................~~ 14,229 (~~940~~6,393) (21,~~577~~453) ~~7,029~~ (3,~~472~~945) 292,~~592~~438 ~~36,576~~(206) Interest Income ~~and other..................~~ -- -- -- 403 403 -- ~~202 202~~ Interest and other financing costs~~.........~~ -- (~~2,628) (~~1,~~662~~115) -- (35,~~229~~534) (76,~~519~~649) -- -------- -------~~------~~ ---------~~----~~ --------~~-----~~ --------- -------- Income (Loss) before income taxes~~..........~~ $ 13,114 $(~~940~~6,393) $ (51,~~205~~453) $ 5(9,~~367~~076) $ (3,~~472~~808) $ ~~26,565~~(206) ~~$ 29,259~~ ========== =======~~======~~ =========~~====~~ ========~~=====~~ ========= ======== Long-Lived Assets~~..........................~~ $ 69377,~~341~~554 $ ~~154~~77,~~802~~581 $ ~~431~~68,~~080~~093 $ 272,~~948~~217 $ 3525,~~515~~445 $~~686,686~~ -- ========== =======~~======~~ =========~~====~~ ========~~=====~~ ========= ======== Additions to Long-Lived Assets~~.............~~ $ (19,~~615)~~429 $ ~~(18)~~7,610 $ ~~36,174~~96 $ ~~1,248~~8 $ 8817,143 $ ~~35,877~~193 ========== =======~~======~~ =========~~====~~ ========~~=====~~ ========= ======== Three months ended ~~September~~June 30, ~~2000~~2001: ~~-------------------------------------~~ Total ~~Revenues.............................~~revenues $ --38,399 $ -- $ ~~57,150~~-- $ ~~14,019~~(351) $ (538,~~186)~~048 $ 6514,~~983~~110 Production and operating costs~~.............~~ 5,289 -- ~~364~~155 61 5,~~502~~445 3,~~210~~467 ~~-- 10,076~~ Exploration costs~~..........................~~ 25,~~354~~761 ~~-- 4~~1,~~892~~921 ~~634~~ -- 7378 8,~~880~~060 199 Depletion, depreciation and amortization~~...~~ 9,769 -- 1,~~232~~314 ~~14,178~~465 811,~~771~~548 ~~427 24~~4,~~608~~620 Other costs~~................................~~ ~~-- -- 3~~4,~~423~~104 (b) -- 7-- 4,~~421~~830 108,~~844~~934 -- -------- -------~~------~~ ---------~~----~~ --------~~-----~~ --------- -------- Operating Income (Loss)~~....................~~ (213,~~354)~~476 (1,~~596~~921) ~~28,155~~ (1,~~404~~469) (136,~~034~~025) 124,~~575~~061 5,824 Interest Income ~~and other..................~~ -- -- -- --254 ~~431~~254 ~~431~~9 Interest and other financing costs~~.........~~ (1,820) -- (3,~~543~~401) (2,~~309~~544) -- (37,~~009~~765) ~~(8,861)~~ -- -------- -------~~------~~ ---------~~----~~ --------~~-----~~ --------- -------- Income (Loss) before income taxes~~..........~~ $ (211,~~354)~~656 $ (51,~~139~~921) $ 25(4,~~846~~870) $ 1(8,~~404~~315) $ (153,~~612~~450) $ 45,~~145~~833 ========== =======~~======~~ =========~~====~~ ========~~=====~~ ========= ======== Long-Lived Assets~~..........................~~ $ 75415,~~645~~233 $ ~~147~~95,~~584~~196 $ ~~437~~157,~~187~~091 $ 394,~~573~~090 $ 4671,~~847~~610 $~~704~~ 30,~~836~~932 ========== =======~~======~~ =========~~====~~ ========~~=====~~ ========= ======== Additions to Long-Lived Assets~~.............~~ $ 1141,~~999~~733 $ ~~(497)~~2,411 $ 2613,~~213~~517 $ ~~6,747~~342 $ ~~222~~58,003 $ 442,~~684~~411 ========== =======~~======~~ =========~~====~~ ========~~=====~~ ========= ========

7 EEX CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Deepwater Continuing Discontinued ------------------------------ Operations ~~FPS/Pipelines~~Operations - Onshore~~/Shelf~~ ~~International~~Operations FPS/Pipelines Other(a) Total ~~----------~~International ------------- ------------- -------------- -------- ----- ~~Nine months ended September 30, 2001:~~ ------------- -------------~~----------~~ Six months ended June 30, 2002: Total ~~Revenues.............................~~revenues $ --64,178 $ -- $ ~~121,937~~-- $ 3914,~~415~~975 $ (179,~~443)~~153 $ ~~159~~10,~~909~~408 Production and operating costs~~.............~~ ~~-- 610 15,062~~ 10,~~286~~523 753 690 -- 2511,~~958~~966 3,734 Exploration costs~~..........................~~ 185,~~131~~825 8,839 -- ~~17,321 1,616~~ -- 3714,~~068~~664 380 Depletion, depreciation and amortization~~...~~ 21,102 -- 42,~~899~~118 ~~29,916~~866 1424,~~030~~086 ~~1,382~~-- ~~50,227~~Impairment ~~Other~~of ~~costs................................~~oil --and 3gas ~~12,063~~properties ~~(b)~~as --required ~~(15,024)~~per ~~(2,958)~~SFAS 144 -- -- -- -- -- 4,051 Other costs 5,450 (b) -- -- 11,154 16,604 (245) --------- -------- ----- ---- --------- --------- -------- Operating Income (Loss)~~....................~~ 21,278 (189,~~131~~592) (52,~~512~~808) 472,~~575~~955 1311,~~483~~833 122,~~199~~488 ~~49,614~~ Interest Income ~~and other..................~~ -- -- -- --960 ~~874~~960 ~~874~~7 Interest and other financing costs~~.........~~ -- (92,~~427~~479) -- (51,~~474~~926) -- (8,~~195~~406) (2312,~~096~~811) -- -------- --------~~-----~~ ---------~~----~~ -------~~------~~ --------- -------- Income (Loss) before income taxes~~..........~~ $ (18,~~131)~~799 $ (149,~~939~~592) $ 42(4,~~101~~734) $ 13(4,~~483~~491) $ ~~4,878~~(18) $ 272,~~392~~495 ========== ========~~=====~~ =========~~====~~ ========~~=====~~ ========= ========= Long-Lived Assets~~..........................~~ $ 69377,~~341~~554 $ ~~154~~77,~~802~~581 $ ~~431~~68,~~080~~093 $ 272,~~948~~217 $ 3525,~~515~~445 $ ~~686,686~~-- ========== ========~~=====~~ =========~~====~~ ========~~=====~~ ========= ========= Additions to Long-Lived Assets~~.............~~ $ 420,~~529~~305 $ 1314,~~499~~134 $ ~~111,877~~211 $ ~~6,287~~53 $ ~~465~~34,703 $ ~~136~~2,~~657~~028 ========== ========~~=====~~ =========~~====~~ ========~~=====~~ ========= ========= ~~Nine~~Six months ended ~~September~~June 30, ~~2000~~2001: ~~------------------------------------~~ Total ~~Revenues.............................~~revenues $ --89,922 $ -- $ ~~150,837~~-- $ 41(6,~~178~~274) $ (283,~~885)~~648 $ ~~189~~27,~~130~~772 Production and operating costs~~.............~~ 10,082 -- ~~613~~304 ~~17,708~~1 1110,~~081~~387 ~~-- 29~~7,~~402~~025 Exploration costs~~..........................~~ 610,~~520~~085 ~~-- 13~~17,~~761~~191 ~~1,853~~ -- 22495 27,~~134~~771 635 Depletion, depreciation and amortization~~...~~ ~~-- 3,278 46,325~~ 19,~~971~~443 ~~1,283 70,857 Impairment of producing oil and gas properties...............................~~ -- --2,628 ~~200~~917 1222,~~000~~988 ~~-- 12~~9,~~200~~606 Other costs~~................................~~ ~~-- -- 7~~9,~~997~~766 (b) -- 233 10,~~431~~200 3119,~~428~~969 -- -------- --------~~-----~~ ---------~~----~~ -------~~------~~ --------- -------- Operating Income (Loss)~~....................~~ (640,~~520)~~546 (317,~~891~~191) ~~64,846~~ (32,~~727~~935) (2717,~~599~~887) 232,~~109~~533 10,506 Interest Income ~~and other..................~~ -- -- -- --652 ~~893~~652 ~~893~~20 Interest and other financing costs~~.........~~ -- (103,~~571~~812) ~~(7,553)~~ -- (6,~~695~~799) (244,~~819~~966) (15,577) -- -------- --------~~-----~~ ---------~~----~~ -------~~------~~ --------- -------- Income (Loss) before income taxes~~..........~~ $ (636,~~520)~~734 $ (1417,~~462~~191) $ 57(9,~~293~~734) $ (322,~~727~~201) $ (3312,~~401~~392) $ ~~(817)~~10,526 ========== ========~~=====~~ =========~~====~~ ========~~=====~~ ========= ========= Long-Lived Assets~~..........................~~ $ 75415,~~645~~233 $ ~~147~~95,~~584~~196 $ ~~437~~157,~~187~~091 $ 394,~~573~~090 $ 4671,~~847~~610 $ ~~704~~30,~~836~~932 ========== ========~~=====~~ =========~~====~~ ========~~=====~~ ========= ========= Additions to Long-Lived Assets~~.............~~ $ 2675,~~531~~703 $ 6,~~711~~144 $ 7513,~~821~~517 $ ~~10,981~~365 $ 195,~~027~~729 $ ~~121~~5,~~071~~051 ========== ========~~=====~~ =========~~====~~ ========~~=====~~ ========= =========

(a) Includes primarily cogeneration plant operations, general and administrative, gains/loss on hedging and sale of assets. (b) Includes taxes other than income. 10. The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. The Company enters into swaps, options, collars and other derivative contracts to hedge the price risks associated with a portion of anticipated future oil and gas production. While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. The Company enters into the majority of its hedging transactions with one counterparty and a netting agreement is in place with that counterparty. The Company does not obtain collateral to support the agreements but monitors the financial viability of counter-parties and believes its credit risk is minimal on these transactions. In the event of nonperformance, the Company would be exposed to price risk. The Company has some risk of accounting loss since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. The net gain related to financial hedging activities that was reclassified to revenues to match the underlying sales transaction being hedged was approximately $1 million for the quarter ended June 30, 2002, compared to a loss of $2 million for the same period of 2001. 8 EEX CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued) At June 30, 2002, EEX had outstanding natural gas swaps that were entered into as hedges extending through December 31, 2003, to exchange payments on 29,290 billion British Thermal Units of natural gas. At June 30, 2002, the weighted average strike price and market price per million British Thermal Units ("MMBtu") of natural gas were $3.47 and $3.73, respectively. At June 30, 2002, the Company estimated, using a NYMEX price strip as of that date, that the fair market value represented a net current liability of approximately $2.8 million, a net noncurrent liability of $3.7 million and accumulated other comprehensive loss of approximately $6.5 million. The Company realized no hedge ineffectiveness in the second quarter of 2002. At June 30, 2002, EEX had outstanding natural gas collars that were entered into as hedges extending through October 2002 to exchange payments on approximately 1 Bcf of natural gas. At June 30, 2002, the weighted average floor and ceiling strike prices and the market price per MMBtu of natural gas were $2.40, $2.73 and $3.30, respectively. At June 30, 2002, the Company estimated, using a NYMEX price strip as of that date, that the fair market value represented a net current liability of approximately $0.4 million and accumulated other comprehensive loss of approximately $0.4 million. The Company recognized no hedge ineffectiveness in the second quarter of 2002. The Company may from time to time settle early derivative transactions. Gains or losses are included in accumulated other comprehensive income until they are recognized in revenues to match the underlying sales transaction being hedged. The Company also terminated several financial hedges with Enron North America Corp. in December 2001 due to Enron's bankruptcy filing. During the second quarter of 2002, the Company reclassified approximately $1.3 million from accumulated other comprehensive income to revenues related to these transactions. As of June 30, 2002, approximately $2.5 million remains to be reclassified from other comprehensive income to revenues in 2002 and approximately $3.2 million remains to be reclassified from other comprehensive income to revenues in 2003. 9 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Management's Discussion and Analysis of Financial Condition and Results of Operations and all accompanying information should be read in conjunction with the consolidated financial statements, accompanying notes and other financial information included in this Quarterly Report on Form 10-Q and in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2001. Certain statements in this report, including statements of EEX and management's expectations, intentions, plans and beliefs, are "forward-looking statements," within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and are subject to certain events, risks and uncertainties that may be outside EEX's control. Actual results and developments could differ materially from those expressed in or implied by such statements due to a number of factors, including, without limitation, those described in the context of such forward-looking statements, the risks, uncertainties and critical accounting policies and estimates described in the Company's Annual Report on Form 10-K for the year ended December 31, 2001, and described from time to time in EEX's other documents and reports filed with the Securities and Exchange Commission. The following discussion should be read in conjunction with Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations--Risks, Uncertainties and Critical Accounting Policies and Estimates," in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. Newfield Merger On May 29, 2002, EEX entered into a definitive merger agreement with Newfield Exploration Company ("Newfield"). In the aggregate, the outstanding shares of EEX common stock would be converted into approximately 2.4 million shares of Newfield common stock, or 0.05703 shares of Newfield common stock per share of EEX common stock. EEX's common shareholders will also have the option to elect to receive units in a new trust in lieu of Newfield stock. Approximately 42.5 million trust units will be available. For each unit that an EEX shareholder elects to receive, the number of shares of Newfield common stock that the shareholder would otherwise receive will be reduced by 0.00054 of one share. The trust will own overriding royalty interests in future production from defined intervals generally below 20,000 feet from Gulf of Mexico lease blocks in which EEX owns or may acquire an interest. Those leases are the subject of the Asset Purchase, Farmout and Joint Exploration Agreement effective as of March 1, 2002, with BP Exploration & Production Inc. ("BP") described below. The holders of EEX's preferred stock, each of whom has signed a voting agreement to vote its shares in favor of the merger, will receive a total of 4.7 million shares of Newfield common stock in the merger. The merger is subject to the approval of EEX's shareholders, certain regulatory approvals and other conditions. Gulf of Mexico Deep Shelf In May 2002, EEX entered into an Asset Purchase, Farmout and Joint Exploration Agreement effective as of March 1, 2002, with BP. BP acquired 75% of EEX's current interest in 22 outer continental shelf ("OCS") leases. As part of this agreement, BP will conduct further leasing and geophysical activities with a minimum cost of $4.7 million in an area encompassing 140 OCS blocks. At the end of the initial evaluation period, BP may, at its option, commit to the drilling of up to three wells. The first election must be made on or before June 1, 2003, and the well must be commenced not later than December 31, 2003. BP may elect to drill a second well within 180 days of the completion of the first well and a third well within 120 days of the completion of the second well. EEX will be carried for its 25% interest of the costs of the initial evaluation period and the drilling of the first three exploration wells. There is no production currently associated with the interests that are the subject of the agreement. In addition to the acquired blocks, EEX and BP were successful bidders on six federal offshore blocks at OCS Lease Sale No. 182 held March 20, 2002, that are included in the agreement. All the blocks have been awarded by the Minerals Management Service. 10 Other Gulf of Mexico Activities The Devil's Island well completed operations on June 12, 2002. The original well bore encountered approximately 100 feet of pay and the updip sidetrack, the second of two sidetracks, encountered approximately 30 feet of pay in a zone separate from that encountered in the original well bore. EEX has a 20% working interest in the Devil's Island project. The Glomar Arctic I rig was demobilized from the Devil's Island well location to a stack location effective June 14, 2002. The rig contract expired on July 3, 2002 and the rig was released. The Devil's Island operator plans further study to determine future operations. EEX is preparing possible development options for consideration by the operator that would combine the Devil's Island discovery and EEX's Jason discovery. EEX continued its marketing efforts for the Floating Production System ("FPS") and the Pipelines during the second quarter. EEX owns 60% of the FPS and Pipelines; a subsidiary of Exxon Mobil Corp. owns 40%. EEX has received market inquiries for use of the FPS as a drilling rig. EEX is continuing to market the asset for use as a floating production system which use management believes is higher valued than use as a drilling rig. No assurance can be given that EEX will be successful in selling this asset at the higher valued use or that any sale will recover the carrying value of the asset. The value of the Pipelines depends on their use to transport production from the greater Llano area or other areas in proximity to the Pipelines. EEX is now developing a proposal for the Pipelines to transport production from the Jason and Devil's Island discoveries. While EEX currently holds controlling interest in the Jason discovery, the Devil's Island development plan will be decided by the operator. EEX is also awaiting notification from the Llano operator to determine the utility of the Pipelines for Llano field production. There can be no assurance that these efforts will be successful or that the value received from transportation of production from such discoveries would recover the carrying value of the asset. If the Llano owners decide to use other pipelines for the Llano field's development, the potential markets for use of the Pipelines will be narrower. When the proposed merger with Newfield is completed, new management may employ a different strategy to realize value from these assets, which may impact their value. RESULTS OF OPERATIONS EEX Corporation reported a second quarter 2002 net loss of $8 million, or ($0.19) per share, compared to a net loss of $1 million, or ($0.03) per share for the second quarter of 2001. The Indonesian subsidiaries (the International segment) are reported as a discontinued operation under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," ("SFAS No. 144"). The financial statements have been restated in accordance with SFAS No. 144 to eliminate the impact of the discontinued Indonesian operations from continuing operations. During the second quarter, the Company closed and recorded the sale of all of the shares of the subsidiary that owns a 25% interest in the Tuban Concession. The sale of the other Indonesian subsidiary that owns a 15% interest in the Asahan Concession has not closed. A discussion of results of continuing operations for the three and six months ended June 30, 2002, compared to the same period of 2001 follows. RESULTS OF CONTINUING OPERATIONS Quarters Ended June 30, 2002 and 2001 For the second quarter of 2002, EEX reported a loss from continuing operations of $8 million ($0.18 per share), versus a net loss of $7 million ($0.17 per share) for the same period in 2001. For the second quarter of 2002, total revenues were $39 million, 2% higher than the first quarter of 2001. Natural gas revenues for the second quarter of 2002 were 6% higher than the same quarter of 2001. This increase was due to a 2% increase in the average natural gas sales price and a 4% increase in production. Natural gas production for the second quarter of 2002 was 11 billion cubic feet ("Bcf"), slightly higher than the same period of 2001. The average natural gas sales price per thousand cubic feet ("Mcf") was $3.18 in the second quarter of 2002, compared with $3.13 in the same period of 2001. The average natural gas sales price for the second quarter 2002 includes hedging gains of $1 million and 2,645 billion British thermal units ("BBtu") delivered under the gas sales obligation at an average price of $2.36 per million British thermal units ("MMBtu"). The average natural gas sales price of $3.13 per Mcf for the second quarter 2001 includes hedging losses of approximately $2 million and 5,730 BBtu delivered under fixed-price delivery contracts and the gas sales obligation at an average price of $2.54 per MMBtu. Oil revenues for the second quarter of 2002 decreased 17% from the same quarter of 2001. This decrease was primarily due to a 5% decrease in the average oil sales price and a 13% decrease in production. The average oil price per barrel during the second quarter of 2002 was $24.65 compared to $25.85 for the same period of 2001. 11 Costs and expenses for the second quarter of 2002 were $36 million, compared with $34 million in the same period of 2001. Operating expenses (production and operating, general, administrative and other, and taxes other than income) were $14 million in the current quarter, 13% higher than the second quarter of 2001. This increase was primarily due to increased general, administrative and other primarily due to approximately $1 million of fees incurred in the second quarter of 2002 related to the Company's planned merger and exploration of strategic alternatives. Exploration expenses for the second quarter of 2002 were $9 million, compared to $8 million for the same period of 2001. The second quarter of 2002 includes approximately $3 million in costs associated with stacking of the Arctic I rig compared to $0.6 million for the same period of 2001. "Stacking" means maintaining the rig inactive, in this case, at an offshore location. Depletion, depreciation and amortization for the second quarter of 2002 was $12 million, unchanged from the same period of 2001. Total interest and other financing costs for the second quarter of 2002, including interest income, preferred stock dividends and other income, were $10 million, a $1 million decrease from the same period of 2001. This decrease is primarily due to lower interest expense related to the debt associated with the FPS and Pipelines and the gas sales obligation offset by higher interest expense associated with increased borrowings under the revolving credit agreement. Six Months Ended June 30, 2002 and 2001 For the six months ended June 30, 2002, total revenues were $79 million, 5% lower than total revenues for the six months ended June 30, 2001. Natural gas revenues for the first six months of 2002 were 2% lower than the first six months of 2001. This decrease was due to a 6% decrease in average natural gas sales prices offset by a 5% increase in production. The average natural gas sales price per Mcf was $3.30 for the first six months of 2002, compared with $3.50 in the same period of 2001. The average natural gas sales price of $3.30 per Mcf for the first six months of 2002 includes hedging gains of $12 million and 5,456 BBtu delivered under the gas sales obligation at an average price of $2.47 per MMBtu. The average natural gas sales price of $3.50 per Mcf for the first six months of 2001 includes hedging losses of approximately $10 million and 10,847 BBtu delivered under fixed-price delivery contracts and the gas sales obligation at an average price of $2.67 per MMBtu. Natural gas production for the first six months of 2002 was 22 Bcf, compared with 21 Bcf in the same period of 2001. Oil revenues decreased 27% primarily due to a 19% decline in average oil sales prices for the six months ended June 30, 2002. The average oil price during the first six months of 2002 decreased to $21.70 from $26.80, a decrease of 19%. Costs and expenses for the first six months of 2002 were $67 million, compared with $81 million for the same period of 2001. Operating expenses (production and operating, general and administrative and taxes other than income) remained flat from period to period. General, administrative and other costs and production and operating costs were higher, offset by lower taxes, other than income. General, administrative and other costs were higher primarily due to fees related to the Company's planned merger and exploration of strategic alternatives. Taxes, other than income were lower for the six months ended June 30, 2002 primarily due to lower average natural gas sales prices. Exploration expenses for the first six months of 2002 were $15 million, compared to $28 million for the same period of 2001. Exploration expense for the first six months of 2002 includes approximately $3 million in costs associated with the stacking of the Arctic I rig compared to $14 million in costs associated with the stacking of the Arctic I rig and recognition of the net cost associated with the assignment of the Arctic I contract through May 2001 included in the first six months of 2001. Depletion, depreciation and amortization for the first six months of 2002 was $24 million, $1 million higher than the same period of 2001. Total interest and other financing costs for the first six months of 2002, including interest income, preferred stock dividends and other income, were $20 million, a $3 million decrease from the same period of 2001. This decrease is primarily due to lower interest expense related to the debt associated with the FPS and Pipelines and the gas sales obligation offset by higher interest expense associated with increased borrowings under the revolving credit agreement. 12 EEX CORPORATION SUMMARY OF SELECTED OPERATING DATA FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Three Months Ended ~~Nine~~Six Months Ended ~~September~~June 30 ~~September~~June 30 ----------------------------~~---~~ ---------------------------~~----~~ 2002 2001 ~~2000~~2002 2001 ~~2000~~ -------------- -------------- -------------- -------------- Sales volume Natural gas (Bcf) (a)~~..................................~~ 11.31 1310.56 3221.07 4220.07 Oil, condensate and natural gas liquids (MMBbls) (d)~~...~~ 0.61 0.6 1.9 0.2 0.13 Total volumes (Bcfe) (a)~~.............................~~ 1411.97 1711.43 4323.50 5422.62 Average sales price (b) Natural gas (per Mcf) (c)~~..............................~~ $ 23.8918 $ 3.2513 $ 3.2830 $ 23.9150 Oil, condensate and natural gas liquids (per Bbl)~~......~~ 23.4293 3123.0183 2520.0461 2824.3578 Total (per Mcfe) (c)~~.................................~~ 3.1421 3.6818 3.5230 3.3354 Average costs and expenses (per Mcfe) (c) Production and operating (b)~~...........................~~ $ 0.5749 $ 0.5848 $ 0.6052 $ 0.5447 Exploration~~............................................~~ 0.5877 0.4571 0.8564 01.4125 Depletion, depreciation and amortization~~...............~~ 1.1803 1.4102 1.1505 1.3003 General, administrative and other~~......................~~ 0.2042 0.2728 0.2240 0.29 Taxes, other than income~~...............................~~ 0.1532 0.2036 0.2725 0.1444

------------------ (a) Billion cubic feet or billion cubic feet equivalent, as applicable. Ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids. (b) Before related production, severance and ad valorem taxes. (c) One thousand cubic feet or one thousand cubic feet equivalent, as applicable. Ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids. (d) One million barrels of crude oil or other liquid hydrocarbons. RESULTS OF DISCONTINUED OPERATIONS During the second quarter of 2002, EEX closed and recorded the sale of all of the shares of the subsidiary that owns a 25% interest in the Tuban Concession. The sale of the other Indonesian subsidiary that owns a 15% interest in the Asahan Concession has not closed. For the six months ended June 30, 2002, EEX reported net income from discontinued Indonesian operations (International segment), net of tax, of approximately $3 million, $0.06 per share, versus net income of approximately $11 million, $0.26 per share, for the same period of 2001. For the six months ended June 30, 2002, oil revenues were $10 million, 63% lower than oil revenues in the same period of 2001 primarily due to recording revenues for only the first quarter of 2002 due to the sale of the Mudi Field. The average oil price per barrel during the first six months of 2002 was $20.57 compared to $26.03 for the same period of 2001, a decrease of approximately 21%. Oil production for the first six months of 2002 decreased 53% compared to the same period in 2001. In accordance with SFAS No. 144, an impairment of approximately $4 million, net of tax, was recorded in the first quarter of 2002, which represented the Company's estimate at that time of the difference between the book value and the fair value of the assets held for sale. In accordance with SFAS No. 144, depletion was suspended in the first quarter of 2002. Depletion for the first six months of 2001 was approximately $10 million. Net cash flows provided by discontinued operations were $27 million for the six months ended June 30, 2002, compared to net cash flows provided by discontinued operations of $16 million for the same period 2001. The 2002 cash flow is primarily due to the proceeds received from the sale of all of the shares of the subsidiary that owns a 25% interest in the Tuban Concession during the second quarter of 2002. The 2001 cash flow is primarily attributable to operations. 13 LIQUIDITY AND CAPITAL RESOURCES Cash and Cash Equivalents and Cash Flows from Continuing Operations The following summary table reflects the Company's cash flows from continuing operations (in millions): Six Months Ended June 30 ------------------ 2002 2001 -------- --------- Net cash provided by operating activities $ 15 $ 3 Net cash (used in) investing activities (32) (92) Net cash (used in) provided by financing activities (130) 56 As of June 30, 2002, the cash and cash equivalents balance was approximately $17 million. Net cash flows provided by operating activities from continuing operations for the six months ended June 30, 2002 were approximately $15 million, an increase of approximately $13 million over the same period of 2001. This increase was primarily due to full utilization of the Arctic I rig through mid June 2002. Net cash flows used in investing activities for continuing operations for the six months ended June 30, 2002 were approximately $32 million, a $61 million decrease from cash flows used in investing activities for the same period of 2001. The decrease in investing activities is primarily due to lower capital expenditures and proceeds received from dispositions of property, plant and equipment in 2002. The Encogen obligation was completed in the first half of 2001 and onshore spending was reduced in 2002 due to capital constraints offset by capital spent on the Devil's Island well. In addition, the Company received $11 million from the sale of a part of the production payment associated with the Encogen obligation. Net cash flows used in financing activities for continuing operations for the six months ended June 30, 2002 were approximately $130 million, compared to net cash flows provided by financing activities of $56 million for the same period of 2001. During the second quarter of 2002, the Company entered into a new credit facility and paid down the old facility resulting in a net repayment of approximately $104 million. During the second quarter of 2001, the Company borrowed $132 million. Financing Activities Effective May 28, 2002, EEX Operating, L.P. ("EEX Operating"), as Borrower and an Obligor and EEX, as an additional Obligor, entered into a new revolving credit facility with a group of banks and JPMorgan Chase Bank, as Administrative Agent. A copy of the new credit agreement and related documents were filed as exhibits to EEX's Current Report on Form 8-K filed on June 6, 2002. Unless indicated otherwise, capitalized terms used in this section are defined in the new credit agreement. Maximum credit amount: $240 million, with a $10 million sublimit for letters of credit, and an additional $10 million available only for letters of credit to support surety bond obligations of EEX. Maturity: March 31, 2003, unless earlier terminated upon the occurrence of certain specified events. Interest rate: (i) For Base Rate Loans, the higher of Federal Funds Rate plus 1/2 of 1% or Administrative Agent's prime rate plus 2.75% and (ii) for Eurodollar Loans, the Eurodollar Rate plus 4.0%, each rate increasing 0.5% per quarter beginning June 30, 2002. Fees: A loan restructuring fee of $2,500,000 and an arrangement fee of $750,000 are payable by September 30, 2002; provided, that in the event that EEX has received all governmental approvals for its proposed merger and has distributed all proxy and related voting materials to its shareholders by such date, then payment of the fees shall be delayed until November 30, 2002; and provided further, that if the merger has been consummated by November 30, 2002, then EEX Operating shall have no obligation to pay the fees. Guaranties: Loans are guaranteed by all of EEX's domestic subsidiaries other than EEX Reserves Funding LLC and its subsidiaries. 14 Security: Security interests in the equity and ownership interests of EEX's domestic subsidiaries (other than the subsidiaries of EEX Reserves Funding LLC); other material tangible and intangible assets of EEX Operating, EEX and its subsidiaries; and mortgages on substantially all of the oil and gas properties of EEX Operating and EEX. EEX and EEX Operating are required to maintain liens on oil and gas properties of not less than 100% of the total value of their oil and gas properties and 100% of the proved and probable reserves (other than $500,000 of properties outside of Texas and Louisiana). Mandatory Prepayment: The proceeds from sales of assets and equity offerings must be used to prepay loans outstanding; mandatory prepayments reduce the maximum credit amount. Negative Covenants: Limits on additional borrowings, repayment of existing debt, capital expenditures, dividends, distributions and redemptions, investments, loans and advances, liens, gas imbalances, take-or-pay obligations, other prepayments, mergers, property transfers and the sale of oil and gas properties and hedging agreements; restrictions on the restructuring of the gas sales obligation with Bob West Treasure L.L.C., an Enron affiliate; and other customary negative covenants. EEX may not use borrowed funds to pay the scheduled principal and interest payment due January 2, 2003 on its Secured Notes. Financial Covenants: The ratio of Total Debt to EBITDAX for the four most recent quarters may not be greater than 4.0 to 1.0. Commencing April 1, 2002, the ratio of EBITDAX to Fixed Charges may not be less than 1.0 to 1.0. EEX is required to maintain at least 375 Bcfe of proved oil and natural gas reserves. The present value, using JPMorgan's price deck and discount rate (currently 9%), of EEX's proved developed producing reserves must be at least 70% of the present value of EEX's total proved reserves. Events of Default: Nonpayment of principal when due; nonpayment of interest, fees or other amounts after an agreed upon grace period; material inaccuracy of representations and warranties; violation of covenants; cross-default; bankruptcy events; material judgments; change in control; and other defaults customary for oil and gas industry borrowers. EEX Operating borrowed $225 million under the new credit agreement upon execution and advanced that amount to EEX, and EEX used that amount, together with $100 million in cash it had on hand, to repay and terminate its existing revolving credit agreement. On July 31, 2002, the outstanding amount under the new credit agreement was $223 million and the available credit was $17 million. As of June 30, 2002, EEX met the required financial covenant ratios of the Total Debt to EBITDAX and EBITDAX to Fixed Charges. Based upon preliminary information, EEX expects to meet the requirement to maintain at least 375 Bcfe of proved reserves with at least 70% of the present value attributed to proved developed producing. There can be no assurances that EEX will be able to meet the financial covenants of the new credit agreement as of the end of the third fiscal quarter, and, if it does not, it will be in default. There can be no assurances that EEX will be able to cure such default, or any other covenant default that may occur. Future Capital Requirements Capital expenditures from continuing operations for the six months ended June 30, 2002 were approximately $35 million, compared to approximately $96 million for the six months ended June 30, 2001. This decrease in capital spending during the first half of 2002 is primarily due to the completion of the Encogen obligation in the same period of 2001 and reduced onshore spending due to capital constraints offset by capital spent on the Devil's Island Well. Capital expenditures for the remainder of 2002 are expected to be approximately $20 million. Substantially all of these capital expenditures will be made on drilling development wells on the Onshore segement. Sources of Capital and Liquidity During April 2002, the Company received approximately $26 million from the sale of the shares of a subsidiary that owns a 25% interest in the Tuban Concession. During the remainder of the year, EEX's sources of liquidity will be operating cash flows from EEX Operating and borrowings under the new credit agreement. The operating cash flows from EEX E&P Company, L.P. will not be available to EEX because of restrictions in the agreement related to the gas sales obligation. EEX estimates, based upon its current budget forecast, that it will have drawn all of its available credit under the new credit agreement at or before December 31, 2002. EEX has no current source of funds to make the approximately $15 million payment on its Secured Notes due January 2, 2003. 15 EEX is not currently pursuing additional sources of financing because of the pending merger and merger agreement with Newfield. If the merger does not take place, there can be no assurances that EEX will be able to obtain additional financing before it uses all of its available credit under the new credit agreement. EEX will also require additional financing to make the January 2, 2003 payment on the Secured Notes if the merger does not take place. No assurances can be given that EEX will be successful in completing the merger with Newfield or an acceptable financing plan should the merger not occur. In the event of default under the new credit agreement, EEX's lenders may attempt to enforce their security interest in EEX's oil and gas properties and other assets. EEX may then have to seek protection from its creditors and reorganization under Federal bankruptcy laws. Item 3. Quantitative and Qualitative Disclosures About Market Risk Hedging activity for the six months ended June 30, 2002 resulted in a gain of approximately $12 million for natural gas. The table below provides information about EEX's hedging instruments as of June 30, 2002. The Notional Amount is equal to the volumetric hedge position of EEX during the periods. The fair values of the hedging instruments, which have been recorded in other comprehensive income, are based on the difference between the applicable strike price and the New York Mercantile Exchange future prices for the applicable trading months.

Notional Average Fair Value at Amount Strike Price ~~September~~June 30, ~~2001~~2002 (BBtu) (1) (Per MMBtu) (2) (In thousands) --------------- ---- ------------------ ------------------ Floor Ceiling --------- --------- Natural Gas Collars: July 2002 - September 2002 460 $2.40 $2.73 $ (263) October 2002 155 2.40 2.73 (89) ------ ~~Floor~~-------- ~~Ceiling~~Total 615 $ (352) ======= ======== Notional Average Fair Value at Amount Swap Price June 30, 2002 (BBtu) (1) (Per MMBtu) (2) (In thousands) ------------------- ------------------- ------------------ Natural Gas ~~Collars~~Swaps: ~~October~~July ~~2001~~2002 - ~~December~~September ~~2001........~~2002 25,~~760~~060 $3.~~242~~42 $~~4.962~~ ~~$2,783~~586 ~~January~~October 2002 - ~~March~~December 2002~~...........~~ 15,~~350~~060 3.~~854~~63 6198 January 2003 - March 2003 4,500 3.~~137~~55 (1,~~393~~612) April ~~2002~~2003 - June ~~2002~~2003 4,550 3.~~.............~~29 (1,~~365~~984) July 2003 - September 2003 5,060 3.~~374~~36 (1,724) October 2003 - December 2003 5,060 3.~~658~~55 ~~813~~(1,971) -------~~------------~~ --------~~---------------~~ Total~~............................~~ 529,~~475~~290 $4 (6,~~989~~507) =======~~============~~ ========~~===============~~

---------- (1) Billions of British Thermal Units. (2) Millions of British Thermal Units. 16 PART II. OTHER INFORMATION Item 1. Legal Proceedings EEX is involved in a number of legal and administrative proceedings incident to the ordinary course of its business. In the opinion of management, based on the advice of EEX's General Counsel, Richard L. Edmonson, individual litigation counsel, and current assessments, any liability to EEX relative to these ordinary course proceedings will not have a material adverse effect on EEX's operations or financial condition. The operations and financial position of EEX continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and gas production, imports and exports, natural gas regulation, tax increases, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on EEX vary greatly and are not predictable. EEX has taken and will continue to take into account uncertainties and potential exposures in legal and administrative proceedings in periodically establishing accounting reserves. Item 2. Changes in Securities and Use of Proceeds (a) On May 29, 2002, EEX amended it Rights Agreement by the Third Amendment to Rights Agreement. The amendment provides that the execution of the merger agreement with Newfield and of certain voting agreements entered into in connection with the merger agreement, the performance of the merger agreement and consummation of the transactions contemplated in the merger agreement and voting agreements (see Part I, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operation - Newfield Merger," above) will not be considered events that trigger the distribution of Rights under the Rights Agreement. A copy of the Third Amendment to Rights Agreement is an exhibit to EEX's Current Report on Form 8-K, filed June 6, 2002 with the Securities and Exchange Commission. Item 4. Submission of Matters to a Vote of Security Holders At the annual meeting of shareholders held on May 30, 2002, the shareholders elected two directors for terms expiring at the annual meeting in 2005, and ratified the appointment of Ernst & Young LLP as Independent Auditors for fiscal year 2002. In addition to the two directors elected at the meeting, Thomas M Hamilton, B. A. Bridgewater, Frederick M. Lowther, and M. P. Mallardi continued their respective terms of office after the meeting. Below is the result of the vote. Election of Directors: Abstentions and Broker Name Votes for Withheld Non-Votes ---- ---------- ----------------- --------- F. S. Addy 45,081,714 671,016 -- H. H. Newman 45,086,142 666,588 -- Appointment of Ernst & Young LLP as Independent Auditors: Abstentions and For Against Broker Non-Votes ----- ------- ---------------- 45,382,675 272,987 97,068 Item 6. Exhibits and Reports on Form 8-K (a) Exhibits 2.1* Amended and Restated Agreement and Plan of Merger dated as of May 29, 2002 by and among Newfield Exploration Company, Newfield Operating Company and EEX Corporation, incorporated by reference to Annex A to the proxy statement/prospectus in Amendment No. 1 to the Registration Statement on Form S-4, No. 333-91014, of Newfield Exploration Company and Treasure Island Royalty Trust, filed under CIK 0000912750 on July 3, 2002. 4.1* Second Amendment to Rights Agreement, dated May 13, 2002, among EEX Corporation, Harris Trust Company of New York and Computershare Investor Services, LLC, incorporated by reference to Exhibit 4.1 to Registrant's Current Report on Form 8-K with report date of May 29, 2002, filed on June 6, 2002. 4.2* Third Amendment to Rights Agreement, dated May 29, 2002 by and between EEX Corporation and Computershare Investor Services, LLC, incorporated by reference to Exhibit 4.2 to Registrant's Current Report on Form 8-K with report date of May 29, 2002, filed on June 6, 2002. 10.1 Asset Purchase, Farmout and Joint Exploration Agreement dated as of March 1, 2002, between BP Exploration & Production Inc. and EEX 10.2 Offshore Operating Agreement effective March 1, 2002, between BP Exploration & Production Inc. and EEX (Exhibit D to the Asset Purchase, Farmout and Joint Exploration Agreement) 10.3 Letter Agreement dated May 8, 2002, between BP Exploration & Production Inc. and EEX 10.4 Amendatory Letter dated July 17, 2002, between BP Exploration & Production Inc. and EEX 10.5* Credit Agreement, dated as of May 28, 2002 among EEX Operating L.P., as Borrower and an Obligor, EEX Corporation, as an additional Obligor, JPMorgan Chase Bank, as Administrative Agent, Canadian Imperial Bank of Commerce, as Syndication Agent, J.P. Morgan Securities Inc., as Lead Arranger and Sole Bookrunner, CIBC World Markets Corp., as Co-Arranger, and the Lenders signatory thereto, incorporated by reference to Exhibit 10.2 to Registrant's Current Report on Form 8-K with report date of May 29, 2002, filed on June 6, 2002. 10.6* Guarantee and Collateral Agreement, dated as of May 28, 2002 made by each of the Grantors defined therein in favor of JPMorgan Chase Bank, as Administrative Agent, incorporated by reference to Exhibit 10.3 to Registrant's Current Report on Form 8-K with report date of May 29, 2002, filed on June 6, 2002. 10.7* Form of Mortgage, Assignment of Production, Security Agreement and Financing Statement executed by EEX Operating L.P. and EEX Corporation to JPMorgan Chase Bank, as Administrative Agent, incorporated by reference to Exhibit 10.4 to Registrant's Current Report on Form 8-K with report date of May 29, 2002, filed on June 6, 2002. 10.8* Form of Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement executed by EEX Operating L.P. and EEX Corporation to Robert C. Mertensotto, as Trustee for the benefit of JPMorgan Chase Bank, as Administrative Agent, incorporated by reference to Exhibit 10.5 to Registrant's Current Report on Form 8-K with report date of May 29, 2002, filed on June 6, 2002. 23.1 Consent of Richard L. Edmonson 99.1 Certifications of Registrant's Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ------------- * incorporated by reference (b) Reports on Form 8-K Current Report on Form 8-K filed June 6, 2002 and dated May 29, 2002 (news release -- merger with Newfield Exploration Company) Current Report on Form 8-K filed June 17, 2002 and dated May 28, 2002 (new credit agreement, liquidity and capital resources and Devil's Island well results) 17 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. EEX CORPORATION (Registrant) Dated: August 13, 2002 By: /s/ R. S. Langdon ------------------------------ R. S. Langdon Executive Vice President, Finance and Administration, and Chief Financial Officer 18

Notional Average Fair Value at Amount Swap Price September 30, 2001 (BBtu) (1) (Per MMBtu) (2) (In thousands) ----------------------- ----------------------- ----------------------- Natural Gas Swaps: October 2001 - December 2001........ 2,150 $4.24 $ 4,380 January 2002 - March 2002........... 4,500 4.38 7,026 April 2002 - June 2002.............. 4,550 3.95 5,308 July 2002 - September 2002.......... 4,600 4.03 5,209 October 2002 - December 2002........ 4,600 4.20 5,015 January 2003 - March 2003........... 2,700 3.93 1,708 April 2003 - June 2003.............. 2,730 3.59 1,451 July 2003 - September 2003.......... 2,760 3.67 1,485 October 2003 - December 2003........ 2,760 3.84 1,458 ----------------------- ----------------------- Total............................ 31,350 $33,040 ======================= =======================

Filing Compare · NEWFIELD EXPLORATION GULF COAST INC