10-Q 1 h97819e10vq.txt EOTT ENERGY PARTNERS, L.P. - DATED 3/31/2002 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended MARCH 31, 2002 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 1-12872 EOTT ENERGY PARTNERS, L.P. (Exact name of registrant as specified in its charter) Delaware 76-0424520 --------------------------- --------------------------- (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification No.) 2000 West Sam Houston Parkway South, Suite 400 Houston, Texas 77042 --------------------------- --------------------------- (Address of principal executive offices) (Zip Code) (713) 993-5200 ------------------------------------------------------ (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 12 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 No [X] 1 EOTT ENERGY PARTNERS, L.P. TABLE OF CONTENTS Page ---- PART I. FINANCIAL INFORMATION ITEM 1. Financial Statements Condensed Consolidated Statements of Operations (Unaudited) -- Three Months Ended March 31, 2002 and 2001............................3 Condensed Consolidated Balance Sheets (Unaudited) -- March 31, 2002 and December 31, 2001..................................4 Condensed Consolidated Statements of Cash Flows (Unaudited) -- Three Months Ended March 31, 2002 and 2001............................5 Condensed Consolidated Statement of Partners' Capital (Unaudited) -- Three Months Ended March 31, 2002.....................................6 Notes to Condensed Consolidated Financial Statements....................7 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................22 ITEM 3. Quantitative and Qualitative Disclosures about Market Risk......35 PART II. OTHER INFORMATION ITEM 1. Legal Proceedings...............................................37 ITEM 6. Exhibits and Reports on Form 8-K................................37 2 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS EOTT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS) (UNAUDITED)

~~Page~~THREE ~~PART~~MONTHS I.ENDED ~~FINANCIAL~~MARCH ~~INFORMATION~~31, ~~ITEM~~--------------------------- 1.2002 ~~Financial~~2001 ~~Statements~~------------ ~~Condensed~~------------ ~~Consolidated~~Revenue........................................................... ~~Statements~~$1,209,399 of$ ~~Operations~~2,544,437 ~~(Unaudited)~~Cost -of ~~Three~~Sales..................................................... ~~Months~~1,147,342 ~~Ended~~2,484,383 ~~September~~Operating 30Expenses................................................ 32,349 ~~2001~~27,054 ~~and~~Depreciation ~~2000~~ and ~~Nine~~Amortization ~~Months~~-- ~~Ended~~operating........................ ~~September~~8,337 307,699 ~~2001~~---------- ~~and~~----------- ~~2000~~Gross Profit........................3.............................. ~~Condensed~~21,371 ~~Consolidated~~25,301 ~~Balance~~---------- ~~Sheets (Unaudited)~~ ----------- ~~September 30~~Selling, ~~2001~~General and ~~December~~Administrative ~~31, 2000~~Expenses...................... 12,675 12,002 Depreciation and Amortization -- corporate & other ...........4.... ~~Condensed~~820 ~~Consolidated~~808 ~~Statements~~Other of(Income) ~~Cash~~Expense............................................ ~~Flows~~(928) (~~Unaudited~~6) ---------- ~~Nine~~----------- ~~Months~~Operating ~~Ended~~Income.................................................. ~~September~~8,804 3012,497 ~~2001~~---------- ----------- Interest Expense and ~~2000~~Related Charges............................5.. ~~Condensed Consolidated Statement of Partners' Capital~~ (~~Unaudited~~11,240) ~~- Nine Months Ended September 30~~(7,166) ~~2001~~Interest Income.....................................6.............. ~~Notes~~18 to300 ~~Condensed~~Other, ~~Consolidated Financial Statements~~net........................7................................ ~~ITEM~~73 2(362) ---------- ----------- Net Income (Loss) Before Cumulative Effect of Accounting Changes.. ~~Management's~~(2,345) ~~Discussion~~5,269 ~~and~~Cumulative ~~Analysis~~Effect of ~~Financial~~Accounting ~~Condition~~Changes (Notes 2 and ~~Results~~3)........... of-- ~~Operations~~1,073 ---------- ----------- Net Income (Loss)...............................21.................. ~~ITEM~~$ 3.(2,345) ~~Quantitative~~$ ~~and~~6,342 ~~Qualitative~~========== ~~Disclosures~~=========== ~~about~~Basic ~~Market~~Net ~~Risk~~Income (Loss) Per Unit (Note 5) Common...........35............................................... ~~PART~~$ II(0.03) ~~OTHER~~$ ~~INFORMATION ITEM 1~~0.23 ~~Legal~~========== ~~Proceedings~~=========== Subordinated....................................................36 ~~ITEM~~$ 6(0.19) ~~Exhibits~~$ ~~and~~0.23 ~~Reports~~========== on=========== ~~Form~~Diluted ~~8-K~~Net Income (Loss) Per Unit (Note 5)....................... $ (0.08) $ 0.23 ========== =========== Number of Units Outstanding for Diluted Computation............36... 27,476 27,476 ========== ===========

The accompanying notes are an integral part of these condensed consolidated financial statements. 3 EOTT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED BALANCE SHEETS (IN THOUSANDS) (UNAUDITED)

~~THREE~~MARCH ~~MONTHS~~31, ~~ENDED~~DECEMBER ~~NINE MONTHS ENDED SEPTEMBER 30~~31, ~~SEPTEMBER~~2002 ~~30,~~2001 ----------~~----------------~~ -----------~~---------------~~ ~~2001~~ASSETS ~~2000~~Current ~~2001~~Assets ~~2000~~Cash ~~-----------~~and ~~-----------~~cash ~~-----------~~equivalents ~~----------- Revenue~~ ....................................... $ 617 $ 2,941 Trade and other receivables, net of allowance for doubtful accounts of $1,212 and $ 1,225, respectively ..................~~...~~ $455,696 2495,~~322,553~~896 $Inventories (Note 3~~,143,529~~) $............................................ 794,~~123,936~~514 ~~$ 8~~89,~~340,159~~685 ~~Cost~~Other ~~of Sales~~ ........................................................... 223,~~256,102~~535 331,~~084,634~~650 ~~6,937,782 8,162,201~~ ----------- ----------- ~~-----------~~Total ~~-----------~~current ~~Gross~~assets ~~Margin~~ ............................................~~...........~~ 66574,~~451~~362 58620,~~895~~172 ~~186,154~~---------- ~~177~~---------- Property,~~958~~ ~~Expenses~~Plant ~~Operating~~& ~~expenses~~Equipment, at cost ...............................~~...............~~ 40664,~~647~~752 40656,~~217~~993 ~~118,874~~Less: ~~118,884~~Accumulated ~~Depreciation~~depreciation ~~and amortization~~ ................................... 8199,~~069~~544 8191,~~423~~118 ~~24,966 25,282~~ ----------- ----------- ~~-----------~~Net ~~-----------~~property, ~~Total~~plant & equipment ............................... 465,208 465,875 ---------- ---------- Other Assets, net of amortization .................................. 4819,~~716~~760 4814,~~640~~463 ~~143,840 144,166~~ ----------- ----------- ~~-----------~~Total ~~-----------~~Assets ~~Operating Income~~ ....................................................... 17$1,~~735 10~~059,~~255~~330 42$1,~~314 33~~100,~~792~~510 ~~Other~~========== ~~Income~~========== ~~(Expense)~~LIABILITIES ~~Interest~~AND ~~income~~PARTNERS' CAPITAL Current Liabilities Trade accounts payable ..........................................~~.......~~ ~~390~~$ ~~489 1~~477,~~202~~023 1$ 532,~~111~~235 ~~Interest~~Accrued ~~and~~taxes ~~related~~payable ~~charges~~ ........................................... (810,~~895)~~867 (78,~~481)~~846 ~~(24,554)~~Short-term ~~(22,823)~~borrowings ~~Other, net~~ ........................................... 40,000 40,000 Repurchase agreements ........... ~~(1,867) (252) (2,197) (1,960) ----------- ----------- ----------- ----------- Total~~ ................................ 100,000 100,000 Receivable financing ............................................ ~~(10~~50,~~372)~~000 (742,~~244)~~500 ~~(25,549)~~Payable ~~(23,672)~~to ~~-----------~~Enron ~~-----------~~Corp. ~~-----------~~& ~~-----------~~affiliates, ~~Net~~net ~~Income~~........................ ~~Before~~40,228 ~~Cumulative~~37,681 ~~Effect~~Performance ofcollateral ~~Accounting~~from ~~Change~~Enron Corp. ......................... 15,829 15,829 Other ........... ~~7,363 3,011 16,765 10,120 Cumulative Effect of Accounting Change~~ ................................................ --43,296 ~~-- 1~~35,~~073~~817 -- --------~~---~~ ----------- Total current liabilities ..................................... 777,243 812,908 ----------- ---------- Long-Term ~~Net~~Liabilities ~~Income~~11% Senior notes ................................................~~.........~~ ~~$ 7~~235,~~363~~000 ~~$ 3~~235,~~011~~000 $Other ~~17,838 $ 10,120 =========== =========== =========== =========== Basic Net Income Per Unit Common~~ .......................................................... ~~$ 0~~.26 $6,858 ~~0.11~~5,316 $---------- ~~0.64~~---------- $Total ~~0.36~~long-term ~~===========~~liabilities ~~=========== =========== =========== Subordinated~~ ................................... 241,858 240,316 ---------- ---------- Commitments and Contingencies (Notes 7 and 8) Additional Partnership Interests ................. ~~$ 0~~.~~26 $ 0~~.~~11 $ 0~~.~~64 $ 0~~.36.............. ~~===========~~9,318 ~~===========~~9,318 ~~===========~~---------- ~~===========~~---------- ~~Diluted~~Partners' ~~Net~~Capital ~~Income~~Common ~~Per~~Unitholders ~~Unit~~ ........................................ ~~$ 0~~.~~26 $ 0~~.~~11 $ 0~~.~~64 $ 0~~.36.. ~~===========~~(2,487) ~~===========~~2,685 ~~===========~~Subordinated ~~===========~~Unitholders ~~Number of Units Outstanding for Diluted Computation~~ ........................................~~....~~ 27,~~476~~467 2729,~~476~~155 ~~27,476~~General ~~27,476~~Partner ~~=========== =========== =========== =========== Pro forma amount, assuming the new inventory valuation method was applied retroactively: (Note 3) Net Income~~ .................................................~~.....~~ ~~$ 2~~5,~~313~~931 ~~$ 9~~6,~~920~~128 ~~===========~~---------- ~~===========~~---------- ~~Diluted~~Total ~~Net~~Partners' ~~Income~~Capital ~~Per Unit~~ ....................................... $30,911 037,968 ---------- ---------- Total Liabilities and Partners' Capital .08........................... $1,059,330 ~~0.35~~$1,100,510 =========== ===========

The accompanying notes are an integral part of these condensed consolidated financial statements. 4 EOTT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) (UNAUDITED)

~~SEPTEMBER~~THREE ~~30,~~MONTHS ~~DECEMBER~~ENDED MARCH 31, ~~2001 2000~~ ------------ ------------ ~~ASSETS~~2002 ~~Current~~2001 ~~Assets~~---------- ~~Cash~~---------- ~~and~~CASH ~~cash~~FLOWS ~~equivalents~~FROM ~~...................................~~OPERATING $ACTIVITIES ~~22,116~~Reconciliation $of ~~54,230~~net ~~Trade~~income ~~and~~(loss) ~~other~~to ~~receivables,~~ net ofcash ~~allowance~~provided ~~for~~by ~~doubtful~~(used ~~accounts~~in) ofoperating ~~$1,869~~activities ~~and~~-- ~~$1,827,~~Net ~~respectively~~income ~~.............. 674,738 917,748 Inventories~~ (~~Note 3~~loss) ....................................... ~~26,403~~$ 84(2,~~653~~345) ~~Other~~$ 6,342 Depreciation...........................................~~............~~ 378,~~911~~651 268,~~208~~243 ~~----------~~Amortization ~~----------~~of ~~Total~~intangible ~~current~~ assets ......................~~...............~~ ~~761,168~~506 ~~1,082,839~~264 ~~----------~~Net ~~----------~~unrealized ~~Property,~~change ~~Plant~~in &crude ~~Equipment,~~oil attrading ~~cost~~ activities..~~..........................~~ ~~644,316~~(549) ~~562~~(1,~~393~~897) ~~Less:~~(Gains) ~~Accumulated~~losses ~~depreciation~~on disposal of assets...................~~...........~~ ~~183,211~~(24) ~~168,460~~158 ~~----------~~Changes ~~----------~~in ~~Net~~components ~~property,~~of ~~plant~~working &capital ~~equipment~~-- Receivables.......................... ~~461,105 393,933 ---------- ---------- Other Assets, net of amortization~~ ................~~...............~~ 4540,~~048~~200 16160,~~221~~428 ~~---------- ---------- Total Assets~~ Inventories..........................................~~..........~~ $15,~~267,321~~223 $1(35,~~492,993~~483) ~~==========~~Other ~~==========~~current ~~LIABILITIES AND PARTNERS' CAPITAL Current Liabilities Trade accounts payable~~ assets.................................~~.....~~ ~~$ 775~~5,~~672~~855 $12,~~118,754~~064 ~~Accrued~~Trade ~~taxes~~accounts payable ...............................~~........~~ 12(52,~~390~~665) 10(210,~~755~~260) ~~Repurchase~~Accrued ~~agreements~~taxes payable................................~~.......~~ ~~110~~2,~~000~~021 --(1,203) Other current liabilities............................ 1,225 3,155 Other assets and liabilities........................... 413,~~517~~966 221,~~802~~509 ---------- ---------- ~~Total~~Net ~~current~~Cash ~~liabilities~~Provided By (Used In) Operating Activities.......~~.........................~~ ~~939~~12,~~579~~064 1(66,~~152,311~~680) ---------- ---------- ~~Long-Term~~CASH ~~Liabilities~~FLOWS ~~11%~~FROM ~~Senior~~INVESTING ~~notes~~ACTIVITIES Proceeds from sale of property, plant and equipment....~~........................................~~ ~~235~~107 1,~~000~~077 ~~235~~Additions to property,~~000~~ ~~Other~~plant and equipment.............~~..........................................~~ 1(17,~~595~~283) --(4,292) ---------- ---------- ~~Total~~Net ~~long-term~~Cash ~~liabilities~~Used In Investing Activities.....................~~.........~~ ~~236~~(17,~~595~~176) ~~235~~(3,~~000~~215) ---------- ---------- ~~Commitments~~CASH ~~and~~FLOWS ~~Contingencies~~FROM ~~(Note~~FINANCING 9)ACTIVITIES ~~Additional~~Increase ~~Partnership~~in ~~Interests~~receivable financing.......................~~.........~~ 97,~~318~~500 ~~9,318~~ --~~--------~~ ~~----------~~Increase ~~Partners'~~in ~~Capital~~repurchase ~~Common Unitholders~~ agreements......................~~....................~~ ~~33,009~~-- 4730,~~581~~000 ~~Subordinated~~Distributions ~~Unitholders~~to Unitholders...........................~~.........~~ 41(4,~~822~~712) 41(10,~~496~~791) ~~General~~--------- ~~Partner~~-------- Net Cash Provided By Financing Activities.................~~............................~~ 62,~~998~~788 719,~~287~~209 ---------- ---------- ~~Total~~Decrease ~~Partners'~~In ~~Capital~~Cash and Cash Equivalents..................... (2,324) (50,686) Cash and Cash Equivalents, Beginning of Period............. 812,~~829~~941 9654,~~364~~230 ---------- ---------- ~~Total~~Cash ~~Liabilities~~ and ~~Partners'~~Cash ~~Capital~~Equivalents, End of Period.................. $ 617 $ 3,544 ========= ======== Supplemental Cash Flow Information: Interest paid ......................................... $1 2,~~267,321~~123 $~~1,492,993~~ 408 ========== ==========

The accompanying notes are an integral part of these condensed consolidated financial statements. 5 EOTT ENERGY PARTNERS, L.P. CONDENSED CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (IN THOUSANDS) (UNAUDITED)

~~NINE~~COMMON ~~MONTHS~~SUBORDINATED ~~ENDED~~GENERAL ~~SEPTEMBER~~UNITHOLDERS ~~30,~~UNITHOLDERS PARTNER TOTAL ----------- ----------- ~~2001 2000~~ --------- -----~~----~~ ~~CASH~~Partners' ~~FLOWS~~Capital ~~FROM~~at ~~OPERATING~~December ~~ACTIVITIES~~31, ~~Reconciliation of net income to net cash provided by (used in) operating activities - Net income~~ 2001..~~...........................................~~ $ 172,~~838~~685 $ 1029,~~120~~155 ~~Depreciation~~$ ~~........................................... 24~~6,~~924~~128 24$37,~~490~~968 ~~Amortization~~Net ~~of intangible assets~~ income...................... ~~1,571 792 Net unrealized change in crude oil trading activities~~ .. ~~(3,449) 3,216 (Gains) losses on disposal of assets~~ ......~~.............~~ ~~507~~ (~~555~~553) ~~Changes in components of working capital - Receivables ......................................... 245,076~~ (791,~~993~~688) ~~Inventories ......................................... 53,897 73,198 Other current assets ................................ 7,621 12,818 Trade accounts payable ..............................~~ (~~345,242~~104) ~~19,491 Accrued taxes payable ............................... 1,635~~ (2,~~252 Other current liabilities ........................... 8,656 4,849 Other assets and liabilities ........................... (1,207~~345) ~~994 --------- --------- Net~~ Cash ~~Provided By Operating Activities~~ distributions.................. ~~11,827 71,672 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from sale of assets~~ ....~~.......................~~ ~~16,935 1,100 Acquisitions ...........................................~~ (~~117~~4,~~000~~619) -- ~~Additions to property, plant and equipment .............~~ (~~21,503~~93) (94,~~675~~712) --------- --------- ~~Net Cash Used In Investing Activities ...................... (121,568) (8,575)~~ --------- --------- ~~CASH~~Partners' ~~FLOWS~~Capital ~~FROM~~at ~~FINANCING~~March ~~ACTIVITIES Increase (decrease) in repurchase agreements ........... 110~~31,~~000~~ ~~(26,251) Distributions to Unitholders~~ 2002.....~~......................~~ ~~(32,373)~~$ (262,~~796~~487) ~~Issuance of Additional Partnership Interests ........... -- 6~~$27,~~771~~467 --------- --------- Net Cash Provided By (Used In) Financing Activities ........ 77,627 (46,276) --------- --------- Increase (Decrease) In Cash and Cash Equivalents ........... (32,114) 16,821 Cash and Cash Equivalents, Beginning of Period ............. 54,230 17,525 --------- --------- Cash and Cash Equivalents, End of Period ................... $ 225,~~116~~931 $ 3430,~~346~~911 ========= ========= ~~Supplemental Cash Flow Information: Interest paid .......................................... $ 16,839 $ 15,985~~ ========= =========

The accompanying notes are an integral part of these condensed consolidated financial statements. 6 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION EOTT Energy Partners, L.P. (the "MLP") is a Delaware limited partnership which operates through its affiliated limited partnerships, EOTT Energy Operating Limited Partnership, EOTT Energy Canada Limited Partnership, EOTT Energy Pipeline Limited Partnership and EOTT Energy Liquids, L.P., each of which is a Delaware limited partnership. In 1999, EOTT Energy Partners, L.P. formed EOTT Energy Finance Corp. as a direct wholly-owned subsidiary of the MLP. This entity was set up in connection with a debt offering to facilitate certain investors' ability to purchase EOTT's senior notes. The terms "we", "EOTT" and the "Partnership" herein refer to EOTT Energy Partners, L.P. and its affiliated limited partnerships. EOTT Energy Corp. (the "General Partner"), a Delaware corporation and a wholly-owned subsidiary of Enron Corp. ("Enron"), serves as the sole general partner of the MLP. EOTT Energy General Partner, L.L.C., which is wholly-owned by the MLP, serves as general partner of the four operating limited partnerships. At March 31, 2002, EOTT Energy Corp. owned an approximate 1.98% general partner interest in the MLP. Based upon information provided by Enron, Enron beneficially owns approximately 18% of our outstanding common units, 78% of our outstanding subordinated units or 37% of our total units outstanding because it retains voting power and shared investment power over the securities. The accompanying condensed consolidated financial statements and related notes present the financial position of the Partnership as of March 31, 2002 and December 31, 2001, the results of operations and cash flows for the three months ended March 31, 2002 and 2001, and changes in partners' capital for the three months ended March 31, 2002. For the three months ended March 31, 2002 and 2001, traditional net income and comprehensive income are the same. Because of the withdrawal of our former independent accountants, Arthur Andersen LLP, on February 5, 2002, the time necessary to select PricewaterhouseCoopers ("PWC") as our new independent accountants, and the time required for completion of our audit for 2001, we filed a "Notification of Late Filing" on Form 12B-25 with the U.S. Securities and Exchange Commission ("SEC") on April 2, 2002, disclosing that we were unable to timely file the Annual Report on Form 10-K for the year ended December 31, 2001 ("Form 10-K"). We subsequently filed our Form 10-K on May 31, 2002. As disclosed in a "Notification of Late Filing" on Form 12B-25 filed with the SEC on March 16, 2002, due to the delay in filing our Form 10-K we were unable to timely file this Quarterly Report on Form 10-Q for the period ending March 31, 2002. In addition, as more fully disclosed in the Form 10-K, financial statements included in the Form 10-K for the years 1999 and 2000 were unaudited. The financial statements included herein have been prepared by the Partnership without audit pursuant to the rules and regulations of the SEC. Accordingly, they reflect all adjustments (which consist solely of normal recurring adjustments) which are, in our opinion, necessary for a fair presentation of the financial results for interim periods. Certain information and notes normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. However, we believe that the disclosures are adequate to make the information presented not misleading. These financial statements should be read in conjunction with the financial statements and notes thereto included in the Partnership's Form 10-K. The preparation of financial statements in conformity with generally accepted accounting principles 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 revenues and expenses during the reporting period. Actual results could differ from those estimates. 7 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Certain reclassifications have been made to prior period amounts to conform with the current period presentation. Additionally, we have made certain reclassifications and revisions to our income statement presentation. We now reflect, as a component of "gross profit", all costs associated with the production of revenues (including costs of sales, operating expenses and applicable depreciation and amortization). This contrasts with prior year presentations that included the cost of products and associated transportation costs as components of "gross margin". Additionally, certain other income and expenses (including gains and losses on assets sales and income or expense related to litigation settlements) which were previously classified as "Other, net" have been reclassified and are reflected as a component of "Operating Income." These reclassifications had no impact on reported net income. 2. NEW ACCOUNTING STANDARDS Effective January 1, 2001, we began reporting derivative activities in accordance with Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended. SFAS No. 133 requires that derivative instruments (including certain derivative instruments embedded in other contracts) 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. SFAS No. 133 requires that as of the date of the initial adoption, the difference between the fair value of derivative instruments and the previous carrying amount of those derivatives be recorded in net income or other comprehensive income, as appropriate, as the cumulative effect of a change in accounting principle. The cumulative effect of adopting SFAS No. 133 effective January 1, 2001 was $1.3 million ($0.05 per diluted unit) and is reflected as an increase in income in the Condensed Consolidated Statement of Operations. We have not designated any derivatives as hedging instruments. In July 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142, which must be applied to fiscal years beginning after December 15, 2001, modifies the accounting and reporting of goodwill and intangible assets. The pronouncement requires entities to discontinue the amortization of goodwill, reallocate all existing goodwill among its reporting segments based on criteria set by SFAS No. 142 and perform initial impairment tests by applying a fair value-based analysis on the goodwill in each reporting segment. Any impairment at the initial adoption date shall be recognized as the effect of a change in accounting principle. Subsequent to the initial adoption, goodwill shall be tested for impairment annually or more frequently if circumstances indicate a possible impairment. Under SFAS No. 142, entities are required to determine the useful life of other intangible assets and amortize the value over the useful life. If the useful life is determined to be indefinite, no amortization will be recorded. For intangible assets recognized prior to the adoption of SFAS No. 142, the useful life should be reassessed. Other intangible assets are required to be tested for impairment in a manner similar to goodwill. While we do not expect the adoption of SFAS No. 142 to result in an impairment of recorded goodwill, we have not yet completed our initial impairment tests. At March 31, 2002 and December 31, 2001, we had $7.4 million of net goodwill in Other Assets. The following reconciliation shows the effect of goodwill amortization in prior periods as follows (in thousands except per unit amounts):

~~COMMON~~FOR ~~SUBORDINATED~~THE ~~GENERAL~~THREE ~~UNITHOLDERS~~MONTHS ~~UNITHOLDERS~~ENDED ~~PARTNER~~MARCH 31, ----------- ------------ ------------- ~~Partners'~~2002 ~~Capital~~2001 at-------- ~~December~~------- ~~31,~~Reported ~~2000~~net income (loss)........................... $ 47(2,~~581~~345) $ 416,~~496~~342 $Add ~~7,287~~back: ~~Net~~Goodwill ~~income~~ amortization...................... -- 264 -------- ------- Adjusted net income (loss)........................... 11$ (2,~~756~~345) 5$ 6,~~726~~606 ~~356~~======== ~~Cash~~======= ~~distributions~~Diluted earnings (loss) per unit: Reported net income (loss).......................... ~~(26,328)~~$ (~~5,400~~0.08) ~~(645)~~$ 0.23 Goodwill amortization.............................. --~~------~~ 0.01 -------- -------- ~~Partners'~~Adjusted ~~Capital~~net atincome ~~September 30, 2001~~ (loss)......................... $ ~~33,009~~(0.08) $ ~~41,822~~0.24 ~~$ 6,998~~ ======== =======~~= ========~~

8 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, a corresponding increase in the carrying amount of the related long-lived asset would be recorded. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss on settlement. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. We are currently evaluating the effect on our financial statements of adopting SFAS No. 143 and plan to adopt the statement effective January 1, 2003. In August 2001, the FASB issued SFAS No. 144, "Accounting for Impairment on Disposal of Long-Lived Assets." This statement clarified the financial accounting and reporting for the impairment or disposal of long-lived assets. Impairment is required to be recognized if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows. The impairment loss to be recognized is the difference between the carrying amount and the fair value of the asset. The standard also provides guidance on the accounting for the long-lived assets that are held for disposal. This standard was effective for the Partnership beginning January 1, 2002. Adoption of SFAS No. 144 had no effect on our financial statements. In April 2002, the FASB issued SFAS No. 145 "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections." Certain provisions of SFAS No.145 are effective for transactions occurring after or financial statements issued after May 15, 2002. The adoption of SFAS No. 145 had no effect on our financial statements. 3. CHANGE IN ACCOUNTING PRINCIPLE In the first quarter of 2001, we changed our method of accounting for inventories used in our energy trading activities from the average cost method to the fair value method. The cumulative effect of the change in accounting for inventories as of January 1, 2001 was $0.2 million ($0.01 per diluted unit) and is reported as a decrease in net income for the first quarter of 2001. 4. ENERGY TRADING/DERIVATIVE ACTIVITIES Changes in the market value of transactions designated as energy-trading activities in accordance with Emerging Issues Task Force Issue 98-10, and derivative instruments accounted for under SFAS No. 133, are recorded in revenues every period as mark-to-fair value gains or losses. The related price risk management assets and liabilities are recorded in other current or non-current assets and liabilities, as applicable, on the balance sheet. The fair value of transactions designated as energy-trading activities are determined primarily based on forward prices of the commodity, adjusted for certain transaction costs associated with the 9 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS transactions. For the three months ended March 31, 2002 and 2001, we had a net mark-to-fair value gain of $0.5 million and a net mark-to-fair value gain of $0.7 million, respectively. Certain estimates were made in determining the fair value of contracts. We have determined these estimates using available market data and valuation methodologies. Judgment may be required in interpreting data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts. 5. EARNINGS PER UNIT Net income (loss) shown in the tables below excludes the approximate two percent interest of the General Partner. Earnings per unit are calculated as follows (in thousands, except per unit amounts):

THREE MONTHS ENDED ~~SEPTEMBER~~MARCH 3031, ----------------------------------------------------------------~~--------~~ 2002 2001 ~~2000~~ -------------------------------- -----------------------------~~----~~ Wtd. Wtd. Net Average Per Net Average Per ~~Income~~Loss Units Unit Income Units Unit ------- ---------- ------- --------- ------- ------- Basic (1) Common $~~4,852~~ (553) 18,476 $ (0.2603) $1 4,~~985~~180 18,476 $ 0.1123 Subordinated $2(1,~~364~~688) 9,000 $ (0.2619) $ ~~966~~2,035 9,000 $ 0.1123 Diluted (2) $7(2,~~216~~241) 27,476 $ (0.2608) $2 6,~~951~~215 27,476 $ 0.1123

(1) Net income, excluding the General Partner interest, has been apportioned to each class of unitholder based on the ownership of total units outstanding which is also reflected on the Statement of Partners' Capital. Due to a negative capital balance in the first quarter of 2002, the loss allocated to the common unitholders for the first quarter was reallocated to the remaining unitholders based on their ownership percentage. The allocated loss will be recouped by the unitholders allocated the additional losses through future income. (2) The diluted income per unit calculation assumes the conversion of subordinated units into common units. Net income and per unit information related to the net income before cumulative effect of accounting changes and cumulative effect of the accounting changes for the three months ended March 31, 2001 is as follows (in thousands except per unit amounts):

~~NINE~~NET ~~MONTHS~~INCOME ~~ENDED SEPTEMBER 30,~~ --------------------------------------- Basic ------------------------~~---------~~ ~~2001~~Common ~~2000~~Subordinated Diluted --------- ------------~~-----------~~ -----------~~----------------------~~ ~~Wtd.~~Net ~~Wtd~~Income Before Cumulative Effect...... ~~Net~~$ ~~Average~~3,473 ~~Per~~$ ~~Net~~1,691 ~~Average~~$ ~~Per~~5,164 ~~Income~~Cumulative ~~Units~~Effect ~~Unit~~of ~~Income~~Accounting ~~Units~~Changes ~~Unit~~Adoption of SFAS No.133................ 833 405 1,238 Change in Inventory Valuation Method... (126) (61) (187) ------- --~~-----~~ ------- --~~-----~~ ------- --~~-----~~ ~~Basic~~Net ~~(1) Common $11,756 18,476 $ 0~~Income.~~64 $ 6,670 18,476 $ 0~~.~~36 Subordinated $ 5,726 9,000 $ 0~~.64............................ $ 34,~~248~~180 ~~9,000~~ $ ~~0.36 Diluted (~~2~~) $17~~,~~482~~035 ~~27,476~~ $ ~~0.64 $ 9~~6,~~918~~215 ~~27,476~~========= $========= ~~0.36~~=========

10 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~NET~~PER ~~INCOME~~UNIT ---------------------------------------- Basic -------------------------- Common Subordinated Diluted --------- ------------ --------- Net Income Before Cumulative Effect ...... $ ~~11,049~~0.19 $ ~~5,382~~0.19 $ ~~16,431~~0.19 Cumulative Effect of Accounting Changes -Adoption of SFAS No.133 ................ ~~833~~0.05 ~~405~~0.05 ~~1,238~~0.05 -Change in Inventory Valuation Method... (~~126~~0.01) (610.01) (~~187~~0.01) -------- -------- -------- Net Income ............................... $ ~~11,756~~0.23 $ ~~5,726~~0.23 $ ~~17,482~~0.23 ======== ======== ========

6. CREDIT RESOURCES AND LIQUIDITY EOTT has agreements with Standard Chartered Bank ("Standard Chartered") and Standard Chartered Trade Services ("SCTS") which provide up to an aggregate of $500 million of working capital loans, letters of credit, receivables financing and commodity repurchase funding comprised of the following: (i) Up to $300 million of letter of credit and working capital financing ("Credit Facility") with a working capital loan sublimit of $40 million; (ii) Up to $100 million of receivables financing under a receivables purchasing agreement ("Receivables Agreement") with SCTS; and (iii) Up to $100 million of commodity repurchase financing under a commodity repurchase agreement ("Inventory Repurchase Agreement") with SCTS. On April 23, 2002, we amended and extended these agreements with Standard Chartered and SCTS to February 2003. An arrangement fee of 2% is charged on the Credit Facility, Inventory Repurchase Agreement and Receivables Agreement. The Credit Facility is subject to defined borrowing base limitations. The borrowing base is the sum of cash and equivalents, specified percentages of eligible receivables, inventory, products contracted for or delivered but not billed and a specified percentage of eligible fixed assets. Letter of credit fees are up to 3% per annum. The commitment fee is 0.5% per annum of the unused portion of the Credit Facility. We may elect that loans under the Credit Facility bear interest at a rate per annum equal to the alternative base rate, as defined in the amended Credit Facility, or LIBOR plus 3%. The alternative base rate is defined in the amended Credit Facility to mean 3% per annum plus the higher of (a) the annual rate of interest announced from time to time by Standard Chartered as its base rate or (b) 1/2 of 1% above the overnight Federal Funds rate, as published by the Federal Reserve Bank of New York. The Credit Facility includes covenants and restrictions primarily related to distributions to unitholders, amount of permitted expansion capital and specified quarterly amounts for earnings before interest, depreciation and amortization, net income and tangible net worth. Distributions to unitholders will not be permitted under the Credit Facility until all of the following occur: (i) we permanently reduce our aggregate obligations to Standard Chartered and SCTS to an amount not exceeding $300 million; (ii) our consolidated net worth is $10 million greater than our consolidated net worth as of January 31, 2002, excluding any non-cash asset write-downs incurred after January 31, 2002; and (iii) we resolve certain claims (trade and other payables) of Enron and its affiliates against us related to Enron's bankruptcy proceedings. See Note 7. At March 31, 2002 and December 31, 2001, we had $243.5 million and $196.1 million, respectively, in letters of credit outstanding under the Credit Facility. At March 31, 2002, we had an outstanding repurchase amount of $100 million. Pursuant to the Inventory Repurchase Agreement, which had terms of thirty-one days, we repurchased the crude oil inventory on April 11 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 25, 2002 for approximately $100.4 million. At December 31, 2001, we had outstanding repurchase agreements of approximately $100 million. As of March 31, 2002 and December 31, 2001, $50.0 million and $42.5 million, respectively, of receivables had been transferred under the Receivables Agreement. In the first quarter of 2001, we accounted for these transactions as a sale under the provisions of SFAS No. 125. These transactions did not qualify as sales under SFAS No. 140 and therefore are accounted for as financings at March 31, 2002 and December 31, 2001. We believed that the Credit Facility, Inventory Repurchase Agreement and Receivables Agreement would have been sufficient to support our purchasing activities and working capital and liquidity requirements prior to the Enron bankruptcy. However, as a result of Enron's bankruptcy, some of our trade creditors have been less willing to extend credit to us on an unsecured basis and the amount of letters of credit we have been required to post increased from $196.1 million at December 31, 2001 to $243.5 million at March 31, 2002. Subsequent to year-end, due to the impacts of the Enron bankruptcy as well as the rise in crude oil prices, we have had to reduce our marketing activities due to the availability of credit support under the Credit Facility. Our ability to obtain letters of credit to support our purchases of crude oil or other petroleum products is fundamental to our gathering and marketing activities. Additionally, we have a significant need for working capital due to the large dollar volume of marketing transactions. We can give no assurance that we will not be required to further reduce or restrict our gathering and marketing activities because of limitations on our ability to obtain credit support and financing for our working capital needs. Any significant decrease in our financial strength, regardless of the reason for such decrease, may also increase the number of transactions requiring letters of credit or other financial support, may make it more difficult for us to obtain such letters of credit, and/or may increase the cost of obtaining them. This could in turn adversely affect our ability to maintain or increase our level of purchasing and marketing activities or otherwise adversely affect our profitability and Available Cash as defined in the MLP's Partnership Agreement and amendments thereto, and thus, our ability to meet the conditions necessary to make distributions. Under the Partnership Agreement, it is intended that we distribute 100% of our Available Cash within 45 days after the end of each quarter to unitholders of record and to the General Partner. Available Cash consists generally of all of the cash receipts of the Partnership adjusted for its cash disbursements and net changes to reserves. The full definition of Available Cash is set forth in the Partnership Agreement and amendments thereto, which have been filed as exhibits with the SEC. From Available Cash, we are required to make a minimum quarterly distribution ("MQD") to the General Partner and the holders of our common units. The MQD is currently measured at $0.475 per common unit, distributed 98.02% to the holders of our common units and 1.98% to our General Partner. If we fail to make the entire minimum distribution in any quarter, the part of distribution not made is accounted for as an "arrearage." If, in any quarter, we have Available Cash in excess of the MQD, we are required to make the MQD and then repay the arrearage to holders of our common units, before making a distribution to the holders of the subordinated units or the Additional Partnership Interests ("APIs"). Under a Support Agreement with Enron, Enron committed to provide total cash distribution support in an amount necessary to pay MQDs, with respect to quarters ending on or before December 31, 2001, in an amount up to an aggregate of $29 million in exchange for APIs. The distribution for the fourth quarter of 2001 of $0.25 per common unit was lower than the MQD amount of $0.475 per common unit. Enron did not pay the fourth quarter distribution shortfall of $0.225 per common unit. We expect to make a claim for the distribution support amount of $4.2 million through the bankruptcy proceedings. See further discussion in Note 7. On April 3, 2002, we suspended the distribution to limited partners for the first quarter of 2002. As previously discussed, under the Credit Facility, there are restrictions on the ability to pay distributions to our 12 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS limited partners. We do not expect to make any distributions to our unitholders prior to the fourth quarter of 2002. 7. IMPACT OF ENRON BANKRUPTCY AND TRANSACTIONS WITH ENRON AND RELATED PARTIES IMPACT OF ENRON BANKRUPTCY Beginning on December 2, 2001, Enron, along with certain of its subsidiaries, filed to initiate bankruptcy proceedings under Chapter 11 of the Federal Bankruptcy Code. Neither the General Partner nor the Partnership are included in the filings. Because of our contractual relationships with Enron and certain of its subsidiaries, the bankruptcy has significantly impacted us in various ways, discussed below. Rejection of Certain Agreements with an Enron Affiliate. We have been impacted as a result of the inclusion of Enron Gas Liquids, Inc. ("EGLI"), a wholly owned subsidiary of Enron, in Enron's bankruptcy. We had in place ten-year toll conversion and storage agreements (the "Toll Conversion and Storage Agreements") with EGLI. On April 2, 2002, the bankruptcy court entered a Stipulation, rejecting the Toll Conversion and Storage Agreements, which Stipulation became final and non-appealable on April 12, 2002. As a result of EGLI's non-performance under these agreements, we recorded a $29.1 million non-cash impairment at December 31, 2001. Additionally, we have a monetary damage claim against EGLI and Enron as a result of the rejection of the agreements under the Stipulation. On May 12, 2002, we filed claims for rejection damages in excess of $500 million with the bankruptcy court. The final amount of our claim resulting from the rejection of the two agreements has not yet been fully determined. Performance Collateral from Enron. Enron guaranteed payments under the Toll Conversion and Storage Agreements, however, such guaranty was limited to $50 million under the Toll Conversion Agreement and $25 million under the Storage Agreement. In May 2002, we filed a claim under such guaranty in the Enron bankruptcy proceeding. We, however, cannot predict the amounts that we will collect or the timing of collection, if any. In addition, EGLI owed us approximately $9 million under the Toll Conversion and Storage Agreements prior to filing for bankruptcy. Pursuant to these agreements, on November 27, 2001, we requested that EGLI post two $25 million letters of credit. In lieu of posting letters of credit, we received a $25 million deposit/performance collateral from EGLI/Enron, against which we recouped the $9 million of outstanding invoices. We currently intend to apply the remaining sum, approximately $16 million, to recoup or offset a portion of our damages as a result of EGLI's rejection of the Toll Conversion and Storage Agreements. We also have outstanding accounts payable to EGLI in the amount of approximately $2 million for butane and methanol feedstock we acquired prior to EGLI filing for bankruptcy. We are exploring the possibility of offsetting this $2 million payable against a portion of the damages resulting from EGLI's rejection of the Toll Conversion and Storage Agreements. We are uncertain, however, as to how these issues will be resolved. Tax and Environmental Indemnities. We might also incur unexpected losses in the event that Enron fails to indemnify us for certain ad valorem taxes and potential environmental expenditures relating to the hydrocarbon processing facility (the "MTBE Plant") and the liquids storage facility (the "Mont Belvieu Facility"). Cost and Availability of Credit. As a result of Enron's bankruptcy, we have incurred higher costs in obtaining credit than we have in the past. In addition, our trade creditors have been less willing to extend credit to us on an unsecured basis and the amount of letters of credit we have been required to post for our marketing activities has increased significantly. See further discussion in Note 6. 13 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS General Partner Alternatives. Although neither our General Partner nor we have filed for Chapter 11 bankruptcy protection, it is possible that Enron could attempt to cause our General Partner to file for bankruptcy protection. If our General Partner were to file for bankruptcy relief, the filing would be an "Event of Withdrawal" under our Partnership Agreement and our General Partner will be deemed to have withdrawn. Upon the occurrence of an Event of Withdrawal, our General Partner is required to give notice to our limited partners within 30 days after such occurrence. An Event of Withdrawal triggers dissolution and winding up of the affairs of the Partnership unless (i) a successor General Partner is elected and admitted to the Partnership within 180 days, (ii) a written opinion of counsel is issued that such withdrawal would not result in the loss of the limited liability of any limited partner or of the limited partner of any of our operating limited partnerships or cause the Partnership or any of our operating limited partnerships to be taxed as a corporation, and (iii) the new general partner executes a new partnership agreement and executes and files a new certificate of limited partnership. Election of a successor General Partner requires a vote of a majority of the outstanding units to reconstitute the Partnership and approve the successor general partner. Upon the election of a new general partner, the General Partner's interest will be converted to common units. Despite the provisions of our Partnership Agreement discussed in this section, if our General Partner were to file for bankruptcy protection, the bankruptcy court may refuse to enforce these provisions or may require different or additional procedures and consideration to allow these provisions to be followed. Enron has to date, however, chosen not to take action to cause the inclusion of our General Partner in its bankruptcy proceedings which were commenced on December 2, 2001. Neither Enron Corp., the General Partner, nor any other Enron affiliate has advised us of any intention of Enron, any Enron affiliate or our General Partner to place our General Partner into bankruptcy. Because the bankruptcy of Enron created conflicts of interest between EOTT and Enron and certain of its affiliates (for example, with respect to the EGLI contracts, now rejected) the General Partner and Enron established a Restructuring Committee to consider (among other things) all matters involving a possible restructuring of our relationship with Enron. This committee is comprised solely of our three independent, non-Enron related directors. This committee was also granted the power, through amendments to our charter and by-laws, to place our General Partner into bankruptcy. Pension Plan Underfunding Issues. Our General Partner is a participating employer in a defined benefit pension plan known as the Enron Corp. Cash Balance Plan (the "Cash Balance Plan"). It is management's understanding, based on information provided by Enron, that the assets of the Cash Balance Plan are currently less than the present value of all accrued benefits on both an SFAS No. 87 (Employers' Accounting for Pensions) basis and a plan termination basis by approximately $90 million, with approximately 48 percent of that amount attributable to members of the Enron "controlled group" that are not in bankruptcy. A federal government corporation known as the Pension Benefit Guaranty Corporation (the "PBGC") has the power to terminate underfunded pension plans in certain situations, after receiving the permission either of the employer or of a court. In the event of termination of the Cash Balance Plan, the PBGC could impose a "controlled group" liability as defined in ERISA on our General Partner. Under these circumstances, our General Partner would exercise all its rights to defend against such a claim, and, in the event that the PBGC had not already pursued and collected from solvent members of the "controlled group," it would assert its rights to recover contribution from such members. At this time, management cannot predict whether either the PBGC or Enron will seek to terminate the Cash Balance Plan. Any claim paid by the General Partner would become our responsibility under the MLP's Partnership Agreement subject to any claims of indemnity, offset, recoupment or any counterclaims we might have against our General Partner or any of its affiliates. Distributions to Our Common Unitholders. Our distribution for the fourth quarter of 2001 was $0.25 per common unit, which is lower than the minimum quarterly distribution amount of $0.475 per common unit. Enron was obligated under a Support Agreement to provide cash distribution support through the fourth quarter of 2001. As a result of Enron's financial deterioration and bankruptcy, however, Enron did not pay the fourth quarter cash distribution shortfall of $0.225 per common unit. We expect to submit a claim for such 14 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS distribution support amount in Enron's bankruptcy proceedings. In addition, on April 3, 2002, we announced that we would not make a distribution to our common unitholders for the first quarter of 2002. Claims Against Enron's Bankruptcy Estate. We have several potential claims against Enron's bankruptcy estate and have retained outside counsel to evaluate such claims. The claims will likely be deemed to be unsecured claims against certain of the Enron related Chapter 11 companies. We have also filed a claim for rejection damages in excess of $500 million against Enron and certain of its subsidiaries in Enron's bankruptcy proceedings. We are uncertain regarding the ultimate amount of claims that we will be able to establish in the bankruptcy proceeding and we cannot predict the amounts, if any, that we may collect or the timing of such collection. TRANSACTIONS WITH ENRON AND AFFILIATES We do not directly employ any persons responsible for managing or operating the Partnership or for providing services relating to day-to-day business affairs. The General Partner provides such services or obtains such services from third parties and we are responsible for reimbursing the General Partner for substantially all of its direct and indirect costs and expenses. The General Partner entered into an agreement with Enron Pipeline Services Company ("EPSC"), a wholly owned subsidiary of Enron that is not in bankruptcy, to provide certain operating and administrative services. The General Partner and EPSC have decided to terminate this agreement and the General Partner will again provide these services to the Partnership in 2002. The General Partner also had an agreement with EGP Fuels Company, a wholly-owned subsidiary of Enron, to provide transition services through December 31, 2001 for the processing of invoices and payments to third parties related to the MTBE Plant and Mont Belvieu Facility. Additionally, through the MLP Partnership Agreement, the General Partner provides services to us including liability and casualty insurance and certain data processing services and employee benefits. Total amounts owed under these agreements were $37.1 million and $36.0 million at March 31, 2002 and December 31, 2001, respectively. All related party transactions in our opinion are no more or less favorable than can be obtained from unaffiliated third parties. 8. LITIGATION AND OTHER CONTINGENCIES Litigation. We are, in the ordinary course of business, a defendant in various lawsuits, some of which are covered in whole or in part by insurance. We believe that the ultimate resolution of litigation, individually and in the aggregate, will not have a materially adverse impact on our financial position or results of operations. Various legal actions have arisen in the ordinary course of business, the most significant of which are discussed below. State of Texas Royalty Suit. We were served on November 9, 1995 with a petition styled The State of Texas, et al. vs. Amerada Hess Corporation, et al. The matter was filed in District Court in Lee County, Texas and involves several major and independent oil companies and marketers as defendants. The plaintiffs are attempting to put together a class action lawsuit alleging that the defendants acted in concert to buy oil owned by members of the plaintiff class in Lee County, Texas, and elsewhere in Texas, at "posted" prices, which the plaintiffs allege were lower than true market prices. There is not sufficient information in the petition to fully quantify the allegations set forth in the petition, but the General Partner believes that any such claims against us will prove to be without merit. There has been no activity on this matter in several years. The State of Texas, et al. vs. Amerada Hess Corporation, et al., Cause No. 97-12040; In the 53rd Judicial District Court of Travis County, Texas (Common Purchaser Act Suit). This case was filed on October 23, 1997 in Austin by the Texas Attorney General's office and involves several major and independent oil companies and marketers as defendants. We were served on November 18, 1997. The petition states that the State of Texas brought this action in its sovereign capacity to collect statutory penalties recoverable under the Texas Common Purchaser Act, arising from defendants' alleged willful breach of statutory duties owed to royalty, overriding royalty and working interest owners of crude oil sold to defendants, as well as alleged breach of defendants' 15 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS common law and contractual duties. The plaintiffs also allege that the defendants have engaged in discriminatory pricing of crude oil. This case appears to be similar to the State of Texas Royalty Suit filed by the State of Texas on November 9, 1995. We recorded a $0.4 million litigation reserve related to this suit in 1998. We and several of the defendants reached a settlement with the State in the Common Purchaser Act Suit in a Settlement Agreement dated August 5, 1999. The settlement was funded to an escrow account in July 1999. Settlement amounts for each defendant were confidential. This settlement disposed of any claims the State may have in the State of Texas Royalty Suit, discussed above, but did not dismiss that case, or fully dismiss the Common Purchaser Act Suit. Also, any severance tax claims the State may have were specifically excluded from this settlement. However, no severance tax claims were asserted in the petition filed by the plaintiffs. Assessment for Crude Oil Production Tax from the Comptroller of Public Accounts, State of Texas. We received a letter from the Comptroller's Office dated October 9, 1998 assessing us for severance taxes the Comptroller's Office alleges are due based on a difference the Comptroller's Office believes exists between the market value of crude oil and the value reported on our crude oil tax report for the period of September 1, 1994 through December 31, 1997. The letter states that the action, based on a desk audit of our crude oil production reports, is partly to preserve the statute of limitations where crude oil severance tax may not have been paid on the true market price of the crude oil. The letter further states that the Comptroller's position is similar to claims made in several lawsuits, including the Texas Federal Anti-Trust Suit, in which the Partnership is a defendant. The amount of the assessment, including penalty and interest, is approximately $1.1 million. While the claim is still being reviewed, we believe we should be without liability in this or related matters. There has been no action on this matter since early 1999. Export License with United States Department of Commerce. We have applied for and maintained Export Licenses through the U.S. Department of Commerce ("DOC") since 1994. These licenses authorized us to export crude oil to Canada. Each license provided an applicable license quantity and value of merchandise as authorized by the DOC to be exported. The licenses generally covered either a one or two year period. In early 1999, as we were preparing a new license application, we discovered that we had exported more barrels and value than had been authorized by the DOC under our current (and prior) license. Pursuant to Section 764.5 of the Export Administration Regulations, we filed a Voluntary Disclosure with the DOC on February 5, 1999, giving the DOC notice of these license overruns. We have negotiated a monetary settlement with the DOC of approximately $0.5 million and have accrued the settlement amount. John H. Roam, et al. vs. Texas-New Mexico Pipe Line Company and EOTT Energy Pipeline Limited Partnership, Cause No. CV43296, In the District Court of Midland County, Texas, 238th Judicial District (Kniffen Estates Suit). The Kniffen Estates Suit was filed on March 2, 2001 by certain residents of the Kniffen Estates, a residential subdivision located outside of Midland, Texas. The allegations in the petition state that free crude oil products were discovered in water wells in the Kniffen Estates area, on or about October 3, 2000. The plaintiffs claim that the crude oil products are from a 1992 release from a pipeline then owned by the Texas-New Mexico Pipe Line Company ("Tex-New Mex"). We purchased that pipeline from Tex-New Mex in 1999. The plaintiffs have alleged that Tex-New Mex was negligent, grossly negligent and malicious in failing to accurately report and remediate the spill. With respect to us, the plaintiffs are seeking damages arising from any contamination of the soil or groundwater since we acquired the pipeline in question. No specific amount of money damages was claimed, and it is not possible to determine any potential exposure to us at this stage of the matter. In response to the Kniffen Estates Suit, we filed a cross-claim against Tex-New Mex. In the cross-claim, we claim that, in relation to the matters alleged by the plaintiffs, Tex-New Mex breached the Purchase and Sale Agreement between the parties dated May 1, 1999, by failing to disclose the 1992 release and by failing to undertake the defense and handling of the toxic tort claims, fair market value claims, and remediation claims arising from the release. Additionally, we are asserting claims of gross negligence, fraud and specific performance. On April 5, 2002, we filed an amended cross claim which alleges that Tex-New Mex defrauded us as part of Tex-New Mex's sale of the pipeline systems to us in 1999. The amended cross claim also alleges that various practices employed by Tex New Mex in the operation of its pipelines constitute gross negligence and willful misconduct and void our obligation to indemnify Tex-New 16 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Mex for remediation of releases that occurred prior to May 1, 1999. Due to the early stages of the proceedings, it is not possible to determine the possible outcome of this matter. Jimmie B. Cooper and Shryl S. Cooper v. Texas-New Mexico Pipeline Company, Inc., EOTT Energy Pipeline Limited Partnership and Amerada Hess Corporation, Case No. CIV 01-1321 M/JHG, In the United States District Court for the District of New Mexico. Plaintiffs in this lawsuit, filed on October 5, 2001, are surface interest owners of certain property located in Lea County, New Mexico. The plaintiffs allege that aquifers underlying their property and water wells located on their property have been contaminated as a result of spills and leaks from a pipeline running across their property that is or was owned by Tex-New Mex and us. The plaintiffs also allege that oil and gas operations conducted by Amerada Hess Corporation resulted in leaks or spills of pollutants that ultimately contaminated the plaintiffs' aquifers and water wells. Our initial investigation of this matter indicated that the alleged contamination of the aquifers underlying the plaintiffs' property was not caused by leaks from the pipeline now owned by us that traverses the plaintiffs' property. Although no assurance can be made that we will successfully defend this lawsuit, we believe that the ultimate resolution of this lawsuit will not have a materially adverse impact on our financial position or results of operations. Richard D. Warden and Nancy J. Warden v. EOTT Energy Pipeline Limited Partnership and EOTT Energy Corp., Case No. CIV-02-370 L, In the United States District Court for the Western District of Oklahoma. In this lawsuit, filed on February 28, 2002, the plaintiffs are landowners, seeking damages allegedly arising from a release of crude oil from a pipeline owned by us. Although we undertook extensive remediation efforts with respect to the crude oil release that is the subject of this lawsuit, plaintiffs allege that we did not properly remediate the crude oil release and claim causes of action for negligence, gross negligence, unjust enrichment, and nuisance. Due to the early stages of the proceeding it is not possible for us to speculate on the possible outcome of this matter. We believe that the ultimate resolution of this matter, however, will not have a materially adverse impact on our financial position or results of operations. David A. Huettner, et al v. EOTT Energy Partners, L.P., et al,Case No. 1:02 CV-917, In the United States District Court, Northern District of Ohio Eastern Division ("Securities Suit"). This lawsuit was filed on May 15, 2002 for alleged violations of the Securities and Exchange Act of 1934 and common law fraud. The suit was brought by three of our former unit holders who claim that Enron, our General Partner, certain of the officers and directors of Enron and our General Partner and our independent accountants were aware of material misstatements or omissions of information within various press releases, SEC filings and other public statements, and failed to correct the alleged material misstatements or omissions. Plaintiffs maintain that they were misled by our press releases, SEC filings and other public statements when purchasing our common units and were financially damaged thereby. Due to the recent filing of this lawsuit, we have been unable to thoroughly investigate the validity of the Plaintiff's allegations, but based on management's current knowledge, we believe the allegations are without merit. We can provide no assurances regarding the outcome of this lawsuit, but will continue to gather and analyze new information as it becomes available. Environmental. We are subject to extensive federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, and which require expenditures for remediation at various operating facilities and waste disposal sites, as well as expenditures in connection with the construction of new facilities. At the federal level, such laws include, among others, the Clean Air Act ("CAA"), the Clean Water Act, the Oil Pollution Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the National Environmental Policy Act, as each may be amended from time to time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties or the imposition of injunctive relief. We believe that our operations and facilities are in general compliance with applicable environmental regulations. Environmental laws and regulations have changed substantially and rapidly over the last 20 years, and we anticipate that there will be continuing changes. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may 17 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS impact the environment, such as emissions of pollutants, generation and disposal of wastes and use and handling of chemical substances. Increasingly strict environmental restrictions and limitations have increased our operating costs and those of other businesses throughout the United States, and it is possible that the costs of compliance with environmental laws and regulations will continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. Enron received a request for information from the Environmental Protection Agency ("EPA") under Section 308 of the Clean Water Act, requesting information regarding certain spills and releases from oil pipelines owned or operated by Enron and its affiliated companies for the time period July 1, 1998 to July 11, 2001. Because we are the only Enron affiliated entity with domestic crude oil pipeline operated by Enron, Enron responded for itself and on behalf of us to the EPA's request on January 29, 2002. At this time, we are not able to predict the outcome of the response made to the EPA's Section 308 request. In 2001, expenses incurred for spill clean up and remediation costs related to the assets purchased from Tex-New Mex increased significantly. Based on our experience with these assets, we filed an amended cross-claim against Tex-New Mex, as previously discussed, alleging contingent claims for potential remediation issues not yet known to us. We allege that Tex-New Mex failed to report spills, underreported spills, failed to properly respond to leaks in the pipeline and engaged in other activities with regard to the pipeline that may result in future remediation liabilities. We obtained $20 million in insurance coverage in connection with the acquisition from Tex-New Mex believing that amount would be sufficient to cover remediation requirements along the pipeline for a 10-year period. After 3 years into the term of the insurance policy, approximately seventy percent of the policy amount has been utilized. We have accrued current estimates for future remediation costs on all environmental spills or releases through March 31, 2002; however, actual future expenditures may be different than amounts currently anticipated. The presence of MTBE in some water supplies in California and other states due to gasoline leakage from underground and aboveground storage tanks, automobile and tanker truck accidents, pipelines and certain other sources including operation of recreational watercraft on surface waters has led to public concern that MTBE has contaminated drinking water supplies, and thereby resulted in a possible health risk. As a result, in 1999, the Governor of California ordered the ban of the use of MTBE as a gasoline component by the end of 2002. The Governor of California extended the deadline for the ban of the use of MTBE in California to December 31, 2003, based on concerns about the availability and cost of alternatives to MTBE. Heightened public awareness has also resulted in other states, the federal government and the EPA either passing or proposing restrictions on, or banning the use of, MTBE. For example, provisions are included within the federal government's proposed Energy Policy Act of 2002 that would ban the use of MTBE four years post enactment. However, the proposed Energy Policy Act of 2002 also includes provisions that would provide monetary assistance to domestic MTBE producers to be used to defray the costs associated with the transition of current MTBE production facilities into facilities producing MTBE substitutes. In addition, MTBE is being further regulated through drinking water and remediation standards. If the ban in California becomes effective or the proposed federal legislation is enacted, we would expect such ban to materially reduce MTBE demand which could have a material adverse effect on our financial results. If MTBE were to be restricted or banned throughout the United States, we could modify the MTBE Plant to produce other products. We believe that modifying our existing MTBE Plant to produce other gasoline blendstocks such as alkylates would require a substantial capital investment. We can give no assurance that we would have the resources available to effect such a conversion or that such conversion would be economically viable. Further, we cannot predict whether legislation will be passed, whether the federal government will take steps to reverse California's ban on the use of MTBE as a gasoline component, or if the federal government will provide monetary assistance for conversion. 18 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS We may experience future releases of crude oil into the environment or discover releases that were previously unidentified. While an inspection program is maintained on our pipelines to prevent and detect such releases, and operational safeguards and contingency plans are in place for the operation of our processing facilities, damages and liabilities incurred due to any future environmental releases could affect our business. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and that there are no outstanding potential liabilities or claims relating to safety and environmental matters the resolution of which, individually or in the aggregate, would have a materially adverse effect on our financial position or results of operations. Our environmental expenditures include amounts spent on permitting, compliance and response plans, monitoring and spill cleanup and other remediation costs. In addition, we could be required to spend substantial sums to ensure the integrity of our pipeline systems, and in some cases, we may take pipelines out of service if we believe the costs of upgrades will exceed the value of the pipelines. No assurance can be given as to the amount or timing of future expenditures for environmental remediation or compliance, and actual future expenditures may be different from the amounts currently anticipated. In the event of future increases in costs, we may be unable to pass on those increases to our customers. 9. BUSINESS SEGMENT INFORMATION We have four reportable segments, which management reviews when making decisions about resources to be allocated and assessing its performance: North American Crude Oil - East of Rockies, Pipeline Operations, Liquids Operations and West Coast Operations. The North American Crude Oil - East of Rockies segment is organized into five operating regions and primarily engages in energy trading activities including purchasing, gathering, transporting and marketing of crude oil. For segment reporting purposes, these five operating regions have been aggregated as one reportable segment due to similarities in their operations as allowed by SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information". The Pipeline Operations segment operates approximately 7,400 active miles of common carrier pipelines in 12 states. The Liquids Operations includes the MTBE Plant and the Mont Belview Facility. The West Coast Operations include crude oil gathering and marketing, refined products marketing and a natural gas liquids business. Effective June 30, 2001, we sold our West Coast crude oil gathering and marketing operations. Effective June 1, 2002, we sold our West Coast refined products marketing operations. The accounting policies of the segments are the same as those described in the summary of significant accounting policies as discussed in Note 2 included in the our Annual Report on Form 10-K for the year ended December 31, 2001 and Notes 2 and 3 included herein. We evaluate the performance of each operating segment based on operating income (loss). We account for intersegment revenue and transfers between North American Crude Oil - East of Rockies, West Coast Operations and Pipeline Operations as if the sales or transfers were to third parties, that is, at current market prices. Intersegment transportation revenues for Pipeline Operations are based on published pipeline tariffs. 19 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS FINANCIAL INFORMATION BY BUSINESS SEGMENT (In Thousands)

~~PER~~NORTH ~~UNIT~~AMERICAN WEST CORPORATE CRUDE OIL PIPELINE COAST AND - EOR OPERATIONS LIQUIDS (c) OPERATIONS OTHER (b) CONSOLIDATED ---------- ----------- ----------- ~~Basic~~---------- --------- ------------ THREE MONTHS ENDED MARCH 31, 2002 Revenue from external customers $1,137,501 $ 5,968 $ 36,399 $ 29,531 $ -- ~~Common~~$1,209,399 ~~Subordinated~~Intersegment ~~Diluted~~revenue (a)... 13,256 22,339 -- -- (35,595) -- ---------- ---------- ---------- ~~Net~~----------- ~~Income~~--------- ~~Before~~---------- ~~Cumulative~~Total ~~Effect~~ revenue......... $0.~~60 $0~~.~~60 $0~~.60 ~~Cumulative~~1,150,757 ~~Effect~~28,307 of36,399 ~~Accounting~~29,531 ~~Changes~~(35,595) 1,209,399 -~~Adoption~~--------- of---------- ~~SFAS~~---------- ~~No.~~----------- ~~133~~---------- ---------- Gross profit............... 4,603 12,528 3,891 349 -- 21,371 ---------- ---------- ---------- ----------- ---------- ---------- Operating income (loss).. 0.~~05 0~~.05 0250 10,808 3,598 (225) (5,627) 8,804 Other expense, net.05........ -~~Change~~- in-- ~~Inventory~~-- ~~Valuation~~-- ~~Method~~(11,149) (11,149) ---------- ---------- ---------- ----------- ---------- ---------- Net income (loss).......... 250 10,808 3,598 (~~0.01~~225) (~~0.01~~16,776) (02,345) ---------- ---------- ---------- ----------- ---------- ---------- Depreciation and amortization 1,452 5,204 1,260 421 820 9,157 ---------- ---------- ---------- ----------- ---------- ---------- ------------------------------------------------------------------------------------------------------------------ THREE MONTHS ENDED MARCH 31, 2001 Revenue from external customers $2,348,472 $ 8,354 $ -- $ 187,611 $ -- $2,544,437 Intersegment revenue (a).01.. 8,419 23,007 -- 8,418 (39,844) -- ---------- ---------- ---------- ~~Net~~----------- ~~Income~~---------- ---------- Total revenue............ 2,356,891 31,361 -- 196,029 (39,844) 2,544,437 ---------- ---------- ---------- ----------- ---------- ---------- Gross profit............... 8,109 16,367 -- 825 -- 25,301 ---------- ---------- ---------- ----------- ---------- ---------- Operating income (loss).... 4,035 14,734 (13) (6,259) 12,497 Other expense, net......... $0-- -- -- -- (7,228) (7,228) ---------- ---------- ---------- ----------- ---------- ---------- Net income (loss).64......... 4,035 14,734 -- (13) (13,487) 5,269 ---------- ---------- ---------- ----------- ---------- ---------- Depreciation and amortization 1,535 5,501 -- 663 808 8,507 ---------- ---------- ---------- ----------- ---------- ---------- ------------------------------------------------------------------------------------------------------------------- TOTAL ASSETS AT MARCH 31, 2002 $~~0.64~~ 586,921 $~~0.64~~ ~~=====~~285,623 ~~=====~~$ ~~=====~~101,838 $ 44,567 $ 40,381 $1,059,330 ---------- ---------- ---------- ----------- ---------- ---------- TOTAL ASSETS AT DECEMBER 31, 2001 629,199 290,805 85,961 48,091 46,454 1,100,510 ---------- ---------- ---------- ----------- ---------- ----------

(a) Intersegment revenue for North American Crude Oil - EOR and West Coast Operations is at prices comparable to those received from external customers. Intersegment revenue for Pipeline Operations is primarily transportation costs charged to North American Crude Oil - EOR for the transport of crude oil at published pipeline tariffs. (b) Corporate and Other also includes intersegment eliminations. (c) The Liquids Operations were acquired on June 30, 2001. 10. SUBSEQUENT EVENTS On April 2, 2002, a federal bankruptcy judge signed the stipulation and agreed order approving the rejection of the contracts with EGLI. The order became final and non-appealable on April 12, 2002. See further discussion in Note 7. On April 3, 2002, we suspended the first quarter 2002 distribution to unitholders. See further discussion in Notes 6 and 7. 20 EOTT ENERGY PARTNERS, L.P. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS On April 23, 2002, we closed the amended and extended $300 million Credit Facility with Standard Chartered and extended the Inventory Repurchase Agreement and Receivables Agreement. These facilities will be available through the end of February 2003. See further discussion in Note 6. Effective June 1, 2002, we sold our West Coast refined products marketing operations to Trammo Petroleum, Inc. The sales price was not significant. 21 EOTT ENERGY PARTNERS, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. INFORMATION REGARDING FORWARD-LOOKING INFORMATION The statements in this Quarterly Report on Form 10-Q that are not historical information are 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. Such forward-looking statements include the discussions in "Management's Discussion and Analysis of Financial Condition and Results of Operations." Any forward-looking statements are not guarantees of future performance and involve significant risks and uncertainties, and actual results may vary materially from those in the forward-looking statements as a result of various factors. See in this section, "Recent Events Concerning the Impact of the Bankruptcy of Enron and Certain of Its Subsidiaries, and Related Events," and "Liquidity and Capital Resources," for statements regarding important factors that could cause actual results to differ materially from those in the forward-looking statements herein. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that these are all the factors that could cause actual results to vary materially or that our expectations regarding future developments will prove to be correct. RECENT EVENTS CONCERNING THE IMPACT OF THE BANKRUPTCY OF ENRON AND CERTAIN OF ITS SUBSIDIARIES, AND RELATED EVENTS We are managed by our general partner, EOTT Energy Corp. (the "General Partner"), which is a wholly owned subsidiary of Enron Corp. ("Enron"). Beginning on December 2, 2001, Enron and certain subsidiaries of Enron filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code with the United States Bankruptcy Court for the Southern District of New York (the "Bankruptcy Court"). Neither our General Partner nor we are included in the bankruptcy. However, because of our contractual relationships with Enron and certain of its subsidiaries at the time of the filing of the bankruptcy petition, the bankruptcy has impacted us in various ways, discussed below and in our Annual Report on Form 10-K for the year ending December 31, 2001. Rejection of Certain Agreements with Enron's Subsidiary We have also been impacted as a result of the inclusion of Enron Gas Liquids, Inc. ("EGLI"), a wholly owned subsidiary of Enron, in Enron's bankruptcy. We had in place ten-year toll conversion and storage agreements (the "Toll Conversion and Storage Agreements") with EGLI. On April 2, 2002, the Bankruptcy Court entered a Stipulation and Agreed Order rejecting the Toll Conversion and Storage Agreements (the "Stipulation"), which became final and non-appealable on April 12, 2002. As a result of EGLI's non-performance under these agreements, we incurred a non-cash impairment of approximately $29.1 million in the fourth quarter of 2001 for the write-down of our Toll Conversion and Storage Agreements. Additionally, we have monetary damage claims against EGLI and Enron as a result of the rejection of the agreements under the Stipulation, which damage claims have been filed in the Bankruptcy Court. On May 12, 2002, we filed claims for rejection damages in excess of $500 million with the Bankruptcy Court. The final amount of our claim resulting from the rejection of the two agreements has not yet been fully determined. Performance Collateral from Enron Enron guaranteed payments under the Toll Conversion and Storage Agreements, however, such guaranty was limited to $50 million under the Toll Conversion Agreement and $25 million under the Storage Agreement. We have made appropriate claims under such guaranty in the Enron bankruptcy proceeding. We, however, cannot predict the amounts that we will collect or the timing of collection, if any. In addition, EGLI 22 EOTT ENERGY PARTNERS, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS owed us approximately $9 million under the Toll Conversion and Storage Agreements prior to filing for bankruptcy. Pursuant to these agreements, on November 27, 2001, we requested that EGLI post two $25 million letters of credit. In lieu of posting letters of credit, we received a $25 million deposit/performance collateral from EGLI/Enron, against which we recouped the $9 million of outstanding invoices. We currently intend to apply the remaining sum, approximately $16 million, to recoup or offset a portion of our damages as a result of EGLI's rejection of the Toll Conversion and Storage Agreements. We also have outstanding accounts payable to EGLI in the amount of approximately $2 million for butane and methanol feedstock we acquired prior to EGLI filing for bankruptcy. We are exploring the possibility of offsetting this $2 million payable against a portion of the damages resulting from EGLI's rejection of the Toll Conversion and Storage Agreements. We are uncertain, however, as to how these issues will be resolved. Tax and Environmental Indemnities We might also incur unexpected losses in the event that Enron fails to indemnify us for certain ad valorem taxes and possible environmental expenditures relating to our hydrocarbon processing facility (the "MTBE Plant") and our liquids storage facility (the "Mont Belvieu Facility"). Cost and Availability of Credit As a result of Enron's bankruptcy, we have incurred higher costs in obtaining credit than we have in the past. In addition our trade creditors have been less willing to extend credit to us on an unsecured basis and the amount of letters of credit we have been required to post for our marketing activities has increased significantly. See "Liquidity and Capital Resources" below. Distributions to Our Common Unitholders On April 3, 2002, we announced that we would not make a distribution to our common unitholders for the first quarter of 2002. Under our amended credit facility, effective April 23, 2002 with Standard Chartered Bank ("Standard Chartered"), we are not permitted to make distributions unless certain conditions are met. See "Liquidity and Capital Resources" below. Claims Against Enron's Bankruptcy Estate We have several potential claims against Enron's bankruptcy estate and have retained outside counsel to evaluate such claims. See Note 7 to the Condensed Consolidated Financial Statements. These claims will likely be deemed to be unsecured claims against certain of the Enron related chapter 11 companies. We have also filed a claim for rejection damages in excess of $500 million against Enron and certain of its subsidiaries in Enron's bankruptcy proceedings. We are uncertain regarding the ultimate amount of damages for breach of contract or other claims that we will be able to establish in the bankruptcy proceeding and we cannot predict the amounts, if any, that we will collect or the timing of such collection. Board of Directors of Our General Partner On April 10, 2002, three independent directors joined the board of directors of our General Partner, allowing the General Partner to reconstitute its audit committee (the "Audit Committee"). The General Partner of the MLP restructured its board of directors to reduce the number of directors from seven to five, such that independent directors now constitute a majority of our board of directors. Nevertheless, Enron, as the sole shareholder of our General Partner, may elect and remove directors. In addition to the board restructure, our General Partner created a restructuring committee (the "Restructuring Committee"). The Restructuring Committee has powers and authority of the board of directors with respect to any restructuring transactions 23 EOTT ENERGY PARTNERS, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS concerning the General Partner or the MLP or any of its affiliates. Any proposed agreement or action involving a potential conflict, however, must first be submitted to the audit committee and the audit committee must determine that the proposed agreement or transaction is fair and reasonable to us or our General Partner, as the case may be. Our General Partner's Operation and General Administration of the Partnership We have liabilities of approximately $40.2 million to Enron and its affiliates as of March 31, 2002, including the General Partner, under various agreements. We are exploring possibilities of recouping and/or seeking offset against certain of our claims in the bankruptcy proceeding against our liabilities to Enron and its affiliates, including the General Partner. At this point, however, it is uncertain how these issues will be resolved. See Note 7 to our Condensed Consolidated Financial Statements. Delay in Filing Periodic Reports/Unaudited Annual Financial Statements Because of the withdrawal of our former independent accountants, Arthur Andersen LLP, on February 5, 2002, the time necessary to select PricewaterhouseCoopers ("PWC") as our new independent accountants, and the time required for completion of our audit for 2001, we filed a "Notification of Late Filing" on Form 12B-25 with the U.S. Securities and Exchange Commission ("SEC") on April 2, 2002, disclosing that we were unable to timely file our Form 10-K Annual Report for the period ending December 31, 2001 ("Form 10-K"). We subsequently filed our Form 10-K on May 31, 2002. As disclosed in a "Notification of Late Filing" on Form 12B-25 filed with the SEC on March 16, 2002, due to the delay in filing our Form 10-K we were unable to timely file this Quarterly Report on Form 10-Q for the period ending March 31, 2002. In addition, as more fully disclosed in the Form 10-K, financial statements included in the Form 10-K for the years 1999 and 2000 were unaudited. OVERVIEW Through our four operating limited partnerships, EOTT Energy Operating Limited Partnership, EOTT Energy Canada Limited Partnership, EOTT Energy Pipeline Limited Partnership, and EOTT Energy Liquids, L.P., we purchase, gather, transport, store, process and resell crude oil, refined petroleum products, natural gas liquids and other related products. Our principal business segments are our North American Crude Oil - East of Rockies, our Pipeline Operations, our Liquids Operations, and our West Coast Operations. See Note 9 to our Condensed Consolidated Financial Statements for certain financial information by business segment. Gathering, Marketing and Trading Operations Gross profit from gathering, marketing and trading operations varies from period-to-period, depending, to a significant extent, upon changes in the supply and demand of crude oil and the resulting changes in United States crude oil inventory levels. The gross profit from gathering and marketing operations is generated by the difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale, minus the associated costs of gathering and transportation, field operating costs and depreciation and amortization. In addition to purchasing crude oil at the wellhead, we purchase crude oil in bulk at major pipeline terminal points and major marketing points and enter into exchange transactions with third parties. These bulk and exchange transactions are characterized by large volume and narrow profit margins on purchase and sale transactions, and the absolute price levels for crude oil do not necessarily bear a relationship to gross profit, although such price levels significantly impact revenues and cost of sales. Because period-to-period variations in revenues and cost of sales are not generally meaningful in analyzing the variation in gross profit for gathering and marketing operations, such changes are not addressed in the following discussion. 24 EOTT ENERGY PARTNERS, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Our operating results are sensitive to a number of factors including: grades or types of crude oil, variability in lease crude oil barrels produced, individual refinery demand for specific grades of crude oil, area market price structures for the different grades of crude oil, location of customers, availability of transportation facilities, and timing and costs (including storage) involved in delivering crude oil to the appropriate customer. In general, as we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, or by entering into future delivery obligations with respect to futures contracts on the New York Mercantile Exchange ("NYMEX"), thereby minimizing or reducing exposure to price fluctuations. Through these transactions, we seek to maintain positions that are substantially balanced between crude oil purchases and sales or future delivery obligations. However, depending on market conditions, positions may be taken subject to established price risk management position limits. As a result, changes in the absolute price level for crude oil do not necessarily impact the margin from gathering and marketing. Throughout the marketing process, we seek to maintain a substantially balanced risk position at all times. We do have certain risks that cannot be completely hedged, such as a portion of certain basis risks. Basis risk arises when crude oil is acquired by a purchase or exchange that does not meet the specifications of the crude oil we are contractually obligated to deliver, whether in terms of geographic location, grade or delivery schedule. In accordance with our risk management policy, we seek to limit price risk and maintain margins through a combination of physical sales, NYMEX hedging activities and exchanges of crude oil with third parties. We operate the business differently as market conditions change. During periods when the demand for crude oil is weak, the market for crude oil is often in "contango," meaning that the price of crude oil in a given month is less than the price of crude oil in a subsequent month. In a contango market, storing crude oil is favorable, because storage owners at major trading locations can simultaneously purchase production at low current prices for storage and sell at higher prices for future delivery. When there is a higher demand than supply of crude oil in the near term, the market is "backwardated," meaning that the price of crude oil in a given month exceeds the price of crude oil in a subsequent month. A backwardated market has a positive impact on marketing margins because crude oil gatherers can capture a premium for prompt deliveries. Pipeline Operations Pipeline revenues and gross profit are primarily a function of the level of throughput and storage activity and are generated by the difference between the regulated published tariff and the fixed and variable costs of operating the pipeline. Transporting crude oil at published pipeline tariffs for our North American Crude Oil - East of Rockies business segment, generates a majority of our pipeline revenues. Approximately 79% of the revenues of our Pipeline Operations business segment for the three months ended March 31, 2002 were generated from tariffs charged to our North American Crude Oil - East of Rockies business segment and sales of crude oil inventory to our North American Crude Oil - East of Rockies business segment. Changes in revenues and pipeline operating costs, therefore, are relevant to the analysis of financial results of the Pipeline Operations business segment and are addressed in the following discussions of the Pipeline Operations business segment. Liquids Operations, Toll Conversion and Storage Agreements Gross profit for our Liquids Operations prior to Enron's bankruptcy included the processing fee for converting feedstocks into products at the MTBE Plant; storage and transportation fees related to our Mont Belvieu Facility; the fixed and variable costs of operating these facilities; and the depreciation and 25 EOTT ENERGY PARTNERS, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS amortization related to these facilities. Revenues from the processing operations were based upon a fixed fee received for certain minimum quantities of product converted on a take-or-pay basis. Revenues from the storage and transportation operations were based upon a fixed rate for certain minimum capacity levels and actual volumes stored and transported at the liquids storage facility. Subsequent to the filing of EGLI's bankruptcy, we began conducting commercial supply and marketing activities of the MTBE Plant. Under a merchant operation, gross profit from the Liquids Operations includes the difference between the purchase price of feedstocks and the price of MTBE at the point of sale minus any transportation costs, fixed and variable costs of operating these facilities and the depreciation and amortization related to these facilities. Until the Storage Agreement was rejected by EGLI and approved by the Bankruptcy Court on April 2, 2002, we were unable to market the storage facility or enter into third party spot or term contracts. As a result, we could only charge an administrative fee to EGLI until the contract was rejected under the stipulation, which became final and non-appealable on April 12, 2002. ACQUISITIONS AND DISPOSITIONS In June 2001, we purchased certain liquids processing, storage and transportation assets located in the Texas Gulf Coast region through our wholly owned subsidiary, EOTT Energy Liquids, L.P. and concurrently entered into ten year Toll Conversion and Storage Agreements. We paid $117 million in cash to Enron and State Street Bank and Trust Company of Connecticut, National Association, Trustee. The assets held by the Trustee were held under a lease financing arrangement with Enron. Immediately prior to the acquisition, all of the assets were operated by EGP Fuels Company, a wholly owned subsidiary of Enron. Effective June 30, 2001, we sold our West Coast crude oil gathering and blending operations to Pacific Marketing and Transportation LLC ("Pacific") for $14.3 million. We could be required to repay up to $1.5 million of the sale price, subject to a two-year look-back provision regarding average operating results during the period July 1, 2001 through June 30, 2003. Such amount is reflected in Other Long-Term Liabilities in the Consolidated Balance Sheet. Effective June 1, 2002, we sold our West Coast refined products marketing operations to Trammo Petroleum, Inc. The sales price was not significant. RESULTS OF OPERATIONS We reported a net loss of $2.3 million or $0.08 per diluted unit for the first quarter of 2002 compared to net income of $6.3 million or $0.23 per diluted unit for the first quarter of 2001. We adopted Statement of Financial Accounting Standards ("SFAS") No. 133, as amended, and changed the method of valuing inventory used in our energy trading activities from average cost to fair value effective January 1, 2001 (see Notes 2 and 3 to the Condensed Consolidated Financial Statements). The net cumulative effect of adopting these accounting changes was $1.1 million and is reflected as an increase in net income in the Condensed Consolidated Statement of Operations. The decrease in net income, excluding the cumulative effect of the accounting changes, compared to the same period in 2001 is due to: strong crude oil market conditions in the first quarter of 2001; a reduction in our marketing activities and in lease volumes purchased in the first quarter of 2002 in the North American Crude Oil-East of Rockies business segment; lower volumes transported in our Pipeline Operations; and higher financing costs in 2002. The reduction in marketing activities and lease volumes purchased reflects the loss of certain lease and spot barrels as a result of increased requests for credit from our suppliers due primarily to the Enron 26 EOTT ENERGY PARTNERS, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS bankruptcy. The increase in financing costs is due to the financing of the Liquids Operations acquisition in June 2001 and higher letter of credit costs and facility costs under the new credit facility with Standard Chartered. The factors decreasing net income were partially offset by operating income from the Liquids Operations acquired in June 2001, lower employee related costs and lower repairs and maintenance costs in our fleet operations in our North American Crude Oil-East of Rockies business segment and the settlement of an insurance claim. 27 EOTT ENERGY PARTNERS, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Selected financial data for EOTT's business segments are summarized below, in millions:

~~PRO~~THREE ~~FORMA FOR THE NINE~~ MONTHS ENDED ~~SEPTEMBER~~MARCH 3031, --------------------- 2002 2001 ---------- ~~2001~~--------- ~~2000~~Revenues: North American Crude Oil -- East of Rockies........ $ 1,150.8 $ 2,356.9 Pipeline Operations................................ 28.3 31.4 West Coast Operations.............................. 29.5 196.0 Liquids Operations................................. 36.4 -- Corporate and Other................................ -- -- Intersegment eliminations.......................... (35.6) (39.9) -- ------- -------- ~~Revenue~~ Total............................................. $7 1,~~223,911~~209.4 $82,~~501,161~~544.4 ========= ======== Gross ~~Margin~~profit: North American Crude Oil -- East of Rockies (1)... $ 4.6 $ 8.1 Pipeline Operations................................ 12.5 16.4 West Coast Operations.............................. 0.4 0.8 Liquids Operations................................. 3.9 -- Corporate and Other................................ -- -- --------- -------- Total............................................. $ ~~192,314~~21.4 $ ~~194,143~~25.3 ~~Net~~========= ~~Income~~======== Operating income (loss): North American Crude Oil -- East of Rockies (1)... $ 0.2 $ 4.0 Pipeline Operations................................ $10.8 14~~,975~~.7 $West ~~16,734~~Coast ~~Diluted~~Operations.............................. ~~Net~~(0.2) ~~Income~~-- ~~per~~Liquids ~~Unit~~Operations................................. 3.6 -- Corporate and Other................................ (5.6) (6.2) --------- -------- Total............................................. $ 08.538 $ 012.605 ========= ========

(1) Includes intersegment transportation costs from the Pipeline Operations segment for the transport of crude oil at published pipeline tariffs and purchases of crude oil inventory from the Pipeline Operations segment. Intersegment costs from the Pipeline Operations were $22.3 million and $23.0 million for the three months ended March 31, 2002 and 2001, respectively. THREE MONTHS ENDED MARCH 31, 2002 COMPARED WITH THREE MONTHS ENDED MARCH 31, 2001. North American Crude Oil - East of Rockies: The North American Crude Oil - East of Rockies segment had operating income of $0.2 million for the first quarter of 2002 compared to operating income of $4.0 million for the same period in 2001. Gross profit decreased $3.5 million from $8.1 million in the first quarter of 2001 to $4.6 million in the first quarter of 2002 due primarily to the strong crude oil market conditions in the first quarter of 2001 and reductions in our marketing activities and lease volumes purchased in the first quarter of 2002 due to increased requests for credit from our suppliers primarily as a result of the Enron bankruptcy. These decreases were offset by reductions in employee related costs and lower repairs and maintenance costs for our fleet operations. Intersegment costs charged by our Pipeline Operations segment were $22.3 million and $23.0 million for the three months ended March 31, 2002 and 2001, respectively. Crude oil lease volumes averaged 308,800 barrels per day for the three months ended March 31, 2002 compared to an average of 377,700 barrels per day for the three months ended March 31, 2001. The decline in 28 EOTT ENERGY PARTNERS, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS lease volumes is attributable to the elimination of certain low margin crude oil lease volumes in the first half of 2001 and the loss of lease volumes resulting from increased requests for credit from our suppliers starting in late 2001 as a result of the Enron bankruptcy. Pipeline Operations: Operating income from our Pipeline Operations declined $3.9 million to $10.8 million for the first quarter of 2002 compared to $14.7 million for the same period in 2001. Revenues for the first quarter of 2002 decreased $3.1 million from $31.4 million in the first quarter of 2001 to $28.3 million in the first quarter of 2002 due primarily to a decline of volumes being transported on our West Texas and New Mexico pipeline systems. Pipeline volumes averaged 439,500 barrels per day for the three months ended March 31, 2002 as compared to 531,300 barrels per day for the same period in 2001. The decline in volumes is primarily attributable to lower volumes being transported for the North American Crude Oil-East of Rockies business segment discussed above. Approximately $22.3 million and $23.0 million of revenues for the three months ended March 31, 2002 and 2001, respectively, were generated primarily from tariffs charged to the North American Crude Oil - East of Rockies segment and sales of crude oil inventory to our North American Crude Oil segment. Operating expenses including depreciation and amortization, of $15.5 million for the first quarter of 2002 were higher compared to the first quarter of 2001 due to higher employee expenses and environmental costs offset by lower amortization costs. Liquids Operations. Our Liquids Operations had operating income of $3.6 million and gross profit of $3.9 million for the first quarter of 2002. In the first quarter of 2002, the MTBE Plant was taken out of service for approximately one month due to the scheduled turnaround of the MTBE Plant. During the scheduled turnaround of the MTBE Plant, we did not generate any revenues to cover our fixed operating expenses of the facility; however, the margins (difference between the costs of feedstocks and the sales price of MTBE, less any transportation costs) during the remainder of the quarter were higher than historically at this time of year. Generally, margins related to MTBE will be higher during the spring and summer, when the demand for reformulated gasoline is higher. MTBE equivalent sales volumes from the MTBE Plant averaged 10,176 barrels per day in the first quarter of 2002, and were lower than normal due to the turnaround. Until the Storage Agreement was rejected by EGLI in April 2002, we could only charge an administrative fee to EGLI of approximately $0.5 million per month related to the Storage Agreement for the first quarter of 2002. West Coast Operations: West Coast Operations had an operating loss of $0.2 million for the first quarter of 2002, compared to break even for the same period in 2001 primarily due to the sale of the crude oil operations in June 2001. Corporate and Other: Corporate and Other costs were $5.6 million for the first quarter of 2002 compared to $6.2 million in the first quarter of 2001. The decrease is due primarily to settlement of an insurance claim for $1.1 million offset by higher legal and accounting costs due to the change in auditors and attorneys as well as higher insurance costs. Interest and related charges, net in the first quarter 2002 were $11.2 million compared to $6.9 million for the same period in 2001. The increase is due primarily to higher average short-term debt required to finance crude oil stored as a result of market being in contango, the financing of the Liquids assets acquired in June 2001, and higher letters of credit costs and facility fees under the new credit facility. 29 EOTT ENERGY PARTNERS, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS LIQUIDITY AND CAPITAL RESOURCES General We anticipate that our cash requirements, including sustaining capital expenditures for the foreseeable future, will be funded primarily by cash generated from operations. Additionally, we anticipate that short-term liquidity and working capital requirements will be supported by our credit facility, inventory repurchase agreement and receivables agreement, as amended and extended in April 2002. The bankruptcy of Enron and certain of its subsidiaries has had a significant impact on our financing alternatives. For further detail, see "Working Capital and Credit Resources" below. Cash Flows From Operating Activities Net cash provided by operating activities totaled $12.1 million for the first three months of 2002 compared to net cash used of $66.7 million for the same period in 2001. Cash provided from operations in the first quarter of 2002 reflects increased interest payable as well as reduced deposit requirements in connection with futures and derivative activities. Cash used in operations in the first quarter of 2001 reflects an increase in inventory due to crude oil being stored as a result of market conditions shifting from backwardation to contango in March 2001, combined with a reduction in receivables sold during the period. Such transfers of receivables no longer qualify as sales transactions and are now accounted for as components of cash flows from financing activities. Cash Flows From Investing Activities Net cash used in investing activities totaled $17.2 million for the first three months of 2002 compared to $3.2 million for the same period in 2001. Cash additions to property, plant, and equipment of $17.3 million in 2002 primarily include $8.6 million related to expansion capital projects and $6.3 million related to the turnaround of the MTBE Plant. Proceeds from asset sales were $0.1 million in the first three months of 2002 compared to $1.1 million in the first three months of 2001. Cash Flows From Financing Activities Net cash provided by financing activities totaled $2.8 million for the first three months of 2002 compared to $19.2 million for the same period in 2001. The 2002 amount primarily reflects an increase in receivables financed, offset by distributions to unitholders. The 2001 amount reflects an increase in repurchase agreement borrowings offset by distributions to unitholders. The decline in distributions to unitholders from $10.8 million in the first quarter of 2001 to $4.7 million in the first quarter of 2002 reflects a quarterly distribution of $0.475 per unit paid for the fourth quarter of 2000 compared to $0.25 per unit paid for the fourth quarter of 2001, along with the decision not to pay distributions to the subordinated unitholders for the fourth quarter of 2001. Working Capital and Credit Resources EOTT has agreements with Standard Chartered Bank ("Standard Chartered") and Standard Chartered Trade Services ("SCTS") which provide up to an aggregate of $500 million of working capital loans letters of credit, receivables financing and commodity repurchase funding comprised of the following: (i) Up to $300 million of letter of credit and working capital financing ("Credit Facility") with a working capital loan sublimit of $40 million; (ii) Up to $100 million of receivables financing under a receivables purchasing agreement ("Receivables Agreement") with SCTS; and 30 EOTT ENERGY PARTNERS, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (iii) Up to $100 million of commodity repurchase financing under a commodity repurchase agreement ("Inventory Repurchase Agreement") with SCTS. On April 23, 2002, we amended and extended these agreements with Standard Chartered and SCTS to February 2003. An arrangement fee of 2% is charged on the Credit Facility, Inventory Repurchase Agreement and Receivables Agreement. The Credit Facility is subject to defined borrowing base limitations. The borrowing base is the sum of cash and equivalents, specified percentages of eligible receivables, inventory, products contracted for or delivered but not billed and a specified percentage of eligible fixed assets. Letter of credit fees are up to 3% per annum. The commitment fee is 0.5% per annum of the unused portion of the Credit Facility. We may elect that loans under the Credit Facility bear interest at a rate per annum equal to the alternative base rate, as defined in the amended Credit Facility, or LIBOR plus 3%. The alternative base rate is defined in the amended Credit Facility to mean 3% per annum plus the higher of (a) the annual rate of interest announced from time to time by Standard Chartered Bank as its base rate or (b) 1/2 of 1% above the overnight Federal Funds rate, as published by the Federal Reserve Bank of New York. The Credit Facility includes covenants and restrictions primarily related to distributions to unitholders, amount of permitted expansion capital and specified quarterly amounts for earnings before interest, depreciation and amortization, net income and tangible net worth. Distributions to unitholders will not be permitted under the Credit Facility until all of the following occur: (i) we permanently reduce our aggregate obligations to Standard Chartered and SCTS to an amount not exceeding $300 million; (ii) our consolidated net worth is $10 million greater than our consolidated net worth as of January 31, 2002, excluding any non-cash asset write-downs incurred after January 31, 2002; and (iii) we resolve certain claims (trade and other payables) of Enron and its affiliates against us related to Enron's bankruptcy proceedings. See Note 7. At March 31, 2002 and December 31, 2001, we had $243.5 million and $196.1 million, respectively, in letters of credit outstanding under the Credit Facility. At March 31, 2002, we had an outstanding repurchase amount of $100 million. Pursuant to the Inventory Repurchase Agreement, which had terms of thirty-one days, we repurchased the crude oil inventory on April 25, 2002 for approximately $100.4 million. At December 31, 2001, we had outstanding repurchase agreements of approximately $100 million. As of March 31, 2002 and December 31, 2001, $50.0 million and $42.5 million, respectively, of receivables had been transferred under the Receivables Agreement. In the first quarter of 2001, we accounted for these transactions as a sale under the provisions of SFAS No. 125. These transactions did not qualify as sales under SFAS No. 140 and therefore are accounted for as financings at March 31, 2002 and December 31, 2001. We believed that the Credit Facility, Inventory Repurchase Agreement and Receivables Agreement would have been sufficient to support our purchasing activities and working capital and liquidity requirements prior to the Enron bankruptcy. However, as a result of Enron's bankruptcy, some of our trade creditors have been less willing to extend credit to us on an unsecured basis and the amount of letters of credit we have been required to post increased from $196.1 million at December 31, 2001 to $243.5 million at March 31, 2002. Subsequent to year-end, due to the impacts of the Enron bankruptcy as well as the rise in crude oil prices, we have had to reduce our marketing activities due to the availability of credit support under the Credit Facility. 31 EOTT ENERGY PARTNERS, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Our ability to obtain letters of credit to support our purchases of crude oil or other petroleum products is fundamental to our gathering and marketing activities. Additionally, we have a significant need for working capital due to the large dollar volume of marketing transactions. We can give no assurance that we will not be required to further reduce or restrict our gathering and marketing activities because of limitations on our ability to obtain credit support and financing for our working capital needs. Any significant decrease in our financial strength, regardless of the reason for such decrease, may also increase the number of transactions requiring letters of credit or other financial support, may make it more difficult for us to obtain such letters of credit, and/or may increase the cost of obtaining them. This could in turn adversely affect our ability to maintain or increase our level of purchasing and marketing activities or otherwise adversely affect our profitability and Available Cash as defined in the MLP's Partnership Agreement and amendments thereto, and thus, our ability to meet the conditions necessary to make distributions. Under the Partnership Agreement, it is intended that we distribute 100% of our Available Cash within 45 days after the end of each quarter to unitholders of record and to the General Partner. Available Cash consists generally of all of the cash receipts of the Partnership adjusted for its cash disbursements and net changes to reserves. The full definition of Available Cash is set forth in the Partnership Agreement and amendments thereto, which have been filed as exhibits with the SEC. From Available Cash, we are required to make a minimum quarterly distribution ("MQD") to the General Partner and the holders of our common units. The MQD is currently measured at $0.475 per common unit, distributed 98.02% to the holders of our common units and 1.98% to our General Partner. If we fail to make the entire minimum distribution in any quarter, the part of distribution not made is accounted for as an "arrearage." If, in any quarter, we have Available Cash in excess of the MQD, we are required to make the MQD and then repay the arrearage to holders of our common units, before making a distribution to the holders of the subordinated units or the Additional Partnership Interests ("APIs"). Under a Support Agreement with Enron, Enron committed to provide total cash distribution support in an amount necessary to pay MQDs, with respect to quarters ending on or before December 31, 2001, in an amount up to an aggregate of $29 million in exchange for APIs. The distribution for the fourth quarter of 2001 of $0.25 per common unit was lower than the MQD amount of $0.475 per common unit. Enron did not pay the fourth quarter distribution shortfall of $0.225 per common unit. We expect to make a claim for the distribution support amount of $4.2 million through the bankruptcy proceedings. See further discussion in Note 7 to the Consolidated Financial Statements. On April 3, 2002, we suspended the distribution to limited partners for the first quarter of 2002. As previously discussed, under the Credit Facility, there are restrictions on the ability to pay distributions to our limited partners. We do not expect to make any distributions to our unitholders prior to the fourth quarter of 2002. OTHER MATTERS CRITICAL ACCOUNTING POLICIES AND ESTIMATES The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") 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 actual revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from those estimates. Our significant accounting policies are summarized in Note 2 to the Consolidated Financial Statements included in 32 EOTT ENERGY PARTNERS, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS our Annual Report on Form 10-K for the year ended December 31, 2001. The critical accounting policies that we have identified are discussed below. Revenue and Expenses We routinely make accruals for both revenues and expenses due to the timing of receiving information from third parties, reconciling our records with those of third parties, claims that have been incurred but not processed and costs that accrue over time under benefit and incentive plans. In addition, substantially all of our crude oil and refined products gathering, marketing and trading operations are marked to fair value pursuant to Emerging Issues Task Force ("EITF") Issue 98-10 or SFAS No. 133. Certain estimates were made in determining the fair value of contracts and inventory. We have determined these estimates using available market data and valuation methodologies. We believe our estimates for these items are reasonable, but there is no assurance that actual amounts will not vary from estimated amounts. Depreciation and Amortization We calculate our depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are put into service, we make estimates with respect to useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. Impairment of Assets We evaluate impairment of our long-lived assets in accordance with SFAS No. 121, and effective January 1, 2002 with SFAS No. 144, and would recognize an impairment when estimated future cash flows associated with an asset or group of assets are less than the asset carrying amount. Certain assets included in PP&E, primarily pipelines, and the MTBE Plant are subject to factors which could affect future cash flows. These factors include competition, regulation, environmental matters, consolidation in the industry, refinery demand for specific grades of crude oil, area market price structures and continued development drilling in certain areas of the United States. We continuously monitor these factors and pursue alternative strategies to maintain or enhance cash flows associated with these assets; however, no assurances can be given that we can mitigate the effects, if any, on future cash flows related to any changes in these factors. Contingencies We accrue reserves for contingent liabilities, which include environmental remediation and potential legal claims. A loss contingency is accrued when our assessment indicates that it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Our estimates are based upon currently available facts, existing technology and presently enacted laws and regulations. These estimated liabilities are subject to revision in future periods based on actual costs or new information. NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142, which must be applied to fiscal years beginning after December 15, 2001, modifies the accounting and reporting of goodwill and intangible assets. The pronouncement requires entities to discontinue the amortization of goodwill, reallocate all existing goodwill among its reporting segments based on criteria set by SFAS No. 142 and perform initial impairment tests by applying a fair value-based analysis on the goodwill in each reporting 33 EOTT ENERGY PARTNERS, L.P. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS segment. Any impairment at the initial adoption date shall be recognized as the effect of a change in accounting principle. Subsequent to the initial adoption, goodwill shall be tested for impairment annually or more frequently if circumstances indicate a possible impairment. Under SFAS No. 142, entities are required to determine the useful life of other intangible assets and amortize the value over the useful life. If the useful life is determined to be indefinite, no amortization will be recorded. For intangible assets recognized prior to the adoption of SFAS No. 142, the useful life should be reassessed. Other intangible assets are required to be tested for impairment in a manner similar to goodwill. While we do not expect the adoption of SFAS No. 142 to result in an impairment of recorded goodwill, we have not yet completed our initial impairment tests. At March 31, 2002, we have $7.4 million of net goodwill in Other Assets. In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, a corresponding increase in the carrying amount of the related long-lived asset would be recorded. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss on settlement. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. We are currently evaluating the effect on our financial statements of adopting SFAS No. 143 and plan to adopt the statement effective January 1, 2003. In August 2001, the FASB issued SFAS No. 144, "Accounting for Impairment on Disposal of Long-Lived Assets." This statement clarified the financial accounting and reporting for the impairment or disposal of long-lived assets. Impairment is required to be recognized if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows. The impairment loss to be recognized is the difference between the carrying amount and the fair value of the asset. The standard also provides guidance on the accounting for the long-lived assets that are held for disposal. This standard was effective for the Partnership beginning January 1, 2002. The adoption of SFAS No. 144 had no effect on our financial statements. In April 2002, the FASB issued SFAS No. 145, "Recission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections." Certain provisions of SFAS No. 145 are effective for transactions occurring after or financial statements issued after May 15, 2002. The adoption of SFAS No. 145 had no effect on our financial statements. 34 EOTT ENERGY PARTNERS, L.P. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7a in our Annual Report on Form 10-K for the year ended December 31, 2001, in addition to the interim condensed consolidated financial statements and accompanying notes presented in Part I, Items 1 and 2 of this Form 10-Q. There are no material changes in interest rate or foreign currency exchange rate risks faced by the Partnership from those reported in our Annual Report on Form 10-K for the year ended December 31, 2001. COMMODITY PRICE RISK We have performed a value at risk analysis of our financial derivative commodity instruments. Value at risk incorporates numerous variables that could impact the fair value of our investments, including commodity prices, as well as correlation within and across these variables. We estimate value at risk commodity exposures using a model based on Monte Carlo simulation of delta/gamma positions, which captures a significant portion of the exposure related to open futures contracts. The value at risk method utilizes a one-day holding period and a 95% confidence level. Cross-commodity correlations are used as appropriate. The use of the value at risk model allows management to aggregate risks across our operations, compare risk on a consistent basis and identify the drivers of risk. The following table illustrates the value at risk for commodity price risk (in millions): March 31, December 31, 2002 2001 --------- ------------ Commodity price (1)........... $ 0.1 $ 1.3 (1) The above value at risk amount represents financial derivative commodity instruments, primarily commodity futures contracts, entered into to hedge future physical crude oil purchase commitments. The commitments to purchase physical crude oil have not been included in the above value at risk computation. (2) At March 31, 2002, we had crude oil future contracts to purchase 3.7 million barrels of crude oil and to sell 3.7 million barrels of crude oil, with the majority of these contracts maturing in the second quarter of 2002. At December 31, 2001, we had crude oil future contracts to purchase 2.6 million barrels of crude oil and to sell 3.8 million barrels of crude oil, with the majority of these contracts maturing in the first quarter of 2002. ENERGY TRADING AND DERIVATIVE TRANSACTIONS ACCOUNTED FOR AT FAIR VALUE Generally as we purchase crude oil, we enter into corresponding sales transactions involving physical delivery of crude oil to third party users or corresponding sales transactions on the NYMEX. This process enables us to minimize our exposure to price risk until we take physical delivery of the crude oil. Substantially all of our crude oil and refined products marketing and trading operations are accounted for on a fair value basis pursuant to SFAS No. 133 or Emerging Issues Task Force Issue 98-10. In addition, we account for inventories used in our energy trading activities at fair value. 35 EOTT ENERGY PARTNERS, L.P. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The following table indicates fair values and changes in fair value for the quarter ended March 31, 2002 (in thousands): Fair value of contracts at January 1, 2002 $ (5,597) Change in realized and unrealized value 625 Fair value of new contracts entered into during 2002 (10,128) -------- Fair value of contracts at March 31, 2002 $(15,100) ========

*Approximately $13.0 million of the fair value loss at March 31, 2002 relates to physical sales transactions or sales transactions on the NYMEX entered into to hedge physical inventory. The fair value of inventory is not included in the table above. FAIR VALUE OF CONTRACTS AT MARCH 31, 2002

~~NORTH~~Maturity ~~AMERICAN~~greater ~~CORPORATE~~than ~~CRUDE~~Maturity ~~OIL~~of ~~PIPELINE~~90 ~~WEST~~90 ~~COAST~~days ~~LIQUIDS~~but ~~AND~~less -than ~~EOR~~Source ~~OPERATIONS~~of ~~OPERATIONS~~Fair ~~OPERATIONS(c)~~Value ~~OTHER(d)~~days ~~CONSOLIDATED~~or ~~-----------~~less ~~-----------~~one ~~-----------~~year -------------- ----------- ------------ THREE MONTHS ENDED SEPTEMBER 30, 2001 Revenue from external customers ....... $ 2,201,190 $ 6,518 $ 92,852 $ 21,993 $ -- $ 2,322,553 Intersegment revenue(a) ............... 17,443 27,690 1,314 -- (46,447) -- ----------- ----------- ----------- ----------- ----------- ----------- Total ~~revenue~~Fair ~~......................~~Value ~~2,218,633 34,208 94,166 21,993 (46,447) 2,322,553~~ ----------- ----------- ----------- ----------- ----------- ----------- ~~Gross margin .......................... 20,906 32,548 2,690 10,307~~ -- ~~66,451~~ ----------- ---~~--------~~ ~~-----------~~Prices ~~-----------~~Actively ~~-----------~~Quoted ~~-----------~~$ ~~Operating income~~(~~loss) ................ 2~~11,~~351 12,899 (1,538~~702) 9,543 (5,520) 17,735 Other expense, net .................... -- -- -- -- (10,372) (10,372) ----------- ----------- ----------- ----------- ----------- ----------- Net income(loss) before cumulative effect of accounting change ........ 2,351 12,899 (1,538) 9,543 (15,892) 7,363 ----------- ----------- ----------- ----------- ----------- ----------- Depreciation and amortization(b) ...... 1,498 5,415 405 1,529 751 9,598 ----------- ----------- ----------- ----------- ----------- ----------- THREE MONTHS ENDED SEPTEMBER 30, 2000 Revenue from external customers ....... $ 23,~~882,325~~170 $ ~~6,885 $ 254,319 $ -- $ -- $ 3,143,529 Intersegment revenue~~(~~a) ............... -- 28~~8,~~785 -- -- (28,785~~532) --Prices ~~-----------~~Provided ~~-----------~~by ~~-----------~~other ~~-----------~~External ~~-----------~~Source* ~~----------- Total revenue ...................... 2,882,325 35,670 254,319 --~~ (~~28,785) 3,143,529 ----------- ----------- ----------- ----------- ----------- ----------- Gross margin .......................... 18,125 35,357~~ 5,~~413 -- -- 58,895 ----------- ----------- ----------- ----------- ----------- ----------- Operating income(loss~~880) ~~................~~ (~~1,842~~688) ~~17,687~~ (147) -- (5,443) 10,255 Other expense ......................... -- -- -- -- (7,244) (7,244) ----------- ----------- ----------- ----------- ----------- ----------- Net income(loss) ...................... (1,842) 17,687 (147) -- (12,687) 3,011 ----------- ----------- ----------- ----------- ----------- ----------- Depreciation and amortization ......... 1,821 5,299 685 -- 618 8,423 ----------- ----------- ----------- ----------- ----------- ----------- NINE MONTHS ENDED SEPTEMBER 30, 2001 Revenue from external customers ....... $ 6,~~641,839 $ 19,580 $ 440,524 $ 21,993 $ -- $ 7,123,936 Intersegment revenue(a~~568) ~~............... 34,110 78,324 19,683~~ -- ~~(132,117)~~ -- ----------- ----------- ----------- ----------- --------~~---~~ ~~-----------~~ Total ~~revenue~~$ ~~...................... 6,675,949 97,904 460,207 21,993~~ (~~132~~17,~~117~~582) 7,123,936 ----------- ----------- ----------- ----------- ----------- ----------- Gross margin .......................... 68,102 95,589 12,156 10,307 -- 186,154 ----------- ----------- ----------- ----------- ----------- ----------- Operating income(loss) ................ 11,648 41,443 (2,~~233)~~482 9,543 (18,087) 42,314 Other expense ......................... -- -- -- -- (25,549) (25,549) ----------- ----------- ----------- ----------- ----------- ----------- Net income(loss) before cumulative effect of accounting change ........ 11,648 41,443 (2,233) 9,543 (43,636) 16,765 ----------- ----------- ----------- ----------- ----------- ----------- Depreciation and amortization(b) ...... 4,531 16,388 1,729 1,529 2,318 26,495 ----------- ----------- ----------- ----------- ----------- ----------- NINE MONTHS ENDED SEPTEMBER 30, 2000 Revenue from external customers ....... $ ~~7,703,823 $ 21,802 $ 614,534 $ -- $ -- $ 8,340,159 Intersegment revenue~~(a) ............... 5,671 81,979 -- -- (87,650) -- ----------- ----------- ----------- ----------- ----------- ----------- Total revenue ...................... 7,709,494 103,781 614,534 -- (87,650) 8,340,159 ----------- ----------- ----------- ----------- ----------- ----------- Gross margin .......................... 58,417 104,430 15,~~111 -- -- 177,958 ----------- ----------- ----------- ----------- ----------- ----------- Operating income(loss~~100) ................ (508) 52,314 (1,635) -- (16,379) 33,792 Other expense ......................... -- -- -- -- (23,672) (23,672) ----------- ----------- ----------- ----------- ----------- ----------- Net income(loss) ...................... (508) 52,314 (1,635) -- (40,051) 10,120 ----------- ----------- ----------- ----------- ----------- ----------- Depreciation and amortization ......... 5,649 15,839 2,017 -- 1,777 25,282 ----------- ----------- ----------- ----------- ----------- ----------- TOTAL ASSETS AT SEPTEMBER 30, 2001 .... $ 705,046 $ 296,549 $ 85,466 $ 128,774 $ 51,486 $ 1,267,321 ----------- ----------- ----------- ----------- ----------- ----------- TOTAL ASSETS AT DECEMBER 31, 2000 ..... 999,973 288,956 124,427 -- 79,637 1,492,993 ----------- ----------- ----------- ----------- ----------- -----------========================================================

*In determining the fair value of certain contracts, adjustments may be made to published posting data, for location differentials and quality basis adjustments. 36 PART II. OTHER INFORMATION EOTT ENERGY PARTNERS, L.P. ITEM 1. Legal Proceedings See Part I. Item 1, Note 8 to the Condensed Consolidated Financial Statements entitled "Litigation and Other Contingencies," which is incorporated herein by reference. ITEM 6. Exhibits and Reports on Form 8-K (a) Exhibits. None. (b) Reports on Form 8-K. Current Report on Form 8-K filed on February 11, 2002 pursuant to Item 4. Changes in Registrants Certifying Accountant regarding resignation of Arthur Andersen LLP. Current Report on Form 8-K filed on March 27, 2002 pursuant to Item 4. Changes in Registrants Certifying Accountant regarding engagement of PricewaterhouseCoopers LLP. Current Report on Form 8-K filed on April 3, 2002 pursuant to Item 5. Other Events regarding suspension of first quarter distributions. Current Report on Form 8-K filed on April 15, 2002 pursuant to Item 5. Other Events regarding election of new Chairman and restructure of Board. Current Report on Form 8-K filed on April 16, 2002 pursuant to Item 5. Other Events regarding extension of credit facility. Current Report on Form 8-K filed on April 17, 2002 pursuant to Item 5. Other Events regarding our delay in filing our Annual Report on Form 10-K. Current Report on Form 8-K filed on May 1, 2002 pursuant to Item 5. Other Events regarding our press release dated April 24, 2002. Current Report on Form 8-K filed on May 17, 2002 pursuant to Item 5. Other Events regarding our press release dated May 16, 2002. 37 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 thereunto duly authorized. EOTT ENERGY PARTNERS, L.P. (A Delaware Limited Partnership) Date: June 19, 2002 By: EOTT ENERGY CORP. as General Partner /s/ LORI L. MADDOX ------------------------------ Lori L. Maddox Vice President and Controller (Principal Accounting Officer) 38

THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------ ------------------------ 2001 2000 2001 2000 -------- -------- -------- -------- Revenues: North American Crude Oil - East of Rockies .... $2,218.6 $2,882.3 $6,675.9 $7,709.5 Pipeline Operations ........................... 34.2 35.7 97.9 103.8 West Coast Operations ......................... 94.2 254.3 460.2 614.5 Liquids Operations ............................ 22.0 -- 22.0 -- Intersegment Eliminations ..................... (46.4) (28.8) (132.1) (87.6) -------- -------- -------- -------- Total ......................................... $2,322.6 $3,143.5 $7,123.9 $8,340.2 ======== ======== ======== ======== Gross margin: North American Crude Oil - East of Rockies (1) $ 20.9 $ 18.1 $ 68.1 $ 58.4 Pipeline Operations ........................... 32.5 35.4 95.5 104.4 West Coast Operations ......................... 2.7 5.4 12.2 15.1 Liquids Operations ............................ 10.3 -- 10.3 -- -------- -------- -------- -------- Total ......................................... $ 66.4 $ 58.9 $ 186.1 $ 177.9 ======== ======== ======== ======== Operating income (loss): North American Crude Oil - East of Rockies (1) $ 2.3 $ (1.9) $ 11.7 $ (0.5) Pipeline Operations ........................... 12.9 17.7 41.4 52.3 West Coast Operations ......................... (1.5) (0.2) (2.2) (1.6) Liquids Operations ............................ 9.5 -- 9.5 -- Corporate and Other ........................... (5.5) (5.4) (18.1) (16.4) -------- -------- -------- -------- Total ......................................... $ 17.7 $ 10.2 $ 42.3 $ 33.8 ======== ======== ======== ========

EXHIBIT NUMBER DESCRIPTION ------ ----------- Exhibit 3.13 Agreement of Limited Partnership dated as of June 28, 2001 of EOTT Energy Liquids, L.P. Exhibit 3.14 Limited Liability Company Agreement dated as of June 27, 2001 of EOTT Energy General Partner, L.L.C. Exhibit 3.15 Amendment No. 1 dated as of August 29, 2001, to the Limited Liability Company Agreement of EOTT Energy General Partner, L.L.C.

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