SEC Filing | Enterprise Products Partners L.P.

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT PURSUANT

TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported): August 16, 2006

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	1-14323	76-0568219
(State or Other Jurisdiction of Incorporation or Organization)	(Commission File Number)	(I.R.S. Employer Identification No.)

1100 Louisiana, 18th Floor
Houston, Texas 77002
(Address of Principal Executive Offices, including Zip Code)

(713) 381-6500
(Registrant’s Telephone Number, including Area Code)

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):

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01. Regulation FD Disclosure.

In accordance with General Instruction B.2 of Form 8-K, the following information shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933, as amended.

On August 16, 2006, Robert G. Phillips, and several members of senior management of Enterprise Products Partners L.P. (“Enterprise Products Partners”), gave a presentation to investors and analysts regarding the businesses, growth strategies and recent financial performance of Enterprise Products Partners. Mr. Phillips is the President and Chief Executive Officer of Enterprise Products GP, LLC, the general partner of Enterprise Products Partners. Enterprise Products Partners is a North American midstream energy company that provides a wide range of services to producers and consumers of natural gas, natural gas liquids (“NGLs”), and crude oil. In addition, Enterprise Products Partners is an industry leader in the development of pipeline and other midstream assets in the continental United States and Gulf of Mexico.

A copy of the presentation is filed as Exhibit 99.1 to this Current Report on Form 8-K. In addition, interested parties will be able to view the presentation by visiting Enterprise Products Partners’ website, www.epplp.com. The presentation will be archived on its website for 90 days.

Unless the context requires otherwise, references to “we,” “our,” “EPD,” or the “Company” within the presentation or this Current Report on Form 8-K shall mean Enterprise Products Partners and its consolidated subsidiaries. References to “EPE” refer to Enterprise GP Holdings L.P., which is the sole member of Enterprise Products GP, LLC. EPE and its general partner and the Company and its general partner are under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO, Inc. (“EPCO”). Mr. Duncan is the primary sponsor of the Company’s activities.

References to “GTM” or “GulfTerra” mean Enterprise GTM Holdings L.P., the successor to GulfTerra Energy Partners, L.P. Also, “merger with GTM” or “GTM Merger” refers to the merger of GulfTerra with a wholly owned subsidiary of Enterprise Products Partners on September 30, 2004 and the various transactions related thereto.

The presentation contains various forward-looking statements. For a general discussion of such statements, please refer to Slide 2.

USE OF INDUSTRY TERMS AND OTHER ABBREVIATIONS IN PRESENTATION

As used within the Investor Presentation, the following industry terms and other abbreviations have the following meanings:

Bcf

Billion cubic feet

Bcf/d

Billion cubic feet per day

BEF

An octane enhancement production facility wholly-owned by the Company

bph

Barrels per hour

CAGR

Compound Annual Growth Rate

Cameron Highway

or CHOPS

Cameron Highway Oil Pipeline

CGP

Chemical grade propylene

DCF

Distributable Cash Flow

EBITDA

Earnings before interest, taxes, depreciation and amortization

FERC

Federal Energy Regulatory Commission

GOM

Gulf of Mexico

General partner

IDR

Incentive distribution rights

LNG

Liquefied natural gas

Limited partner

LPG

Liquefied petroleum gas

MAPL

Mid-America Pipeline System, an NGL pipeline system wholly-owned by the Company

Use of Industry Terms and Other Abbreviations in Presentation (Continued)

MBPD

Thousand barrels per day

Mdth/d

Million decatherms per day

MLP

Master Limited Partnership

MMBbls

Million barrels

MMBbl/yr

Millions of barrels per year

MMBPD

Millions of barrels per day

MMDth/d

Millions of decatherms per day

MMcf/d

Million cubic feet per day

MTBV, MB or

Mont Belvieu

Mont Belvieu, Texas

NGL

Natural gas liquid

NYSE

New York Stock Exchange

PGP

Polymer grade propylene

RGP

Refinery grade propylene

ROI

Return on investment

TBtu/d

Trillion British thermal units per day

Tcf

Trillion cubic feet

TEPPCO

TEPPCO Partners, L.P.

WACC

Weighted-average cost of capital

USE OF NON-GAAP FINANCIAL MEASURES

Our presentation includes references to the non-generally accepted accounting principle (“non-GAAP”) financial measures of gross operating margin, distributable cash flow, EBITDA and Consolidated EBITDA. To the extent appropriate, this Current Report on Form 8-K provides reconciliations of these non-GAAP financial measures to their most directly comparable historical financial measures calculated and presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Our non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance.

Gross Operating Margin

Gross operating margin amounts (Slides 9, 10, 130 and 162). We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The GAAP measure most directly comparable to total segment gross operating margin is operating income.

We define total segment gross operating margin as operating income before: (i) depreciation, amortization and accretion expense; (ii) operating lease expenses for which we do not have the payment obligation; (iii) gains and losses on the sale of assets; and (iv) general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest, cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intercompany transactions. In accordance with GAAP, intercompany accounts and transactions are eliminated in consolidation. Our non-GAAP financial measure of total segment gross operating margin should not be considered as an alternative to GAAP operating income.

We include earnings from equity method unconsolidated affiliates in our measurement of segment gross operating margin. Our joint ventures with industry partners are a vital component of our business strategy. They are a means by which we conduct our operations to align our interests with those of our customers, which may be a supplier of raw materials to the joint venture or a consumer of products made by the joint venture. This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk we

assume versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations. As circumstances dictate, we may increase our ownership interests in such investments, which could result in their subsequent consolidation into our operations.

Reconciliations of our non-GAAP quarterly gross operating margin amounts (as shown in our presentation) to their respective GAAP operating income amounts are presented as Schedule A to this Current Report on Form 8-K.

Distributable Cash Flow

Distributable cash flow. We define distributable cash flow as net income or loss plus: (i) depreciation, amortization and accretion expense; (ii) operating lease expenses for which we do not have the payment obligation; (iii) cash distributions received from unconsolidated affiliates less equity in the earnings of such unconsolidated affiliates; (iv) the subtraction of sustaining capital expenditures; (v) the addition of losses or subtraction of gains relating to the sale of assets; (vi) cash proceeds from the sale of assets or return of investment from unconsolidated affiliates; (vii) gains or losses on monetization of financial instruments recorded in accumulated other comprehensive income less related amortization of such amount to earnings; (viii) transition support payments received from El Paso related to the GTM merger and (ix) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income for the period. Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to and major renewals of existing assets. Distributable cash flow is a significant liquidity metric used by our senior management to compare basic cash flows generated by us to the cash distributions we expect to pay our partners. Using this metric, our management can compute the coverage ratio of estimated cash flows to planned cash distributions.

Distributable cash flow is also an important non-GAAP financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain or support an increase in our quarterly cash distribution rate. Distributable cash flow is also a quantitative standard used by the investment community with respect to publicly traded partnerships such as ours because the value of a partnership unit is in part measured by its yield (which in turn is based on the amount of cash distributions a partnership pays to a unitholder). The GAAP measure most directly comparable to distributable cash flow is cash flow from operating activities.

Reinvested distributable cash flow (Slide 132 and 135). Our presentation includes references to the estimated amount of distributable cash flow that we have reinvested in the Company since (i) January 1, 1999 and (ii) September 30, 2004, which was the date we completed the GTM Merger. These estimates were calculated by summing our distributable cash flow amounts for the respective periods and deducting the cash distributions we paid to partners with respect to such periods.

Schedule B to this Current Report on Form 8-K presents (i) our calculation of the estimated reinvestment distributable cash flow amount for each period and (ii) a reconciliation of the underlying quarterly distributable cash flow amounts to their respective GAAP cash flow from operating activities amounts.

EBITDA

EBITDA (Slide 162). We define EBITDA as net income or loss plus interest expense, provision for income taxes and depreciation, amortization and accretion expense. EBITDA is commonly used as a supplemental financial measure by management and external users of our financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (i) the financial performance of our assets without regard to financing methods, capital structures or historical cost basis; (ii) the ability of our assets to generate cash sufficient to pay interest cost and support our indebtedness; (iii) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure; and (iv) the viability of projects and the overall rates of return on alternative investment opportunities. Because EBITDA excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the EBITDA data presented in the our presentation may not be comparable to similarly titled measures of other companies. The GAAP measure most directly comparable to EBITDA is cash flow from operating activities.

Reconciliations of our non-GAAP EBITDA amounts (as shown in the presentation) to their respective GAAP cash flow from operating activities amounts are presented as Schedule C to this Current Report on Form 8-K.

Consolidated EBITDA

Consolidated EBITDA (Slide 10 and 131). The presentation includes references to our Consolidated EBITDA, which is a financial measure calculated by Enterprise Products Operating L.P. (our “Operating Partnership”) in connection with the provisions of its multi-year revolving credit facility. Schedule D presents the Operating Partnership’s calculation of quarterly Consolidated EBITDA amounts along with a reconciliation to its closest GAAP counterpart, which is cash flow from operating activities.

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

Exhibit Number	Exhibit
99.1	Enterprise Products Partners L.P. investor and analyst presentation, August 16, 2006.

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, as general partner

Date: August 16, 2006	By: ___/s/ Michael J. Knesek_______________
		Michael J. Knesek
		Senior Vice President, Controller
		and Principal Accounting Officer
		of Enterprise Products GP, LLC

Enterprise Products Partners L.P.				Schedule A
Gross Operating Margin by Segment (Dollars in 000s, Unaudited)

		For the Quarterly Period
		4Q 04	1Q 05	2Q 05	3Q 05
Gross operating margin by segment:
	NGL Pipelines & Services	$142,466	$153,304	$120,328	$ 153,760
	Onshore Natural Gas Pipelines & Services	72,049	79,358	84,903	93,513
	Offshore Pipelines & Services	33,901	23,224	22,034	16,922
	Petrochemical Services	30,784	19,328	18,610	47,621
Total segment gross operating margin		279,200	275,214	245,875	311,816
Adjustments to reconcile Non-GAAP "Gross Operating Margin"
to GAAP "Operating Income"
	Deduct depreciation and amortization in operating costs and expenses	(99,060)	(99,965)	(101,048)	(103,028)
	Deduct operating lease expense paid by EPCO	(885)	(528)	(528)	(528)
	Add/Deduct gains (losses) on sales of assets	16,059	5,436	(83)	(611)
	Deduct general and administrative expenses	(20,030)	(14,693)	(18,710)	(13,252)
Operating Income		$175,284	$165,464	$125,506	$ 194,397


		For the Quarterly Period
		4Q 05	1Q 06	2Q 06
Gross operating margin by segment:
	NGL Pipelines & Services	$152,314	$170,950	$146,414
	Onshore Natural Gas Pipelines & Services	95,302	96,803	86,651
	Offshore Pipelines & Services	15,325	17,252	20,515
	Petrochemical Services	40,501	27,518	57,044
Total segment gross operating margin		303,442	312,523	310,624
Adjustments to reconcile Non-GAAP "Gross Operating Margin"
to GAAP "Operating Income"
	Deduct depreciation and amortization in operating costs and expenses	(109,400)	(104,816)	(107,952)
	Deduct operating lease expense paid by EPCO	(528)	(528)	(528)
	Add/Deduct gains (losses) on sales of assets	(254)	61	136
	Deduct general and administrative expenses	(15,611)	(13,740)	(16,235)
Operating Income		$177,649	$193,500	$186,045

Enterprise Products Partners L.P.

Schedule B

Reinvested Distributable Cash Flow (Dollars in 000s, Unaudited)

Our computation of distributable cash flow reinvested since the GTM Merger, which closed on September 30, 2004, is as follows:

			For the Quarterly Period
			4Q 04	1Q 05	2Q 05	3Q 05
Reconciliation of Non-GAAP "Distributable Cash Flow" to GAAP
	"Net Cash Flow provided by (used in) Operating Activities"
Net Cash Flow provided by (used in) Operating Activities			$ 355,525	$ 164,246	$ (46,409)	$ 226,796
	Adjustments to reconcile Distributable Cash Flow to Net Cash Flow provided
	by (used in) Operating Activities (add or subtract as indicated):
		Sustaining capital expenditures	(21,314)	(15,550)	(21,293)	(25,935)
		Proceeds from sale of assets	6,772	42,158	109	953
		Amortization of net gain from forward-starting interest rate swaps	(857)	(886)	(896)	(905)
		Minority interest in total	(1,281)	(1,945)	(380)	(861)
		Net effect of changes in operating accounts	(146,801)	58,920	237,353	17,929
		Return of investment in unconsolidated affiliate			47,500
		El Paso transition support payments	4,500	4,500	4,500	4,500
Distributable Cash Flow			196,544	251,443	220,484	222,477
Less amounts paid to partners with respect to such period			(162,687)	(176,066)	(181,624)	(187,107)
Estimate of reinvested distributable cash flow			$ 33,857	$ 75,377	$ 38,860	$ 35,370


			For the Quarterly Period
			4Q 05	1Q 06	2Q 06
Net Cash Flow provided by Operating Activities			$ 287,075	$ 494,276	$ 77,049
	Adjustments to reconcile Distributable Cash Flow to Net Cash Flow provided
	by Operating Activities (add or subtract as indicated):
		Sustaining capital expenditures	(29,380)	(30,010)	(34,521)
		Proceeds from sale of assets	1,526	75	181
		Amortization of net gain from forward-starting interest rate swaps	(915)	(925)	(935)
		Minority interest in total	(2,574)	(2,198)	(538)
		Net effect of changes in operating accounts	(47,807)	(247,084)	172,392
		El Paso transition support payments	3,750	3,750	3,750
Distributable Cash Flow			211,675	217,884	217,378
Less amounts paid to partners with respect to such period			(193,160)	(206,580)	(214,790)
Estimate of reinvested distributable cash flow			$ 18,515	$ 11,304	$ 2,588
Total reinvested Distributable Cash Flow since GTM Merger (sum of periods)					$ 215,871

Enterprise Products Partners L.P.

Schedule B (Continued)

Reinvested Distributable Cash Flow (Dollars in 000s, Unaudited)

Our computation of distributable cash flow reinvested since January 1, 1999 is as follows:

			For the Year Ended December 31,
			1999	2000	2001	2002	2003
Reconciliation of Non-GAAP "Distributable Cash Flow" to GAAP
	"Net Cash Flow provided by Operating Activities"
Net Cash Flow provided by Operating Activities			$ 177,953	$ 360,870	$ 283,328	$ 329,761	$ 424,705
	Adjustments to reconcile Distributable Cash Flow to Net Cash Flow provided by
	Operating Activities (add or subtract as indicated by sign of number):
		Sustaining capital expenditures	(2,440)	(3,548)	(5,994)	(7,201)	(20,313)
		Proceeds from sale of assets	8	92	568	165	212
		Minority interest in earnings not included in Distributed Cash Flow	3			(1,968)	(2,967)
		Minority interest in allocation of lease expense paid by EPCO, Inc.	108	107	105	92	90
		Net effect of changes in operating accounts	(27,906)	(71,111)	25,897	(92,655)	(122,961)
		Collection of notes receivable from unconsolidated affiliates	19,979	6,519
Distributable Cash Flow			167,705	292,929	303,904	228,194	278,766
Less amounts paid to partners with respect to such period			(116,315)	(145,437)	(176,003)	(240,125)	(330,723)
Estimate of reinvested distributable cash flow			$ 51,390	$ 147,492	$ 127,901	$ (11,931)	$ (51,957)

			For the Year Ended December 31,		2006	2006
			2004	2005	1Q	2Q
Net Cash Flow provided by Operating Activities			$ 391,541	$ 631,708	$ 494,276	$ 77,049
	Adjustments to reconcile Distributable Cash Flow to Net Cash Flow provided by
	Operating Activities (add or subtract as indicated by sign of number):
		Sustaining capital expenditures	(37,315)	(92,158)	(30,010)	(34,521)
		Proceeds from sale of assets	6,882	44,746	75	181
		Amortization of net gain from forward-starting interest rate swaps	(857)	(3,602)	(925)	(935)
		Settlement of forward-starting interest rate swaps	19,405
		Minority interest in earnings not included in Distributed Cash Flow	(8,128)	(5,760)	(2,198)	(538)
		Minority interest in cumulative effect of change in accounting principle	2,338
		Net effect of changes in operating accounts	93,725	266,395	(247,084)	172,392
		Return of investment in unconsolidated affiliate		47,500
		GTM distributable cash flow for third quarter of 2004	68,402
		El Paso transition support payments	4,500	17,250	3,750	3,750
Distributable Cash Flow			540,493	906,079	217,884	217,378
Less amounts paid to partners with respect to such period			(509,118)	(737,956)	(206,580)	(214,790)
Estimate of reinvested distributable cash flow			$ 31,375	$ 168,123	$ 11,304	$ 2,588
Total reinvested Distributable Cash Flow since January 1, 1999 (sum of periods)						$ 476,285

Enterprise Products Partners L.P.			Schedule C
EBITDA (Dollars in 000s, Unaudited)
			Six Months
			Ended
			June 30,
			2006
Reconciliation of Non-GAAP "EBITDA" to GAAP "Net Income" and
	GAAP "Net Cash provided by Operating Activities"
Net income			$ 260,072
	Additions to net income to derive EBITDA:
		Add interest expense (including related amortization)	114,410
		Add provision for income taxes	9,164
		Add depreciation, amortization and accretion in costs and expenses	216,520
EBITDA			600,166
	Adjustments to EBITDA to derive Net Cash provided by Operating Activities
	(add or subtract as indicated by sign of number):
		Deduct interest expense	(114,410)
		Deduct provision for income taxes	(9,164)
		Deduct cumulative effect of change in accounting principle	(1,475)
		Deduct equity in income of unconsolidated affiliates	(12,041)
		Add amortization in interest expense	487
		Add deferred income tax expense	9,180
		Add distributions received from unconsolidated affiliates	20,348
		Add operating lease expense paid by EPCO	1,056
		Add minority interest	2,736
		Deduct gain on sale of assets	(197)
		Deduct changes in fair market value of financial instruments	(53)
		Add net effect of changes in operating accounts	74,692
Net Cash provided by Operating Activities			$ 571,325

Enterprise Products Partners L.P.						Schedule D
Consolidated EBITDA (Dollars in 000s, Unaudited)
			For the Quarterly Period
			4Q 04	1Q 05	2Q 05		3Q 05
Reconciliation of Non-GAAP "Consolidated EBITDA" to GAAP "Net Income"
	and GAAP "Net Cash provided by (used in) Operating Activities"
Net income (1)			$ 117,483	$ 109,970	$ 71,029		$ 131,344
	Adjustments to net income to derive Consolidated EBITDA
	(add or subtract as indicated by sign of number):
		Deduct equity in income of unconsolidated affiliates	(10,574)	(8,279)	(2,581)		(3,703)
		Add interest expense (including related amortization)	58,784	53,413	56,746		60,538
		Add depreciation, amortization and accretion in costs and expenses	100,408	101,887	102,617		104,562
		Add distributions from unconsolidated affiliates	13,447	21,838	17,070		8,480
		Add provision for income taxes	1,055	1,769	(1,034)		3,223
		Add return of investment in Cameron Highway			47,500
Consolidated EBITDA (2)			280,603	280,598	291,347		304,444
	Adjustments to Consolidated EBITDA to derive Net Cash provided by
	(used in) Operating Activities (add or subtract as indicated):
		Deduct interest expense	(58,784)	(53,413)	(56,746)		(60,538)
		Deduct provision for income taxes	(1,055)	(1,769)	1,034		(3,223)
		Add deferred income tax expense	3,315	1,802	2,073		1,952
		Add/Deduct amortization in interest expense	635	(477)	108		252
		Add provision for non-cash asset impairment charge	99
		Add operating lease expense paid by EPCO	885	528	528		528
		Add minority interest	1,272	1,941	391		903
		Add/Deduct (gain) loss on sale of assets	(16,059)	(5,436)	84		611
		Add/Deduct changes in fair market value of financial instruments	(77)	102	9		11
		Add/Deduct net effect of changes in operating accounts	2,224,867	(60,918)	(243,268)		(18,777)
		Deduct return of investment in Cameron Highway			(47,500)
Net Cash provided by (used in) Operating Activities (3)			$ 2,435,701	$ 162,958	$ (51,940)		$ 226,163

Notes:
(1)		Represents net income for Enterprise Products Operating L.P., the operating partnership of Enterprise Products Partners L.P.
(2)		Defined as "Consolidated EBITDA" in our Multi-Year Revolving Credit Facility
(3)		Represents Net Cash provided by (used in) Operating Activities for Enterprise Products Operating L.P.

Enterprise Products Partners L.P.			Schedule D (Continued)
Consolidated EBITDA (Dollars in 000s, Unaudited)
			For the Quarterly Period
			4Q 05	1Q 06	2Q 06
Reconciliation of Non-GAAP "Consolidated EBITDA" to GAAP "Net Income"
	and GAAP "Net Cash provided by Operating Activities"
Net income (1)			$ 108,607	$ 135,329	$ 126,320
	Adjustments to net income to derive Consolidated EBITDA
	(add or subtract as indicated by sign of number):
		Add/Deduct equity in (income) loss of unconsolidated affiliates	15	(4,029)	(8,013)
		Add interest expense (including related amortization)	59,852	58,077	56,333
		Add depreciation, amortization and accretion in costs and expenses	111,559	106,316	110,206
		Add distributions from unconsolidated affiliates	8,670	8,253	12,095
		Add provision for income taxes	4,404	2,892	6,272
Consolidated EBITDA (2)			293,107	306,838	303,213
	Adjustments to Consolidated EBITDA to derive Net Cash provided by
	Operating Activities (add or subtract as indicated by sign of number):
		Deduct interest expense	(59,852)	(58,077)	(56,333)
		Deduct provision for income taxes	(4,404)	(2,892)	(6,272)
		Add/Deduct cumulative effect of changes in accounting principles	4,208	(1,475)
		Add deferred income tax expense	2,767	1,487	7,693
		Add/Deduct amortization in interest expense	269	251	238
		Add operating lease expense paid by EPCO	528	528	528
		Add minority interest	2,754	2,199	533
		Add/Deduct (gain) loss on sale of assets	253	(61)	(136)
		Add/Deduct changes in fair market value of financial instruments		(53)
		Add/Deduct net effect of changes in operating accounts	45,431	244,509	(191,234)
Net Cash provided by Operating Activities (3)			$ 285,061	$ 493,254	$ 58,230

Notes:
(1)		Represents net income for Enterprise Products Operating L.P., the operating partnership of Enterprise Products Partners L.P.
(2)		Defined as "Consolidated EBITDA" in our Multi-Year Revolving Credit Facility
(3)		Represents cash provided by operating activities for Enterprise Products Operating L.P.

EXHIBIT 99.1

PRESENTATION

Enterprise Products Partners L.P. Analyst Conference New York August 16, 2006

Forward Looking Statements This presentation contains forward-looking statements and information that are based on Enterprise’s beliefs and those of its general partner, as well as assumptions made by and information currently available to them. When used in this presentation, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may,” and similar expressions and statements regarding the contemplated transaction and the plans and objectives of Enterprise for future operations, are intended to identify forward-looking statements. Although Enterprise and its general partner believe that such expectations reflected in such forward looking statements are reasonable, neither it nor its general partner can give assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from those Enterprise anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on Enterprise’s results of operations and financial condition are: Fluctuations in oil, natural gas and NGL prices and production due to weather and other natural and economic forces; A reduction in demand for its products by the petrochemical, refining or heating industries; The effects of its debt level on its future financial and operating flexibility; A decline in the volumes of NGLs delivered by its facilities; The failure of its credit risk management efforts to adequately protect it against customer non-payment; Actual construction and development costs could exceed forecasted amounts; Operating cash flows from our capital projects may not be immediate; Terrorist attacks aimed at its facilities; and The failure to successfully integrate its operations with assets or companies, if any, that it may acquire in the future. Enterprise has no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Use of Non-GAAP Financial Measures This presentation utilizes the Non-GAAP financial measures of Gross Operating Margin and Consolidated EBITDA, and makes references to EBITDA and Distributable Cash Flow. In general, we define Gross Operating Margin as operating income before (i) depreciation, amortization and accretion, (ii) operating lease expense for which we do not have the payment obligation, (iii) gains and losses on the sale of assets and (iv) general and administrative expenses. We define EBITDA as net income or loss before interest; provision for income taxes; depreciation, amortization and accretion expense. In general, we define Distributable Cash Flow as net income or loss plus (i) depreciation, amortization and accretion expense; (ii) operating lease expense for which we do not have the payment obligation; (iii) cash distributions received from unconsolidated affiliates less equity in the earnings of such affiliates; (iv) the subtraction of sustaining capital expenditures; (v) gains and losses on the sale of assets; (vi) cash proceeds from the sale of assets or return of investment from unconsolidated affiliates; (vii) gains or losses on monetization of financial instruments recorded in Accumulated Other Comprehensive Income less related amortization of such amount to earnings; (viii) transition support payments received from El Paso related to the GTM merger and (ix) the addition of losses or subtraction of gains related to other miscellaneous non-cash amounts affecting net income for the period. Distributable Cash Flow is a significant liquidity metric used by our senior management to compare basic cash flows generated by us to the cash distributions we expect to pay partners. Distributable cash flow is also an important Non-GAAP financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment. Distributable cash flow is also a quantitative standard used by the investment community with respect to publicly traded partnerships such as ours because the value of a partnership unit is in part measured by its yield (which in turn is based on the amount of cash distributions a partnership pays to a unit holder). The GAAP measure most directly comparable to Distributable Cash Flow is net cash provided by operating activities. This presentation also includes references to credit leverage ratios that utilize Consolidated EBITDA, which is a term defined in the $1.25 billion revolving credit facility of Enterprise Products Operating L.P. These credit ratios are used by certain of our lenders to evaluate our ability to support debt service. The GAAP measure most directly comparable to Consolidated EBITDA is net cash provided by operating activities. Please see Slides 165, 166 and 167 for our calculations of Gross Operating Margin, Consolidated EBITDA and EBITDA along with the appropriate reconciliations.

Meeting Agenda Michael A. Creel - Introduction Robert G. Phillips - Business Introduction James H. Lytal - Natural Gas Pipelines / Storage / Offshore A.J. “Jim” Teague - Natural Gas Processing / NGLs James M. Collingsworth - Regulated NGL Pipelines Gil H. Radtke - Petrochemical Services Richard H. Bachmann - Corporate Governance Michael A. Creel - Financial Overview Robert G. Phillips - Closing Remarks Appendix

Introduction / Overview Michael A. Creel

Business Overview One of the largest publicly traded energy partnerships serving producers and consumers of natural gas, natural gas liquids (NGLs) and crude oil Enterprise value of over $16 billion Ranked 183rd on Fortune 500 list Only integrated North American midstream network that includes natural gas and NGL transportation, fractionation, processing, storage and import / export services NGL products are ethane, propane, normal butane, isobutane and natural gasoline, which are used as raw materials by the petrochemical industry or motor gasoline refining industry Links producers of natural gas and NGLs from many of the largest supply basins in the United States, Canada and the Gulf of Mexico with the largest consumers of NGLs and international markets Leading business positions across the energy value chain

EPD’s Partnership Structure Largest % ownership by management in MLP sector EPCO has consistently supported growth in EPD Purchased approximately $450 million of new issue equity since IPO Capped GP’s incentive split at 25% for no consideration Contributed half of GTM GP to EPD for no consideration - approximately $460 million in value Value of EPCO’s holdings in EPD and EPE units - approx. $6.7 billion EPCO affiliates receive approx. $360 million in annual cash distributions from EPD directly and indirectly through EPE based on current distribution rates

Key Investment Considerations Strategically located assets serving the most prolific supply basins of natural gas, NGLs and crude oil in the United States Leading business position in each segment of the midstream sector Over 90% of gross operating margin from diversified fee-based assets which enhances stability of EPD’s cash flows Strong, strategic relationships on both the supply and demand sides of the midstream business Maintenance of financial flexibility and investment grade credit metrics: a key financial objective 25% GP split cap reduces cash paid to GP and enhances EPD’s financial flexibility Experienced management team with substantial ownership

Diversified Business Mix Diversification of businesses provides multiple earnings streams and reduces risk NGL Pipelines & Services (50%) Natural gas processing plants & related marketing activities NGL fractionation plants NGL pipelines and storage Onshore Natural Gas Pipelines & Services (30%) Natural gas pipelines Natural gas storage facilities Offshore Pipelines & Services (6%) Natural gas pipelines Oil pipelines Platform services Petrochemical Services (14%) Propylene fractionation facilities Butane isomerization facilities Octane enhancement facilities

Consistent Results from Diversified Businesses Stability and consistency in Gross operating margin “Consolidated EBITDA” Reflects benefits of Integrated value chain Fee-based businesses In spite of three major hurricanes in the last two years Since GTM merger, effectively hedged to swings in natural gas prices

EPD’s Organic Growth and Lower Cost of Capital Drives Cash Flow Accretion “Cash is King” in the partnership sector Cash flow generated by a new investment supports the long-term cost of capital to fund the investment plus provides accretion for existing LP units outstanding Many analysts / investors focus only on the current cash cost of equity capital which ignores the cost of future distribution increases including distributions to the GP through incentive distribution rights (IDRs) Recent acquisitions of mature assets at EBITDA multiples of 10x and greater may provide accretion in near term, but may result in dilution in future years as LP and GP distributions increase EPD’s combination of higher returns associated with organic growth projects and 25% cap on GP IDRs should provide enduring accretion versus partnerships with lower return acquisitions and 50% GP IDRs

Business Introduction Robert G. Phillips

Premier Network of Midstream Energy Assets Key Assets of Enterprise Products Partners 19,470 miles of natural gas pipeline 13,499 miles of NGL & petrochemical pipeline 871 miles of GOM crude oil pipeline 148 MMBbls of NGL storage capacity 25 Bcf of natural gas storage capacity 7 offshore hub platforms 16 NGL & propylene fractionation plants and a butane isomerization complex 29 natural gas processing / treating plants

Competitive Advantages Integrated energy value chain with fees earned in each link of the value chain Diversified business mix with access to prolific supply regions and providing services to high demand markets Significant organic growth opportunities given our size and scale of operations Low cost of capital and size of cash flow base Supportive GP sponsor and experienced management team

Leading Business Positions Across Midstream Energy Value Chain

Integrated Midstream Energy Services Fees are earned at each link of value chain

Integrated Midstream Energy Services Competitive Position and Outlook Production Platforms Position Seven offshore platforms serve Deepwater GOM Marco Polo in process of ramping up Independence Hub platform in early 2007 Future tie backs as smaller fields develop Outlook 17 Deepwater discoveries since January 2005 South Green Canyon / Atwater Valley areas continue to develop Smaller producers like the Marco Polo / Independence model Long-term drilling contracts indicate future developments

Integrated Midstream Energy Services Competitive Position and Outlook Natural Gas and Crude Oil Pipelines Position Largest gas gatherer at 6+ Bcf/d (19,500 miles of oil and gas pipeline) One of the largest gas pipeline systems in Texas with access to South Texas, Barnett Shale, Bossier and Permian Largest conventional gas gatherer in San Juan basin Jonah Gas Gathering joint venture in Wyoming Independence Trail will add 1 Bcf/d of capacity in the Gulf of Mexico CHOPS and Poseidon oil pipelines well positioned in Gulf of Mexico Outlook Prices drive record drilling activity Focus on unconventional plays Renegotiate San Juan Basin gathering contracts; record well connects in 2006 Margin expansion on Texas pipeline; Barnett Shale extends to Waha area Gas storage expansions at Petal and Wilson; evaluating conversion of NGL caverns to gas service Atlantis and Genghis Khan deepwater oil fields in service in early 2007

Integrated Midstream Energy Services Competitive Position and Outlook Gas Processing Position 3rd largest processor at 6.6 Bcf/d (25 plants with 15 Bcf/d gross capacity) 250-300 MBPD feeds downstream assets; approximately 180 MBPD of NGLs extracted from EPD operated plants South Louisiana: Toca, Venice and Yscloskey back on line South Texas plants at 1.4 Bcf/d (80 MBPD) Chaco (San Juan) remains 3rd largest in United States Outlook Meeker (Piceance) and Pioneer (Jonah / Pinedale) plants add 1.4 Bcf/d (75 MBPD) of capacity Strong processing margins in 2006 due to higher product prices and lower gas prices Improving processing economics by daily decisions and plant upgrades New Deepwater production to boost Louisiana processing plants

Integrated Midstream Energy Services Competitive Position and Outlook NGL Pipelines Position Largest NGL pipeline network (13,500 miles) connects supplies to Mont Belvieu and Conway hubs to markets Transports 1.2 MMBPD Y-grade and finished products Provides 55-60 MMBbl/yr propane to heating / agriculture and industrial markets Connected to 97% of ethylene steam cracking plants in the United States and over 90% of the motor gasoline refinery market east of the Rockies Outlook MAPL Phase I Rocky Mountain expansion (50 MBPD) to be completed in 2007; obtained long-term dedications with major shippers on MAPL Expansion of Conway to Hobbs system improves arbitrage opportunity Fully integrated South Texas NGL assets with EPD Mont Belvieu assets; ExxonMobil P/L acquisition creates Lou-Tex style optionality

Integrated Midstream Energy Services Competitive Position and Outlook NGL Fractionation Position Leading United States fractionator with 9 plants and 450-500 MPBD gross throughput Mont Belvieu fractionators running at capacity Mont Belvieu West Texas II fractionator expansion completed in April 2006 Louisiana plants back on line and running consistently Outlook New Hobbs fractionator (75 MBPD) to support increased Rockies volumes from Meeker and Pioneer Optimize / consolidate fractionation capacity amongst Mont Belvieu, Hobbs and South Texas plants Lower operating costs due to improved fuel efficiency and lower gas prices Balancing increased Y-grade vs. increasing propane and mixed butane imports

Integrated Midstream Energy Services Competitive Position and Outlook NGL Storage, Marketing and Distribution Position Largest NGL storage provider (148 MMBbls) 6 MMBbls Ferrellgas storage and terminals acquisition expanded network to western United States and Mid-Continent 650 MBPD United States products sales and refinery services 61% market share of LPG imports and 88% market share of LPG exports YTD 2006 Outlook Expanding storage and brine capacity at Mont Belvieu Long-term import contracts with major international LPG producers Announced expansion of import / export terminal at OTTI Increase product sales and refinery services business as refinery expansions develop during 2007-2010

Natural Gas Pipelines and Storage and Offshore Pipelines and Services James H. Lytal

Texas Pipeline System

Texas Pipeline System 8,222-mile gathering and transportation system with 6.4 Bcf storage YTD 2006 throughput 3.4 TBtu/d Connected to major supply basins North Texas (Barnett Shale) East Texas (Bossier) South Texas (Wilcox, Vicksburg) Permian Basin Connected to all major Texas Markets San Antonio, Austin, DFW, Houston Houston Ship Channel (HSC), Beaumont, Corpus Christi Waha, Carthage, Agua Dulce Hubs 19 power plants Potential for system expansions to support new Barnett Shale production Well-positioned for LNG imports

Texas Drilling Statistics Monthly Average Rig Count Rig Count continues to increase in Barnett, Bossier and Delaware Basins

Barnett Shale Production Growth North Texas Barnett Shale and Bossier producing areas continuing to grow Will need new long-term pipeline capacity Far West Texas Barnett and Woodford Shale plays will provide new opportunities EPD currently transports approximately 450 MMcf/d of Barnett Shale production

2005-2006 GDA Monthly Average Spreads (Waha to HSC)

2005 Highlights Re-contracted or extended term on over 600 MMcf/d Entered into 42 new firm contracts with 20 different customers Transportation revenues increase $16 million All new contracts at increased rates Terms of new contracts range from 3-10 years

2006 Highlights Completed system expansions of 240 MMcf/d 120 MMcf/d West Texas 30” expansion 120 MMcf/d Carthage compression addition Supported by long-term commitments from existing customers and fuel savings Executed long-term agreements with CenterPoint to serve a portion of their Greater Houston Area gas requirements Executed long-term agreements with Shell to transport up to 150 MMcf/d to support expansion of delivery capabilities into Mexico Completed Cerritos gathering system acquisition

West Texas Expansion Addition of 120 MMcf/d capacity Installed 4 new compressors with 24,300 horsepower Supported by 5-year firm transport agreements with City of San Antonio and Devon

CenterPoint Transaction Executed long-term contracts with CenterPoint LDC to serve a portion of their Houston area load Service begins April 1, 2007 and estimated annual demand is approximately 14 Bcf Contracts support estimated cost to connect Enterprise pipelines to 11 high-growth CenterPoint LDC locations and expand existing storage facilities Potential to pick up additional markets in the Houston area

Cerrito Acquisition

Cerrito Acquisition Purchase Price: $325 million ($146 million in cash & approximately 7.1 million EPD common units) for: Approximately 484 miles of gathering, 31,000 compression horsepower and related assets in Webb, Dimmit, Zavala, Frio and LaSalle counties in South Texas Life of lease dedication for the gathering and processing of Lewis’ gas from the Olmos formation - approximately 335,000 acres and current production of 45 MMcf/d Ten year gathering and processing dedication of future rich deep gas and Mexico gas Ten year gathering dedication of lean gas 3rd party gathering and processing agreements Current volumes are approximately 100 MMcf/d of 4-6 gpm gas projected to grow to 230 MMcf/d by 2012 Significant volume growth associated with Eagleford Shale, Austin Chalk and Mexico gas. Anadarko and Chesapeake have large acreage positions in the area.

Cerrito Gas Supply Over 1,450 wells currently connected and flowing over 100 MMcf/d of sweet gas Olmos / Wilcox are the primary reservoirs 1,500 remaining Olmos locations to drill Other formations expected to contribute significantly to future volumes Austin Chalk “B2” Eagleford Shale (reportedly 6 gpm) Cretaceous Limestones 1.5 Tcf Estimated Recoverable Reserves over next 20 years per Enterprise’s estimates

Historical and Projected Cerrito Volumes

San Juan and Permian

San Juan Gathering and Processing Gathering attributes 5,404+ miles of pipeline 276,909 hp compression Pressure ranges from 35 to 325 psig 10,450+ wells connected 1.189 Tbtu/d gathered YTD 2006 Processing facilities Chaco Plant capacity: 650 MMcf/d 500 MMcf/d processed YTD 2006 38,275 Bbls/d 8,086 Bbls/d equity YTD 2006 Major producers: ConocoPhillips, BP, XTO

San Juan Basin Optimization Optimization Project 300+ projects Completed December 2005 Increased pigging capabilities Added TW interconnect Increased capacity by 150 Mdth/d Lowered pressures Strong volume response since completion of the project

San Juan Basin Well Ties

San Juan Area Reserves Reserve to Production Ratios Conventional: 1.6 Bcf/d 27 yrs. Proved / Probable 46 yrs. Proved / Probable / Possible Coal: 2.5 Bcf/d 19 yrs. Proved / Probable 22 yrs. Proved / Probable / Possible

San Juan Basin Production Outlook

Carlsbad Gathering Carlsbad Gathering System 186 MMDth/d gathered YTD 2006 820 miles of pipe 560+ wells connected Major customers: Mewbourne, Devon, EOG NGPL Interconnect Capacity: 80 MMcf/d Supported by EOG commitment Increased system capacity In-service August 2006 South Carlsbad Dew Point Plant Capacity: 150 MMcf/d In-service December 2006 Stable fee based business Assures reliability of flow

Waha Gathering and Treating Waha Gathering System 260 MMdth/d gathered YTD 2006; 24% increase over 2005 volume Currently treat 130+ MMcf/d 630 miles of pipe; 250+ wells connected Major customers: Anadarko, ExxonMobil, Forest, ChevronTexaco Morrow Gas Play Major players: Anadarko, Chesapeake Current production: 128 MMdth/d on EPD 42 wells producing; 14 being completed; 30 permits 14 rigs running in the area; 24 expected end of 2006 Barnett Shale Play Major players: Petro Hunt, Chesapeake, Encana, EOG 1,000,000+ total acres leased with 45,000 acres dedicated to EPD to date Current activity: 51 permits, 9 completed wells, 2 wells connected to EPD

Permian System Throughput

Natural Gas Storage

Petal and Hattiesburg Gas Storage Completed 2.4 Bcf working gas conversion of brine cavern in 2005 Supported by 1.8 Bcf capacity lease with BP 13.9 Bcf of capacity sold under long-term contracts Petal is developing an additional storage cavern 5 Bcf working gas capacity Well drilled; Leaching begins 8/15/06 In-service: April 1, 2008 In negotiations on all capacity at rates that provide a 5-year payout

Petal Gas Storage In September 2006, Petal expects to file for FERC approval to convert 1 brine cavern and 3 Petal NGL caverns to natural gas use Provides for an additional 3.1 Bcf of working gas at Petal Estimated completion date: 3Q 2007 Expect 4 year payout at current market rates

Comparison of Economics & Returns of Natural Gas Storage vs. NGL Storage EPD has the largest storage position at Mont Belvieu, with 94 million barrels of NGL and petrochemical storage

Comparison of Economics & Returns of Natural Gas Storage vs. NGL Storage Actions to realize higher return on storage assets given shortage of United States natural gas storage capacity Increase NGL storage fees at Mont Belvieu Convert NGL storage capacity to natural gas storage consistent with actions at Petal, Mississippi Develop new natural gas storage facilities

Deepwater Gulf of Mexico

Deepwater Gulf of Mexico Overview EPD and its predecessors have been investing in pipeline and platform projects in the Gulf of Mexico since 1993 EPD’s current integrated oil / gas pipeline and platform network covers most major corridors with active deepwater developments Significant new projects have or will be completed in 2004-2007 which are supported by substantial life of lease reserve dedications and active development drilling Weather-related delays and equipment availability have slowed expected production rates, but should see significant increases in 2007

Enterprise Gulf of Mexico Assets

Gulf of Mexico Drilling Activity

Deepwater Trend 2005/2006 Update “The deepwater discoveries to date represent a strong continuing success story in the Gulf of Mexico. We are off to a great start in calendar year 2006.” - - Chris Oynes MMS Regional Director, July 18, 2006

Marco Polo Platform Owner: EPD 50% / Helix 50% Operator: EPD Tension leg platform in 4,300 feet located in prolific South Green Canyon area Platform designed for 120 MBPD and 300 MMcf/d Demand charges of $2.1 million/month and volumetric fees Recent production of 43 MBPD and 33 MMcf/d with majority from K2 (2 wells) and K2 North (2 wells) New production to be added by 3Q 2006 from K2 (1 well) and K2 North (1 well) New production to be added by 1Q 2007 from Genghis Khan (2 wells)

Constitution Oil and Gas Pipelines Owner / operator: EPD First production: February 15, 2006 (ahead of schedule) Currently moving 34 MBPD and 132 Mdth/d from 2 wells at Ticonderoga and 4 wells at Constitution; 2 additional wells planned at Constitution Feeds downstream Anaconda (gas), Cameron Highway and Poseidon pipelines Potential processing, transportation and fractionation opportunities at EPD onshore facilities Discoveries: Caesar, Tonga Numerous prospects nearby

Cameron Highway Oil Pipeline System (CHOPS) Owner: EPD 50% / Valero 50% Operator: EPD Dedications: Holstein, Mad Dog, Atlantis, Constitution, K2, Ticonderoga 15 wells flowing of 50 planned from Holstein, Mad Dog and Atlantis Atlantis: first flows expected in 1Q 2007 Averaged approximately 80 MBPD in 2Q 2006 Ramp up of Mad Dog and Atlantis should increase volumes to over 300 MBPD in 2008 based on producer forecasts Discoveries: Shenzi, Tahiti, Neptune, Puma, Knotty Head, Pony, Caesar, Big Foot, Cascade, Chinook, Cottonwood

Poseidon Oil Pipeline System Owner: EPD 36%, Shell 36%, Marathon 28% Operator: EPD Average 2005 volumes: 120 MBPD August 2006 forecast: 181 MBPD (highest since June 2000) benefiting from diverted volumes from CHOPS Increase due to new production from K2, K2 North, Constitution, Ticonderoga, Holstein (Shell’s 50% interest) and Brutus fields

Increased Crude Oil Deliveries Increase in overall volumes less than expected primarily due to effect on producers from delays and equipment shortages caused by 2005 hurricanes CHOPS volumes impacted by BP’s Texas City refinery complex operating at 50% of capacity Partially offset by Poseidon benefiting from volumes being diverted from CHOPS to higher value markets in Louisiana and CHOPS receiving revenue on certain diverted volumes Expect BP Texas City facility to restart in 2H 2006 Refinery expansions by Valero and Marathon in Texas should create additional demand for Southern Green Canyon volumes via CHOPS

Southern Green Canyon: Continued Exploration Success

South Green Canyon Summary Anticipate finalizing new oil gathering opportunity in South Green Canyon World class oil basin 955 to 1,165 MBPD of capacity upstream of Cameron Highway and Poseidon Anchor tenants active and firmly committed to the area Expansion of franchise area to the south into Walker Ridge

Independence Hub Platform & Trail Pipeline Hub (80% Enterprise) / Pipeline (100% Enterprise) Expanded Hub and Pipeline to 1 Bcf/d capacity Three additional discoveries since project was sanctioned Producers: Anadarko, Kerr-McGee, Dominion, Spinnaker, Devon New 134-mile 24” gas pipeline

Independence Construction Update Hull arrived KOS facility: June 24th Topside and hull fabrication are almost complete Deck to be placed on hull in early September 2006 Pipeline installation complete on or around August 18th West Delta 68 jacket installed West Delta 68 deck installation and commissioning: September 2006 Expected hull installation: 4Q 2006 Expected pipeline commissioning and mechanical completion: 1Q 2007 First monthly demand charge payment of approximately $4.6 million expected in 1Q 2007 First production expected in 2Q 2007

Independence Hub Subsea 104 blocks dedicated for life of lease to the Independence Hub Project 1st eastern Gulf well tested at more than 60 MMcf/d Independent audit confirmed reserves in anchor discoveries 197 miles of subsea flowlines under construction for anchor discoveries

Eastern Gulf of Mexico New Acreage Potential Area available for leasing adjacent to Hub could increase by 8 million acres Senate bill endorsed by White House and Florida senator Senate bill passed August 1, 2006 Subject to conference committee with House

Natural Gas Processing and Natural Gas Liquids (NGLs) A.J. “Jim” Teague

Strong NGL Industry Fundamentals U.S. ethylene production has rebounded from the mid-year 2003 troughs Key factors are the economy and GDP growth, plant operating rates and gas-to-crude price ratio Ethane extraction increases as ethylene production increases History has shown that industry flexibility to switch off ethane cracking diminishes as ethylene production remains at 53 billion lbs/year or higher Gas-to-crude ratios and crack spreads are less of a factor as ethylene production rates remain at or greater than 53 billion lbs/year - - currently at 59 billion lbs/year

NGL Assets

Natural Gas Processing 99%+ of contract portfolio is fee-based and %-of-proceeds in a low frac spread environment

Natural Gas Processing Equity NGLs per Contract Type (MBPD)

Rocky Mountain Assets / Activity

Jonah and Pinedale Fields Growth

Jonah Gas Gathering System Jonah Gas Gathering System Approximately 600+ miles of pipe / 92,000 HP of compression Serves 900+ producing wells in Jonah and Pinedale fields Joint Venture with TEPPCO Announced August 2006 EPD will earn approximately 20% interest through funding of current expansion projects EPD will manage expansion projects and operate system Expansion Increases system capacity from 1.5 to 2.4 Bcf/d Lowers field and wellhead pressures Complete in stages by late-2007

Pioneer Processing Plants Existing Silica Gel Plants EPD purchased 300 MMcf/d plant from TEPPCO in early 2006 Expansion to 600 MMcf/d capacity complete in July 2006 Will serve as backup to new cryogenic plant New Cryogenic Plant 650 MMcf/d cryogenic plant under construction Capable of full NGL extraction, ethane rejection or dew point control At full NGL extraction, capacity of 30 MBPD Residue connections to Kern, NWPL, CIG and Rockies Express / Overthrust planned Y-grade connection to MAPL Completion scheduled for 3Q 2007

Piceance Basin Growth The Piceance Basin has grown by over 20% annually for the past 5 years.

Meeker Processing Plants Phase I New 750 MMcf/d plant capable of inlet gas separation, CO2 treating, NGL recovery and residue compression Capable of full NGL extraction, ethane rejection or dew point control At full NGL extraction, capacity of 35 MBPD Ultimate residue connectivity to numerous pipelines including Rockies Express Y-grade connection to MAPL via new 50 mile NGL pipeline Completion scheduled mid-2007 Phase II EnCana has exercised their option for Meeker Phase II Expansion to 1.4 Bcf/d; capacity of 70 MBPD at full extraction Evaluating condensate pipeline to Rangely

Hobbs Fractionator Existing infrastructure Interconnect between MAPL and Seminole Pipeline Systems Y-grade and purity NGL storage Local delivery infrastructure Expansion New 75 MBPD NGL fractionator Supplied by 100 MBPD of Meeker and Pioneer production New 375,000 barrel underground storage cavern Doubling of brine capacity Increased pipeline capacity to 120 MBPD between Hobbs and Conway Complete mid-2007

Texas Gas Processing 2.0 Bcf of processing in capacity in 10 plants 2005 1.4 Bcf/d throughput 64.4 MBPD NGL production 2006 YTD 1.4 Bcf/d throughput 76.5 MBPD NGL production Recent highlights Acquisition of certain gas gathering systems and related gathering and processing agreements from Lewis Energy Group, L.P. Current volumes are approximately 100 MMcf/d of 4-6 GPM gas Significant volume growth associated with Eagleford Shale, Austin Chalk and Mexico gas

South Texas NGL Facilities

Gulf Coast Gas Processing 10.9 Bcf (3.7 Bcf net) of processing capacity in eleven plants 2005 131.9 MBPD gross NGL production 36.1 MBPD equity NGL production 2006 YTD 111.5 MBPD gross NGL production 28.8 MBPD equity NGL production Hurricane recovery Repairs at Yscloskey and Sea Robin completed VESCO partners discussing alternatives

Louisiana NGL Facilities

Mont Belvieu, Texas & It’s Pivotal Role in the Global LPG Industry Mont Belvieu is a primary global pricing point against which all other regions are balanced due to: Substantial underground storage providing a transparent trading hub Significant connectivity providing accessibility and liquidity to and from storage operators, fractionators, refineries, gas processors and chemical plants Fully integrated and developed production / consumption base with self-sustaining stability Serves as the primary location utilized by the industry to hold the significant seasonal excesses that occur throughout the typical annual business cycle

Mont Belvieu Fractionation, Storage & Distribution System Largest NGL hub in the U.S. Fractionation capacity: 225 MBPD Fractionator running at capacity 15 MBPD expansion completed in first quarter of 2006 De-bottlenecked and improved energy efficiency Storage capacity of 94 million barrels Distribution system provides access to major industry players on the Houston Ship Channel and across the United States Gulf Coast, to the Southeast and the Northeast

Houston Ship Channel Pipelines & Import / Export Terminals Oil Tanking Import / Export Dock Connected to 3 docks and 330,000 barrels of storage from Oil Tanking Primarily imports propane, purity butanes and commercial butane at rates of 10M bph+ Fully and semi-refrigerated vessel loading rates of 6,000 bph+ Houston Ship Channel Pipelines 16” import / export line from MB to Oil Tanking 10” isobutane line supplies product to 4 customers 8” MTBE / isooctane pipeline to / from BEF facility Morgan’s Point Terminal & Pipelines 8” ethane line to Shell Deer Park and from South Texas 6” isobutane pipeline 6” natural gasoline pipeline 6” pipeline transporting isobutane and natural gasoline from MB to Texas City refineries Barge, rail and truck loading for domestic market

Enterprise LPG Imports and Exports

Enterprise NGL Marketing Import Term Contract Slate Under Contract Minimum 19.9 MMBbls / Maximum 31.8 MMBbls In Negotiation Minimum 12.8 MMBbls / Maximum 15.6 MMBbls

Global LPG Supplies Are Expanding Annual increase in LPG supply

Enterprise Import / Export Expansion Current System Connected to 3 docks with 2 loading arms Ability to unload 1 product at a time Ability to unload 1 vessel at a time Maximum discharge rate of 10,000 barrels/hour (bph) Export capacity at 5,500 bph for fully refrigerated loadings Expanded System Connected to 3 docks with 4 loading arms Ability to unload 2 different products at a time at 10,000 bph each Ability to unload 2 vessels at a time Maximum discharge rate of 20,000 bph for a single product Export capacity increasing to 7,500 bph Increase commercial butane processing capacity by 20 MBPD

Enterprise NGL Marketing Wholesale Marketing

Enterprise NGL Marketing West Coast Refinery Services

Enterprise NGL Marketing Gulf Coast Refinery Services

Enterprise NGL Marketing Gulf Coast Petrochemical Services

Enterprise NGL Marketing Domestic Marketing Domestic marketing strategy is focused on maximizing the value of our assets by capturing system opportunities and utilizing incremental capacity Strategies are centered around a combination of system capabilities and customer needs Wet-For-Any: Take advantage of “wet” barrel premium that exists when consumers do not want to hold inventory in tight markets North / South: Buy Conway and sell Mont Belvieu barrels, which is backed by our ability to pump barrels south East / West: Utilize the Lou-Tex Pipeline to take advantage of a market that is lower in one region versus the other Premium Sales: Generally charged to a customer who wants ratable delivery for their barrels, wants flexibility in switching from one product to another, or needs our connectivity between locations Forward Sales: Buy in current month and sell forward (contango market) to take advantage of low storage and working capital costs Front / Back: Sell product in the current month at a premium to the out month

Regulated NGL Pipelines James M. Collingsworth

Regulated NGL Pipeline Group Overview Regulated companies Mid-America Pipeline Company LLC Seminole Pipeline Company Dixie Pipeline Company Non-regulated companies Enterprise Terminalling & Storage Company LLC Dixie Terminalling and Storage Company

MAPL, Seminole and Dixie Pipelines

2006 MAPL Growth Initiatives Western Expansion I of the Rocky Mountain system Expand the MAPL system between Conway and Skellytown Secure long-term volume dedications in Rocky Mountain region Continue to defend cost of service filing on Northern system via FERC process Pancake rate increase on Northern system effective May 2006 Adds $9 million/year in operating margin Sum of both cost of service filings adds $16 million/year operating margin Continue system-wide power optimization projects Seminole Pipeline

MAPL Rocky Mountain System MAPL Rocky Mountain Demethanized Mix system evacuates producers’ NGLs extracted in natural gas processing plant located in the Rocky Mountains to the NGL markets, mostly Mont Belvieu, Texas MAPL’s current system has the capacity to transport approximately 225 MBPD into Hobbs station where it connects to our Seminole Pipeline and continues to Mont Belvieu MAPL Rocky Mountain system has been operating at over 85% capacity over the last four years and significant new volumes are forecast starting as early as late 2006

Expected NGL Volume Growth in Rockies(1) MAPL Rocky Mountain leg flowed at 90%+ of 225 MBPD capacity in 2005 and 93% YTD 2006 MAPL Phase I - 50 MBPD expansion under construction Expected to be completed mid-2007

MAPL Western Expansion Project WEP I expands the MAPL Rocky Mountain system by 50 MBPD through a combination of new pipe and additional horsepower Current status of WEP I 75 of the 165 miles of pipeline looping is complete Remaining 90 miles will be complete by October 2006 adding 30 MBPD of additional capacity Pump station work began in April 2006, adding an additional 20 MBPD of capacity - Scheduled to be complete by mid-2007 WEP I projected to be full by end of 2007 and is right-sized to accommodate WEP II Obtained long-term (10-20 years) shipper dedication agreements from all but one current shipper

MAPL Rocky Mountain System

MAPL Rocky Mountain System Enterprise is environmentally responsible in restoring construction areas

Conway to Skellytown Loop 190 miles of 12” pipe connecting the 102 miles of 10” pipe between Conway (“CN”) and Skellytown (“SK”) Project complete by March 2007 at a cost of $81 million Increase SK to CN capacity by 60+ MBPD Allows MAPL to fully utilize 48 MBPD of idle capacity from SK to Hobbs (“HB”)

Dixie Pipeline 1,300 mile propane pipeline from Mont Belvieu, Texas to Apex, North Carolina (Pinehurst) 7 Dixie-owned loading terminals and 5 privately-owned terminals Storage capacity: 640,000 barrels Capacity: 220 MBPD Average daily rate: 101.4 MBPD Current ownership EPD 66% BP 23% Exxon 11%

Dixie Pipeline 2006 Objectives Seeking cost recovery of $9 million from shippers that injected off-specification propane Refining strategy for pursuing settlement from shippers that injected at Citgo Growth / optimization initiatives Pipeline connection with Dow (1 MMbbls in incremental transportation) Potential for setting up terminals and storage facilities in non-regulated entity which will improve business opportunities Index tariffs by FERC approved methodology of 6.15% on July 1, 2006 Expect to increase Enterprise’s ownership in Dixie during 2006

Revenue Increase from PPI Adjustments FERC-approved formula for annual indexing Indexed changes effective July 1 of each year Annual change in PPI-finished goods plus 1.3% Formula subject to review every five years Formula approved in 2006 and effective through 2010 July 1, 2006 index 6.1485% Potential annual revenue increase for Enterprise entities MAPL / Seminole: $13 million Dixie: $3 million Current estimate for July 1, 2007 6% Based on latest 12-month PPI-finished goods

Petrochemical Services Gil H. Radtke

Petrochemical Services Overview Petrochemical segment consists of 5 businesses Butane isomerization (116 MBPD) Propylene fractionation (4.4 billion pounds or 65 MBPD, net) Mont Belvieu hydrocarbon storage (94 MMbbls of usable capacity) Propylene and HP isobutane pipelines Octane enhancement (10 MBPD)

Mont Belvieu Growth Initiatives Pipelines (3Q 2005 - 1Q 2007) Propylene feedstock from Texas City area (3Q ’05) Propylene feedstock from Port Arthur area (1Q ’07) Raw make from South Texas (1Q ’07) Storage Services (3Q 2006 - 2Q 2007) Two new brine production wells Increase above ground brine storage by 10 MMbbls Upgrade product handling facilities for increased imports and deliveries NGL Fractionation (April 2006) Expand capacity by 15 MBPD Tied to Western Growth Strategy Propylene Fractionation (3Q 2007) Expand capacity by 1.0 billion pounds (15 MBPD) Octane Enhancement (May 2005) Convert existing MTBE facility to produce isooctane Maintains demand for isomerization services

Butane Isomerization Service Isomerization is the process of converting normal butane to high purity isobutane EPD has a combined capacity of 116 MBPD 57 MBPD (49%) is committed under long-term third party processing contracts with escalation provisions on the fees and 20 MBPD is used as feedstock for our Octane Enhancement facility Variations in volumes are typically caused by plant turnarounds and spot opportunities, but overall results are very steady

Isomerization Business Outlook Stable demand from long-term contracts base loads isomerization business EPD has available capacity to service future growth in isobutane demand and seasonal demand for gasoline without investing new capital Expect increase in demand for isobutane as MTBE is phased out and other premium gasoline components such as isooctane and alkylate will be required (isobutane is major component of isooctane and alkylate)

Propylene Fractionation Propylene splitters take refinery grade propylene (RGP) and fractionate it into polymer grade propylene (PGP) or chemical grade propylene (CGP) and propane RGP is typically 60-75% propylene with the balance primarily propane RGP is referred to in barrels per day (BPD) of feed and PGP is referred to in millions of pounds (MMlbs) of production One barrel of propylene is equal to approximately 183 lbs.

Propylene Assets We own and operate 3 polymer grade propylene fractionation (“splitters”) facilities with approximately 4.8 billion pounds per year (72 MBPD) of polymer grade propylene production capacity (our share is 3.9 billion pounds) Basell owns approximately 45% of Splitter 1 and leases this capacity to us TOTAL Petrochemical owns 33% of Splitter 3 and takes its share of production to its polypropylene facility in LaPorte, Texas All 3 facilities are located at our Mont Belvieu site and are integrated into our other facilities including underground storage We own a 30% interest in a 1.5 billion pounds per year (22.5 MBPD) chemical grade propylene splitter in Baton Rouge, Louisiana EPD designed, constructed and operates the facility ExxonMobil has 70% ownership, is the business manager, supplies the feedstock and is the major customer

Combined Propylene Systems

Current Propylene Business Mont Belvieu Toll processing fee agreements - 18% of capacity No exposure to commodity price volatility Implicit fee arrangements - 61% of capacity Back-to-back long-term RGP purchase contracts and long-term PGP sales contracts with a common reference price Variable margin opportunities - 21% of capacity Floating margin volume that varies with the market Baton Rouge Equity income from fee-based fractionation Pipelines Fee-based service for RGP, CGP and PGP transportation

Propylene Outlook Propylene primarily sourced from refineries (to splitters) and as a co-product from steam crackers 2006 World demand expected to be 154 billion pounds 2006 North American demand expected to be 36 billion pounds World polypropylene demand expected to grow at over 5% per year and U.S. growth expected to be 3% per year (grows faster than ethylene) Future steam cracker investments insufficient to meet demand (mostly ethane based with low propylene yield) U.S. refinery expansions will help feed the demand growth

Propylene Expansion Includes the necessary improvements to pipelines, storage and measurement facilities Capacity: 1.0 billion pounds Expandable to 1.5 billion pounds Completion in 3Q 2007 Utilization ramping up from 80% in 2008, 90% in 2009 and 100% in 2010 forward Processing and sales margins of 3.1 cents per pound Incremental operating costs of 0.9 cents per pound

Mt. Belvieu Storage Services Own and operate 94 MMBbls of underground storage capacity at Mont Belvieu These storage facilities are interconnected by multiple pipelines to other producing and offtake facilities throughout the Gulf Coast, as well as connections to the Rocky Mountain and Midwest regions via Seminole Focal point on the Gulf Coast for NGL and Olefins Very stable operating margins from reservation fees (82%) and throughput fees (18%)

Mont Belvieu Storage Outlook Provide critical logistical services for our customers Growth tied to petrochemical, refinery and NGL fractionation markets as well as imported NGL Expansion tied to this growth, as well as new product storage opportunities Very steady cash flows with limited competitors having similar capabilities Connections and service are key to success Brine production to dedicated consumer (Oxy) facilitates expansion Filed request with Texas RRC for permit to allow for 4 existing NGL caverns to be used either for NGL or natural gas service, which would yield 7-8 Bcf of capacity

Octane Enhancement EPD owns a facility at Mont Belvieu that produces octane additives for motor gasoline Modification of the plant to produce isooctane completed in 2Q 2005 Have produced isooctane since March and isobutylene which is used to produce specialty chemicals (performance additive in lube oils)

Isooctane Key markets are Gulf Coast and California Only the second plant of its kind in the world; in place in advance of the phase out of MTBE Isooctane production Current capacity: 10.3 MBPD Capacity beginning February 2007: 12 MBPD Feedstock comes from our isomerization business Requires 2 gallons of high purity isobutane to produce 1 gallon of isooctane Evaluating the restart of sister facility at Morgan’s Point with capacity to produce 9 MBPD of isooctane

Ethanol Drives Demand for Isooctane 2005 Energy Bill effectively removed MTBE from United States gasoline market Significant octane loss with 6.0 lbs. vapor pressure Corresponding Renewable Fuels Standard (RFS) mandated ethanol usage Blends to higher vapor pressure of 15.0 lbs. Forces removal of higher vapor pressure components from gasoline blending such as butanes and pentanes Refineries need new blending components that combine high octane and very low vapor pressure Isooctane combines 99.5 octane with 2.0 lbs. vapor pressure

Ethanol Renewable Fuel Standard

Corporate Governance Richard H. Bachmann

Current EPCO Structure

EPCO Family Governance EPCO is sensitive to the appearance of and the potential for conflicts of interest which may arise among its various public and private entities and strives to ensure that each of the public entities that it controls is governed in a manner that is solely for the benefit of such entity’s debtholders and public investors Independent directors of each public entity have been given the sole power and authority to deal with conflicts of interest and related party transactions Governance of the EPCO family of companies is also set forth in the Administrative Services Agreement (ASA) ASA sets forth policies of cost allocations, business opportunities and other conflicts of interest among the various entities in the EPCO family of companies ASA will be amended to further refine cost allocations and business opportunities among the various EPCO family of entities In addition, EPCO has retained separate Delaware counsel, corporate and securities counsel and antitrust counsel to further refine the conflicts of interest principles and policies among the various entities; expect to finalize by September

Non-Consolidation Objectives Avoiding the risk of “substantive consolidation” is important to the EPCO family of entities (i.e. EPCO, EPE, EPD, TPP) As a result, we are very sensitive to ensuring that third parties understand the “separateness” of the various EPCO family of entities We have provided a draft of an opinion to the rating agencies to the effect that in the event of an EPCO bankruptcy, a bankruptcy court should not substantively consolidate EPD or its general partner We intend to provide one or more similar opinions with respect to whether a bankruptcy court would exercise “substantive consolidation” of EPD, EPE and/or TPP in the event of a bankruptcy of EPCO

Financial Overview Michael A. Creel

Strong 2006 Performance $102 million, or 20%, increase in gross operating margin for first six months of 2006 led by $47 million increase from Petrochemical Services and $44 million increase in NGL Pipeline & Services segment Petrochemical services benefited from $25 million increase from octane enhancement due to start up of isooctane facility, $14 million from propylene fractionation and $8 million from butane isomerization NGL segment increase due to $26 million increase in gas processing and marketing and $19 million increase in NGL pipelines and storage

Strong Financial Position at June 30, 2006

History of Financial Discipline Financial discipline while executing EPD’s growth strategy Financed 53% of $11.8 billion in capital investment since 1999 with equity Retired $1.2 billion acquisition term loan used to finance the acquisition of the Mid-America and Seminole Pipelines in less than 7 months (5 months ahead of schedule) Financed 64% of $6 billion GTM merger with equity Successfully and rapidly integrated businesses after GTM merger Refinanced GTM debt to reduce annual interest expense by approximately $50 million Recognized merger synergies well in excess of street expectations Strong track record of management support EPCO, its affiliates and management have invested approximately $450 million in new equity issues since EPD’s IPO Strong coverage of distributions to limited partners 1.2x coverage of LP distributions paid since 1999 (first full year since the IPO) Retained $476 million of Distributable Cash Flow in the partnership since 1999 Retained $216 million of Distributable Cash Flow in the partnership since completing merger GTM in 3Q 2004

History of Financial Discipline Funding Growth with Equity (1) Capital investment includes the capital expenditures, cash used for business combinations and asset purchases, investments in and advances to unconsolidated affiliates, and intangible asset acquisitions amounts as reflected on our Statements of Consolidated Cash Flows for the respective periods. Also included is the value of equity interests granted to complete the GTM merger and the Shell Midstream acquisition as reflected on our Statements of Consolidated Partners Equity and the Cerrito acquisition during 2006. (2) Equity issued includes net proceeds from the issuance of common units and Class B special units as reflected on our Statements of Consolidated Cash Flows for the respective periods. Also included is the value of equity issued as consideration for the GTM merger and the Shell Midstream acquisition as reflected on our Statements of Consolidated Partners Equity and the Cerrito acquisition.

History of Financial Discipline Debt to Total Capitalization

History of Financial Discipline Managing Distributable Cash Flow 14% of Distributable Cash Flow Retained in Partnership

Realizing Benefits of Eliminating GP’s 50% Splits “Landmark” action taken by EPD’s GP in December 2002 to eliminate GP’s 50% IDR for no consideration is beginning to provide significant benefits to debt and equity investors 2nd Qtr 2006 savings of $17 million Cumulative savings of $67 million 31% of DCF retained in partnership since GTM merger is attributable to elimination of 50% IDR Enhances EPD’s financial flexibility by retaining cash flow for debt retirement, fund growth and distribution increases Results in significantly lower long-term cost of capital and greater cash accretion from capital projects and acquisitions

Cost of Capital Evaluation

10 Largest Energy Partnerships Indicative Cost of Capital Comparison(1) (1) 50/50 mix of debt and equity. 10-year debt cost based on the yield of the nearest note to 10-year maturity for each partnership adjusted for an estimated new 10-year issuance spread provided by a leading debt underwriter in the partnership sector. Cost of equity based on current distribution to LP and GP as a percentage of the common unit price on August 8, 2006. Sensitivity (in gold) for WACC should distribution increase 10% with no increase in unit price.

Updated Cost of Capital Study Updated cost of capital study from January 2006 evaluation. This study shows the cumulative effect of EPD and a Generic MLP with a 50% GP split making a uniform series of $100 million investments each year over a ten-year period. Analysis has 3 return scenarios: A - 15.0% simple cash ROI, with cash flow growing 2% per year B - 12.5% simple cash ROI, with cash flow growing 2% per year C - 10.0% simple cash ROI, stable cash flow (i.e. no growth) Scenarios A and B are capitalized at 50% debt / 50% equity and Scenario C is capitalized at 40% debt / 60% equity to maintain a leverage ratio of 4.0x or better Assumes EPD and the Generic Partnership grow their respective cash distribution rates to limited partners by 7.5% per year EPD generates greater cash accretion potential over the long-term for its limited partners than the Generic partnership due to EPD’s combination of greater potential returns from investing in projects that “bolt on” to its value chain and EPD’s lower cost of capital due to the effect of capping the highest level of its GP splits at 25%

Generic Partnership - Scenarios A & B Assumptions & Resulting WACC

EPD - Scenarios A & B Assumptions and Resulting WACC

Portfolio Cost of Capital per Year Financed 50% Debt / 50% Equity

Portfolio Blending Masks the High Cost of Capital for the Year 1 Investment

Investment Scenario A - 15% ROI + 2% Growth Cash Accretion to Existing Limited Partners

Investment Scenario B - 12.5% ROI + 2% Growth Cash Accretion to Existing Limited Partners

Investment Scenario C - 10% ROI No Growth Cash Accretion to Existing Limited Partners

Capital Expenditure Overview

Capital Expenditures

Capital Expenditures (continued)

Major Organic Growth Projects Expected Investment & Timing

Hybrid Offering Summary

Hybrid Offering Benefits Provides financial flexibility by broadening and diversifying access to capital markets 61 investors, of which 22 investors participated in EPD bond offering for the first time Good distribution; largest investor allocated $30 million Establishes another channel for access to institutional investors for an MLP “equity-like” security Little, if any, overlap with existing investors in EPD common units Reduces sole reliance on traditional sources of equity Lower long-term cost of capital than traditional mix of debt and equity Provides an additional layer of protection for senior debtholders

Hybrid Offering Summary $300 million Hybrid Security due 2066 rated Ba1 (Moody’s), B+ (S&P) and BB+ (Fitch) Equity Content Ascribed: 75% by Fitch, Basket C (50%) by Moody’s and Intermediate (i.e. 50%) by S&P 1st partnership to issue a hybrid 4th non-financial / corporate issuer to issue a hybrid 3 days of marketing $1 billion in demand 3.3x oversubscribed Opportunity to upsize offering to $500 million 61 investors 78% high grade investors 22% high yield investors Priced on July 13th at 10-yr Treasury + 331 bp Currently trading at 10-yr Treasury + 305 bp

Equity Markets Realize Benefit of Hybrid in EPD’s Capital Structure EPD and EPE outperformed Alerian MLP Index from announcement of hybrid offering to ex-distribution date

Hybrid Potential in Capital Structure

10 Largest Energy Partnerships Ranked by Enterprise Value(1) EPD’s business and geographic diversification along with size provide investors with stability and excellent platform for future growth (1) Based on closing unit price on August 8, 2006 applied to outstanding units, inclusive of I-shares and debt per most recent SEC filings.

10 Largest Energy Partnerships Ranked by Average Daily Trading Volume(1) EPD provides investors with greatest daily liquidity of any energy partnership in the $80+ billion MLP sector (1) Based on closing unit price on August 8, 2006 applied to average daily trading volume for the last six months per Bloomberg L.P. adjusted by excluding volume and days associated with the day of pricing of an equity offering and the immediately preceding and succeeding day.

Proven Growth, Superior Returns (1) MLP Index includes BPL, EEP, ETP, KMP, MMP, OKS, PAA and TPP. REIT (2) Long-term growth based on Wall Street research estimates for distribution growth for MLPs and REITs and earnings growth for the Utility Index.

Financial Summary EPD has consistently exercised financial discipline in funding capital investment Investment grade debt ratings a priority - important from both a cost of capital and commercial business perspective Funding with appropriate mix of equity and hybrid-equity EPD has provided LP investors with distribution growth while retaining significant amounts of distributable cash flow to reinvest in the partnership Elimination of 50% GP splits has provided the partnership with additional financial flexibility, supported an attractive LP distribution growth rate and a lower cost of capital Visibility to LP distribution growth provided by one of the largest portfolios of organic growth projects in the midstream energy sector

Closing Remarks Robert G. Phillips

Major Growth Projects Overview1 1 This summary includes selected major growth capital projects which were completed in 2004 or 2005 and projects currently under construction or development.

First Half 2006 Recap Delivered record gross operating margin of $623 million and EBITDA of $600 million Revenue and operating income both increased by 30% from the first half of 2005 Strong contributions from NGL pipelines and processing, onshore natural gas pipelines and our petrochemical services business Made substantial progress on our organic growth projects Expanded scope of Independence Hub & Trail project to 1 Bcf/d; project on schedule Constitution pipelines completed ahead of schedule Completed San Juan optimization project Completed expansion of NGL fractionator at MTBV Initiated construction on MAPL Phase I expansion and new processing plants in Jonah / Pinedale fields and Piceance Basin Acquired Cerrito natural gas gathering system in South Texas Signed new long-term agreements to provide firm natural gas transportation and storage services for CenterPoint Energy Formed JV with TEPPCO to expand Jonah gas gathering system

Summary Enterprise is well capitalized with a leading position in all facets of the midstream business Assets access the most prolific basins of natural gas, crude oil and NGLs in the United States Size and diversity of businesses provide an abundance of organic growth opportunities when acquisition multiples are high Major organic growth projects are on schedule and on budget Low cost of capital advantage and large cash flow base Long-term relationships with major industry participants GP / Management’s interests are aligned with unitholders

Appendix

Non-GAAP Reconciliations