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================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 8-K/A (AMENDMENT NO. 5) CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported): September 30, 2004 ENTERPRISE PRODUCTS PARTNERS L.P. (Exact name of registrant as specified in its charter) DELAWARE 1-14323 76-0568219 (State or Other Jurisdiction of (Commission File Number) (I.R.S. Employer Incorporation or Organization) Identification No.) 2727 NORTH LOOP WEST, HOUSTON, TEXAS 77008-1044 (Address of Principal Executive Offices) (Zip Code) Registrant's Telephone Number, including Area Code: (713) 880-6500 Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below): [ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) [ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) [ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) [ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) ================================================================================

EXPLANATORY NOTE The purpose of this Amendment No. 5 is to amend the Current Report on Form 8-K filed by Enterprise Products Partners L.P. ("Enterprise") on September 30, 2004, as amended by Amendment No. 1 thereto filed on October 5, 2004, Amendment No. 2 thereto filed on October 18, 2004, Amendment No. 3 thereto filed on December 3, 2004 and Amendment No. 4 thereto filed on December 6, 2004 (the "Existing 8-K") to (i) remove the unaudited condensed consolidated financial statements of GulfTerra Energy Partners, L.P. at September 30, 2004 and December 31, 2003 and for the three and nine months ended September 30, 2004 and 2003 contained in Amendment No. 3 to the Existing 8-K, and (ii) file the unaudited condensed financial statements of GulfTerra Energy Partners, L.P. at September 30, 2004 and for the six months ended June 30, 2004, the three months ended September 30, 2004, the nine months total September 30, 2004, and the three months and the nine months ended September 30, 2003 under Item 9.01(a). In accordance with Rule 12b-15, Item 9.01 is restated in its entirety, as amended. There is no change to Items 1.01, 2.01, 2.03, 5.02, 5.03 or 7.01 as set forth in the Existing 8-K. ITEM 9.01. FINANCIAL STATEMENTS AND EXHIBITS. (a) FINANCIAL STATEMENTS OF BUSINESSES ACQUIRED. 1. The Consolidated Financial Statements of GulfTerra Energy Partners, L.P. as of December 31, 2003 and 2002 and for the three year period ended December 31, 2003 and independent auditors' report are contained in Enterprise's Current Report on Form 8-K filed with the Commission on April 20, 2004 and are incorporated herein by reference. 2. The Financial Statements of Poseidon Oil Pipeline Company, L.L.C. as of December 31, 2003 and 2002 and for the three year period ended December 31, 2003 and independent auditors' report are contained in Enterprise's Current Report on Form 8-K filed with the Commission on April 20, 2004 and are incorporated herein by reference. 3. The Combined Financial Statements of El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. as of December 31, 2003 and 2002 and for the three year period ended December 31, 2003 and independent auditors' report are contained in Enterprise's Current Report on Form 8-K filed with the Commission on April 16, 2004 and are incorporated herein by reference. 4. The Unaudited Consolidated Financial Statements of GulfTerra Energy Partners, L.P. at June 30, 2004 and December 31, 2003 and for the six months ended June 30, 2004 and 2003 are contained in Enterprise's Current Report on Form 8-K filed with the Commission on September 17, 2004 and are incorporated herein by reference. 5. The Unaudited Combined Financial Statements of El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. at June 30, 2004 and December 31, 2003 and for the six months ended June 30, 2004 and 2003 are contained in Enterprise's Current Report on Form 8-K filed with the Commission on August 11, 2004 and are incorporated herein by reference. 6. The Unaudited Condensed Consolidated Financial Statements of GulfTerra Energy Partners, L.P. at September 30, 2004 and for the six months ended June 30, 2004, the three months ended September 30, 2004, the nine months total September 30, 2004, and the three months and the nine months ended September 30, 2003 (filed herewith as Annex A to this Current Report on Form 8-K/A). 2

(b) PRO FORMA FINANCIAL INFORMATION. 1. The Unaudited Pro Forma Condensed Consolidated Financial Statements of Enterprise Products Partners L.P. at and for the six months ended June 30, 2004 and for the year ended December 31, 2003 are contained in Enterprise's Current Report on Form 8-K filed with the Commission on September 27, 2004 and are incorporated herein by reference. 2. The Unaudited Pro Forma Condensed Consolidated Financial Statements of Enterprise Products Partners L.P. at and for the nine months ended September 30, 2004 and for the year ended December 31, 2003 are contained in Enterprise's Current Report on Form 8-K/A (Amendment No. 4) filed with the Commission on December 6, 2004 and are incorporated herein by reference. (c) EXHIBITS. Exhibit No. Description - ----------- ------------ 2.1 Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Enterprise's Current Report on Form 8-K filed with the Commission on December 15, 2003). 2.2 Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Enterprise's Current Report on Form 8-K filed with the Commission on December 15, 2003). 2.3 Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C., adopted by GulfTerra GP Holding Company, a Delaware corporation, and Enterprise Products GTM, LLC, a Delaware limited liability company, as of December 15, 2003, (incorporated by reference to Exhibit 2.3 to Enterprise's Current Report on Form 8-K filed with the Commission on December 15, 2003). 2.4 Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Enterprise's Current Report on Form 8-K filed with the Commission on December 15, 2003). 2.5 Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to Enterprise's Current Report on Form 8-K filed with the Commission on April 21, 2004). 2.6 Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Enterprise's Current Report on Form 8-K filed with the Commission on September 7, 2004). 3

3.1* Second Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, among Duncan Family Interests, Inc., Dan Duncan LLC, and GulfTerra GP Holding Company dated September 30, 2004. 4.1* Exchange and Registration Rights Agreement, dated as of September 30, 2004, among GulfTerra GP Holding Company, Enterprise Products GP, LLC and Enterprise Products Partners L.P. 4.2* Performance Guaranty dated as of September 30, 2004, by DFI Delaware Holdings L.P. in favor of GulfTerra GP Holding Company (with respect to the obligations of Enterprise Products GP, LLC under Exhibit 4.1, above). 4.3* Registration Rights Agreement, dated as of September 30, 2004, between El Paso Corporation and Enterprise Products Partners L.P. 4.4** Assumption Agreement dated as of September 30, 2004 between Enterprise Products Partners L.P. and GulfTerra Energy Partners, L.P. relating to the assumption by Enterprise of GulfTerra's obligations under the GulfTerra Series F2 Convertible Units. 4.5 Statement of Rights, Privileges and Limitations of Series F Convertible Units, included as Annex A to Third Amendment to the Second Amended and Restated Agreement of Limited Partnership of GulfTerra Energy Partners, L.P., dated May 16, 2003 (incorporated by reference to Exhibit 3.B.3 to Current Report on Form 8-K of GulfTerra Energy Partners, L.P., file no. 001-11680, filed with the Commission on May 19, 2003). 4.6 Unitholder Agreement between GulfTerra Energy Partners, L.P. and Fletcher International, Inc. dated May 16, 2003 (incorporated by reference to Exhibit 4.L to Current Report on Form 8-K of GulfTerra Energy Partners, L.P., file no. 001-11680, filed with the Commission on May 19, 2003). 10.1*** Letter Agreement dated September 30, 2004, among Enterprise Products Partners L.P., GulfTerra Energy Partners, L.P. and Bart Heijermans. 10.2 1998 Omnibus Compensation Plan of GulfTerra Energy Partners, L.P., Amended and Restated as of January 1, 1999 (incorporated by reference to Exhibit 10.9 to Form 10-K for the year ended December 31, 1998 of GulfTerra Energy Partners, L.P., file no. 001-11680); Amendment No. 1, dated as of December 1, 1999 (incorporated by reference to Exhibit 10.8.1 to Form 10-Q for the quarter ended June 30, 2000 of GulfTerra Energy Partners, L.P., file no. 001-116800); Amendment No. 2 dated as of May 15, 2003 (incorporated by reference to Exhibit 10.M.1 to Form 10-Q for the quarter ended June 30, 2003 of GulfTerra Energy Partners, L.P., file no. 001-11680). 10.3 1998 Enterprise Products Long-Term Incentive Plan (Amended and Restated as of April 8, 2004) (incorporated by reference to Appendix B to Enterprise's Notice of Written Consent dated April 22, 2004, filed with the Commission on April 22, 2004). 99.1* Press release dated September 30, 2004. - ------------ * Filed with original Current Report on Form 8-K. ** Filed with Amendment No. 1 to Current Report on Form 8-K. *** Filed with Amendment No. 2 to Current Report on Form 8-K. 4

SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned hereunto duly authorized. ENTERPRISE PRODUCTS PARTNERS L.P. By: Enterprise Products GP, LLC, its General Partner Date: December 23, 2004 By: /s/ Michael J. Knesek -------------------------------------------- Name: Michael J. Knesek Title: Vice President, Controller and Principal Accounting Officer of Enterprise Products GP, LLC Signature Page

GULFTERRA ENERGY PARTNERS, L.P. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AT SEPTEMBER 30, 2004 AND FOR THE SIX MONTHS ENDED JUNE 30, 2004, THREE MONTHS ENDED SEPTEMBER 30, 2004, NINE MONTHS TOTAL SEPTEMBER 30, 2004, AND THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2003 A-1

GULFTERRA ENERGY PARTNERS, L.P. UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS)

SEPTEMBER 30, 2004 (1) ------------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 40,453 Accounts receivable, net of allowance for doubtful accounts of $4.2 million at September 30, 2004 156,997 Affiliated note receivable Other current assets 32,055 ---------- Total current assets 229,505 PROPERTY, PLANT, AND EQUIPMENT, NET 2,926,861 INTANGIBLE ASSETS 3,080 INVESTMENTS IN UNCONSOLIDATED AFFILIATES 210,742 OTHER ASSETS 26,101 ---------- Total $3,396,289 ========== LIABILITIES AND PARTNERS' EQUITY CURRENT LIABILITIES Current maturities of debt $ 5,000 Accounts payable 133,407 Accrued interest 26,361 Other current liabilities 35,045 ---------- Total current liabilities 199,813 LONG-TERM DEBT 1,878,456 OTHER LONG-TERM LIABILITIES 42,384 COMMITMENTS AND CONTINGENCIES MINORITY INTEREST (12) PARTNERS' EQUITY: Common units (60,638,989 units outstanding at September 30, 2004) 929,110 Series C units (10,937,500 units outstanding at September 30, 2004) 333,063 General partner 13,475 ---------- Total Partners' Equity 1,275,648 ---------- Total $3,396,289 ========== - -------------------------------------------------------------------------------- (1) The September 30, 2004 amounts do not reflect any pro forma impacts of the merger, repayments of debt, changes in ownership of our common unitholders or any other purchase accounting-related adjustments to be made by Enterprise in connection with the merger - see Note 2. See Notes to Unaudited Condensed Consolidated Financial Statements. A-2

GULFTERRA ENERGY PARTNERS, L.P. UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME (DOLLARS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

THREE MONTHS NINE MONTHS SIX MONTHS THREE MONTHS NINE MONTHS ENDED ENDED ENDED ENDED TOTAL ------------------------ JUNE 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, ---------------------------------------- ------------------------ 2004 (1) 2003 ------------------------------------- ----------------------- OPERATING REVENUES $ 445,557 $ 231,165 $ 676,722 $ 213,831 $ 680,957 --------- --------- --------- --------- --------- OPERATING EXPENSES Cost of natural gas and other products 124,522 61,651 186,173 64,277 240,415 Operation and maintenance 100,463 64,361 164,824 51,221 140,416 Depreciation, depletion and amortization 52,303 28,994 81,297 25,218 73,761 Gain on sale of long-lived assets (24) (12) (36) (18,964) (18,707) --------- --------- --------- --------- --------- Total operating expenses 277,264 154,994 432,258 121,752 435,885 --------- --------- --------- --------- --------- OPERATING INCOME 168,293 76,171 244,464 92,079 245,072 --------- --------- --------- --------- --------- EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES 5,466 2,101 7,567 3,195 9,498 --------- --------- --------- --------- --------- Minority interest income (expense) 12 1,813 1,825 (889) (969) Other income 284 188 472 250 942 Interest and debt expense 54,727 27,951 82,678 33,197 99,521 Loss due to early redemptions of debt 16,285 16,285 1,225 4,987 --------- --------- --------- --------- --------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 103,043 52,322 155,365 60,213 150,035 Cumulative effect of accounting change 1,690 --------- --------- --------- --------- --------- NET INCOME $ 103,043 $ 52,322 $ 155,365 $ 60,213 $ 151,725 ========= ========= ========= ========= ========= ALLOCATION OF NET INCOME TO: Series B unitholders $ 4,018 $ 11,792 ========= ========= General partner: Income before cumulative effect of accounting change $ 42,549 $ 21,550 $ 64,099 $ 18,031 $ 48,747 Cumulative effect of accounting change 17 --------- --------- --------- --------- --------- Total allocation to general partner $ 42,549 $ 21,550 $ 64,099 $ 18,031 $ 48,764 ========= ========= ========= ========= ========= Common unitholders: Income before cumulative effect of accounting change $ 51,087 $ 26,044 $ 77,131 $ 31,337 $ 72,951 Cumulative effect of accounting change 1,340 --------- --------- --------- --------- --------- Total allocation to common unitholders $ 51,087 $ 26,044 $ 77,131 $ 31,337 $ 74,291 ========= ========= ========= ========= ========= Series C unitholders: Income before cumulative effect of accounting change $ 9,407 $ 4,728 $ 14,135 $ 6,827 $ 16,545 Cumulative effect of accounting change 333 --------- --------- --------- --------- --------- Total allocation to Series C unitholders $ 9,407 $ 4,728 $ 14,135 $ 6,827 $ 16,878 ========= ========= ========= ========= ========= EARNINGS PER UNIT: Basic income per unit before cumulative effect of accounting change $ 0.86 $ 0.43 $ 1.30 $ 0.63 $ 1.54 Cumulative effect of accounting change, per unit (basic) 0.03 --------- --------- --------- --------- --------- Basic net income per unit $ 0.86 $ 0.43 $ 1.30 $ 0.63 $ 1.57 ========= ========= ========= ========= ========= Diluted income per unit before cumulative effect of accounting change $ 0.86 $ 0.43 $ 1.30 $ 0.62 $ 1.53 Cumulative effect of accounting change, per unit (diluted) 0.03 --------- --------- --------- --------- --------- Diluted net income per unit $ 0.86 $ 0.43 $ 1.30 $ 0.62 $ 1.56 ========= ========= ========= ========= ========= - -------------------------------------------------------------------------------- (1) Amounts shown for the 2004 periods do not reflect any pro forma impacts of the merger, repayments of debt, changes in ownership of our common unitholders or any other purchase accounting-related adjustments to be made by Enterprise in connection with the merger - see Note 2. See Notes to Unaudited Condensed Consolidated Financial Statements. A-3

GULFTERRA ENERGY PARTNERS, L.P. UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (DOLLARS IN THOUSANDS)

- -------------------------------------------------------------------------------- (1) Amounts shown for the 2004 periods do not reflect any pro forma impacts of the merger, repayments of debt, changes in ownership of our common unitholders or any other purchase accounting-related adjustments to be made by Enterprise in connection with the merger - see Note 2. See Notes to Unaudited Condensed Consolidated Financial Statements. A-4

GULFTERRA ENERGY PARTNERS, L.P. UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE LOSS (DOLLARS IN THOUSANDS) COMPREHENSIVE INCOME

GULFTERRA ENERGY PARTNERS, L.P. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of presentation We are a Delaware limited partnership established in 1993 for the purpose of providing midstream energy services, including gathering, transportation, fractionation, storage and other related activities, for producers of natural gas and oil, onshore and offshore in the Gulf of Mexico. Our general partner is GulfTerra Energy Company, L.L.C. ("GulfTerra GP"), a Delaware limited liability company - see Note 2. References to "us", "we", "our", or "GulfTerra" are intended to mean the consolidated business and operations of GulfTerra Energy Partners, L.P. References to "El Paso" refer to El Paso Corporation, its subsidiaries and affiliates. On September 30, 2004, we completed our merger with Enterprise Products Partners L.P. ("Enterprise"). For additional information regarding the merger, see Note 2. Unless otherwise disclosed, these unaudited condensed consolidated financial statements do not reflect any pro forma impacts of the merger, repayments of debt - see Note 4, changes in ownership of our common unitholders, purchase accounting-related adjustments or any other adjustments to be made by Enterprise in connection with the merger. Effective September 30, 2004, most of our then outstanding limited partner interests were converted to Enterprise limited partner interests pursuant to the merger. Those limited partner interests that were not converted into Enterprise limited partner interests were purchased by Enterprise from El Paso for cash immediately prior to the merger. As a result of the merger, we ceased as being a publicly-traded company subject to the filing requirements of the Securities and Exchange Commission ("SEC"). In the opinion of GulfTerra, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules and regulations of the SEC. The results of operations for the six months ended June 30, 2004, the three months ended September 30, 2004 or the total for the nine months ended September 30, 2004 are not necessarily indicative of the results to be expected for the full year. Dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars, unless otherwise stated. Certain reclassifications have been made to the prior year's financial statements to conform to the current year presentation. Typhoon Oil Pipeline, a wholly-owned subsidiary, has transportation agreements with BHP Billiton and ChevronTexaco which provide that Typhoon Oil purchase the oil produced at the inlet of its pipeline for an index price less an amount that compensates Typhoon Oil for transportation services. At the outlet of its pipeline, Typhoon Oil resells this oil back to these producers at the same index price. As disclosed in our 2003 annual report on Form 10-K, as amended, we now record revenue from these buy/sell transactions upon delivery of the oil based on the net amount billed to the producers. For the three and nine months ended September 30, 2003, we reduced by $69.8 million and $191.7 million our revenues and cost of natural gas and other products to conform to the current period presentation. This revision had no effect on operating income, net income or partners' equity. With respect to our Texas intrastate pipeline system, which we acquired in April 2002, we had previously used the pre-acquisition accounting methodology for the cash settlement of natural gas imbalance receivables, which included the cash settlement amounts as a component of operating revenues and cost of natural gas and other products. However, effective January 1, 2004, we have conformed our accounting for cash settlements on that system to the same method we use to account for imbalance receivable settlements on our other systems, which method accounts for these types of cash settlements as an adjustment to cost of natural gas and other products. We have determined that this revision is not material to our previously reported financial statements. Accordingly, we have not revised our previously filed financial statements to reflect this change in methodology. A-6

Accounting for stock-based compensation Under the terms of the merger agreement with Enterprise, we were obligated to repurchase, before the effective time of the merger, all outstanding employee and director unit options that had not been exercised or otherwise cancelled. As a result, we had no outstanding unit options at September 30, 2004. Historically, we used the intrinsic value method established in Accounting Principles Board Opinion ("APB") No. 25, Accounting for Stock Issued to Employees, to value unit options issued to directors of our general partner. We used the provisions of Statement of Financial Accounting Standards ("SFAS") No. 123, Accounting for Stock-Based Compensation, to account for all of our other equity-based compensation programs. The costs associated with our unit options accounted for under APB No. 25 had no impact on net income for the six months ended June 30, 2004, the three months ended September 30, 2004 and the three and nine months ended September 30, 2003, as these options had an exercise price equal to the market value of the underlying common units on the date of grant. Historical compensation expense amounts associated with our unit options accounted for under SFAS No. 123 are shown in the following table. If compensation expense had been determined by applying the fair value method in SFAS No. 123 to all of our grants, our net income allocated to common unitholders and net income per common unit would have approximated the pro forma amounts below (dollars in thousands, except per unit amounts). As a result of applying SFAS No. 123 to all unit options, there was no difference between our historical and pro forma earnings per unit amounts.

Inventory In June 2004, we purchased pipeline inventory, consisting of parts and materials, from El Paso -see Note 8. This inventory is included on our unaudited condensed consolidated balance sheet as of September 30, 2004, in other current assets. We use the average cost method to account for our inventory and we value our inventory at the lower of its cost or market value. Consolidation of variable interest entities During the first quarter of 2004, we adopted the provisions of Financial Accounting Standards Board Interpretation ("FIN") No. 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin ("ARB") No. 51, as replaced by FIN No. 46-R. This interpretation defines a variable interest entity as a A-7

legal entity whose equity owners do not have sufficient equity at risk and/or a controlling financial interest in the entity and excludes certain joint ventures of other entities that meet the characteristics of a business. Our adoption of FIN No. 46 had no effect on our reported results or financial position. Two-class method of computing earnings per common unit During the second quarter of 2004, we adopted the provisions of Emerging Issues Task Force ("EITF") 03-6, Participating Securities and the Two-Class Method under SFAS No. 128. EITF 03-6 requires the use of the two-class method of determining basic earnings per unit. Under the two-class method, distributions to equity owners are subtracted from earnings, and any remaining earnings would be allocated to the various classes of owners in proportion to their right to receive distributions as if those earnings had been distributed. The total of distributions to each class of owner plus the amount allocated to each class would be used to compute earnings per unit for that class. Because our distributions to owners exceeded earnings during the periods presented, as has historically been the case, the two-class method did not produce any change in result from the way we have traditionally computed earnings per unit. As a result, the adoption of this standard had no effect on our earnings per unit calculation for the six months ended June 30, 2004, the three months ended September 30, 2004 and the three and nine months ended September 30, 2003. 2. MERGER WITH ENTERPRISE AND RELATED TRANSACTIONS General description of merger On September 30, 2004, Enterprise and GulfTerra completed the merger of GulfTerra with a wholly-owned subsidiary of Enterprise, with GulfTerra being the surviving entity thereof (the "GulfTerra Merger"). Unless otherwise disclosed, these unaudited condensed consolidated financial statements do not reflect any pro forma impacts of the GulfTerra Merger, repayments of debt - see Note 4, changes in ownership of our common unitholders, purchase accounting-related adjustments or any other adjustments to be made by Enterprise in connection with the GulfTerra Merger. The aggregate value of the total consideration Enterprise paid or issued to complete the GulfTerra Merger was approximately $3.8 billion. Pursuant to the merger agreements, the GulfTerra Merger occurred in several interrelated transactions as described below. o Step One. On December 15, 2003, Enterprise purchased a 50% membership interest in our general partner, GulfTerra GP, from El Paso for $425 million in cash. As a result of Step One of the merger, GulfTerra GP was owned 50% by Enterprise and 50% by El Paso. o Step Two. On September 30, 2004, the GulfTerra Merger was consummated and GulfTerra and GulfTerra GP became wholly-owned subsidiaries of Enterprise. Step Two of the merger included the following transactions: o Immediately prior to closing the GulfTerra Merger, the general partner of Enterprise ("Enterprise GP") acquired El Paso's remaining 50% membership interest in GulfTerra GP for $370 million in cash paid to El Paso and the issuance of a 9.9% membership interest in Enterprise GP to El Paso. Subsequently, Enterprise GP contributed this 50% membership interest in GulfTerra GP to Enterprise. o Immediately prior to closing the GulfTerra Merger, Enterprise paid $500 million in cash to El Paso for our 10,937,500 outstanding Series C units and 2,876,620 of our common units. After giving effect to this purchase, our remaining 57,762,369 common units were converted into 104,549,823 Enterprise common units using a conversion ratio of 1.81 Enterprise common units for each GulfTerra common unit outstanding. A-8

Enterprise's assumption of Series F2 convertible unit obligations Upon completion of the GulfTerra Merger, Enterprise assumed our obligations associated with the outstanding Series F2 convertible units. As a result, the 80 Series F2 convertible units outstanding at the merger date were converted into rights to receive Enterprise common units. The number Enterprise common units and the price per unit were adjusted based on the 1.81 conversion ratio. For additional information regarding the Series F convertible units, see Note 6. Repayment of certain GulfTerra debt in connection with the merger In connection with the closing of our merger with Enterprise on September 30, 2004, we repaid, in full, the amounts outstanding under our revolving credit facility and senior secured term loans using funds contributed by Enterprise - see Note 4. The closing of our merger with Enterprise constituted a change of control, and thus a default, under our credit agreements. In order to avoid the default, Enterprise will contribute $961.7 million to us at closing on September 30, 2004, which we will use to fully repay our outstanding obligations and related interest of $1.2 million under these agreements. All such contributions and repayments are not reflected in our September 30, 2004 unaudited condensed consolidated financial statements. For additional information regarding our remaining debt obligations, see Note 4. Tender offers for GulfTerra notes in connection with the merger On August 4, 2004, in anticipation of completing the merger, Enterprise commenced four cash tender offers to purchase any and all of our outstanding senior and senior subordinated notes having a total outstanding principal amount of approximately $921.5 million. In connection with the tender offers, we executed supplements to the indentures governing these notes that eliminated certain restrictive covenants and default provisions contained in those indentures. Substantially all of our notes ($915 million of $921.5 million) were tendered pursuant to the tender offers. On October 5, 2004, Enterprise purchased the notes for a total price of approximately $1.1 billion, which included $27 million related to consent payments. The following table shows our four senior debt obligations affected, including the principal amount of each series of notes tendered, as well as the payment made by Enterprise to complete the tender offers.

CASH PAYMENTS MADE BY ENTERPRISE PRINCIPAL -------------------------------------------- AMOUNT ACCRUED TENDER TOTAL DESCRIPTION TENDERED INTEREST PRICE (1) PRICE ----------- ---------- ---------- ---------- ---------- 8.50% Senior Subordinated Notes due 2010 (Represents 98.2% of principal amount outstanding) $ 212,057 $ 6,209 $ 246,366 $ 252,575 10.625% Senior Subordinated Notes due 2012 (Represents 99.9% of principal amount outstanding) 133,916 4,901 167,612 172,513 8.50% Senior Subordinated Notes due 2011 (Represents 99.5% of principal amount outstanding) 319,823 9,364 359,379 368,743 6.25% Senior Notes due 2010 (Represents 99.7% of principal amount outstanding) 249,250 5,366 274,073 279,439 ---------- ---------- ---------- ---------- Totals $ 915,046 $ 25,840 $1,047,430 $1,073,270 ========== ========== ========== ========== - -------------------------------------------------------------------------------- (1) Tender price includes consent payment of $30 per $1,000 principal amount tendered. For additional information regarding our senior and senior subordinated notes, see Note 4. A-9

OTHER MERGER-RELATED TRANSACTIONS Prior to our merger with Enterprise, we determined that it was in our and our unitholders' best interest to offer selected employees of El Paso incentives to continue to focus on the business of the partnership during the merger process. We accounted for the cost of these incentives under the provisions of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. In March 2004, we recorded a liability and a related deferred charge of $4.3 million, which was reflected in other current liabilities and other current assets on our balance sheets. Our liability was estimated based upon the number of employees accepting the offer and the discounted amount they were expected to be paid. During the six months ended June 30, 2004 and the three months ended September 30, 2004, we recorded $2.8 million and $1.5 million of amortization expense associated with these incentives. Additionally, pursuant to the terms of the engagement letter, we agreed to pay UBS Securities ("UBS") $10.3 million for advisory fees related to our merger with Enterprise. In the first quarter of 2004, we paid UBS $3.5 million upon receiving a fairness opinion related to the merger, and the remaining $6.8 million was paid on September 30, 2004. Furthermore, during the three months ended September 30, 2004, we recognized a merger-related expense of $4.9 million associated with our repurchase of the outstanding unit options prior to closing the merger with Enterprise. Under the merger agreement with Enterprise, we were obligated to repurchase, at reasonable prices and before the effective time of the merger, all outstanding employee and director unit options that had not been exercised or otherwise cancelled. Approximately 1,000,000 common unit options were outstanding at the merger date, which we repurchased for approximately $13 million. For the unit options accounted for under the provisions of SFAS No. 123, the purchase price recorded had two components. The purchase price paid up to the fair value of the options as of the valuation date was recorded as the repurchase of an equity instrument. The payment above that fair value amount was recorded as compensation expense. For our unit options accounted for under APB No. 25, the amount paid up to the intrinsic value of the options repurchased was also accounted for as the repurchase of an equity instrument, with any amount paid in excess of the intrinsic value recorded as compensation expense. Lastly, during the six months ended June 30, 2004 and the three months ended September 30, 2004, we recognized additional merger-related expenses primarily for legal and audit fees totaling $1.5 million and $1.1 million. All of our merger-related costs are included in operation and maintenance expenses on our unaudited condensed consolidated statements of income and are allocated across all of our operating segments. 3. PROPERTY, PLANT AND EQUIPMENT Our property, plant and equipment consisted of the following at the dates indicated:

The values shown in the table above do not reflect any purchase accounting-related adjustments recorded by Enterprise as a result of the GulfTerra Merger - see Note 2. A-10

4. DEBT OBLIGATIONS Prior to the September 30, 2004 debt repayments and subsequent tender offer payments, both in connection with the merger - see Note 2, our debt consisted of the following at the dates indicated:

SEPTEMBER 30, 2004 ------------- Borrowings under: Revolving Credit Facility (1) $ 462,000 Senior Secured Term Loans (1) 498,500 Senior Notes, 6.25% fixed-rate, due June 2010 (2) 250,000 Senior Subordinated Notes, 10.375% fixed-rate, due June 2009 (3) Senior Subordinated Notes, 8.50% fixed-rate, due June 2010 (2,4) 215,915 Senior Subordinated Notes, 8.50% fixed-rate, due June 2011 (2) 321,600 Senior Subordinated Notes, 10.625% fixed-rate, due Dec. 2012 (2) 134,000 ----------- Total principal amount 1,882,015 Other, including unamortized premiums and discounts 1,441 ----------- Subtotal long-term debt 1,883,456 Less current maturities of debt (5,000) ----------- Long-term debt $ 1,878,456 =========== - -------------------------------------------------------------------------------- (1) In connection with closing the merger, Enterprise contributed approximately $962 million to us on September 30, 2004 to repay in full the $960.5 million in principal amount due under these debt agreements, plus $1.2 million of related accrued interest - see Note 2. (2) On October 5, 2004, $915 million of these senior note obligations were tendered to Enterprise pursuant to its tender offers made in connection with the merger - see Note 2. (3) In June 2004, we redeemed, at a premium, all of our 10.375% Senior Subordinated Notes due 2009. (4) In April 2004, we redeemed, at a premium, approximately $39.1 million of our 8.5% Senior Subordinated Notes due June 2010. After giving effect to the September 30, 2004 debt repayments and subsequent tender offer payments, both in connection with the merger - see Note 2, our debt consisted of the following at the dates indicated:

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PARENT-SUBSIDIARY GUARANTOR RELATIONSHIPS After giving effect to the completion of Enterprise's tender offers on October 5, 2004 -see Note 2, we have $6.5 million in senior and senior subordinated notes outstanding. These obligations are jointly, severally, fully and unconditionally guaranteed by us and each of our subsidiaries, excluding our unrestricted subsidiaries. DEBT MATURITIES After giving effect to the completion of Enterprise's tender offers on October 5, 2004 - see Note 2, aggregate maturities of the principal amounts of long-term debt are none for the remainder of 2004 and in each of the years 2005 through 2008 and $6.5 million in total after 2008. INFORMATION REGARDING VARIABLE INTEREST RATES PAID On September 30, 2004, and prior to the merger-related repayment, we had $462 million outstanding under our revolving credit facility at an average interest rate of 3.82%. On September 30, 2004, and prior to the merger-related repayment, we had $498.5 million outstanding under our senior secured term loans at an average interest rate of 4.07%. LOSS DUE TO EARLY REDEMPTIONS OF DEBT We recognized losses associated with early redemptions of debt as follows:

JOINT VENTURE DEBT OBLIGATIONS We have ownership interests in three joint ventures having long-term debt obligations: Cameron Highway Oil Pipeline Company ("Cameron Highway"); Deepwater Gateway, L.L.C. ("Deepwater Gateway"); and Poseidon Oil Pipeline Company, L.L.C. ("Poseidon"). The following table shows (i) our ownership interest in each entity at September 30, 2004, (ii) total long-term debt obligations (including current maturities) of each unconsolidated affiliate on that date (on a 100% basis to the joint venture), and (iii) the estimated corresponding scheduled maturities of such long-term debt.

SCHEDULED MATURITIES OF LONG-TERM DEBT OUR -------------------------------------------------------------- OWNERSHIP AFTER INTEREST TOTAL 2004 2005 2006 2007 2008 2008 -------------------------------------------------------------------------------------- Cameron Highway (1) 50.0% $ 297,000 $ 16,250 $ 32,500 $ 156,250 $ 92,000 Deepwater Gateway 50.0% 149,500 $ 5,500 $ 22,000 22,000 22,000 22,000 56,000 Poseidon (2) 36.0% 116,000 116,000 --------- -------- -------- -------- -------- --------- -------- Total $ 562,500 $ 5,500 $ 22,000 $ 38,250 $ 54,500 $ 294,250 $148,000 ========= ======== ======== ======== ======== ========= ======== - ------------------------------------------------------------------------------- (1) Cameron Highway has a total borrowing capacity under its project loan facility of $325 million. The scheduled maturities for Cameron Highway assume that the construction loan is or will be converted into a term loan on June 30, 2005 and the scheduled repayments will begin on September 30, 2006. (2) Poseidon has a total borrowing capacity of $170 million under its revolving credit facility. A-12

At September 30, 2004, long-term debt for Cameron Highway consisted of $197 million outstanding under a variable-rate construction loan and $100 million of senior secured notes. Cameron Highway has a borrowing capacity of $225 million under its construction loan. At September 30, 2004, the average variable interest rate charged under Cameron Highway's construction loan agreement was 4.97%. The interest rate on Cameron Highway's senior secured notes is 3.25% over the rate on 10-year U.S. treasury securities, which at September 30, 2004 was 7.4%. At September 30, 2004, long-term debt for Deepwater Gateway consisted of $149.5 million due under a project finance loan used to fund a portion of the construction costs of the Marco Polo tension leg platform ("TLP") and related facilities. Construction of the Marco Polo TLP was completed during the first quarter of 2004, and in June 2004, Deepwater Gateway converted the project finance loan into a term loan which matures in June 2009. At September 30, 2004, the average variable interest rate charged under Deepwater Gateway's term loan was 3.6%. At September 30, 2004, long-term debt for Poseidon consisted of $116 million due under a revolving credit facility, which matures in January 2008. At September 30, 2004, the average variable interest rate charged under Poseidon's credit agreement was 3.7%. 5. INVESTMENTS IN UNCONSOLIDATED AFFILIATES We own interests in various related businesses that are accounted for using the equity method. In general, we use the equity method of accounting for an investment in which we own 20% to 50% of its outstanding ownership interests and exercise significant influence over its operating and financial policies. Our investments in unconsolidated affiliates totaled $210.7 million at September 30, 2004. The following table shows our equity in income of unconsolidated affiliates for the periods indicated:

(1) Cameron Highway is a development stage company at September 30, 2004; therefore, there are no operating revenues or expenses. Since its formation in June 2003, it has incurred organizational expenses and received interest income. In September 2004, construction of the Cameron Highway oil pipeline system was completed and we anticipate that operations will begin during the fourth quarter of 2004 or the first quarter of 2005. (2) The Marco Polo TLP, which is owned by Deepwater Gateway, was installed in the first quarter of 2004. First production and thus volumetric payments started in July 2004. In April 2004, Deepwater Gateway began receiving monthly demand payments of $2.1 million. Prior to the installation of this platform, Deepwater Gateway was a development stage company; therefore, there were no operating revenues or operating expenses. (3) The 2004 period includes a $3.7 million loss associated with our write-off of a note receivable from El Paso we received in connection with the sale of our interest in Copper Eagle Gas Storage, L.L.C. ("Copper Eagle") to El Paso in August 2003. The 2003 period includes a $0.9 million gain we initially recorded on the sale of our interest in Cooper Eagle to El Paso. See Note 8 for additional information regarding this related party transaction. A-13

The following table presents unaudited summarized income statement information for our current unconsolidated affiliates from which we have recorded equity earnings (for the periods indicated, on a 100% basis).

6. PARTNERS' CAPITAL On September 30, 2004, we completed our merger with Enterprise - see Note 2. These unaudited condensed consolidated financial statements do not reflect any changes in ownership of our common unitholders as a result of the merger. Effective September 30, 2004, most of our then outstanding limited partner interests were converted to Enterprise limited partner interests pursuant to the merger. Those limited partner interests that were not converted into Enterprise limited partner interests were purchased by Enterprise from El Paso for cash immediately prior to the merger. As a result of the merger, we ceased as being a publicly-traded company subject to the filing requirements of the SEC. During the first nine months of 2004 we received net proceeds of approximately $78.3 million from the conversion of 80 Series F1 convertible units into 2,061,109 common units (45 Series F1 convertible units were converted into 1,146,418 common units with proceeds paid to us of $45 million during the first six months of 2004). As a result of these conversions in 2004, all of the Series F1 convertible units were converted into GulfTerra common units by the holder prior to our merger with Enterprise. On the merger closing date, Enterprise assumed our obligations associated with the outstanding Series F2 convertible units. A-14

The following table reflects our cash distribution history for the nine months ended September 30, 2004 (dollars in millions, except per unit amounts):

7. EARNINGS PER COMMON UNIT The following table sets forth the computation of basic and diluted earnings per common unit (dollars in thousands, except per unit amounts):

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8. RELATED PARTY TRANSACTIONS For the nine months ended September 30, 2004, there were no changes to our related party relationships. Prior to our merger with Enterprise, our largest related party was our parent company, El Paso. As a result of our merger with Enterprise, El Paso is no longer classified as a related party to us. Revenues received from related parties for the six months ended June 30, 2004 and the three months ended September 30, 2004, were approximately 17 percent and 16 percent of our total revenue. Revenues received from related parties for the three and nine months ended September 30, 2003, were approximately 12 percent and 13 percent of our total revenue. Our transactions with related parties and affiliates are as follows:

The following table provides summary data categorized by our related parties:

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Our accounts receivable due from related parties consisted of the following as of:

Our accounts payable due to related parties consisted of the following as of:

Other matters Petal. In September 2003, we entered into a nonbinding letter of intent with El Paso, regarding the proposed development and sale of a natural gas storage cavern, and the proposed sale of an undivided interest in a related pipeline and other facilities related to that natural gas storage cavern. In June 2004, we and El Paso terminated the letter of intent and we announced that we would hold a nonbinding open season to determine market interest for up to 5.0 Bcf of firm natural gas storage capacity, and up to 500,000 MMBtu/d of firm transportation on the Petal pipeline, all available in the third quarter of 2007. Copper Eagle. In August 2003, a majority-owned subsidiary of ours sold its interest in Copper Eagle Gas Storage, L.L.C. ("Copper Eagle") to El Paso. Copper Eagle is developing a natural gas storage project located outside of Phoenix, Arizona. Under the original sale agreement with El Paso, we had the right to receive $6.2 million of the sale proceeds, including a note receivable for $4.9 million that was to be paid quarterly beginning in January 2004 and ending in October 2004. As of September 30, 2004, we had received principal payments totaling $1.3 million from El Paso related to the note receivable. Prior to the sale, we accounted for our investment in Copper Eagle using the equity method. The proposed natural gas storage project has received strong local opposition by developers and residents due to the close proximity to residential communities. Further, the storage facilities will be near the Luke Air Force Base and the Arizona legislature recently reached a resolution which prohibits the development of a hydrocarbon storage facility within a nine mile range of an air force base or airport. As a result of these developments, we have changed our view on the probability that the Copper Eagle natural gas storage project will actually be developed and we wrote-off the remaining $3.7 million note receivable from El Paso as uncollectible during the third quarter of 2004. The write-off was recorded as a reduction to equity in income of unconsolidated affiliates - see Note 5. In addition, we reduced our minority interest balance by $1.8 million and recognized minority interest income of $1.8 million, which reflects the portion of the write-off allocated to the minority interest owner of our subsidiary. Indemnifications. In addition to the related party transactions discussed above, pursuant to the terms of many of the purchase and sale agreements we have entered into with various entities controlled directly or indirectly by El Paso, we have been indemnified for potential future liabilities, expenses and capital requirements above a negotiated threshold. Some of our agreements obligate certain indirect subsidiaries of El Paso to pay for capital costs related to maintaining assets which were acquired by us, if such costs exceed negotiated thresholds. We have not made any claims during the nine months ended September 30, 2004 or 2003. However, for the full year of 2003, we made claims for approximately $5 million of costs incurred during the year ended December 31, 2003, as costs exceeded the established thresholds for 2003. A-17

Wilson storage operating lease commitment. In connection with our April 2002 purchase of the EPN Holding assets from El Paso, we obtained a long-term operating lease commitment related to the Wilson natural gas storage facility, which is operated by one of our direct subsidiaries. From the acquisition date until the second quarter of 2004, El Paso guaranteed our direct subsidiary's payment and performance under this commitment. In the second quarter of 2004, El Paso was released from the guarantee and, thus, we now are solely liable for our direct subsidiary's payment and performance under this operating lease agreement. 9. COMMITMENTS AND CONTINGENCIES LITIGATION We are sometimes named as a defendant in litigation relating to our normal business operations. Although we insure against various business risks, to the extent management believes it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from legal proceedings as a result of ordinary business activity. Management is not aware of any significant litigation, pending or threatened, that would have a significant adverse effect on our financial position or results of operations. ENVIRONMENTAL Environmental costs for remediation are accrued at their undiscounted estimated amounts based on known remediation requirements. Such accruals are based on management's best estimate of the ultimate costs to remediate a given site and take into account the likely effects of inflation and other societal and economic factors, including estimated associated legal costs. We expense amounts for clean up of existing environmental contamination caused by past operations which do not benefit future periods. We expense or capitalize expenditures for ongoing compliance with environmental regulations that relate to past or current operations as appropriate. As of September 30, 2004, we had an environmental liability initially estimated at $21 million, which is included in other long-term liabilities on our unaudited condensed consolidated balance sheet, for remediation costs expected to be incurred over time associated with mercury gas meters. While the outcome of our outstanding environmental matters cannot be predicted with certainty, based on the information known to date and our existing accruals, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, results of operations or cash flows. It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws and regulations and claims for damage to property, employees, other persons and the environment resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties relating to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our current reserves are adequate. JOINT VENTURES We conduct a portion of our activities through joint venture business arrangements formed to construct, operate and finance the development of our onshore and offshore midstream energy businesses. We are obligated to make our proportionate share of additional capital contributions to our joint ventures only to the extent that they are unable to satisfy their obligations from other sources including proceeds from credit arrangements. Examples of this type of business arrangement include our equity method investments in Cameron Highway, Deepwater Gateway and Poseidon. A-18

OTHER COMMITMENTS Long-term debt-related commitments. We have long-term payment obligations under our senior and senior subordinated notes. See Note 4 for a description of these debt obligations. Operating lease commitments. We lease certain storage facilities located in Texas (one natural gas facility and two NGL facilities). At September 30, 2004, the future minimum lease payments associated with these operating lease commitments are as follows: $0.4 million, 2004; $7 million, 2005; $7 million, 2006; $5.8 million, 2007; $3.2 million, 2008; and $1.8 million thereafter. 10. ACCOUNTING FOR HEDGING ACTIVITIES A majority of our commodity purchases and sales, which relate to sales of oil and natural gas associated with our production operations, purchases and sales of natural gas associated with pipeline operations, sales of natural gas liquids ("NGL") and purchases or sales of gas associated with our processing plants and our gathering activities, are at spot market or forward market prices. We use futures, forward contracts, and swaps to limit our exposure to fluctuations in the commodity markets and allow for a fixed cash flow stream from these activities. In February and August 2003, we entered into derivative financial instruments to hedge our exposure during 2004 to changes in natural gas prices relating to gathering activities in the San Juan Basin. In September 2004, we settled the open San Juan natural gas hedges for October, November and December 2004, prior to their expiration date and prior to our merger with Enterprise. The derivatives were financial swaps on 30,000 MMBtu per day whereby we received an average fixed price of $4.23 per MMBtu and paid a floating price based on the San Juan index. As a result of our early settlement of the open San Juan natural gas hedges, we paid the counterparties, J. Aaron and Company and UBS Energy LLC, $2.5 million during the third quarter of 2004. The derivatives were marked to fair value just prior to settlement and the loss on the settlement was recorded in accumulated other comprehensive income and will be reclassified to earnings in the periods that the previously hedged transaction would have occurred. In September 2004 and prior to our merger with Enterprise, we entered into a derivative financial instrument to hedge our exposure during November 2004 through March 2005 to changes in natural gas prices relating to gathering activities in the San Juan Basin. The derivative is a financial swap on 40,000 MMBtu per day whereby we receive a fixed price of $6.71 per MMBtu and pay a floating price based on the San Juan index. As of September 30, 2004, the fair value of this cash flow hedge was a liability of $0.7 million, as the market price at this date was higher than the hedge price. As a result of our merger with Enterprise on September 30, 2004, Enterprise assumed the liability associated with the hedge. We are accounting for this derivative as a cash flow hedge under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. No ineffectiveness exists in this hedging relationship because all purchase and sales prices are based on the same index and volumes as the hedge transaction. The counterparty for the San Juan hedge activity is UBS Energy LLC. We do not require collateral or anticipate non-performance by this counterparty. During 2003, we entered into derivative financial instruments to hedge a portion of our business' exposure to changes in NGL prices during 2004. We entered into financial swaps for 6,000 barrels per day for the period from August 2003 to September 2004. The average fixed price received was $0.47 per gallon for 2004 while we paid a monthly average floating price based on the Oil Pricing Information Service average price for each month. In September 2004, these cash flow hedges expired and for the six months ended June 30, 2004 and the three months ended September 30, 2004, we reclassified approximately $4.6 million and $5.2 million of unrealized losses from accumulated other comprehensive income to earnings. These reclassifications are included in our natural gas pipelines and plants segment. No ineffectiveness exists in this hedging relationship because all purchase and sales prices are based on the same index and volumes as the hedge transaction. In connection with our GulfTerra Intrastate Alabama operations, we had fixed price contracts with specific customers for the sale of predetermined volumes of natural gas for delivery over established periods of time. We entered into cash flow hedges in 2003 to offset the risk of increasing natural gas prices. For January and February 2004, we contracted to purchase 20,000 MMBtu and for March 2004, we contracted to purchase 15,000 MMBtu. The average fixed price paid during 2004 was $5.28 per MMBtu while we received a floating price based on the A-19

Southern Natural Pipeline index as published by the periodical "Inside FERC". In March 2004, these cash flow hedges expired and we reclassified a gain of approximately $45 thousand from accumulated other comprehensive income to earnings. This reclassification is included in our natural gas pipelines and plants segment. No ineffectiveness existed in this hedging relationship because all purchase and sale prices were based on the same index and volumes as the hedge transaction. In July 2003, to achieve a more balanced mix of fixed rate debt and variable rate debt, we entered into an eight-year interest rate swap agreement to provide for a floating interest rate on $250 million of our 8 1/2% senior subordinated notes due 2011. With this swap agreement, we paid the counterparty a LIBOR based interest rate plus a spread of 4.20% and received a fixed rate of 8 1/2%. We accounted for this derivative as a fair value hedge under SFAS No. 133. In March 2004, we terminated our fixed to floating interest rate swap with our counterparty. The value of the transaction at termination was zero and as such neither we, nor our counterparty, were required to make any payments. Also, neither we, nor our counterparty, have any future obligations under this transaction. We estimate the entire $3.3 million of unrealized losses included in accumulated other comprehensive income at September 30, 2004, will be reclassified from accumulated other comprehensive income as a reduction to earnings over the next six months. When our derivative financial instruments are settled, the related amount in accumulated other comprehensive income is recorded in the income statement in operating revenues, cost of natural gas and other products, or interest and debt expense, depending on the item being hedged. The effect of reclassifying these amounts to the income statement line items is recording our earnings for the period related to the hedged items at the "hedged price" under the derivative financial instruments. 11. BUSINESS SEGMENT INFORMATION Historically, we have segregated our business activities into four distinct operating segments: Natural gas pipelines and plants; Oil and NGL logistics; Natural gas storage; and Platform services. Each of our segments are business units that offer different services and products that are managed separately since each segment's operations required different technology and marketing strategies. Prior our merger with Enterprise, we used performance cash flows to (i) evaluate the performance of our business segments, (ii) determine how resources would be allocated among the segments and (iii) develop strategic plans for our overall business. We defined performance cash flows as earnings before interest, depreciation and amortization and other adjustments. Historically, our lenders and equity investors viewed our performance cash flows measure as an indication of our ability to generate sufficient cash to meet debt obligations or to pay distributions to partners. In addition, this non-GAAP measure was useful to investors because it allowed them to evaluate the effectiveness of our business segments from an operational perspective, exclusive of the costs to finance those activities and depreciation and amortization (neither of which are directly relevant to the efficiency of those operations). Performance cash flows may not be comparable to measurements used by other companies and should not be used a substitute for net income or other performance measures. In this context and for transition purposes only, we have presented performance cash flows as our measure of segment earnings for the six months ended June 30, 2004, the three months ended September 30, 2004 and the three and nine months ended September 30, 2003. Beginning October 1, 2004, we will conform our non-GAAP financial measures to those used by Enterprise. A-20

Information by segment, together with reconciliations to the consolidated totals, is presented in the following table:

- ------------------------------------------------------------------------------- (1) Represents predominantly our oil and natural gas production activities as well as intersegment eliminations. Our intersegment revenues, along with our intersegment operating expenses, consist of normal course of business-type transactions between our operating segments. We record an intersegment revenue elimination, which is the only elimination included in the "Non-Segment Activity" column, to remove intersegment transactions. (2) Revenue from external customers for our Oil and NGL Logistics segment has been reduced by $69.8 million and $191.7 million for the quarter and nine months ended September 30, 2003 to reflect the revision of Typhoon Oil Pipeline's revenues and cost of natural gas and other products to conform to the current period presentation - see Note 1. A-21

A reconciliation of our segment performance cash flows to our consolidated net income is as follows:

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