Edgar Filing: ENTERPRISE PRODUCTS PARTNERS L P

epdform10q_033112.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2012

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___ to ___.

Commission file number: 1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact name of Registrant as Specified in Its Charter)

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

	1100 Louisiana Street, 10th Floor
	Houston, Texas 77002
	(Address of Principal Executive Offices, Including Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

There were 883,776,574 common units and 4,520,431 Class B units (which generally vote together with the common units) of Enterprise Products Partners L.P. outstanding at April 30, 2012. Our common units trade on the New York Stock Exchange under the ticker symbol “EPD.”

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ENTERPRISE PRODUCTS PARTNERS L.P.

TABLE OF CONTENTS

		Page No.
PART I. FINANCIAL INFORMATION.
Item 1.	Financial Statements.
	Unaudited Condensed Consolidated Balance Sheets	2
	Unaudited Condensed Statements of Consolidated Operations	3
	Unaudited Condensed Statements of Consolidated Comprehensive Income	4
	Unaudited Condensed Statements of Consolidated Cash Flows	5
	Unaudited Condensed Statements of Consolidated Equity	6
	Notes to Unaudited Condensed Consolidated Financial Statements:
	1. Partnership Operations, Organization and Basis of Presentation	7
	2. General Accounting Matters	8
	3. Equity-based Awards	11
	4. Derivative Instruments, Hedging Activities and Fair Value Measurements	13
	5. Inventories	21
	6. Property, Plant and Equipment	22
	7. Investments in Unconsolidated Affiliates	23
	8. Intangible Assets and Goodwill	26
	9. Debt Obligations	27
	10. Equity and Distributions	29
	11. Business Segments	31
	12. Related Party Transactions	35
	13. Earnings Per Unit	36
	14. Commitments and Contingencies	37
	15. Supplemental Cash Flow Information	38
	16. Condensed Consolidating Financial Information	39
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	46
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	60
Item 4.	Controls and Procedures.	63

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.	64
Item 1A.	Risk Factors.	64
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	64
Item 3.	Defaults upon Senior Securities.	64
Item 4.	Mine Safety Disclosures.	64
Item 5.	Other Information.	64
Item 6.	Exhibits.	64

Signatures		72

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PART I. FINANCIAL INFORMATION.

Item 1. Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	March 31,			December 31,
ASSETS	2012			2011
Current assets:
Cash and cash equivalents	$	88.3		$	19.8
Restricted cash		81.8			38.5
Accounts receivable – trade, net of allowance for doubtful accounts of $13.0 at March 31, 2012 and $13.4 at December 31, 2011		4,526.7			4,501.8
Accounts receivable – related parties		13.4			43.5
Inventories		934.1			1,111.7
Prepaid and other current assets		452.9			353.4
Total current assets		6,097.2			6,068.7
Property, plant and equipment, net		22,910.3			22,191.6
Investments in unconsolidated affiliates		895.3			1,859.6
Intangible assets, net of accumulated amortization of $987.9 at March 31, 2012 and $990.4 at December 31, 2011		1,644.2			1,656.2
Goodwill		2,092.3			2,092.3
Other assets		253.4			256.7
Total assets	$	33,892.7		$	34,125.1

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	1,050.0		$	500.0
Accounts payable – trade		872.0			773.0
Accounts payable – related parties		79.3			211.6
Accrued product payables		4,830.4			5,047.1
Accrued interest		184.5			288.1
Other current liabilities		680.4			612.6
Total current liabilities		7,696.6			7,432.4
Long-term debt (see Note 9)		13,570.8			14,029.4
Deferred tax liabilities		22.0			91.2
Other long-term liabilities		215.0			352.8
Commitments and contingencies (see Note 14)
Equity: (see Note 10)
Partners’ equity:
Limited partners:
Common units (883,831,574 units outstanding at March 31, 2012 and 881,620,418 units outstanding at December 31, 2011)		12,502.1			12,346.3
Class B units (4,520,431 units outstanding at March 31, 2012 and December 31, 2011)		118.5			118.5
Accumulated other comprehensive loss		(341.8	)		(351.4	)
Total partners’ equity		12,278.8			12,113.4
Noncontrolling interests		109.5			105.9
Total equity		12,388.3			12,219.3
Total liabilities and equity	$	33,892.7		$	34,125.1

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(Dollars in millions, except per unit amounts)

	For the Three Months
	Ended March 31,
	2012			2011
Revenues:
Third parties	$	11,221.7		$	9,933.6
Related parties		30.8			250.1
Total revenues (see Note 11)		11,252.5			10,183.7
Costs and expenses:
Operating costs and expenses:
Third parties		10,318.8			9,111.5
Related parties		148.4			425.6
Total operating costs and expenses		10,467.2			9,537.1
General and administrative costs:
Third parties		23.6			12.9
Related parties		22.7			25.0
Total general and administrative costs		46.3			37.9
Total costs and expenses (see Note 11)		10,513.5			9,575.0
Equity in income of unconsolidated affiliates		9.9			16.2
Operating income		748.9			624.9
Other income (expense):
Interest expense		(186.5	)		(183.8	)
Interest income		0.3			0.3
Other, net (see Note 2)		58.4			0.2
Total other expense, net		(127.8	)		(183.3	)
Income before income taxes		621.1			441.6
Benefit from (provision for) income taxes (see Note 2)		34.4			(7.1	)
Net income		655.5			434.5
Net income attributable to noncontrolling interests (see Note 10)		(4.2	)		(13.8	)
Net income attributable to limited partners	$	651.3		$	420.7

Earnings per unit: (see Note 13)
Basic earnings per unit	$	0.76		$	0.52
Diluted earnings per unit	$	0.73		$	0.49

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME

(Dollars in millions)

	For the Three Months
	Ended March 31,
	2012			2011

Net income	$	655.5		$	434.5
Other comprehensive income (loss):
Cash flow hedges:
Commodity derivative instruments:
Changes in fair value of cash flow hedges		(59.6	)		(151.4	)
Reclassification of gains and losses to net income		22.0			68.9
Interest rate derivative instruments:
Changes in fair value of cash flow hedges		28.9			14.1
Reclassification of gains and losses to net income		2.7			1.5
Total cash flow hedges		(6.0	)		(66.9	)
Change in funded status of pension and postretirement plans, net of tax		(1.2	)		0.3
Proportionate share of other comprehensive income (loss) of unconsolidated affiliate		1.0			(1.0	)
Change in fair value of available-for-sale equity securities		15.8			--
Total other comprehensive income (loss)		9.6			(67.6	)
Comprehensive income		665.1			366.9
Comprehensive income attributable to noncontrolling interests		(4.2	)		(13.8	)
Comprehensive income attributable to limited partners	$	660.9		$	353.1

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in millions)

	For the Three Months
	Ended March 31,
	2012			2011
Operating activities:
Net income	$	655.5		$	434.5
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		266.1			241.1
Non-cash asset impairment charges		5.4			--
Equity in income of unconsolidated affiliates		(9.9	)		(16.2	)
Distributions received from unconsolidated affiliates		27.0			42.5
Gains from asset sales and related transactions		(55.2	)		(18.4	)
Deferred income tax expense (benefit)		(67.2	)		0.8
Changes in fair market value of derivative instruments		(15.4	)		(1.3	)
Net effect of changes in operating accounts (see Note 15)		(201.1	)		120.0
Other operating activities		(0.3	)		(0.3	)
Net cash flows provided by operating activities		604.9			802.7
Investing activities:
Capital expenditures		(973.1	)		(713.5	)
Contributions in aid of construction costs		5.0			3.2
Increase in restricted cash		(15.0	)		(92.9	)
Investments in unconsolidated affiliates		(50.6	)		(3.8	)
Proceeds from asset sales (see Note 15)		998.2			84.2
Other investing activities		--			(3.6	)
Cash used in investing activities		(35.5	)		(726.4	)
Financing activities:
Borrowings under debt agreements		1,396.6			2,821.6
Repayments of debt		(1,300.0	)		(2,316.0	)
Debt issuance costs		(7.1	)		(12.8	)
Monetization of interest rate derivative instruments (see Note 4)		(77.6	)		(5.7	)
Cash distributions paid to limited partners (see Note 10)		(530.4	)		(479.7	)
Cash distributions paid to noncontrolling interests (see Note 10)		(6.6	)		(17.2	)
Cash contributions from noncontrolling interests (see Note 10)		4.9			1.3
Net cash proceeds from issuance of common units		29.0			21.0
Other financing activities		(9.7	)		(3.9	)
Cash provided by (used in) financing activities		(500.9	)		8.6
Net change in cash and cash equivalents		68.5			84.9
Cash and cash equivalents, January 1		19.8			65.5
Cash and cash equivalents, March 31	$	88.3		$	150.4

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(See Note 10 for Unit History, Accumulated Other Comprehensive

Income (Loss) and Noncontrolling Interests)

(Dollars in millions)

	Partners’ Equity
	Limited Partners			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
Balance, December 31, 2011	$	12,464.8		$	(351.4	)	$	105.9		$	12,219.3
Net income		651.3			--			4.2			655.5
Cash distributions paid to limited partners		(530.4	)		--			--			(530.4	)
Cash distributions paid to noncontrolling interests		--			--			(6.6	)		(6.6	)
Cash contributions from noncontrolling interests		--			--			4.9			4.9
Net cash proceeds from issuance of common units		29.0			--			--			29.0
Amortization of fair value of equity-based awards		15.6			--			--			15.6
Cash flow hedges		--			(6.0	)		--			(6.0	)
Change in fair value of available-for-sale equity securities		--			15.8			--			15.8
Other		(9.7	)		(0.2	)		1.1			(8.8	)
Balance, March 31, 2012	$	12,620.6		$	(341.8	)	$	109.5		$	12,388.3

	Partners’ Equity
	Limited Partners			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
Balance, December 31, 2010	$	11,406.7		$	(32.5	)	$	526.6		$	11,900.8
Net income		420.7			--			13.8			434.5
Cash distributions paid to limited partners		(479.7	)		--			--			(479.7	)
Cash distributions paid to noncontrolling interests		--			--			(17.2	)		(17.2	)
Cash contributions from noncontrolling interests		--			--			1.3			1.3
Net cash proceeds from issuance of common units		21.0			--			--			21.0
Amortization of fair value of equity-based awards		12.0			--			0.1			12.1
Cash flow hedges		--			(66.9	)		--			(66.9	)
Other		(3.7	)		(0.7	)		(1.5	)		(5.9	)
Balance, March 31, 2011	$	11,377.0		$	(100.1	)	$	523.1		$	11,800.0

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

With the exception of per unit amounts, or as noted within the context of each footnote disclosure,

the dollar amounts presented in the tabular data within these footnote disclosures are

stated in millions of dollars.

KEY REFERENCES USED IN THESE

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unless the context requires otherwise, references to “we,” “us,” “our,” “Enterprise” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. References to “EPO” mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enterprise, and its consolidated subsidiaries, through which Enterprise Products Partners L.P. conducts its business. Enterprise is managed by its general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a Delaware limited liability company.

The membership interests of Dan Duncan LLC are owned of record by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director of Enterprise GP; (ii) Dr. Ralph S. Cunningham, who is also a director and the Chairman of Enterprise GP; and (iii) Richard H. Bachmann, who is also a director of Enterprise GP. Each of the DD LLC Trustees also currently serves as one of the three managers of Dan Duncan LLC.

References to “EPCO” mean Enterprise Products Company and its privately held affiliates. A majority of the outstanding voting capital stock of EPCO is owned of record by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Williams, who also serves as Chairman of EPCO; (ii) Dr. Cunningham, who also serves as a Vice Chairman of EPCO; and (iii) Mr. Bachmann, who also serves as the President and Chief Executive Officer (“CEO”) of EPCO. Each of the EPCO Trustees is also a director of EPCO.

On April 28, 2011, we, our general partner, EPD MergerCo LLC (“Duncan MergerCo,” a Delaware limited liability company and our wholly owned subsidiary), Duncan Energy Partners L.P. (“Duncan Energy Partners”) and DEP Holdings, LLC (“DEP GP,” the general partner of Duncan Energy Partners) entered into a definitive merger agreement (the “Duncan Merger Agreement”). On September 7, 2011, the Duncan Merger Agreement was approved by the unitholders of Duncan Energy Partners and the merger of Duncan MergerCo with and into Duncan Energy Partners and related transactions were completed, with Duncan Energy Partners surviving such merger as our wholly owned subsidiary (collectively, we refer to these transactions as the “Duncan Merger”). See Note 1 for additional information regarding the Duncan Merger.

References to “TEPPCO” mean TEPPCO Partners, L.P. prior to its merger with one of our subsidiaries on October 26, 2009.

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries.

Note 1. Partnership Operations, Organization and Basis of Presentation

General

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are now a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, refined products and certain petrochemicals. Our midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our assets

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

include approximately 50,600 miles of onshore and offshore pipelines; 190 million barrels (“MMBbls”) of storage capacity for NGLs, crude oil, refined products and certain petrochemicals; and 14 billion cubic feet (“Bcf”) of natural gas storage capacity.

Our midstream energy operations include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and import and export terminaling; crude oil and refined products transportation, storage, and terminaling; offshore production platforms; petrochemical transportation and services; and a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway systems and in the Gulf of Mexico. We have six reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; (v) Petrochemical & Refined Products Services; and (vi) Other Investments.

We are 100% owned by our limited partners from an economic perspective. We are managed and controlled by Enterprise GP, which has a non-economic general partner interest in us. We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates and under the collective common control of the DD LLC Trustees and the EPCO Trustees. We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. See Note 12 for information regarding the ASA and other related party matters.

Completion of Duncan Merger

On September 7, 2011, the Duncan Merger Agreement was approved by the unitholders of Duncan Energy Partners and the merger of Duncan MergerCo and Duncan Energy Partners and related transactions were completed, with Duncan Energy Partners surviving such merger as our wholly owned subsidiary. Each issued and outstanding common unit of Duncan Energy Partners was cancelled and converted into the right to receive common units representing limited partner interests in Enterprise based on an exchange ratio of 1.01 Enterprise common units for each Duncan Energy Partners common unit. Enterprise issued 24,277,310 of its common units (net of fractional common units cashed out) as consideration in the Duncan Merger. No Enterprise common units were issued to Enterprise or its subsidiaries as merger consideration. Since we historically consolidated Duncan Energy Partners for financial reporting purposes, the Duncan Merger did not change the basis of presentation of our historical financial statements.

Note 2. General Accounting Matters

Our results of operations for the three months ended March 31, 2012 are not necessarily indicative of results expected for the full year of 2012. In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”).

These Unaudited Condensed Consolidated Financial Statements and the Notes thereto should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto included in our annual report on Form 10-K for the year ended December 31, 2011 (the “2011 Form 10-K”) filed with the SEC on February 29, 2012.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Allowance for Doubtful Accounts

Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts. The following table presents our allowance for doubtful accounts activity for the periods presented:

	For the Three Months
	Ended March 31,
	2012			2011
Balance at beginning of period	$	13.4		$	18.4
Charged to costs and expenses		0.1			0.2
Deductions (1)		(0.5	)		(5.1	)
Balance at end of period	$	13.0		$	13.5

(1) The 2011 deduction is primarily due to our reassessment of the allowance for doubtful accounts as a result of improved credit ratings of a significant customer, which reduced our exposure to potential uncollectibility.

Contingencies

Certain conditions may exist as of the date our consolidated financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the need for accounting recognition or disclosure of these contingencies, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote.

For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, if feasible, an estimate of the possible loss or range of loss.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 14 for additional information regarding our contingencies.

Derivative Instruments

We use derivative instruments such as futures, swaps, options, forward contracts and other arrangements to manage price risks associated with inventories, firm commitments, interest rates, foreign currencies and certain anticipated future transactions. To qualify for hedge accounting, the hedged item must expose us to risk and the related derivative instrument must reduce that exposure and meet specific hedge documentation requirements related to designation dates, expectations for hedge effectiveness and the probability that hedged future transactions will occur as forecasted. We formally designate derivative instruments as hedges and document and assess their effectiveness at inception of the hedge and on a monthly or quarterly basis thereafter. Forecasted transactions are evaluated for the probability of occurrence and are periodically back-tested once the forecasted period has passed to determine whether similarly forecasted transactions are probable of occurring in the future.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For certain of our physical forward derivative contracts, we apply the normal purchase/normal sale exception, whereby changes in the mark-to-market values of such contracts are not recognized in income. As a result, the revenues and expenses associated with the physical contract transactions are recognized during the period when volumes are physically delivered or received. Physical derivative contracts are evaluated for the probability of future delivery and are periodically back-tested once the forecasted period has passed to determine whether similar contracts are probable of physically delivering in the future.

See Note 4 for additional information regarding our derivative instruments and related interest rate and commodity hedging activities.

Estimates

Preparing our consolidated financial statements in conformity with GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals.

Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements.

Income Tax Benefit

During the first quarter of 2012, we recognized a net income tax benefit of $34.4 million, which was primarily due to a $46.5 million net income tax benefit related to the conversion of certain of our subsidiaries to limited liability companies partially offset by accruals for the Texas Margin Tax. The $46.5 million benefit is attributable to the difference between deferred income taxes accrued by the applicable subsidiaries through the date of conversion and any current income tax due in connection with the conversion.

Other Non-Operating Income

The following table presents the components of “Other, net” income for the periods presented:

	For the Three Months Ended March 31,
	2012		2011
Gain on sales of available-for-sale securities (1)	$	53.3	$	--
Distribution income from available-for-sale securities		4.1		--
Other		1.0		0.2
	$	58.4	$	0.2

(1) Represents gains on the sale of Energy Transfer Equity common units. See Note 7 for information regarding our investment in Energy Transfer Equity.

Recent Accounting Developments

Accounting standard setting organizations have been very active in recent years. Recently, they issued new and revised accounting guidance on a number of topics, including balance sheet offsetting. We do not believe that adoption of this new guidance will have a material impact on our consolidated financial statements.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 3. Equity-based Awards

An allocated portion of the fair value of EPCO’s equity-based awards is charged to us under the ASA. The following table summarizes the expense we recognized in connection with equity-based awards for the periods presented:

	For the Three Months Ended March 31,
	2012		2011
Restricted common unit awards	$	14.8	$	11.4
Unit option awards		0.7		0.9
Other (1)		0.9		(0.5	)
Total compensation expense	$	16.4	$	11.8

(1) Primarily consists of unit appreciation rights (“UARs”), phantom units and similar awards.

The fair value of equity-classified awards (e.g., restricted common unit and unit option awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., UARs and phantom units) is recognized over the requisite service or vesting period based on the fair value of the award remeasured at each reporting period. Liability-classified awards are settled in cash upon vesting.

At March 31, 2012, EPCO’s significant long-term incentive plans applicable to us were the Enterprise Products 1998 Long-Term Incentive Plan (“1998 Plan”) and the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (“2008 Plan”). In addition, there were unvested awards outstanding under an inactive plan, the Enterprise Products 2006 TPP Long-Term Incentive Plan (“2006 Plan”). After giving effect to awards granted under the 1998 Plan and 2008 Plan through March 31, 2012, a total of 531,669 and 4,885,394 additional common units could be issued under these plans, respectively.

Restricted Common Unit Awards

Restricted common unit awards allow recipients to acquire our common units (at no cost to the recipient apart from service or other conditions) once a defined vesting period expires, subject to customary forfeiture provisions. Restricted common unit awards issued in 2012 generally vest at a rate of 25% per year beginning one year after the grant date. As used in the context of EPCO’s long-term incentive plans, the term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires. Restricted common units are included in the number of common units presented on our Unaudited Condensed Consolidated Balance Sheets.

The fair value of a restricted common unit award is based on the market price per unit of the underlying security on the date of grant. Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period.

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The following table presents information regarding restricted common unit awards for the period presented:

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Restricted common units at December 31, 2011		3,868,216		$	34.22
Granted (2)		1,529,438		$	51.92
Vested (3)		(632,298	)	$	38.31
Forfeited		(24,800	)	$	36.33
Restricted common units at March 31, 2012		4,740,556		$	39.37

(1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued in 2012 was $79.4 million based on a grant date market price of $51.92 per unit. An estimated annual forfeiture rate of 3.25% was applied to these awards. (3) Includes awards granted to the independent directors of the board of directors of Enterprise GP as part of their annual compensation for 2012. A total of 10,038 restricted common units were issued in February 2012 to the independent directors of Enterprise GP that immediately vested upon issuance.

Typically, each recipient is also entitled to nonforfeitable cash distributions equal to the product of the number of restricted common units outstanding for the participant and the cash distribution per unit paid to limited partners. Since these restricted common units are participating securities, such distributions are included in “Cash distributions paid to limited partners” as presented on our Unaudited Condensed Statements of Consolidated Cash Flows.

The following table presents supplemental information regarding our restricted common unit awards for the periods presented:

	For the Three Months
	Ended March 31,
	2012		2011
Cash distributions paid to restricted common unit holders	$	2.4	$	2.1
Total intrinsic value of our restricted common unit awards vesting during period		32.6		14.7

For the EPCO group of companies, the unrecognized compensation cost associated with restricted common unit awards was an aggregate $107.5 million at March 31, 2012, of which our allocated share of the cost is currently estimated to be $102.2 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.2 years.

Unit Option Awards

EPCO’s long-term incentive plans provide for the issuance of non-qualified incentive options. These unit option awards are denominated in our common units. When issued, the exercise price of each unit option grant may be no less than the market price of our common units on the date of grant. In general, option grants have a vesting period of four years from the date of grant and expire at the end of the calendar year following the year of vesting (e.g., an option vesting on May 29, 2011 will expire on December 31, 2012). However, unit options only become exercisable at certain times during the calendar year following the year in which they vest (typically the months of February, May, August and November).

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The fair value of each unit option is estimated on the date of grant using a Black-Scholes option pricing model. Compensation expense recorded in connection with unit options is based on the grant date fair value of such awards, net of an allowance for estimated forfeitures, over the requisite service or vesting period. The following table presents unit option activity for the period presented:

	Number of Units			Weighted- Average Strike Price (dollars/unit)		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (1)
Unit options at December 31, 2011		3,753,420		$	28.08		2.6	$	11.1
Exercised		(712,280	)	$	30.76
Unit options at March 31, 2012		3,041,140		$	27.45		2.8	$	--
Options exercisable at March 31, 2012		--					--		--

(1) Aggregate intrinsic value reflects fully vested unit options at the date indicated.

In order to fund its unit option-related obligations, EPCO may purchase common units at fair value either in the open market or directly from us. When employees exercise unit options, we reimburse EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee.

The following table presents supplemental information regarding our unit options during the periods presented:

	For the Three Months Ended March 31,
	2012		2011
Total intrinsic value of unit option awards exercised during period	$	14.0	$	--
Cash received from EPCO in connection with the exercise of unit option awards		10.2		--
Unit option-related reimbursements to EPCO		14.0		--

For the EPCO group of companies, the unrecognized compensation cost associated with unit option awards was an aggregate $3.0 million at March 31, 2012, of which our allocated share of the cost is currently estimated to be $2.7 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 1.3 years.

Unit Appreciation Rights

UARs entitle the recipient to receive a cash payment on the vesting date of the award equal to the excess, if any, of the then current fair market value of our common units over the grant date fair value of the award. UARs are accounted for as liability awards.

At March 31, 2012 and December 31, 2011, there were 107,328 UARs outstanding that had been granted under the 2006 Plan. The accrued liability for UARs at March 31, 2012 and December 31, 2011 was $1.1 million and $0.5 million, respectively.

Note 4. Derivative Instruments, Hedging Activities and Fair Value Measurements

In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with certain anticipated future transactions, we use derivative instruments. Substantially all of our derivatives are used for non-trading activities.

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We are required to recognize derivative instruments at fair value as either assets or liabilities on our balance sheet unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of the derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. Any ineffectiveness associated with a hedge relationship is recognized in earnings immediately. Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item.

A contract designated as a cash flow hedge of an anticipated transaction that is not probable of occurring is immediately recognized in earnings.

Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, they are accounted for using mark-to-market accounting.

Interest Rate Derivative Instruments

Hedged Transaction	Number and Type of Derivatives Outstanding	Notional Amount	Period of Hedge	Rate Swap	Accounting Treatment
Senior Notes AA	10 fixed-to-floating swaps	$750.0	1/11 to 2/16	3.2% to 1.5%	Fair value hedge
Undesignated swaps	6 floating-to-fixed swaps	$600.0	5/10 to 7/14	0.6% to 2.0%	Mark-to-market

Interest expense for the three months ended March 31, 2012 and 2011 reflects a benefit of $2.8 million and $9.7 million, respectively, attributable to interest rate swaps.

In February 2012, we settled 11 fixed-to-floating interest rate swaps having an aggregate notional amount of $800.0 million, resulting in gains totaling $37.7 million. These gains will be amortized to earnings (as a decrease in interest expense) using the effective interest method over the forecasted hedged period of approximately three years.

The following table summarizes our portfolio of forward starting swaps outstanding at March 31, 2012. Forward starting swaps hedge the expected underlying benchmark interest rates related to future issuances of debt.

Hedged Transaction	Number and Type of Derivatives Outstanding	Notional Amount	Expected Termination Date	Average Rate Locked	Accounting Treatment
Future debt offering	7 forward starting swaps	$350.0	8/12	3.7%	Cash flow hedge
Future debt offering	16 forward starting swaps	$1,000.0	3/13	3.7%	Cash flow hedge

In connection with the issuance of Senior Notes EE in February 2012 (see Note 9), we settled ten forward starting swaps having an aggregate notional value of $500.0 million, resulting in losses totaling $115.3 million. These losses are reflected in other comprehensive income for the three months ended March 31, 2012 and amortized to earnings (as an increase in interest expense) using the effective interest method over the forecasted hedge period of ten years.

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Commodity Derivative Instruments

The prices of natural gas, NGLs, crude oil, refined products and certain petrochemical products are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps, basis swaps and options contracts. The following table summarizes our commodity derivative instruments outstanding at March 31, 2012:

	Volume (1)		Accounting
Derivative Purpose	Current (2)	Long-Term (2)	Treatment
Derivatives designated as hedging instruments:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction (“PTR”) (3)	27.7 Bcf	n/a	Cash flow hedge
Forecasted sales of NGLs (4)	2.4 MMBbls	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchases of NGLs	0.3 MMBbls	n/a	Cash flow hedge
Forecasted sales of octane enhancement products	3.2 MMBbls	n/a	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities	10.5 Bcf	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products	3.7 MMBbls	n/a	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products	3.6 MMBbls	0.2 MMBbls	Cash flow hedge
Refined products marketing:
Forecasted purchases of refined products	0.4 MMBbls	n/a	Cash flow hedge
Forecasted sales of refined products	0.4 MMBbls	n/a	Cash flow hedge
Refined products inventory management activities	0.1 MMBbls	n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil	1.6 MMBbls	n/a	Cash flow hedge
Forecasted sales of crude oil	2.6 MMBbls	n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (5,6)	416.9 Bcf	69.6 Bcf	Mark-to-market
Refined products risk management activities (6)	0.4 MMBbls	n/a	Mark-to-market
Crude oil risk management activities (6)	6.1 MMBbls	n/a	Mark-to-market
(1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2013, May 2012 and October 2015, respectively. (3) PTR represents the British thermal unit (“Btu”) equivalent of the NGLs extracted from natural gas by a processing plant, and includes the natural gas used as plant fuel to extract those liquids, plant flare and other shortages. (4) Forecasted sales of NGL volumes under natural gas processing exclude 4.9 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements. (5) Current volumes include approximately 104.2 Bcf of physical derivative instruments that are predominantly priced at an index plus a premium or minus a discount related to location differences. (6) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Our predominant hedging strategies are: (i) hedging natural gas processing margins; (ii) hedging anticipated future contracted sales of NGLs, refined products and crude oil associated with volumes held in inventory; and (iii) hedging the fair value of natural gas in inventory. The following information summarizes these hedging strategies:

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of our expected equity NGL production at fixed prices through December 2012, which is achieved through the use of forward physical sales contracts and commodity derivative instruments and (ii) the purchase of commodity derivative instruments having a notional amount based on the volume of natural gas expected to be consumed as PTR in the production of such equity NGL production.

§	The objective of our NGL, refined products and crude oil sales hedging program is to hedge the margins of anticipated future sales of inventory by locking in sales prices through the use of forward physical sales contracts and commodity derivative instruments.

§	The objective of our natural gas inventory hedging program is to hedge the fair value of natural gas currently held in inventory by locking in the sales price of the inventory through the use of commodity derivative instruments.

Tabular Presentation of Fair Value Amounts, and Gains and Losses on

Derivative Instruments and Related Hedged Items

The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated:

	Asset Derivatives						Liability Derivatives
	March 31, 2012			December 31, 2011			March 31, 2012			December 31, 2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Interest rate derivatives	Other current assets	$	14.7	Other current assets	$	43.7	Other current liabilities	$	146.5	Other current liabilities	$	163.6
Interest rate derivatives	Other assets		22.7	Other assets		44.2	Other liabilities		--	Other liabilities		127.1
Total interest rate derivatives			37.4			87.9			146.5			290.7
Commodity derivatives	Other current assets		47.0	Other current assets		20.3	Other current liabilities		100.1	Other current liabilities		30.3
Commodity derivatives	Other assets		0.4	Other assets		--	Other liabilities		--	Other liabilities		0.2
Total commodity derivatives (1)			47.4			20.3			100.1			30.5
Total derivatives designated as hedging instruments		$	84.8		$	108.2		$	246.6		$	321.2

Derivatives not designated as hedging instruments
Interest rate derivatives	Other current assets	$	--	Other current assets	$	--	Other current liabilities	$	10.9	Other current liabilities	$	10.1
Interest rate derivatives	Other assets		--	Other assets		--	Other liabilities		9.7	Other liabilities		10.6
Total interest rate derivatives			--			--			20.6			20.7
Commodity derivatives	Other current assets		37.2	Other current assets		34.4	Other current liabilities		16.9	Other current liabilities		32.5
Commodity derivatives	Other assets		5.3	Other assets		12.6	Other liabilities		2.4	Other liabilities		2.0
Total commodity derivatives			42.5			47.0			19.3			34.5
Total derivatives not designated as hedging instruments		$	42.5		$	47.0		$	39.9		$	55.2

(1) Represents commodity derivative instrument transactions that have either not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.

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The following tables present the effect of our derivative instruments designated as fair value hedges on our Unaudited Condensed Statements of Consolidated Operations for the periods presented:

Derivatives in Fair Value Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Derivative
		For the Three Months Ended March 31,
		2012			2011
Interest rate derivatives	Interest expense	$	(1.5	)	$	(12.3	)
Commodity derivatives	Revenue		0.7			0.3
Total		$	(0.8	)	$	(12.0	)

Derivatives in Fair Value Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Hedged Item
		For the Three Months Ended March 31,
		2012		2011
Interest rate derivatives	Interest expense	$	1.1	$	11.3
Commodity derivatives	Revenue		0.4		(1.3	)
Total		$	1.5	$	10.0

The following tables present the effect of our derivative instruments designated as cash flow hedges on our Unaudited Condensed Statements of Consolidated Operations and Unaudited Condensed Statements of Consolidated Comprehensive Income for the periods presented:

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income/(Loss) on Derivative (Effective Portion)
	For the Three Months Ended March 31,
	2012			2011
Interest rate derivatives	$	28.9		$	14.1
Commodity derivatives – Revenue		(39.6	)		(155.4	)
Commodity derivatives – Operating costs and expenses		(20.0	)		4.0
Total	$	(30.7	)	$	(137.3	)

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income (Effective Portion)
		For the Three Months
		Ended March 31,
		2012			2011
Interest rate derivatives	Interest expense	$	(2.7	)	$	(1.5	)
Commodity derivatives	Revenue		(10.0	)		(69.2	)
Commodity derivatives	Operating costs and expenses		(12.0	)		0.3
Total		$	(24.7	)	$	(70.4	)

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
		For the Three Months
		Ended March 31,
		2012		2011
Commodity derivatives	Revenue	$	--	$	(0.1	)
Commodity derivatives	Operating costs and expenses		0.3		--
Total		$	0.3	$	(0.1	)

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Over the next twelve months, we expect to reclassify $19.1 million of losses attributable to interest rate derivative instruments from accumulated other comprehensive loss to earnings as an increase in interest expense. Likewise, we expect to reclassify $59.3 million of losses attributable to commodity derivative instruments from accumulated other comprehensive loss to earnings, $18.2 million as an increase in operating costs and expenses and $41.1 million as a decrease in revenue.

The following table presents the effect of our derivative instruments not designated as hedging instruments on our Unaudited Condensed Statements of Consolidated Operations for the periods presented:

Derivatives Not Designated as Hedging Instruments	Location	Gain/(Loss) Recognized in Income on Derivative
		For the Three Months
		Ended March 31,
		2012			2011
Interest rate derivatives	Interest expense	$	(2.2	)	$	(2.1	)
Commodity derivatives	Revenue		20.8			3.8
Commodity derivatives	Operating costs and expenses		(2.8	)		--
Total		$	15.8		$	1.7

Fair Value Measurements

Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk, in the principal market of the asset or liability at a specified measure date. Recognized valuation techniques employ inputs such as contractual prices, quoted market prices or rates, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.

A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy.

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The following table sets forth, by level within the fair value hierarchy, the carrying values of our financial assets and liabilities at March 31, 2012. These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input that is significant to their respective fair value. Our assessment of the relative significance of such inputs requires judgment.

	At March 31, 2012
	Quoted Prices
	in Active
	Markets for		Significant		Significant
	Identical Assets		Observable		Unobservable
	and Liabilities		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Total
Financial assets:
Investment in equity securities – available-for-sale (1)	$	119.8	$	--	$	--	$	119.8
Interest rate derivatives		--		37.4		--		37.4
Commodity derivatives		34.8		50.5		4.6		89.9
Total	$	154.6	$	87.9	$	4.6	$	247.1

Financial liabilities:
Interest rate derivatives	$	--	$	167.1	$	--	$	167.1
Commodity derivatives		89.9		25.8		3.7		119.4
Total	$	89.9	$	192.9	$	3.7	$	286.5

(1) See Note 7 for information related to our investment in Energy Transfer Equity common units, which trade on the NYSE under ticker symbol “ETE.”

The following table sets forth a reconciliation of changes in the overall fair values of our Level 3 financial assets and liabilities for the periods presented:

		For the Three Months
		Ended March 31,
	Location	2012			2011
Balance, January 1		$	0.4		$	(25.9	)
Total gains (losses) included in:
Net income (1)	Revenue		0.5			(0.5	)
Other comprehensive income (loss)	Commodity derivative instruments – changes in fair value of cash flow hedges		0.5			16.2
Settlements			(0.5	)		0.8
Transfers out of Level 3 (2)			--			9.8
Balance, March 31		$	0.9		$	0.4

(1) There were unrealized gains of $0.1 million and losses of $0.2 million included in these amounts for the three months ended March 31, 2012 and 2011, respectively. (2) Transfers out of Level 3 into Level 2 during 2011 were primarily due to the change in observability of forward NGL prices.

The following table provides quantitative information about our Level 3 fair value measurements at March 31, 2012:

	Fair Value
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives – Propane	$	0.6	$	--	Discounted cash flow	Forward commodity price	$1.27 – $1.33 /gallon
Commodity derivatives – Crude Oil		3.9		3.6	Discounted cash flow	Forward commodity price	$103.02 – $104.66 /barrel
Commodity derivatives – Natural gas		0.1		0.1	Discounted cash flow	Forward commodity price	$2.11 – $2.22 /MMBtu
Total	$	4.6	$	3.7

We believe certain forward commodity prices are the most significant unobservable inputs in determining our recurring Level 3 fair value measurements at March 31, 2012. In general, changes in the price of the underlying commodity increases or decreases the fair value of a commodity derivative

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depending on whether the derivative was purchased or sold. We generally expect changes in the fair value of our derivative instruments to be offset by corresponding changes in the fair value of our hedged exposures.

We have a risk management policy that covers our Level 3 commodity derivatives. Governance and oversight of risk management activities for these commodities are provided by our CEO with guidance and support from a risk management committee (“RMC”), which meets quarterly (or on a more frequent basis if needed). Members of executive management attend the RMC meetings, which are chaired by the head of our commodities risk control group. This group is responsible for preparing and distributing daily reports and risk analysis to members of the RMC and other appropriate members of management. These reports include mark-to-market valuations with the one-day and month-to-date changes in fair values. This group also develops and validates forward curves used to determine the fair values of our Level 3 commodity derivatives. These forward curves are based on published indexes, market quotes or are derived from other available inputs.

Nonfinancial Assets and Liabilities

Using appropriate valuation techniques, we reduced the carrying value of certain assets recorded as property, plant and equipment to an estimated fair value of $0.5 million based on the present value of expected future cash flows (Level 3), resulting in nonrecurring fair value adjustments (i.e., non-cash asset impairment charges) totaling $5.4 million during the three months ended March 31, 2012. These impairment charges recorded during the first quarter 2012 were recorded to reflect assets that are no longer in use or to reduce the fair value to what we can expect to receive from anticipated sales. We did not record any non-cash asset impairment charges during the three months ended March 31, 2011.

The following table summarizes our non-cash impairment charges, which are a component of operating costs and expenses, by business segment during the three months ended March 31, 2012:

NGL Pipelines & Services	$	5.1
Petrochemical & Refined Products Services		0.3
Total non-cash impairment charges	$	5.4

Forecast data and other assumptions supporting the fair value of fixed assets being tested for impairment are based on the nonfinancial assets’ highest and best use, which includes estimated probabilities where multiple outcomes are possible. Such probability weights are generally obtained from business management personnel having oversight responsibilities for the assets in question. Key commercial assumptions (e.g., anticipated operating margins, growth rates and timing of cash flows) and test results are certified by members of senior management.

Other Fair Value Information

The carrying amounts of cash and cash equivalents (including restricted cash), accounts receivable and accounts payable approximate their fair values based on their short-term nature. The estimated total fair value of our fixed-rate long-term debt obligations was approximately $16.19 billion and $15.76 billion at March 31, 2012 and December 31, 2011, respectively. The aggregate carrying value of these debt obligations was $14.58 billion and $14.33 billion at March 31, 2012 and December 31, 2011, respectively. These values are based on quoted market prices for such debt or debt of similar terms and maturities (Level 2), our credit standing and the credit standing of our counterparties. Changes in market rates of interest affect the fair value of our fixed-rate debt. The carrying values of our variable-rate long-term debt obligations approximate their fair values since the associated interest rates are market-based. We do not have any long-term investments in debt or equity securities recorded at fair value.

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Note 5. Inventories

Our inventory amounts by product type were as follows at the dates indicated:

	March 31, 2012		December 31, 2011
NGLs	$	402.7	$	563.6
Petrochemicals and refined products		433.4		443.4
Crude oil		58.7		39.2
Natural gas		39.3		65.5
Total	$	934.1	$	1,111.7

In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to actually purchasing volumes for cash from third parties), these volumes are valued at market-based prices during the month in which they are acquired.

Due to fluctuating commodity prices, we recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their net realizable value. These non-cash charges are a component of cost of sales in the period they are recognized. To the extent our commodity hedging strategies address inventory-related price risks and are successful, these inventory valuation adjustments are mitigated or offset. See Note 4 for a description of our commodity hedging activities.

The following table summarizes our cost of sales and lower of cost or market adjustments for the periods presented:

	For the Three Months Ended March 31,
	2012		2011
Cost of sales (1)	$	9,665.8	$	8,819.3
Lower of cost or market adjustments		5.9		1.2
(1) Cost of sales is a component of “Operating costs and expenses,” as presented on our Unaudited Condensed Statements of Consolidated Operations. Quarter-to-quarter fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

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Note 6. Property, Plant and Equipment

The historical costs of our property, plant and equipment and related accumulated depreciation balances were as follows at the dates indicated:

	Estimated Useful Life in Years	March 31, 2012		December 31, 2011
Plants, pipelines and facilities (1)	3-45 (6)	$	22,567.2	$	22,354.4
Underground and other storage facilities (2)	5-40 (7)		1,416.0		1,388.6
Platforms and facilities (3)	20-31		637.5		637.5
Transportation equipment (4)	3-10		153.1		151.5
Marine vessels (5)	15-30		633.5		615.9
Land			141.3		136.1
Construction in progress			2,810.8		2,145.6
Total			28,359.4		27,429.6
Less accumulated depreciation			5,449.1		5,238.0
Property, plant and equipment, net		$	22,910.3	$	22,191.6

(1) Plants and pipelines include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment and related assets. (2) Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets. (3) Platforms and facilities include offshore platforms and related facilities and other associated assets located in the Gulf of Mexico. (4) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. (5) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. (6) In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings, 20-40 years; and laboratory and shop equipment, 5-35 years. (7) In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.

The following table summarizes our depreciation expense and capitalized interest amounts for the periods presented:

	For the Three Months
	Ended March 31,
	2012		2011
Depreciation expense (1)	$	212.0	$	186.5
Capitalized interest (2)		30.6		17.2
(1) Depreciation expense is a component of “Costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations. (2) Capitalized interest reduces interest expense during the period it is recorded and increases the carrying value of the associated asset, which will subsequently increase depreciation expense once the asset is placed in service.

Asset Retirement Obligations

We record asset retirement obligations (“AROs”) related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations. The following table presents information regarding our AROs since December 31, 2011:

ARO liability balance, December 31, 2011	$	112.0
Liabilities incurred during period		0.8
Liabilities settled during period		(1.6	)
Revisions in estimated cash flows		3.4
Accretion expense		1.4
ARO liability balance, March 31, 2012	$	116.0

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Property, plant and equipment at March 31, 2012 and December 31, 2011 includes $37.2 million and $37.7 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset. The following table presents our accretion expense forecasts for AROs for the periods presented:

Remainder of 2012				2013				2014				2015				2016
$	4.0			$	5.6			$	6.0			$	5.8			$	6.1

Certain of our unconsolidated affiliates have AROs recorded at March 31, 2012 and December 31, 2011 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our consolidated financial statements.

Note 7. Investments in Unconsolidated Affiliates

The following table presents our investments in unconsolidated affiliates by business segment at the dates indicated. Unless noted otherwise, we account for these investments using the equity method.

	Ownership Interest at March 31, 2012	March 31, 2012		December 31, 2011
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C.	13.1%	$	34.8	$	35.5
K/D/S Promix, L.L.C.	50%		41.6		40.7
Baton Rouge Fractionators LLC	32.2%		20.9		21.0
Skelly-Belvieu Pipeline Company, L.L.C.	50%		39.6		35.0
Texas Express Pipeline LLC	45%		49.8		13.9
Onshore Natural Gas Pipelines & Services:
Evangeline (1)	49.5%		3.9		4.4
White River Hub, LLC	50%		25.4		25.7
Onshore Crude Oil Pipelines & Services:
Seaway Crude Pipeline LLC	50%		164.6		170.7
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)	36%		52.7		55.4
Cameron Highway Oil Pipeline Company	50%		220.8		222.8
Deepwater Gateway, L.L.C.	50%		93.8		94.6
Neptune Pipeline Company, L.L.C.	25.7%		50.0		51.1
Southeast Keathley Canyon Pipeline Company L.L.C.	50%		33.7		1.0
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator, LLC	30%		9.0		9.5
Centennial Pipeline LLC (“Centennial”)	50%		51.4		51.8
Other (2)	Various		3.3		3.4
Other Investments:
Energy Transfer Equity (3)	1.3%		--		1,023.1
Total		$	895.3	$	1,859.6

(1) Evangeline refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (2) Other unconsolidated affiliates include a 50% interest in a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas and a 25% interest in a company that provides logistics communications solutions between petroleum pipelines and their customers. (3) Effective January 18, 2012, our investment in Energy Transfer Equity common units is no longer accounted for using the equity method (see below).

At December 31, 2011, we owned 29,303,514 common units of Energy Transfer Equity. On January 18, 2012, we sold 22,762,636 of these common units in a private transaction, which generated cash proceeds of approximately $825.1 million and a gain on the sale of $27.5 million. Following the completion of the January 18 transaction, our ownership percentage in Energy Transfer Equity was below 3%, and we discontinued using the equity method to account for this investment and began accounting for the remaining units as an investment in available-for-sale equity securities. For the period January 1, 2012 to January 18, 2012, we recorded an estimated $2.4 million of equity earnings from Energy Transfer

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Equity, which is presented as a component of “Operating income.” Following the January 18 transaction, we sold an additional 3,569,232 Energy Transfer Equity common units through March 31, which generated cash proceeds of approximately $150.8 million and aggregate gains on these sales of $25.8 million. Gains on the first quarter of 2012 sales are presented as a component of “Other income.” Proceeds from these sales were used for general company purposes, including funding capital expenditures.

At March 31, 2012, we owned 2,971,646 common units of Energy Transfer Equity, which represented approximately 1.3% of its common units outstanding on April 3, 2012. The $119.8 million carrying value of these available-for-sale equity securities is a component of “Prepaid and other current assets” as presented on our Unaudited Condensed Consolidated Balance Sheet at March 31, 2012. Accumulated other comprehensive income (loss) at March 31, 2012 includes $15.8 million of unrealized gains related to these available-for-sale equity securities. We sold the remainder of our investment in Energy Transfer Equity in April 2012.

The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods presented:

	For the Three Months
	Ended March 31,
	2012			2011
NGL Pipelines & Services	$	5.2		$	5.9
Onshore Natural Gas Pipelines & Services		1.4			1.2
Onshore Crude Oil Pipelines & Services		0.5			(0.5	)
Offshore Pipelines & Services		6.9			8.3
Petrochemical & Refined Products Services		(6.5	)		(5.0	)
Other Investments (1)		2.4			6.3
Total	$	9.9		$	16.2

(1) With respect to the first quarter of 2012, amount presented reflects our estimated equity in the income of Energy Transfer Equity from January 1, 2012 to January 18, 2012.

The following table presents unamortized excess cost amounts by business segment at the dates indicated:

	March 31, 2012		December 31, 2011
NGL Pipelines & Services	$	24.5	$	24.7
Onshore Crude Oil Pipelines & Services		19.0		19.2
Offshore Pipelines & Services		14.5		14.8
Petrochemical & Refined Products Services		2.8		2.9
Other Investments (1)		--		1,119.0
Total	$	60.8	$	1,180.6

(1) On January 18, 2012, we discontinued using the equity method to account for our investment in Energy Transfer Equity common units and began accounting for them as available-for-sale equity securities. As a result, we no longer have any excess cost amounts associated with this investment.

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The following table presents our amortization of excess cost amounts by business segment for the periods presented:

	For the Three Months
	Ended March 31,
	2012		2011
NGL Pipelines & Services	$	0.2	$	0.3
Onshore Crude Oil Pipelines & Services		0.2		0.2
Offshore Pipelines & Services		0.3		0.3
Petrochemical & Refined Products Services		0.1		--
Other Investments (1)		0.3		9.1
Total	$	1.1	$	9.9

(1) Reflects amortization of excess cost amounts related to our investment in Energy Transfer Equity through January 18, 2012. We ceased using the equity method to account for this investment on January 18, 2012.

In April 2012, we, along with Anadarko Petroleum Corporation and DCP Midstream, LLC formed a new joint venture, Front Range Pipeline LLC (“Front Range”), to design and construct a new NGL pipeline that will originate in the Denver-Julesburg Basin (the “DJ Basin”) in Weld County, Colorado and extend approximately 435 miles to Skellytown in Carson County, Texas. Each party holds a one-third ownership interest in the joint venture. The Front Range Pipeline, with connections to our Mid-America Pipeline System and the Texas Express Pipeline, is expected to provide producers in the DJ Basin with access to the Gulf Coast, the largest NGL market in the U.S. Depending on shipper interest in a binding open commitment period that commenced in April 2012, initial capacity on the Front Range Pipeline is expected to be approximately 150 MBPD, which can be readily expanded to approximately 230 MBPD. We will construct and operate the pipeline, which is expected to begin service in the fourth quarter of 2013.

Summarized Income Statement Information of Unconsolidated Affiliates

The following table presents unaudited income statement information (on a 100% basis) of our unconsolidated affiliates, aggregated by the business segments to which they relate, for the periods presented:

	Summarized Income Statement Information for the Three Months Ended
	March 31, 2012								March 31, 2011
			Operating			Net					Operating			Net
	Revenues		Income (Loss)			Income (Loss)			Revenues		Income (Loss)			Income (Loss)
NGL Pipelines & Services	$	110.9	$	27.0		$	27.0		$	100.1	$	23.4		$	23.4
Onshore Natural Gas Pipelines & Services		30.9		2.6			2.6			35.5		2.6			2.6
Onshore Crude Oil Pipelines & Services		12.3		0.8			0.8			11.2		0.5			0.5
Offshore Pipelines & Services		41.1		19.1			18.4			46.3		18.9			18.7
Petrochemical & Refined Products Services		5.4		(9.4	)		(11.4	)		10.1		(7.0	)		(9.2	)
Other Investments (1)		--		--			--			1,989.1		364.2			88.6
(1) On January 18, 2012, we discontinued using the equity method to account for our investment in Energy Transfer Equity common units. As such, income statement data for Energy Transfer Equity is not presented for the three months ended March 31, 2012. For the three months ended March 31, 2011, net income for Energy Transfer Equity represents net income attributable to their partners.

The credit agreements of Poseidon and Centennial restrict their ability to pay cash dividends if a default or event of default (as defined in each credit agreement) has occurred and is continuing at the time such payments are scheduled to be paid. These businesses were in compliance with the terms of their credit agreements at March 31, 2012.

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Note 8. Intangible Assets and Goodwill

Identifiable Intangible Assets

The following table summarizes our intangible assets by business segment at the dates indicated:

	March 31, 2012							December 31, 2011
	Gross Value		Accum. Amort.			Carrying Value		Gross Value		Accum. Amort.			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	340.8	$	(133.0	)	$	207.8	$	340.8	$	(128.2	)	$	212.6
Contract-based intangibles		284.7		(142.4	)		142.3		298.4		(169.7	)		128.7
Segment total		625.5		(275.4	)		350.1		639.2		(297.9	)		341.3
Onshore Natural Gas Pipelines & Services:
Customer relationship intangibles		1,163.6		(220.2	)		943.4		1,163.6		(209.7	)		953.9
Contract-based intangibles		466.1		(296.2	)		169.9		464.8		(290.9	)		173.9
Segment total		1,629.7		(516.4	)		1,113.3		1,628.4		(500.6	)		1,127.8
Onshore Crude Oil Pipelines & Services:
Customer relationship intangibles		9.7		(4.3	)		5.4		9.7		(4.1	)		5.6
Contract-based intangibles		0.4		(0.2	)		0.2		0.4		(0.2	)		0.2
Segment total		10.1		(4.5	)		5.6		10.1		(4.3	)		5.8
Offshore Pipelines & Services:
Customer relationship intangibles		205.8		(131.8	)		74.0		205.8		(129.2	)		76.6
Contract-based intangibles		1.2		(0.3	)		0.9		1.2		(0.3	)		0.9
Segment total		207.0		(132.1	)		74.9		207.0		(129.5	)		77.5
Petrochemical & Refined Products Services:
Customer relationship intangibles		104.3		(29.6	)		74.7		104.3		(28.4	)		75.9
Contract-based intangibles		55.5		(29.9	)		25.6		57.6		(29.7	)		27.9
Segment total		159.8		(59.5	)		100.3		161.9		(58.1	)		103.8
Total all segments	$	2,632.1	$	(987.9	)	$	1,644.2	$	2,646.6	$	(990.4	)	$	1,656.2

The following table presents the amortization expense of our intangible assets by business segment for the periods presented:

	For the Three Months
	Ended March 31,
	2012		2011
NGL Pipelines & Services	$	10.2	$	10.4
Onshore Natural Gas Pipelines & Services		15.8		19.9
Onshore Crude Oil Pipelines & Services		0.2		0.1
Offshore Pipelines & Services		2.6		3.0
Petrochemical & Refined Products Services		3.5		4.3
Total	$	32.3	$	37.7

The following table presents forecasted amortization expense associated with existing intangible assets for the years presented:

Remainder of 2012				2013				2014				2015				2016
$	89.8			$	110.7			$	107.0			$	106.5			$	107.6

Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. There have been no changes to our goodwill amounts since those reported in our 2011 Form 10-K.

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Note 9. Debt Obligations

The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated:

	March 31, 2012			December 31, 2011
EPO senior debt obligations:
Senior Notes S, 7.625% fixed-rate, due February 2012	$	--		$	490.5
Senior Notes P, 4.60% fixed-rate, due August 2012		500.0			500.0
Senior Notes C, 6.375% fixed-rate, due February 2013		350.0			350.0
Senior Notes T, 6.125% fixed-rate, due February 2013		182.5			182.5
Senior Notes M, 5.65% fixed-rate, due April 2013		400.0			400.0
Senior Notes U, 5.90% fixed-rate, due April 2013		237.6			237.6
Senior Notes O, 9.75% fixed-rate, due January 2014		500.0			500.0
Senior Notes G, 5.60% fixed-rate, due October 2014		650.0			650.0
Senior Notes I, 5.00% fixed-rate, due March 2015		250.0			250.0
Senior Notes X, 3.70% fixed-rate, due June 2015		400.0			400.0
Senior Notes AA, 3.20% fixed-rate, due February 2016		750.0			750.0
$3.5 Billion Multi-Year Revolving Credit Facility, variable-rate, due September 2016		--			150.0
Senior Notes L, 6.30% fixed-rate, due September 2017		800.0			800.0
Senior Notes V, 6.65% fixed-rate, due April 2018		349.7			349.7
Senior Notes N, 6.50% fixed-rate, due January 2019		700.0			700.0
Senior Notes Q, 5.25% fixed-rate, due January 2020		500.0			500.0
Senior Notes Y, 5.20% fixed-rate, due September 2020		1,000.0			1,000.0
Senior Notes CC, 4.05% fixed-rate, due February 2022		650.0			650.0
Senior Notes D, 6.875% fixed-rate, due March 2033		500.0			500.0
Senior Notes H, 6.65% fixed-rate, due October 2034		350.0			350.0
Senior Notes J, 5.75% fixed-rate, due March 2035		250.0			250.0
Senior Notes W, 7.55% fixed-rate, due April 2038		399.6			399.6
Senior Notes R, 6.125% fixed-rate, due October 2039		600.0			600.0
Senior Notes Z, 6.45% fixed-rate, due September 2040		600.0			600.0
Senior Notes BB, 5.95% fixed-rate, due February 2041		750.0			750.0
Senior Notes DD, 5.70% fixed-rate, due February 2042		600.0			600.0
Senior Notes EE, 4.85% fixed-rate, due August 2042		750.0			--
TEPPCO senior debt obligations:
TEPPCO Senior Notes, 7.625% fixed-rate, due February 2012		--			9.5
TEPPCO Senior Notes, 6.125% fixed-rate, due February 2013		17.5			17.5
TEPPCO Senior Notes, 5.90% fixed-rate, due April 2013		12.4			12.4
TEPPCO Senior Notes, 6.65% fixed-rate, due April 2018		0.3			0.3
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038		0.4			0.4
Total principal amount of senior debt obligations		13,050.0			12,950.0
EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066		550.0			550.0
EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067		285.8			285.8
EPO Junior Subordinated Notes B, fixed/variable-rate, due January 2068		682.7			682.7
TEPPCO Junior Subordinated Notes, fixed/variable-rate, due June 2067		14.2			14.2
Total principal amount of senior and junior debt obligations		14,582.7			14,482.7
Other, non-principal amounts:
Change in fair value of debt hedged in fair value hedging relationship (1)		35.2			73.8
Unamortized discounts, net of premiums		(33.0	)		(30.0	)
Unamortized deferred net gains related to terminated interest rate swaps (1)		35.9			2.9
Total other, non-principal amounts		38.1			46.7
Less current maturities of debt (2)		(1,050.0	)		(500.0	)
Total long-term debt	$	13,570.8		$	14,029.4

(1) See Note 4 for information regarding our interest rate hedging activities. (2) We expect to refinance the current maturities of our debt obligations prior to their maturity.

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The following table presents contractually scheduled maturities of our consolidated debt obligations outstanding at March 31, 2012 for the next five years, and in total thereafter:

			Scheduled Maturities of Debt
	Total		Remainder of 2012		2013		2014		2015		2016		After 2016
Revolving Credit Facility	$	--	$	--	$	--	$	--	$	--	$	--	$	--
Senior Notes		13,050.0		500.0		1,200.0		1,150.0		650.0		750.0		8,800.0
Junior Subordinated Notes		1,532.7		--		--		--		--		--		1,532.7
Total	$	14,582.7	$	500.0	$	1,200.0	$	1,150.0	$	650.0	$	750.0	$	10,332.7

Apart from that discussed below and routine fluctuations in the balance of our revolving credit facility, there have been no significant changes in the terms or amounts of our consolidated debt obligations since those reported in our 2011 Form 10-K.

Issuance of Senior Notes EE.

In February 2012, EPO issued $750.0 million in principal amount of 30-year unsecured Senior Notes EE at 99.542% of their principal amount. Senior Notes EE have a fixed interest rate of 4.85% and mature on August 15, 2042. Enterprise guarantees the notes through an unconditional guarantee on an unsecured and unsubordinated basis. Net proceeds from the issuance of Senior Notes EE were used to repay outstanding amounts on the maturity of our $490.5 million principal amount of Senior Notes S due February 2012 and our $9.5 million principal amount of TEPPCO Senior Notes due February 2012 and for general company purposes.

Senior Notes EE rank equal with EPO’s existing and future unsecured and unsubordinated indebtedness. They are senior to any existing and future subordinated indebtedness of EPO. Senior Notes EE are subject to make-whole redemption rights and were issued under indentures containing certain covenants, which generally restrict EPO’s ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.

Letters of Credit

At March 31, 2012, EPO had $77.5 million in letters of credit outstanding related to its commodity derivative instruments. These letters of credit do not reduce the amount available for borrowing under EPO’s $3.5 Billion Multi-Year Revolving Credit Facility.

Parent-Subsidiary Guarantor Relationships

Enterprise Products Partners L.P. acts as guarantor of the consolidated debt obligations of EPO with the exception of the remaining debt obligations of TEPPCO. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full and unconditional repayment of that obligation.

Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at March 31, 2012.

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Information Regarding Variable Interest Rates Paid

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt obligation during the three months ended March 31, 2012:

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
EPO $3.5 Billion Multi-Year Revolving Credit Facility	1.62% to 1.67%	1.66%

Note 10. Equity and Distributions

Our partners’ equity reflects the various classes of limited partner interests of Enterprise (e.g., common units (including restricted common units) and Class B units). The following table summarizes changes in the number of Enterprise’s outstanding units since December 31, 2011:

	Common Units			Class B Units		Treasury Units
Balance, December 31, 2011		881,620,418			4,520,431		--
Common units issued in connection with DRIP and EUPP		691,936			--		--
Common units issued in connection with equity-based awards		201,925			--		--
Restricted common units issued		1,529,438			--		--
Forfeiture of restricted common units		(24,800	)		--		--
Acquisition of treasury units in connection with equity-based awards		(187,343	)		--		187,343
Cancellation of treasury units		--			--		(187,343	)
Balance, March 31, 2012		883,831,574			4,520,431		--

During the three months ended March 31, 2012, 632,298 restricted common units vested and converted to common units. Of this amount, 187,343 were sold back to us by employees to cover related withholding tax requirements. We cancelled such treasury units immediately upon acquisition.

We may issue additional equity or debt securities to assist us in meeting our future liquidity and capital spending requirements. We have filed a universal shelf registration statement (the “2010 Shelf”) with the SEC. The 2010 Shelf allows Enterprise and EPO (on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. EPO utilized the 2010 Shelf to issue its Senior Notes EE in February 2012 (see Note 9).

In March 2012, we filed a registration statement with the SEC authorizing the issuance of up to $1.0 billion in our common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings. As of March 31, 2012, we have not issued any common units under this registration statement.

We have also filed registration statements with the SEC authorizing the issuance of up to an aggregate of 70,000,000 of our common units in connection with a distribution reinvestment plan (“DRIP”). The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of common units they own by reinvesting the quarterly cash distributions they would otherwise receive into the purchase of additional common units. After taking into account the number of common units issued under these registration statements through March 31, 2012, Enterprise may issue an additional 25,506,188 common units under its DRIP. A total of 667,095 common units were issued during the first quarter of 2012 under our DRIP, which generated net cash proceeds of $31.8 million.

Enterprise has a registration statement on file with the SEC authorizing the issuance of 440,879 common units under the Enterprise employee unit purchase plan (“EUPP”). After taking into account the number of common units issued under this registration statement through March 31, 2012, Enterprise may issue an additional 405,864 common units under its EUPP. During the first quarter of 2012, Enterprise

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issued 24,841 common units under the Enterprise EUPP, which generated net cash proceeds of $1.2 million.

The net cash proceeds received during the first quarter of 2012 from Enterprise’s DRIP and EUPP were used to temporarily reduce borrowings outstanding under EPO’s revolving credit facility and for general company purposes.

Accumulated Other Comprehensive Income (Loss)

Our accumulated other comprehensive income (loss) primarily include the effective portion of the gain or loss on derivative instruments designated and qualified as cash flow hedges. Amounts accumulated in other comprehensive income (loss) related to cash flow hedges are reclassified into earnings in the same period(s) in which the underlying hedged forecasted transactions affect earnings. If it becomes probable that a forecasted transaction will not occur, the related net gain or loss in accumulated other comprehensive income (loss) must be immediately reclassified into earnings.

The following table presents the components of accumulated other comprehensive income (loss) as reported on our Unaudited Condensed Consolidated Balance Sheets at the dates indicated:

	March 31, 2012			December 31, 2011
Commodity derivative instruments (1)	$	(59.0	)	$	(21.4	)
Interest rate derivative instruments (1)		(297.4	)		(329.0	)
Foreign currency translation adjustment (2)		1.7			1.7
Pension and postretirement benefit plans		(2.9	)		(1.7	)
Proportionate share of other comprehensive loss of Energy Transfer Equity		--			(1.0	)
Unrealized gain on investment in available-for-sale equity securities (3)		15.8			--
Total accumulated other comprehensive loss in partners’ equity	$	(341.8	)	$	(351.4	)

(1) See Note 4 for additional information regarding these components of accumulated other comprehensive income (loss). (2) Relates to transactions of our Canadian NGL marketing subsidiary. (3) Relates to our investment in Energy Transfer Equity common units, which is accounted for as available-for-sale at March 31, 2012. This investment was accounted for using the equity method at December 31, 2011 through January 18, 2012.

Noncontrolling Interests

Prior to the completion of the Duncan Merger, effective September 6, 2011, we accounted for the former owners’ interest in Duncan Energy Partners as noncontrolling interest. Under this method of presentation, all pre-Duncan Merger revenues and expenses of Duncan Energy Partners are included in net income, and the former owners’ share of the income of Duncan Energy Partners is a component of “Net income attributable to noncontrolling interests” as reflected on our Unaudited Condensed Statements of Consolidated Operations.

Additionally, cash distributions paid to and cash contributions received from the former owners of Duncan Energy Partners are reflected as a component of cash distributions paid to and cash contributions received from noncontrolling interests.

The following table presents additional information regarding noncontrolling interests as presented on our Unaudited Condensed Consolidated Balance Sheets at the dates indicated:

	March 31, 2012		December 31, 2011
Joint venture partners (1)	$	109.5	$	105.9
(1) Represents third party ownership interests in joint ventures that we consolidate, including Tri-States NGL Pipeline L.L.C., Independence Hub LLC, Rio Grande Pipeline Company and Wilprise Pipeline Company LLC.

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The following table presents the components of net income attributable to noncontrolling interests as presented on our Unaudited Condensed Statements of Consolidated Operations for the periods presented:

	For the Three Months
	Ended March 31,
	2012		2011
Former owners of Duncan Energy Partners	$	--	$	7.9
Joint venture partners		4.2		5.9
Total	$	4.2	$	13.8

The following table presents cash distributions paid to and cash contributions received from noncontrolling interests as presented on our Unaudited Condensed Statements of Consolidated Cash Flows and Statements of Consolidated Equity for the periods presented:

	For the Three Months
	Ended March 31,
	2012		2011
Cash distributions paid to noncontrolling interests:
Former owners of Duncan Energy Partners	$	--	$	10.9
Joint venture partners		6.6		6.3
Total cash distributions paid to noncontrolling interests	$	6.6	$	17.2

Cash contributions from noncontrolling interests:
Former owners of Duncan Energy Partners	$	--	$	0.6
Joint venture partners		4.9		0.7
Total cash contributions from noncontrolling interests	$	4.9	$	1.3

Cash distributions paid to the limited partners of Duncan Energy Partners (prior to the Duncan Merger) represent the quarterly cash distributions paid to its unitholders. Similarly, cash contributions received from the limited partners of Duncan Energy Partners (prior to the Duncan Merger) represent net cash proceeds received from the issuance of limited partner units.

Cash Distributions

The following table presents our declared quarterly cash distribution rates with respect to the quarter indicated:

	Distribution Per Common Unit		Record Date	Payment Date
2012
1st Quarter	$	0.6275	04/30/12	05/09/12

In connection with the merger of Enterprise and Enterprise GP Holdings L.P. during 2010, a privately held affiliate of EPCO agreed to temporarily waive the regular quarterly cash distributions it would otherwise receive from us with respect to a certain number of our common units (the “Designated Units”) it owned over a five-year period after the merger closing date of November 22, 2010. The number of Designated Units to which the temporary distribution waiver applies is as follows for distributions paid or to be paid, if any, during the following calendar years: 30,610,000 during 2011; 26,130,000 during 2012; 23,700,000 during 2013; 22,560,000 during 2014; and 17,690,000 during 2015. Accordingly, distributions paid to partners during calendar year 2012 exclude 26,130,000 Designated Units.

Note 11. Business Segments

We have six reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; (v) Petrochemical & Refined Products Services; and (vi) Other Investments. Our business

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segments are generally organized and managed according to the type of services rendered (or technologies employed) and products produced and/or sold.

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 our 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 financial measure most directly comparable to total segment gross operating margin is operating income. Our non-GAAP financial measure of total segment gross operating margin should not be considered an alternative to GAAP operating income.

We define total segment gross operating margin as operating income before: (i) depreciation, amortization and accretion expenses; (ii) non-cash asset impairment charges; (iii) operating lease expenses for which we did not have the payment obligation; (iv) gains and losses from asset sales and related transactions; and (v) general and administrative costs. 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 the preparation of our consolidated financial statements. Gross operating margin is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests.

We include equity in income of unconsolidated affiliates in our measurement of segment gross operating margin and operating income. Equity investments with industry partners are a vital component of our business strategy. They are a means by which we conduct operations to align our interests with those of customers and/or suppliers. This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a standalone basis. Many of these businesses perform supporting or complementary roles to our other business operations.

The following table shows our measurement of total segment gross operating margin for the periods presented:

	For the Three Months
	Ended March 31,
	2012			2011
Revenues	$	11,252.5		$	10,183.7
Less: Operating costs and expenses		(10,467.2	)		(9,537.1	)
Add: Equity in income of unconsolidated affiliates		9.9			16.2
Depreciation, amortization and accretion in operating costs and expenses (1)		254.6			230.8
Non-cash asset impairment charges		5.4			--
Operating lease expenses paid by EPCO		--			0.2
Gains from asset sales and related transactions in operating costs and expenses (2)		(2.5	)		(18.4	)
Total segment gross operating margin	$	1,052.7		$	875.4

(1) Amount is a component of “Depreciation, amortization and accretion” as presented on the Unaudited Condensed Statements of Consolidated Cash Flows. (2) Amount is a component of “Gains from asset sales and related transactions” as presented on the Unaudited Condensed Statements of Consolidated Cash Flows.

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The following table presents a reconciliation of total segment gross operating margin to operating income and further to income before income taxes for the periods presented:

	For the Three Months Ended March 31,
	2012			2011
Total segment gross operating margin	$	1,052.7		$	875.4
Adjustments to reconcile total segment gross operating margin to operating income:
Depreciation, amortization and accretion in operating costs and expenses		(254.6	)		(230.8	)
Non-cash asset impairment charges		(5.4	)		--
Operating lease expenses paid by EPCO		--			(0.2	)
Gains from asset sales and related transactions in operating costs and expenses		2.5			18.4
General and administrative costs		(46.3	)		(37.9	)
Operating income		748.9			624.9
Other expense, net		(127.8	)		(183.3	)
Income before income taxes	$	621.1		$	441.6

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

	Reportable Business Segments
			Onshore		Onshore Crude Oil					Petrochemical & Refined
	NGL		Natural Gas		Onshore Crude Oil			Offshore		Petrochemical & Refined					Adjustments
	Pipelines		Pipelines		Pipelines			Pipelines		Products			Other		and			Consolidated
	& Services		& Services		& Services			& Services		Services			Investments		Eliminations			Totals
Revenues from third parties:
Three months ended March 31, 2012	$	4,354.1	$	804.9	$	4,473.6		$	54.4	$	1,534.7		$	--	$	--		$	11,221.7
Three months ended March 31, 2011		4,055.4		871.7		3,370.6			60.6		1,575.3			--		--			9,933.6
Revenues from related parties:
Three months ended March 31, 2012		0.4		28.7		--			1.7		--			--		--			30.8
Three months ended March 31, 2011		201.4		44.9		--			3.8		--			--		--			250.1
Intersegment and intrasegment revenues:
Three months ended March 31, 2012		2,818.2		223.7		1,730.9			3.3		439.9			--		(5,216.0	)		--
Three months ended March 31, 2011		3,474.6		270.9		707.1			1.7		473.1			--		(4,927.4	)		--
Total revenues:
Three months ended March 31, 2012		7,172.7		1,057.3		6,204.5			59.4		1,974.6			--		(5,216.0	)		11,252.5
Three months ended March 31, 2011		7,731.4		1,187.5		4,077.7			66.1		2,048.4			--		(4,927.4	)		10,183.7
Equity in income (loss) of unconsolidated affiliates:
Three months ended March 31, 2012		5.2		1.4		0.5			6.9		(6.5	)		2.4		--			9.9
Three months ended March 31, 2011		5.9		1.2		(0.5	)		8.3		(5.0	)		6.3		--			16.2
Gross operating margin:
Three months ended March 31, 2012		654.9		206.2		39.3			52.1		97.8			2.4		--			1,052.7
Three months ended March 31, 2011		504.4		159.2		31.8			61.3		112.4			6.3		--			875.4
Segment assets:
At March 31, 2012		8,014.1		9,984.9		960.1			2,007.7		3,764.5			--		2,810.8			27,542.1
At December 31, 2011		7,966.4		9,949.6		944.6			2,000.9		3,769.5			1,023.1		2,145.6			27,799.7
Property, plant and equipment, net: (see Note 6)
At March 31, 2012		7,136.1		8,546.0		478.7			1,399.7		2,539.0			--		2,810.8			22,910.3
At December 31, 2011		7,137.8		8,495.4		456.9			1,416.4		2,539.5			--		2,145.6			22,191.6
Investments in unconsolidated affiliates: (see Note 7)
At March 31, 2012		186.7		29.3		164.6			451.0		63.7			--		--			895.3
At December 31, 2011		146.1		30.1		170.7			424.9		64.7			1,023.1		--			1,859.6
Intangible assets, net: (see Note 8)
At March 31, 2012		350.1		1,113.3		5.6			74.9		100.3			--		--			1,644.2
At December 31, 2011		341.3		1,127.8		5.8			77.5		103.8			--		--			1,656.2
Goodwill: (see Note 8)
At March 31, 2012		341.2		296.3		311.2			82.1		1,061.5			--		--			2,092.3
At December 31, 2011		341.2		296.3		311.2			82.1		1,061.5			--		--			2,092.3

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

During the first quarter of 2012, we sold 26,331,868 of the common units we owned of Energy Transfer Equity and sold the remaining units in April 2012. Our reporting for the Other Investments segment ceased on January 18, 2012, when we discontinued using the equity method to account for this investment and began accounting for the remaining units as available-for-sale securities. See Note 7 for additional information regarding our investment in Energy Transfer Equity and related sales.

The following table provides additional information regarding our consolidated revenues and costs and expenses for the periods presented:

	For the Three Months Ended March 31,
	2012			2011
NGL Pipelines & Services:
Sales of NGLs and related products	$	4,115.3		$	4,057.7
Midstream services		239.2			199.1
Total		4,354.5			4,256.8
Onshore Natural Gas Pipelines & Services:
Sales of natural gas		572.6			712.7
Midstream services		261.0			203.9
Total		833.6			916.6
Onshore Crude Oil Pipelines & Services:
Sales of crude oil		4,447.6			3,348.2
Midstream services		26.0			22.4
Total		4,473.6			3,370.6
Offshore Pipelines & Services:
Sales of natural gas		0.1			0.3
Sales of crude oil		1.4			3.3
Midstream services		54.6			60.8
Total		56.1			64.4
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		1,351.2			1,382.8
Midstream services		183.5			192.5
Total		1,534.7			1,575.3
Total consolidated revenues	$	11,252.5		$	10,183.7

Consolidated costs and expenses
Operating costs and expenses:
Cost of sales related to our marketing activities	$	8,688.5		$	7,930.1
Depreciation, amortization and accretion		254.6			230.8
Gains from asset sales and related transactions		(2.5	)		(18.4	)
Non-cash asset impairment charges		5.4			--
Other operating costs and expenses		1,521.2			1,394.6
General and administrative costs		46.3			37.9
Total consolidated costs and expenses	$	10,513.5		$	9,575.0

Changes in our revenues and operating costs and expenses quarter-to-quarter are explained in part by changes in energy commodity prices. In general, higher energy commodity prices result in an increase in our revenues attributable to the sale of NGLs, natural gas, crude oil, petrochemicals and refined products; however, these higher commodity prices also increase the associated cost of sales as purchase costs rise.

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Note 12. Related Party Transactions

The following table summarizes our related party transactions for the periods presented:

	For the Three Months Ended March 31,
	2012		2011
Revenues – related parties:
Energy Transfer Equity and subsidiaries	$	--	$	210.2
Other unconsolidated affiliates		30.8		39.9
Total revenue – related parties	$	30.8	$	250.1
Costs and expenses – related parties:
EPCO and affiliates	$	166.0	$	173.0
Energy Transfer Equity and subsidiaries		--		267.4
Other unconsolidated affiliates		5.1		10.2
Total costs and expenses – related parties	$	171.1	$	450.6

Effective with the first quarter of 2012, we no longer report Energy Transfer Equity and its subsidiaries as related parties. See Note 7 for information related to the sale of Energy Transfer Equity common units.

The following table summarizes our related party accounts receivable and accounts payable amounts at the dates indicated:

	March 31, 2012		December 31, 2011
Accounts receivable - related parties:
Energy Transfer Equity and subsidiaries	$	--	$	28.4
Other unconsolidated affiliates		13.4		15.1
Total accounts receivable – related parties	$	13.4	$	43.5

Accounts payable - related parties:
EPCO and affiliates	$	53.2	$	108.3
Energy Transfer Equity and subsidiaries		--		92.6
Other unconsolidated affiliates		26.1		10.7
Total accounts payable – related parties	$	79.3	$	211.6

We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties.

Relationship with EPCO and Affiliates

We have an extensive and ongoing relationship with EPCO and its privately held affiliates (including Enterprise GP, our sole general partner), which entities are not a part of our consolidated group of companies.

EPCO is a privately held company controlled collectively by the EPCO Trustees. At March 31, 2012, EPCO and its affiliates (including Dan Duncan LLC and two Duncan family trusts, the beneficiaries of which include the estate of Mr. Duncan) beneficially owned the following limited partner interests in us:

Number of Units	Percentage of Outstanding Units
338,930,881 (1)	38.2%
(1) Includes 4,520,431 Class B units.

Dan Duncan LLC owns 100% of our general partner, Enterprise GP.

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We and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are separate from those of EPCO and its other affiliates. EPCO and its privately held affiliates depend on the cash distributions they receive from us and other investments to fund their other operations and to meet their debt obligations. During the three months ended March 31, 2012 and 2011, we paid EPCO and its privately held affiliates cash distributions of $183.7 million and $172.1 million, respectively.

We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to the ASA or by other service providers. The following table presents a breakout of costs and expenses related to the ASA and other EPCO transactions for the periods presented:

	For the Three Months Ended March 31,
	2012		2011
Operating costs and expenses	$	142.7	$	147.4
General and administrative expenses		23.3		25.6
Total costs and expenses	$	166.0	$	173.0

Note 13. Earnings Per Unit

Basic earnings per unit is computed by dividing net income or loss attributable to our limited partners by the weighted-average number of our distribution-bearing units outstanding during a period, which excludes the Designated Units (see Note 10) to the extent that such units do not participate in the distributions to be paid with respect to such period.

Diluted earnings per unit is computed by dividing net income or loss attributable to our limited partners by the sum of (i) the weighted-average number of our distribution-bearing units outstanding during a period (as used in determining basic earnings per unit), (ii) the weighted-average number of our Class B units outstanding during a period, (iii) the weighted-average number of Designated Units outstanding during a period and (iv) the number of incremental common units resulting from the assumed exercise of dilutive unit options outstanding during a period (the “incremental option units”).

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The following table presents our calculation of basic and diluted earnings per unit for the periods presented:

	For the Three Months Ended March 31,
	2012		2011
BASIC EARNINGS PER UNIT
Numerator:
Net income attributable to limited partners	$	651.3	$	420.7
Denominator:
Common units		852.3		809.9
Time-vested restricted common units		4.3		4.0
Total		856.6		813.9
Basic earnings per unit:
Net income attributable to limited partners	$	0.76	$	0.52
DILUTED EARNINGS PER UNIT
Numerator:
Net income attributable to limited partners	$	651.3	$	420.7
Denominator:
Common units		852.3		809.9
Time-vested restricted common units		4.3		4.0
Class B units		4.5		4.5
Designated Units		26.1		30.6
Incremental option units		1.5		1.3
Total		888.7		850.3
Diluted earnings per unit:
Net income attributable to limited partners	$	0.73	$	0.49

Note 14. Commitments and Contingencies

As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings.We will vigorously defend the partnership in litigation matters.

Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the possible need for accounting recognition and disclosure of these contingencies. We accrue an undiscounted liability for those contingencies where the loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount in the range is accrued.

We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Based on a consideration of all relevant known facts and circumstances (including the availability of insurance coverage), we do not believe the ultimate outcome of any currently pending lawsuit against us will have a material impact on our financial statements individually or in the aggregate.

At March 31, 2012 and December 31, 2011, litigation accruals on an undiscounted basis of $16.3 million and $16.5 million, respectively, were recorded in our Unaudited Condensed Consolidated Balance Sheets as a component of “Other current liabilities.” Our evaluation of litigation contingencies is based on the facts and circumstances of each case and predicting the outcome of these matters involves substantial uncertainties. In the event the assumptions we use to evaluate these matters change in future periods or new information becomes available, we may be required to record additional accruals. In an effort to mitigate expenses associated with litigation, we may settle legal proceedings out of court.

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Contractual Obligations

Scheduled Maturities of Long-Term Debt. With the exception of (i) routine fluctuations in the balance of our revolving credit facility, (ii) the issuance of Senior Notes EE in February 2012 and (iii) the repayment of Senior Notes S and TEPPCO Senior Notes in February 2012, there have been no significant changes in our consolidated debt obligations since those reported in our 2011 Form 10-K. See Note 9 for additional information regarding our consolidated debt obligations.

Operating Lease Obligations. Consolidated lease and rental expense was $22.4 million and $20.5 million during the three months ended March 31, 2012 and 2011, respectively. There have been no material changes in our operating lease commitments since those reported in our 2011 Form 10-K.

Purchase Obligations. There have been no material changes in our consolidated purchase obligations since those reported in our 2011 Form 10-K.

Other Claims

As part of our normal business activities with joint venture partners and certain customers and suppliers, we occasionally make claims against such parties or have claims made against us as a result of disputes related to contractual agreements or similar arrangements. As of March 31, 2012, our contingent claims against such parties were approximately $38.3 million and claims against us were approximately $41.4 million. These matters are in various stages of assessment and the ultimate outcome of such disputes cannot be reasonably estimated at this time; however, in our opinion, the likelihood of a material impact on our Unaudited Condensed Consolidated Financial Statements from such disputes is remote. Accordingly, accruals for loss contingencies related to these matters have not been reflected in our Unaudited Condensed Consolidated Financial Statements.

Note 15. Supplemental Cash Flow Information

The following table provides information regarding the net effect of changes in our operating accounts for the periods presented:

	For the Three Months
	Ended March 31,
	2012			2011
Decrease (increase) in:
Accounts receivable – trade	$	(25.6	)	$	(81.2	)
Accounts receivable – related parties		30.0			(8.1	)
Inventories		135.6			357.2
Prepaid and other current assets		14.1			25.8
Other assets		(16.4	)		(11.8	)
Increase (decrease) in:
Accounts payable – trade		63.4			28.0
Accounts payable – related parties		(132.2	)		5.7
Accrued product payables		(195.7	)		(114.8	)
Accrued interest		(103.6	)		(71.6	)
Other current liabilities		40.7			(9.3	)
Other liabilities		(11.4	)		0.1
Net effect of changes in operating accounts	$	(201.1	)	$	120.0

We incurred liabilities for construction in progress that had not been paid at March 31, 2012 and December 31, 2011 of $273.0 million and $286.9 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Unaudited Condensed Statements of Consolidated Cash Flows.

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with projects related to pipeline

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construction and production well tie-ins. These cash receipts are presented as “Contributions in aid of construction costs” within the investing activities section of our Unaudited Condensed Statements of Consolidated Cash Flows.

Proceeds from asset sales and related transactions increased $914.0 million quarter-to-quarter, primarily from the sale of 26,331,868 common units of Energy Transfer Equity during the first quarter of 2012. See Note 7 for information regarding our investment in Energy Transfer Equity.

See Note 10 for information regarding cash amounts attributable to noncontrolling interests.

Note 16. Condensed Consolidating Financial Information

EPO conducts substantially all of our business. Currently, we have no independent operations and no material assets outside those of EPO.

EPO has issued publicly traded debt securities. Enterprise Products Partners L.P., as the parent company of EPO, guarantees the debt obligations of EPO, with the exception of the remaining debt obligations of TEPPCO. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full repayment of that obligation. EPO’s consolidated subsidiaries have no significant restrictions on their ability to pay distributions or make loans to Enterprise Products Partners L.P. See Note 9 for additional information regarding our consolidated debt obligations.

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Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Balance Sheet

March 31, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non-guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	144.1	$	31.8	$	(5.5	)	$	170.4	$	--		$	(0.3	)	$	170.1
Accounts receivable – trade, net		1,517.4		3,018.1		(8.8	)		4,526.7		--			--			4,526.7
Accounts receivable – related parties		221.4		1,557.2		(1,752.5	)		26.1		(12.7	)		--			13.4
Inventories		788.6		147.6		(2.1	)		934.1		--			--			934.1
Prepaid and other current assets		147.5		309.1		(4.1	)		452.5		0.4			--			452.9
Total current assets		2,819.0		5,063.8		(1,773.0	)		6,109.8		(12.3	)		(0.3	)		6,097.2
Property, plant and equipment, net		1,504.0		21,415.8		(9.5	)		22,910.3		--			--			22,910.3
Investments in unconsolidated affiliates		26,410.1		7,485.5		(33,000.3	)		895.3		12,291.4			(12,291.4	)		895.3
Intangible assets, net		158.5		1,499.1		(13.4	)		1,644.2		--			--			1,644.2
Goodwill		458.9		1,633.4		--			2,092.3		--			--			2,092.3
Other assets		122.7		128.5		2.1			253.3		0.1			--			253.4
Total assets	$	31,473.2	$	37,226.1	$	(34,794.1	)	$	33,905.2	$	12,279.2		$	(12,291.7	)	$	33,892.7

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	1,032.6	$	17.4	$	--		$	1,050.0	$	--		$	--		$	1,050.0
Accounts payable – trade		312.2		565.2		(5.5	)		871.9		0.4			(0.3	)		872.0
Accounts payable – related parties		1,683.8		147.8		(1,752.3	)		79.3		--			--			79.3
Accrued product payables		1,911.6		2,929.9		(11.1	)		4,830.4		--			--			4,830.4
Accrued interest		183.6		0.9		--			184.5		--			--			184.5
Other current liabilities		332.6		351.9		(4.1	)		680.4		--			--			680.4
Total current liabilities		5,456.4		4,013.1		(1,773.0	)		7,696.5		0.4			(0.3	)		7,696.6
Long-term debt		13,543.5		27.3		--			13,570.8		--			--			13,570.8
Deferred tax liabilities		5.7		15.1		2.1			22.9		--			(0.9	)		22.0
Other long-term liabilities		26.8		188.2		--			215.0		--			--			215.0
Commitments and contingencies
Equity:
Partners’ and other owners’ equity		12,440.8		28,208.1		(28,374.0	)		12,274.9		12,278.8			(12,274.9	)		12,278.8
Noncontrolling interests		--		4,774.3		(4,649.2	)		125.1		--			(15.6	)		109.5
Total equity		12,440.8		32,982.4		(33,023.2	)		12,400.0		12,278.8			(12,290.5	)		12,388.3
Total liabilities and equity	$	31,473.2	$	37,226.1	$	(34,794.1	)	$	33,905.2	$	12,279.2		$	(12,291.7	)	$	33,892.7

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Balance Sheet

December 31, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non-guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	48.2	$	21.3	$	(11.2	)	$	58.3	$	--		$	--		$	58.3
Accounts receivable – trade, net		1,599.4		2,913.2		(10.8	)		4,501.8		--			--			4,501.8
Accounts receivable – related parties		141.1		2,155.5		(2,252.0	)		44.6		(1.1	)		--			43.5
Inventories		943.6		170.5		(2.4	)		1,111.7		--			--			1,111.7
Prepaid and other current assets		216.8		152.6		(16.0	)		353.4		--			--			353.4
Total current assets		2,949.1		5,413.1		(2,292.4	)		6,069.8		(1.1	)		--			6,068.7
Property, plant and equipment, net		1,477.5		20,723.7		(9.6	)		22,191.6		--			--			22,191.6
Investments in unconsolidated affiliates		27,060.0		8,266.7		(33,467.1	)		1,859.6		12,114.5			(12,114.5	)		1,859.6
Intangible assets, net		142.4		1,527.4		(13.6	)		1,656.2		--			--			1,656.2
Goodwill		458.9		1,633.4		--			2,092.3		--			--			2,092.3
Other assets		146.4		107.5		2.8			256.7		--			--			256.7
Total assets	$	32,234.3	$	37,671.8	$	(35,779.9	)	$	34,126.2	$	12,113.4		$	(12,114.5	)	$	34,125.1

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	500.0	$	--	$	--		$	500.0	$	--		$	--		$	500.0
Accounts payable – trade		205.6		578.6		(11.2	)		773.0		--			--			773.0
Accounts payable – related parties		2,407.2		71.9		(2,267.5	)		211.6		--			--			211.6
Accrued product payables		2,141.0		2,912.4		(6.3	)		5,047.1		--			--			5,047.1
Accrued interest		287.1		1.0		--			288.1		--			--			288.1
Other current liabilities		298.1		321.8		(7.4	)		612.5		--			0.1			612.6
Total current liabilities		5,839.0		3,885.7		(2,292.4	)		7,432.3		--			0.1			7,432.4
Long-term debt		13,975.1		54.3		--			14,029.4		--			--			14,029.4
Deferred tax liabilities		22.2		67.1		2.8			92.1		--			(0.9	)		91.2
Other long-term liabilities		155.3		197.5		--			352.8		--			--			352.8
Commitments and contingencies
Equity:
Partners’ and other owners’ equity		12,242.7		28,799.8		(28,946.4	)		12,096.1		12,113.4			(12,096.1	)		12,113.4
Noncontrolling interests		--		4,667.4		(4,543.9	)		123.5		--			(17.6	)		105.9
Total equity		12,242.7		33,467.2		(33,490.3	)		12,219.6		12,113.4			(12,113.7	)		12,219.3
Total liabilities and equity	$	32,234.3	$	37,671.8	$	(35,779.9	)	$	34,126.2	$	12,113.4		$	(12,114.5	)	$	34,125.1

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non-guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	7,639.8		$	7,158.5		$	(3,545.8	)	$	11,252.5		$	--	$	--		$	11,252.5
Costs and expenses:
Operating costs and expenses		7,409.8			6,603.6			(3,546.2	)		10,467.2			--		--			10,467.2
General and administrative costs		15.4			30.7			--			46.1			0.2		--			46.3
Total costs and expenses		7,425.2			6,634.3			(3,546.2	)		10,513.3			0.2		--			10,513.5
Equity in income of unconsolidated affiliates		594.5			78.4			(663.0	)		9.9			651.5		(651.5	)		9.9
Operating income		809.1			602.6			(662.6	)		749.1			651.3		(651.5	)		748.9
Other income (expense):
Interest expense		(185.6	)		(0.9	)		--			(186.5	)		--		--			(186.5	)
Other, net		0.1			58.6			--			58.7			--		--			58.7
Total other expense, net		(185.5	)		57.7			--			(127.8	)		--		--			(127.8	)
Income before income taxes		623.6			660.3			(662.6	)		621.3			651.3		(651.5	)		621.1
Benefit from income taxes		27.0			7.4			--			34.4			--		--			34.4
Net income		650.6			667.7			(662.6	)		655.7			651.3		(651.5	)		655.5
Net loss (income) attributable to noncontrolling interests		--			(44.4	)		39.7			(4.7	)		--		0.5			(4.2	)
Net income attributable to entity	$	650.6		$	623.3		$	(622.9	)	$	651.0		$	651.3	$	(651.0	)	$	651.3

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non-guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	8,324.8		$	6,078.7		$	(4,219.8	)	$	10,183.7		$	--	$	--		$	10,183.7
Costs and expenses:
Operating costs and expenses		8,178.2			5,578.6			(4,219.7	)		9,537.1			--		--			9,537.1
General and administrative costs		0.9			33.7			--			34.6			3.3		--			37.9
Total costs and expenses		8,179.1			5,612.3			(4,219.7	)		9,571.7			3.3		--			9,575.0
Equity in income of unconsolidated affiliates		458.0			31.8			(473.6	)		16.2			424.0		(424.0	)		16.2
Operating income		603.7			498.2			(473.7	)		628.2			420.7		(424.0	)		624.9
Other income (expense):
Interest expense		(179.0	)		(6.7	)		1.9			(183.8	)		--		--			(183.8	)
Other, net		2.0			0.4			(1.9	)		0.5			--		--			0.5
Total other expense, net		(177.0	)		(6.3	)		--			(183.3	)		--		--			(183.3	)
Income before income taxes		426.7			491.9			(473.7	)		444.9			420.7		(424.0	)		441.6
Provision for income taxes		(2.8	)		(4.3	)		--			(7.1	)		--		--			(7.1	)
Net income		423.9			487.6			(473.7	)		437.8			420.7		(424.0	)		434.5
Net loss (income) attributable to noncontrolling interests		--			(3.4	)		(10.7	)		(14.1	)		--		0.3			(13.8	)
Net income attributable to entity	$	423.9		$	484.2		$	(484.4	)	$	423.7		$	420.7	$	(423.7	)	$	420.7

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Comprehensive Income

Three Months Ended March 31, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non-guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	679.8	$	648.1		$	(662.6	)	$	665.3		$	651.3	$	(651.5	)	$	665.1
Comprehensive income attributable to noncontrolling interests		--		(44.4	)		39.7			(4.7	)		--		0.5			(4.2	)
Comprehensive income attributable to entity	$	679.8	$	603.7		$	(622.9	)	$	660.6		$	651.3	$	(651.0	)	$	660.9

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Comprehensive Income

Three Months Ended March 31, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non-guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Comprehensive income	$	435.1	$	408.8		$	(473.7	)	$	370.2		$	420.7	$	(424.0	)	$	366.9
Comprehensive income attributable to noncontrolling interests		--		(3.4	)		(10.7	)		(14.1	)		--		0.3			(13.8	)
Comprehensive income attributable to entity	$	435.1	$	405.4		$	(484.4	)	$	356.1		$	420.7	$	(423.7	)	$	353.1

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non-guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	650.6		$	667.7		$	(662.6	)	$	655.7		$	651.3		$	(651.5	)	$	655.5
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		33.0			233.4			(0.3	)		266.1			--			--			266.1
Equity in income of unconsolidated affiliates		(594.5	)		(78.4	)		663.0			(9.9	)		(651.5	)		651.5			(9.9	)
Distributions received from unconsolidated affiliates		10.0			25.8			(8.8	)		27.0			531.6			(531.6	)		27.0
Net effect of changes in operating accounts and other operating activities		(489.4	)		335.8			(191.4	)		(345.0	)		11.5			(0.3	)		(333.8	)
Net cash flows provided by operating activities		(390.3	)		1,184.3			(200.1	)		593.9			542.9			(531.9	)		604.9
Investing activities:
Capital expenditures, net of contributions in aid of construction costs		(16.0	)		(952.1	)		--			(968.1	)		--			--			(968.1	)
Proceeds from asset sales		976.1			22.1			--			998.2			--			--			998.2
Other investing activities		(38.9	)		(39.2	)		12.5			(65.6	)		(31.8	)		31.8			(65.6	)
Cash used in investing activities		921.2			(969.2	)		12.5			(35.5	)		(31.8	)		31.8			(35.5	)
Financing activities:
Borrowings under debt agreements		1,396.6			--			--			1,396.6			--			--			1,396.6
Repayments of debt		(1,290.5	)		(9.5	)		--			(1,300.0	)		--			--			(1,300.0	)
Cash distributions paid to partners		(531.6	)		(208.0	)		208.0			(531.6	)		(530.4	)		531.6			(530.4	)
Cash distributions paid to noncontrolling interests		--			(4.4	)		(2.2	)		(6.6	)		--			--			(6.6	)
Cash contributions from noncontrolling interests		--			--			4.9			4.9			--			--			4.9
Net cash proceeds from issuance of common units		--			--			--			--			29.0			--			29.0
Cash contributions from owners		31.8			17.3			(17.3	)		31.8			--			(31.8	)		--
Other financing activities		(84.6	)		--			(0.1	)		(84.7	)		(9.7	)		--			(94.4	)
Cash provided by (used in) financing activities		(478.3	)		(204.6	)		193.3			(489.6	)		(511.1	)		499.8			(500.9	)
Net change in cash and cash equivalents		52.6			10.5			5.7			68.8			--			(0.3	)		68.5
Cash and cash equivalents, January 1		9.7			21.3			(11.2	)		19.8			--			--			19.8
Cash and cash equivalents, March 31	$	62.3		$	31.8		$	(5.5	)	$	88.6		$	--		$	(0.3	)	$	88.3

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Unaudited Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2011

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non-guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	423.9		$	487.6		$	(473.7	)	$	437.8		$	420.7		$	(424.0	)	$	434.5
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		27.8			213.6			(0.3	)		241.1			--			--			241.1
Equity in income of unconsolidated affiliates		(458.0	)		(31.8	)		473.6			(16.2	)		(424.0	)		424.0			(16.2	)
Distributions received from unconsolidated affiliates		65.5			56.1			(79.1	)		42.5			481.7			(481.7	)		42.5
Net effect of changes in operating accounts and other operating activities		455.1			(275.3	)		(85.3	)		94.5			6.3			--			100.8
Net cash flows provided by operating activities		514.3			450.2			(164.8	)		799.7			484.7			(481.7	)		802.7
Investing activities:
Capital expenditures, net of contributions in aid of construction costs		(24.9	)		(685.4	)		--			(710.3	)		--			--			(710.3	)
Other investing activities		(309.5	)		79.0			214.4			(16.1	)		(22.1	)		22.1			(16.1	)
Cash used in investing activities		(334.4	)		(606.4	)		214.4			(726.4	)		(22.1	)		22.1			(726.4	)
Financing activities:
Borrowings under debt agreements		2,662.1			159.5			--			2,821.6			--			--			2,821.6
Repayments of debt		(2,266.0	)		(50.0	)		--			(2,316.0	)		--			--			(2,316.0	)
Cash distributions paid to partners		(481.7	)		(132.8	)		132.8			(481.7	)		(479.7	)		481.7			(479.7	)
Cash distributions paid to noncontrolling interests		--			(41.7	)		24.5			(17.2	)		--			--			(17.2	)
Cash contributions from noncontrolling interests		--			214.3			(213.0	)		1.3			--			--			1.3
Net cash proceeds from issuance of common units		--			--			--			--			21.0			--			21.0
Cash contributions from owners		22.1			1.4			(1.4	)		22.1			--			(22.1	)		--
Other financing activities		(18.5	)		--			--			(18.5	)		(3.9	)		--			(22.4	)
Cash provided by (used in) financing activities		(82.0	)		150.7			(57.1	)		11.6			(462.6	)		459.6			8.6
Net change in cash and cash equivalents		97.9			(5.5	)		(7.5	)		84.9			--			--			84.9
Cash and cash equivalents, January 1		0.5			67.9			(2.9	)		65.5			--			--			65.5
Cash and cash equivalents, March 31	$	98.4		$	62.4		$	(10.4	)	$	150.4		$	--		$	--		$	150.4

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

For the three months ended March 31, 2012 and 2011.

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying Notes included in this quarterly report on Form 10-Q and the Audited Consolidated Financial Statements and related Notes, together with our discussion and analysis of financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2011, as filed on February 29, 2012 (the “2011 Form 10-K”). Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”).

Key References Used in this Quarterly Report

On April 28, 2011, we, our general partner, EPD MergerCo LLC (“Duncan MergerCo,” a Delaware limited liability company and our wholly owned subsidiary), Duncan Energy Partners L.P. (“Duncan Energy Partners”) and DEP Holdings, LLC (“DEP GP,” the general partner of Duncan Energy Partners) entered into a definitive merger agreement (the “Duncan Merger Agreement”). On September 7, 2011, the Duncan Merger Agreement was approved by the unitholders of Duncan Energy Partners and the merger of Duncan MergerCo with and into Duncan Energy Partners and related transactions were completed, with Duncan Energy Partners surviving such merger as our wholly owned subsidiary (collectively, we refer to these transactions as the “Duncan Merger”). Since we historically consolidated Duncan Energy Partners for financial reporting purposes, the Duncan Merger did not change the basis of presentation of our historical financial statements. For additional information regarding the Duncan Merger, see Note 1 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

References to “TEPPCO” mean TEPPCO Partners, L.P. prior to its merger with one of our subsidiaries on October 26, 2009.

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries.

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As generally used in the energy industry and in this quarterly report, the acronyms below have the following meanings:

/d	= per day	MMBbls	= million barrels
BBtus	= billion British thermal units	MMBPD	= million barrels per day
Bcf	= billion cubic feet	MMBtus	= million British thermal units
BPD	= barrels per day	MMcf	= million cubic feet
MBPD	= thousand barrels per day	TBtus	= trillion British thermal units

Cautionary Statement Regarding Forward-Looking Information

This discussion contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we and our general partner believe that our expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A “Risk Factors” included in our 2011 Form 10-K. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this quarterly report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

Overview of Business

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are now a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, refined products and certain petrochemicals. Our midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the U.S., Canada and the Gulf of Mexico with domestic consumers and international markets. Our assets include approximately 50,600 miles of onshore and offshore pipelines; 190 MMBbls of storage capacity for NGLs, crude oil, refined products and certain petrochemicals; and 14 Bcf of working natural gas storage capacity.

We conduct substantially all of our business through EPO and are owned 100% by our limited partners from an economic perspective. Enterprise GP owns a non-economic general partner interest in us.

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Significant Recent Developments

The following information highlights significant developments since January 1, 2012 through the date of this filing (May 10, 2012), including (i) information relevant to an understanding of our financial condition, changes in financial condition or results of operation; and (ii) certain unusual or infrequent events or transactions and known trends or uncertainties that have had or that we reasonably expect may have a material impact on our revenues or income from continuing operations.

Plans to Construct Front Range Pipeline

In April 2012, we, along with Anadarko Petroleum Corporation and DCP Midstream, LLC formed a new joint venture, Front Range Pipeline LLC, to design and construct a new NGL pipeline that will originate in the Denver-Julesburg Basin (the “DJ Basin”) in Weld County, Colorado and extend approximately 435 miles to Skellytown in Carson County, Texas. Each party holds a one-third ownership interest in the joint venture. The Front Range Pipeline, with connections to our Mid-America Pipeline System and the Texas Express Pipeline, is expected to provide producers in the DJ Basin with access to the Gulf Coast, the largest NGL market in the U.S. Depending on shipper interest in a binding open commitment period that commenced in April 2012, initial capacity on the Front Range Pipeline is expected to be approximately 150 MBPD, which can be readily expanded to approximately 230 MBPD. We will construct and operate the pipeline, which is expected to begin service in the fourth quarter of 2013.

Expansion of Seaway Crude Oil Pipeline

We and Enbridge Inc. (“Enbridge”) are nearing completion of the first phase of the reversal of the Seaway Crude Pipeline System (the “Seaway Pipeline”), which will provide 150 MBPD of southbound takeaway capacity from the Cushing, Oklahoma hub to the Gulf Coast as early as May 17, 2012. Following pump station additions and modifications, which are expected to be completed by the first quarter of 2013, throughput capacity on the Seaway Pipeline would increase to 400 MBPD, assuming a mix of light and heavy grades of crude oil.

In March 2012, we and Enbridge announced that we had secured capacity commitments from shippers to proceed with an expansion of the Seaway Pipeline. During the supplemental binding open commitment period, additional commitments were made with terms ranging from five to 20 years that support construction of a 512-mile, 30-inch diameter parallel pipeline along the existing route of the Seaway Pipeline, which would add 450 MBPD of throughput capacity to the system and bring total southbound throughput capacity up to 850 MBPD by mid-2014.

The reversed Seaway Pipeline will deliver crude oil from Cushing into the Houston, Texas market by utilizing affiliate and third party pipelines. Seaway plans to build a 65-mile pipeline that will link its pipeline to our Enterprise Crude Houston (“ECHO”) crude oil storage terminal, which is being constructed southeast of Houston. Completion of this pipeline segment is expected in 2013. In addition, Seaway plans to build an 85-mile pipeline from our ECHO facility to the Port Arthur/Beaumont, Texas refining center that would provide shippers access to the region’s heavy oil refining capabilities. Completion of this pipeline segment is expected in early 2014.

Plans to Construct NGL Fractionators Seven and Eight at Our Mont Belvieu Complex

In March 2012, we announced plans to construct two additional NGL fractionators at our Mont Belvieu, Texas complex that would provide us with 150 MBPD of incremental NGL fractionation capacity. The two new fractionation units (each with 75 MBPD of design capacity) are projected to begin service in the fourth quarter of 2013 and would facilitate the continued growth of NGL production from expanding production basins such as the Eagle Ford Shale in South Texas and various Rocky Mountain production basins. Once these two new units are constructed and placed in service, the NGL fractionation capacity of our Mont Belvieu units (eight fractionators in total) would be 610 MBPD in the aggregate.

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Development of Our ATEX Express Long-Haul Ethane Pipeline

In January 2012, we announced the receipt of sufficient transportation commitments to support development of our 1,230-mile Appalachia to Texas pipeline (the “ATEX Express”) that will transport growing ethane production from the Marcellus and Utica Shale producing areas of Pennsylvania, West Virginia and Ohio to the U.S. Gulf Coast. Demand for ethane feedstock over more expensive crude oil-based derivatives within the Gulf Coast petrochemical market has reached over 1 MMBPD and continues to increase given current pricing differentials. Several petrochemical companies have made announcements to modify, expand or build new facilities that would use ethane as a feedstock. As currently designed, the ATEX Express will have the capacity to transport up to 190 MBPD of ethane from the Appalachian production areas to our storage and distribution assets in southeast Texas.

The project would utilize a combination of new and existing infrastructure. The northern portion of the ATEX Express involves construction of a pipeline that would originate in Pennsylvania and extend west, then southwest, to Indiana following existing pipeline corridors in order to minimize the footprint of the project. The southern portion of ATEX Express would utilize a significant portion of our existing Products Pipeline System, which would be reversed to accommodate southbound delivery of ethane to the U.S. Gulf Coast. At the southern terminus of the ATEX Express in Beaumont, we plan to construct a 55-mile pipeline to provide shippers with access to our NGL storage complex at Mont Belvieu, which would provide them with direct and indirect access to every ethylene plant in the U.S. We expect that the ATEX Express will begin commercial operations in the first quarter of 2014.

Plans to Construct a Crude Oil Pipeline in the Gulf of Mexico with Genesis

In January 2012, we announced the execution of crude oil transportation agreements with a consortium of six Gulf of Mexico producers that will provide the necessary support for construction of a crude oil gathering pipeline serving the Lucius oil and gas field located in the southern Keathley Canyon area of the deepwater central Gulf of Mexico. The pipeline will be constructed and owned by Southeast Keathley Canyon Pipeline Company, L.L.C. (“SEKCO”), which is a 50/50 joint venture owned by us and Genesis Energy, L.P. (“Genesis”). We will serve as construction manager and operator of the new deepwater pipeline (the “SEKCO Oil Pipeline”). The SEKCO Oil Pipeline is expected to begin service by mid-2014.

Sales of Energy Transfer Equity Common Units

At December 31, 2011, we owned 29,303,514 common units of Energy Transfer Equity. On January 18, 2012, we sold 22,762,636 of these common units in a private transaction, which generated cash proceeds of approximately $825.1 million and a gain on the sale of $27.5 million. Following the January 18 transaction, we sold an additional 3,569,232 Energy Transfer Equity common units through March 31, which generated cash proceeds of approximately $150.8 million and aggregate gains on these sales of $25.8 million. Proceeds from these sales were used for general company purposes, including funding capital expenditures.

Following completion of the January 18 transaction, our ownership percentage in Energy Transfer Equity was below 3% and we discontinued using the equity method to account for this investment and began accounting for the remaining units as an investment in available-for-sale equity securities. At March 31, 2012, we owned 2,971,646 common units of Energy Transfer Equity, which represented approximately 1.3% of its common units outstanding on April 3, 2012. We sold the remainder of our investment in Energy Transfer Equity in April 2012. See Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, Item 1 of this quarterly report for information regarding our investment in Energy Transfer Equity and related sales.

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Results of Operations

The following table summarizes the key components of our results of operations for the periods presented (dollars in millions):

	For the Three Months
	Ended March 31,
	2012		2011
Revenues	$	11,252.5	$	10,183.7
Operating costs and expenses		10,467.2		9,537.1
General and administrative costs		46.3		37.9
Equity in income of unconsolidated affiliates		9.9		16.2
Operating income		748.9		624.9
Interest expense		186.5		183.8
Benefit from (provision for) income taxes		34.4		(7.1	)
Net income		655.5		434.5
Net income attributable to noncontrolling interests		4.2		13.8
Net income attributable to limited partners		651.3		420.7

Our non-GAAP gross operating margin by business segment and in total is as follows for the periods presented (dollars in millions):

	For the Three Months
	Ended March 31,
	2012		2011
NGL Pipelines & Services	$	654.9	$	504.4
Onshore Natural Gas Pipelines & Services		206.2		159.2
Onshore Crude Oil Pipelines & Services		39.3		31.8
Offshore Pipelines & Services		52.1		61.3
Petrochemical & Refined Products Services		97.8		112.4
Other Investments (1)		2.4		6.3
Total segment gross operating margin	$	1,052.7	$	875.4

(1) Represents the equity earnings we recorded from our investment in Energy Transfer Equity. Our reporting for this segment ceased on January 18, 2012 when we stopped using the equity method to account for this investment. See Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our investment in Energy Transfer Equity.

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The following table presents a reconciliation of total segment gross operating margin to GAAP operating income and further to income before income taxes for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2012			2011
Total segment gross operating margin	$	1,052.7		$	875.4
Adjustments to reconcile total segment gross operating margin to operating income:
Depreciation, amortization and accretion in operating costs and expenses		(254.6	)		(230.8	)
Non-cash asset impairment charges		(5.4	)		--
Operating lease expenses paid by EPCO		--			(0.2	)
Gains from asset sales and related transactions in operating costs and expenses		2.5			18.4
General and administrative costs		(46.3	)		(37.9	)
Operating income		748.9			624.9
Other expense, net		(127.8	)		(183.3	)
Income before income taxes	$	621.1		$	441.6

The following table summarizes each business segment’s contribution to revenues (net of eliminations and adjustments) for the periods presented (dollars in millions):

	For the Three Months Ended March 31,
	2012		2011
NGL Pipelines & Services:
Sales of NGLs and related products	$	4,115.3	$	4,057.7
Midstream services		239.2		199.1
Total		4,354.5		4,256.8
Onshore Natural Gas Pipelines & Services:
Sales of natural gas		572.6		712.7
Midstream services		261.0		203.9
Total		833.6		916.6
Onshore Crude Oil Pipelines & Services:
Sales of crude oil		4,447.6		3,348.2
Midstream services		26.0		22.4
Total		4,473.6		3,370.6
Offshore Pipelines & Services:
Sales of natural gas		0.1		0.3
Sales of crude oil		1.4		3.3
Midstream services		54.6		60.8
Total		56.1		64.4
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		1,351.2		1,382.8
Midstream services		183.5		192.5
Total		1,534.7		1,575.3
Total consolidated revenues	$	11,252.5	$	10,183.7

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Selected Price and Volumetric Data

The following table presents selected annual and quarterly industry index prices for natural gas, crude oil and selected NGL and petrochemical products for the periods presented:

													Polymer		Refinery
	Natural						Normal				Natural		Grade		Grade
	Gas,		Ethane,		Propane,		Butane,		Isobutane,		Gasoline,		Propylene,		Propylene,		Crude Oil,
	$/MMBtu		$/gallon		$/gallon		$/gallon		$/gallon		$/gallon		$/pound		$/pound		$/barrel
	(1)		(2)		(2)		(2)		(2)		(2)		(3)		(3)		(4)
2011
1st Quarter	$	4.11	$	0.66	$	1.37	$	1.75	$	1.85	$	2.27	$	0.76	$	0.68	$	94.10
2nd Quarter	$	4.32	$	0.78	$	1.49	$	1.87	$	2.02	$	2.48	$	0.89	$	0.79	$	102.56
3rd Quarter	$	4.20	$	0.78	$	1.54	$	1.88	$	2.09	$	2.37	$	0.78	$	0.67	$	89.76
4th Quarter	$	3.54	$	0.86	$	1.44	$	1.89	$	2.26	$	2.24	$	0.59	$	0.44	$	94.06
2011 Averages	$	4.04	$	0.77	$	1.46	$	1.85	$	2.06	$	2.34	$	0.76	$	0.64	$	95.12

2012
1st Quarter	$	2.72	$	0.56	$	1.26	$	1.93	$	2.04	$	2.39	$	0.69	$	0.60	$	102.93

(1) Natural gas prices are based on Henry-Hub I-FERC commercial index prices. (2) NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service. (3) Polymer-grade propylene prices represent average contract pricing for such product as reported by Chemical Market Associates, Inc. (“CMAI”). Refinery grade propylene prices represent weighted-average spot prices for such product as reported by CMAI. (4) Crude oil prices are based on commercial index prices for West Texas Intermediate as measured on the New York Mercantile Exchange (“NYMEX”).

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The following table presents our significant average throughput, production and processing volumetric data for the periods presented. These statistics are reported on a net basis, taking into account our ownership interests in certain joint ventures, and reflect the periods in which we owned an interest in such operations. These statistics reflect volumes for newly constructed assets from the dates such assets were placed into service and for recently purchased assets from the date of acquisition.

	For the Three Months
	Ended March 31,
	2012		2011
NGL Pipelines & Services, net:
NGL transportation volumes (MBPD)		2,340		2,366
NGL fractionation volumes (MBPD)		623		549
Equity NGL production (MBPD) (1)		112		119
Fee-based natural gas processing (MMcf/d) (2)		4,134		3,698
Onshore Natural Gas Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)		13,081		11,678
Onshore Crude Oil Pipelines & Services, net:
Crude oil transportation volumes (MBPD)		706		666
Offshore Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)		962		1,155
Crude oil transportation volumes (MBPD)		288		299
Platform natural gas processing (MMcf/d)		356		445
Platform crude oil processing (MBPD)		21		16
Petrochemical & Refined Products Services, net:
Butane isomerization volumes (MBPD)		82		88
Propylene fractionation volumes (MBPD)		72		73
Octane additive and associated plant production volumes (MBPD)		4		13
Transportation volumes, primarily refined products and petrochemicals (MBPD)		659		743
Total, net:
NGL, crude oil, refined products and petrochemical transportation volumes (MBPD)		3,993		4,074
Natural gas transportation volumes (BBtus/d)		14,043		12,833
Equivalent transportation volumes (MBPD) (3)		7,689		7,451
(1) Represents the NGL volumes we earn and take title to in connection with our processing activities. (2) Volumes reported correspond to the revenue streams earned by our gas plants. (3) Reflects equivalent energy volumes where 3.8 MMBtus of natural gas are equivalent to one barrel of NGLs.

Comparison of Three Months Ended March 31, 2012 with Three Months Ended March 31, 2011

Revenues for the first quarter of 2012 were $11.25 billion compared to $10.18 billion for the first quarter of 2011, a $1.07 billion quarter-to-quarter increase primarily due to a $1.10 billion increase in crude oil sales revenues attributable to higher sales volumes and prices (more than 80% of the increase in crude oil sales revenues is due to higher sales volumes). Operating costs and expenses were $10.47 billion for the first quarter of 2012 compared to $9.54 billion for the first quarter of 2011, a $930.1 million quarter-to-quarter increase. Cost of sales related to our marketing activities increased $758.4 million quarter-to-quarter primarily due to higher crude oil sales volumes and prices.

Changes in our revenues and operating costs and expenses quarter-to-quarter are explained in part by changes in energy commodity prices. The weighted-average indicative market price for NGLs was $1.35 per gallon during the first quarter of 2012 versus $1.36 per gallon during the first quarter of 2011. Our determination of the weighted-average indicative market price for NGLs is based on U.S. Gulf Coast prices for such products at Mont Belvieu, Texas, which is the primary industry hub for domestic NGL production. The market price of natural gas (as measured at Henry Hub in Louisiana) averaged $2.72 per MMBtu during the first quarter of 2012 versus $4.11 per MMBtu during the first quarter of 2011 – a 34% quarter-to-quarter decrease. The market price of crude oil (as measured on the NYMEX) averaged $102.93 per barrel during the first quarter of 2012 compared to $94.10 per barrel during the first quarter of 2011 – a 9% quarter-to-quarter increase. See “Selected Price and Volumetric Data” included within this Item 2 for additional historical energy commodity pricing information.

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General and administrative costs were $46.3 million for the first quarter of 2012 compared to $37.9 million for the first quarter of 2011. The $8.4 million quarter-to-quarter increase is primarily due to higher employee compensation, professional services and depreciation expenses for the first quarter of 2012 compared to the first quarter of 2011.

Consolidated interest expense was $186.5 million in the first quarter of 2012 compared to $183.8 million in the first quarter of 2011, a $2.7 million quarter-to-quarter increase. Although our average debt principal balances increased to $14.5 billion in the first quarter of 2012 from $14.11 billion in the first quarter of 2011, a substantial portion of the costs associated with the new borrowings was capitalized in connection with our capital spending program. Capitalized interest increased $13.4 million quarter-to-quarter to $30.6 million for the first quarter of 2012 from $17.2 million for the first quarter of 2011.

We recognized $53.3 million of gains during the first quarter of 2012 in connection with our sales of 26,331,868 common units of Energy Transfer Equity. These gains are a component of “Other, net” as presented on our Unaudited Condensed Statements of Consolidated Operations. See Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, Item 1 of this quarterly report for information regarding our investment in Energy Transfer Equity and related sales.

We recognized a net income tax benefit of $34.4 million during the first quarter of 2012 compared to a $7.1 million provision for income taxes recognized for the first quarter of 2011. The $41.5 million quarter-to-quarter change in income taxes is primarily due to a $46.5 million benefit related to the conversion of certain of our subsidiaries to limited liability companies in the first quarter of 2012.

The following information highlights significant quarter-to-quarter variances in gross operating margin by business segment and the primary drivers of these variances:

NGL Pipelines & Services. Gross operating margin from this business segment was $654.9 million for the first quarter of 2012 compared to $504.4 million for the first quarter of 2011, a $150.5 million quarter-to-quarter increase. Gross operating margin from our natural gas processing and related NGL marketing business was $421.7 million for the first quarter of 2012 compared to $277.7 million for the first quarter of 2011, a $144.0 million quarter-to-quarter increase. Gross operating margin from our NGL marketing activities increased $64.8 million quarter-to-quarter due to higher sales margins. Collectively, gross operating margin from our natural gas processing plants located in southern Louisiana, the Rocky Mountains and Permian Basin increased $72.2 million quarter-to-quarter primarily due to higher natural gas processing margins during the first quarter of 2012 compared to the first quarter of 2011 and a benefit of $20.0 million from a vendor settlement in the first quarter of 2012.

Gross operating margin from our NGL pipelines and related storage business was $168.4 million for the first quarter of 2012 compared to $179.9 million for the first quarter of 2011, an $11.5 million quarter-to-quarter decrease. Gross operating margin from our Dixie Pipeline and related NGL terminals decreased $8.5 million quarter-to-quarter primarily due to higher pipeline integrity expenses during the first quarter of 2012 and a 52 MBPD decrease in transportation volumes attributable to warmer weather and project-related downtime. Gross operating margin from our NGL pipelines in southern Louisiana decreased $7.3 million quarter-to-quarter primarily due to a 107 MBPD decrease in transportation volumes attributable to lower production volumes from the Gulf of Mexico and decreased volumes transported from Mont Belvieu to NGL fractionators in southern Louisiana. Gross operating margin from our Mid-America Pipeline System, Seminole Pipeline and related NGL terminals increased $14.1 million quarter-to-quarter primarily due to an 84 MBPD increase in transportation volumes and an increase in system-wide tariffs in July 2011. Collectively, gross operating margin from the remainder of our NGL pipelines and related storage business decreased $9.8 million primarily due to higher operating expenses during the first quarter of 2012 compared to the first quarter of 2011. Gross operating margin from net operational measurement gains during the first quarter of 2011 that did not reoccur during the first quarter of 2012, higher maintenance expenses and expense accruals for sales and use taxes all contributed to the quarter-to-quarter increase in operating expenses.

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Gross operating margin from our NGL fractionation business was $64.8 million for the first quarter of 2012 compared to $46.8 million for the first quarter of 2011, an $18.0 million quarter-to-quarter increase. Gross operating margin from our Mont Belvieu NGL fractionators increased $14.0 million quarter-to-quarter primarily due to higher NGL fractionation volumes. During the fourth quarter of 2011, we placed into service a fifth NGL fractionator at our complex in Mont Belvieu, Texas, which added more than 75 MBPD of NGL fractionation capacity at this key industry hub.

Onshore Natural Gas Pipelines & Services. Gross operating margin from this business segment was $206.2 million for the first quarter of 2012 compared to $159.2 million for the first quarter of 2011, a $47.0 million quarter-to-quarter increase. Gross operating margin from our Acadian Gas System increased $40.8 million quarter-to-quarter primarily due to revenues earned by our Haynesville Extension pipeline. The Haynesville Extension of our Acadian Gas System commenced operations in November 2011 and transported 1.18 TBtus/d of natural gas during the first quarter of 2012. Gross operating margin from our Texas Intrastate System increased $29.0 million quarter-to-quarter primarily due to higher firm capacity reservation revenues and a 428 BBtus/d quarter-to-quarter increase in natural gas throughput volumes. Increased natural gas production volumes from the Eagle Ford Shale supply basin resulted in stronger demand for our natural gas transportation services during the first quarter of 2012 compared to the first quarter of 2011. Gross operating margin from our natural gas marketing activities decreased $5.8 million quarter-to-quarter primarily due to lower sales margins. Gross operating margin from our natural gas storage business was $1.8 million for the first quarter of 2012 compared to $13.2 million for the first quarter of 2011, an $11.4 million quarter-to-quarter decrease primarily due to the sale of our Mississippi natural gas storage facilities in December 2011.

Onshore Crude Oil Pipelines & Services. Gross operating margin from this business segment was $39.3 million for the first quarter of 2012 compared to $31.8 million for the first quarter of 2011, a $7.5 million quarter-to-quarter increase. Gross operating margin from our crude oil marketing and related activities increased $2.8 million quarter-to-quarter primarily due to higher sales volumes. Our crude oil marketing activities benefited from increased crude oil production volumes from supply basins in the Eagle Ford Shale, Barnett Shale, West Texas and Rocky Mountains. Collectively, gross operating margin from our South Texas Crude Oil Pipeline System, West Texas System, Red River System and Basin Pipeline System increased $5.8 million quarter-to-quarter due to a 41 MBPD increase in throughput volumes and higher average fees during the first quarter of 2012.

Offshore Pipelines & Services. Gross operating margin from this business segment was $52.1 million for the first quarter of 2012 compared to $61.3 million for the first quarter of 2011, a $9.2 million quarter-to-quarter decrease. Collectively, gross operating margin from our Independence Hub platform and Trail pipeline decreased $8.8 million quarter-to-quarter primarily due to lower throughput volumes and platform demand fee revenues during the first quarter of 2012 compared to the first quarter of 2011. Producers connected to our Independence Hub platform paid us approximately $54.6 million of demand fees annually for five years beginning in March 2007 until that period expired in March 2012. Expiration of the contractual demand fees during the first quarter of 2012 resulted in a $4.0 million quarter-to-quarter decrease in gross operating margin. Net to our interest, natural gas processing volumes on the Independence Hub platform decreased 95 MMcf/d quarter-to-quarter as a result of depletion at existing production wells and the watering-out of certain wells, which volumes have not been replaced by new production.

Petrochemical & Refined Products Services. Gross operating margin from this business segment was $97.8 million for the first quarter of 2012 compared to $112.4 million for the first quarter of 2011, a $14.6 million quarter-to-quarter decrease.

Gross operating margin from propylene fractionation and related activities was $61.1 million for the first quarter of 2012 compared to $48.8 million for the first quarter of 2011, a $12.3 million quarter-to-quarter increase. The quarter-to-quarter increase in gross operating margin is primarily due to higher propylene sales volumes and margins during the first quarter of 2012 compared to the first quarter of 2011.

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Gross operating margin from butane isomerization was $20.6 million for the first quarter of 2012 compared to $25.7 million for the first quarter of 2011, a $5.1 million quarter-to-quarter decrease. The quarter-to-quarter decrease in gross operating margin is primarily due to lower isomerization volumes and decreased by-product sales. The decrease in isomerization volumes was attributable to downtime at our octane enhancement facility during the first quarter of 2012, which reduced the demand for isobutane used as feedstock.

Gross operating margin from octane enhancement and HPIB production was a loss of $13.1 million for the first quarter of 2012 compared to income of $6.1 million for the first quarter of 2011, a $19.2 million quarter-to-quarter decrease. The quarter-to-quarter decrease in gross operating margin is primarily due to lower volumes and higher operating expenses at our octane enhancement facility in Mont Belvieu, Texas as a result of unscheduled maintenance during the first quarter of 2012.

Gross operating margin from refined products pipelines and related activities was $12.1 million for the first quarter of 2012 compared to $18.3 million for the first quarter of 2011, a $6.2 million quarter-to-quarter decrease. The quarter-to-quarter decrease in gross operating margin is primarily due to a 59 MBPD quarter-to-quarter decrease in propane and butane volumes delivered to Northeast U.S. markets and a 59 MBPD quarter-to-quarter decrease in refined products volumes delivered to Midwest U.S. markets. Warmer weather during the first quarter of 2012 compared to the same period in 2011 resulted in lower demand for propane used as heating fuel, while shipments of refined products from the Gulf Coast to Midwest markets decreased as a result of low prices for such products.

Liquidity and Capital Resources

At March 31, 2012, we had $3.59 billion of consolidated liquidity, which is defined as unrestricted cash on hand plus borrowing capacity available under EPO’s $3.5 Billion Multi-Year Revolving Credit Facility. Based on current market conditions, we believe we will have sufficient liquidity, cash flow from operations and access to capital markets to fund our capital expenditures and working capital needs.

Long-Term Debt

We had approximately $14.58 billion of principal amounts outstanding under consolidated debt agreements at March 31, 2012. In February 2012, EPO issued $750.0 million in principal amount of 30-year unsecured Senior Notes EE. These notes were issued at 99.542% of their principal amount, have a fixed-rate of interest of 4.85% and mature on August 15, 2042. Net proceeds from the issuance of Senior Notes EE were used to temporarily reduce borrowings outstanding under EPO’s $3.5 Billion Multi-Year Revolving Credit Facility (which was used to repay at maturity its $490.5 million principal amount of Senior Notes S due February 2012 and $9.5 million principal amount of TEPPCO Senior Notes due February 2012 prior to the delivery of Senior Notes EE) and for general company purposes.

For additional information regarding our consolidated debt obligations, see Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Registration Statements

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For information regarding our registration statements, see Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Credit Ratings

As of May 1, 2012, the investment-grade credit ratings of EPO’s senior unsecured debt securities were: BBB from Standard and Poor’s; Baa2 from Moody’s; and BBB from Fitch Ratings. EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods indicated (dollars in millions). For additional information regarding our cash flow amounts, please refer to the Unaudited Condensed Statements of Consolidated Cash Flows included under Part I, Item 1 of this quarterly report.

	For the Three Months
	Ended March 31,
	2012			2011
Net cash flows provided by operating activities	$	604.9		$	802.7
Cash used in investing activities		35.5			726.4
Cash provided by (used in) financing activities		(500.9	)		8.6

Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities. As a result, these cash flows are exposed to certain risks. We operate predominantly in the midstream energy industry. We provide products and services to producers and consumers of natural gas, NGLs, crude oil, refined products and certain petrochemicals. The products that we process, sell, transport or store are principally used as fuel for residential, agricultural and commercial heating; as feedstocks in petrochemical manufacturing; and in the production of motor gasoline. Reduced demand for our services or products by industrial customers, whether because of a decline in general economic conditions, reduced demand for the end products made with our products, or increased competition from other service providers or producers due to pricing differences or other reasons, could have a negative impact on our earnings and operating cash flows. For a more complete discussion of these and other risk factors pertinent to our business, see “Risk Factors” under Part I, Item 1A of our 2011 Form 10-K.

The following information highlights significant quarter-to-quarter variances in our cash flow amounts and the primary drivers of these variances:

Comparison of Three Months Ended March 31, 2012 with Three Months Ended March 31, 2011

Operating Activities. The $197.8 million quarter-to-quarter decrease in net cash flows provided by operating activities was primarily due to the timing of related cash receipts and disbursements partially offset by increased earnings (e.g., our gross operating margin increased $177.3 million quarter-to-quarter).

Investing Activities. The $690.9 million decrease in cash used for investing activities was primarily due to proceeds from asset sales, which increased $914.0 million quarter-to-quarter due to the sale of 26,331,868 Energy Transfer Equity common units for $975.9 million during the first quarter of 2012 partially offset by a $257.8 million increase in capital spending for property, plant and equipment primarily for Eagle Ford Shale growth capital projects.

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Financing Activities. Cash used in financing activities was $500.9 million during the first quarter of 2012 compared to cash provided by financing activities of $8.6 million during the first quarter of 2011. The $509.5 million change was primarily due to the following:

Net borrowings under our consolidated debt agreements decreased $409.0 million quarter-to-quarter. EPO issued $750.0 million and repaid $500.0 million in principal amount of senior notes during the first quarter of 2012, compared to the issuance of $1.5 billion and repayment of $450.0 million in principal amount of senior notes during the first quarter of 2011. In addition, net repayments under our consolidated revolving bank credit facilities and term loans decreased approximately $388.5 million quarter-to-quarter.

Monetization of interest rate derivative instruments during the first quarter of 2012 resulted in a net cash outflow of $77.6 million compared to a $5.7 million outflow for similar activities during the first quarter of 2011. For information regarding our interest rate hedging activities, see Note 4 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

§	Cash distributions paid to limited partners increased $50.7 million quarter-to-quarter primarily due to a higher number of distribution-bearing common units outstanding and the associated quarterly distribution rates.

Capital Spending

An integral part of our business strategy involves expansion through growth capital projects, business combinations and investments in joint ventures. We believe that we are positioned to continue to expand our system of assets through the construction of new facilities and to capitalize on expected increases in natural gas, NGL and crude oil production resulting from development activities in the Rocky Mountains, Midcontinent, Northeast and U.S. Gulf Coast regions, including the Barnett, Eagle Ford, Haynesville, Marcellus and Utica Shale plays and deepwater Gulf of Mexico producing regions.

Although our current focus is on expansion through growth capital projects, management continues to analyze potential business combinations, joint ventures and similar transactions with businesses that operate in complementary markets or geographic regions. In past years, major oil and gas companies have sold non-strategic assets in the midstream energy sector in which we operate. We believe this trend will continue and we expect independent oil and natural gas companies to consider similar divestitures.

The following table summarizes our capital spending for the periods presented (dollars in millions):

	For the Three Months Ended March 31,
	2012		2011
Capital spending for property, plant and equipment, net of contributions in aid of construction costs	$	968.1	$	710.3
Capital spending for investments in unconsolidated affiliates		50.6		3.8
Other investing activities		--		3.6
Total capital spending	$	1,018.7	$	717.7

For the three months ended March 31, 2012, we spent $910 million on growth capital projects, of which approximately $449 million was for Eagle Ford Shale projects.

Based on information currently available, we estimate our consolidated capital spending for 2012 will approximate $4.0 billion, which includes estimated expenditures of $3.7 billion for growth capital projects and $0.3 billion for sustaining capital expenditures. Our forecast of consolidated capital expenditures for 2012 is based on our announced strategic operating and growth plans, which are dependent upon our ability to generate the required funds from either operating cash flows or other means,

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including borrowings under debt agreements, issuance of additional debt and equity securities, and potential divestitures. We may revise our forecast of capital spending due to factors beyond our control, such as weather related issues, changes in supplier prices or adverse economic conditions. Furthermore, our forecast of capital spending may change as a result of decisions made by management at a later date, which may include the addition of costs associated with unforeseen acquisition opportunities.

Our success in raising capital, including the formation of joint ventures to share costs and risks, continues to be a principal factor in determining how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs and, although we currently intend to make the forecast capital expenditures noted above, we may adjust the timing and amounts of projected expenditures in response to changes in capital markets.

At March 31, 2012, we had approximately $958.2 million in purchase commitments outstanding that relate to our capital spending for property, plant and equipment. These commitments primarily relate to construction projects in Texas, including those in the Eagle Ford Shale and at our Mont Belvieu facility.

Pipeline Integrity Costs

Our pipelines are subject to safety programs administered by the U.S. Department of Transportation (“DOT”). This federal agency has issued safety regulations containing requirements for the development of integrity management programs for hazardous liquid pipelines (e.g., NGL, crude oil, refined products and petrochemical pipelines) and natural gas pipelines. In general, these regulations require companies to assess the condition of their pipelines in certain high consequence areas (as defined by the regulation) and to perform any necessary repairs. The following table summarizes our pipeline integrity costs, including those attributable to DOT regulations, for the periods presented (dollars in millions):

	For the Three Months
	Ended March 31,
	2012		2011
Expensed	$	19.0	$	7.7
Capitalized		12.9		10.7
Total	$	31.9	$	18.4

We expect the cost of our pipeline integrity program, irrespective of whether such costs are capitalized or expensed, to approximate $85.0 million for the remainder of 2012. The cost of our pipeline integrity program was $117.3 million for the year ended December 31, 2011.

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 2011 Form 10-K. The following estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis:

§	depreciation methods and estimated useful lives of property, plant and equipment;

§	measuring recoverability of long-lived assets and equity method investments;

§	amortization methods and estimated useful lives of qualifying intangible assets;

§	methods we employ to measure the fair value of goodwill;

§	revenue recognition policies and the use of estimates when recording revenue and expense accruals;

§	reserves for environmental matters and litigation contingencies; and

§	natural gas imbalances.

When used in the preparation of our Unaudited Condensed Consolidated Financial Statements, such estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates

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will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.

Recent Accounting Developments

Other Items

Contractual Obligations

Since January 1, 2012, we (i) issued Senior Notes EE in February 2012 and (ii) repaid our Senior Notes S and $9.5 million principal amount of TEPPCO Senior Notes in February 2012. See Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, Item 1 of this quarterly report for information regarding our consolidated debt obligations. There were no material changes in our operating lease or purchase obligations since those reported in our 2011 Form 10-K.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably expected to have a material current or future effect on our financial position, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources.

Related Party Transactions

For information regarding our related party transactions, see Note 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Our exposures to market risk have not changed materially since those reported under Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” included in our 2011 Form 10-K.

We assess the risk of each of our derivative instrument portfolios using a sensitivity analysis model. The sensitivity analysis applied to each portfolio measures the potential income or loss (i.e., the change in fair value of the derivative instrument portfolio) based upon a hypothetical 10% movement in the underlying interest rates or quoted market prices (as applicable) at the dates indicated. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. The calculated results of the sensitivity analysis model do not reflect the impact that the same hypothetical price movement would have on the hedged exposures to which they relate.

We routinely review the effectiveness of our derivative instrument portfolios in light of current market conditions. If changes in market conditions or exposures warrant, the nature and volume of derivative instruments may change depending on the specific exposures being managed.

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See Note 4 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our derivative instruments and hedging activities.

Interest Rate Derivative Instruments

We may utilize interest rate swaps, forward starting swaps and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. This strategy is a component in controlling our overall cost of capital associated with such borrowings. The composition of our derivative instrument portfolios may change from period-to-period depending on our hedging requirements. As presented in the tabular data below, each portfolio’s estimated fair value at a given date is based on a number of factors, including the number and types of derivatives outstanding at that date, the notional value of the swaps and associated interest rates.

The following table shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated fair value (“FV”) of our interest rate swap portfolio at the dates presented (dollars in millions):

		Interest Rate Swap Portfolio Aggregate Fair Value at
	Resulting	December 31,		March 31,		April 17,
Scenario	Classification	2011		2012		2012
FV assuming no change in underlying interest rates	Asset	$	67.2	$	16.8	$	21.8
FV assuming 10% increase in underlying interest rates	Asset		64.4		15.0		20.1
FV assuming 10% decrease in underlying interest rates	Asset		70.0		18.8		23.5

The following table shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated fair value (“FV”) of our forward starting swap portfolio at the dates presented (dollars in millions):

		Forward Starting Swap Portfolio Aggregate Fair Value at
	Resulting	December 31,			March 31,			April 17,
Scenario	Classification	2011			2012			2012
FV assuming no change in underlying interest rates	Liability	$	(290.7	)	$	(146.5	)	$	(174.6	)
FV assuming 10% increase in underlying interest rates	Liability		(251.8	)		(115.4	)		(145.6	)
FV assuming 10% decrease in underlying interest rates	Liability		(330.6	)		(178.5	)		(204.4	)

Due to a decrease in forward London Interbank Offered Rates in 2011, the fair value of our forward starting swap portfolio was a liability of $290.7 million at December 31, 2011. In connection with the issuance of Senior Notes EE in February 2012, we settled ten forward starting swaps having an aggregate notional value of $500.0 million, resulting in our making cash payments totaling $115.3 million. The fair value of the remaining forward starting swaps was a liability of $146.5 million at March 31, 2012 and $174.6 million at April 17, 2012. The $28.1 million increase in the liability between March 31 and April 17 is attributable to further decreases in forward London Interbank Offered Rates during April.

Commodity Derivative Instruments

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The objective of our natural gas processing strategy is to hedge an amount of gross margin associated with our natural gas processing activities. We achieve this objective by using physical and financial instruments to lock in the purchase prices of natural gas consumed as plant thermal reduction (“PTR”) and the sales prices of the related NGL products. This program consists of (i) the forward sale of a portion of our expected equity NGL production at fixed prices through December 2012, which is achieved through the use of forward physical sales contracts and commodity derivative instruments and (ii) the purchase of commodity derivative instruments having a notional amount based on the volume of natural gas expected to be consumed as PTR in the production of such equity NGL production.

At March 31, 2012, the program had hedged future remaining estimated gross margins (before plant operating expenses) of $591.8 million on 12.2 MMBbls of forecasted NGL sales transactions and equivalent PTR volumes extending through December 2012. Our estimates of future gross margins are subject to various business risks, including unforeseen outages or declines, counterparty risk, or similar events or developments that are outside of our control.

§	The objective of our NGL, refined products and crude oil sales hedging program is to hedge the margins of anticipated future sales of inventory by locking in sales prices through the use of forward physical sales contracts and commodity derivative instruments.

§	The objective of our natural gas inventory hedging program is to hedge the fair value of natural gas currently held in inventory by locking in the sales price of the inventory through the use of commodity derivative instruments.

Certain basis swaps, basis spread options and other derivative instruments not designated as hedging instruments are used to manage market risks associated with anticipated purchases and sales of natural gas necessary to optimize our owned and contractually committed transportation and storage capacity. There is some uncertainty involved in the timing of these transactions often due to the development of more favorable profit opportunities or when spreads are insufficient to cover variable costs thus reducing the likelihood that the transactions will occur as originally forecasted. As a result of this timing uncertainty, these derivative instruments do not qualify for hedge accounting even though they are effective at managing the risk exposures of these assets. The earnings volatility caused by fluctuations in non-cash, mark-to-market earnings cannot be predicted and the impact to earnings could be material.

The following table shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated fair value of our natural gas marketing portfolio at the dates presented (dollars in millions):

		Portfolio Fair Value at
	Resulting	December 31,		March 31,		April 17,
Scenario	Classification	2011		2012		2012
FV assuming no change in underlying commodity prices	Asset	$	22.2	$	26.6	$	27.8
FV assuming 10% increase in underlying commodity prices	Asset		14.9		22.0		24.2
FV assuming 10% decrease in underlying commodity prices	Asset		29.5		31.3		31.5

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The following table shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated fair value of our NGL, refined products and petrochemical operations portfolio at the dates presented (dollars in millions):

		Portfolio Fair Value at
	Resulting	December 31,			March 31,			April 17,
Scenario	Classification	2011			2012			2012
FV assuming no change in underlying commodity prices	Liability	$	(12.3	)	$	(50.2	)	$	(45.9	)
FV assuming 10% increase in underlying commodity prices	Liability		(32.2	)		(99.7	)		(97.8	)
FV assuming 10% decrease in underlying commodity prices	Asset (Liability)		7.6			(0.8	)		6.0

The following table shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated fair value of our crude oil marketing portfolio at the dates presented (dollars in millions):

		Portfolio Fair Value at
	Resulting	December 31,			March 31,			April 17,
Scenario	Classification	2011			2012			2012
FV assuming no change in underlying commodity prices	Liability	$	(7.6	)	$	(5.9	)	$	(4.5	)
FV assuming 10% increase in underlying commodity prices	Liability		(10.0	)		(12.5	)		(7.8	)
FV assuming 10% decrease in underlying commodity prices	Asset (Liability)		(5.0	)		0.7			(1.2	)

Item 4. Controls and Procedures.

Disclosure Controls and Procedures

As of the end of the period covered by this quarterly report, our management carried out an evaluation, with the participation of our general partner’s chief executive officer (Michael A. Creel, who is our principal executive officer) and chief financial officer (W. Randall Fowler, our principal financial officer), of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based on this evaluation, as of the end of the period covered by this quarterly report, Mr. Creel and Mr. Fowler concluded:

(i)

that our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive and financial officers, as appropriate to allow for timely decisions regarding required disclosures; and

(ii)	that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during the first quarter of 2012, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

The required certifications of Mr. Creel and Mr. Fowler under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 are included as exhibits to this quarterly report (see Exhibits 31 and 32 under Part II, Item 6 of this quarterly report).

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

For information regarding litigation matters, see Note 14, “Commitments and Contingencies,” of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report, which is incorporated herein by reference.

Item 1A. Risk Factors.

Security holders and potential investors in our securities should carefully consider the risk factors set forth in our 2011 Form 10-K, in addition to other information in such annual report. The risk factors set forth in our 2011 Form 10-K are important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

The following table summarizes our repurchase activity during the first quarter of 2012:

				Maximum
			Total Number of	Number of Units
		Average	Units Purchased	That May Yet
	Total Number of	Price Paid	as Part of Publicly	Be Purchased
Period	Units Purchased	per Unit	Announced Plans	Under the Plans
February 2012 (1)	187,343	$51.55	--	--
(1) Of the 632,298 restricted common units that vested in February 2012 and converted to common units, 187,343 units were sold back to us by employees to cover related withholding tax requirements.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

Item 6. Exhibits.

Exhibit Number	Exhibit*
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 Form 8-K filed December 15, 2003).

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2.2	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 Form 8-K filed September 7, 2004).
2.3	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 Form 8-K filed December 15, 2003).
2.4	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 Form 8-K filed April 21, 2004).
2.5	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 Form 8-K filed December 15, 2003).
2.6	Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub B LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed June 29, 2009).
2.7	Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub A LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 29, 2009).
2.8	Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise ETE LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2010).
2.9	Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products GP, LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed September 7, 2010).
2.10	Contribution Agreement, dated as of September 30, 2010, by and between Enterprise Products Company and Enterprise Products Partners L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2010).
2.11	Agreement and Plan of Merger, dated as of April 28, 2011, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPD MergerCo LLC, Duncan Energy Partners L.P. and DEP Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 29, 2011).
3.1	Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 9, 2007).
3.2	Certificate of Amendment to Certificate of Limited Partnership of Enterprise Products Partners L.P., filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.6 to Form 8-K filed November 23, 2010).
3.3	Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated November 22, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K filed November 23, 2010).
3.4	Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 11, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 16, 2011).
3.5	Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC) (incorporated by reference to Exhibit 3.3 to Form S-1/A Registration Statement, Reg. No. 333-124320, filed by Enterprise GP Holdings L.P. on July 22, 2005).
3.6	Certificate of Amendment to Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC), filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.5 to Form 8-K filed November 23, 2010).

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3.7	Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC dated effective as of September 7, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 8, 2011).
3.8	Company Agreement of Enterprise Products Operating LLC dated June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 8, 2007).
3.9	Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.10	Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
4.1	Form of Common Unit certificate (incorporated by reference to Exhibit A to Exhibit 3.1 to Form 8-K filed August 16, 2011).
4.2	Indenture, dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000).
4.3	First Supplemental Indenture, dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.4	Second Supplemental Indenture, dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.5	Third Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed August 8, 2007).
4.6	Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 6, 2004).
4.7	Third Supplemental Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed October 6, 2004).
4.8	Fourth Supplemental Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 6, 2004).
4.9	Fifth Supplemental Indenture, dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed March 3, 2005).
4.10	Sixth Supplemental Indenture, dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 3, 2005).
4.11	Eighth Supplemental Indenture, dated as of July 18, 2006, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed July 19, 2006).
4.12	Ninth Supplemental Indenture, dated as of May 24, 2007, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed May 24, 2007).

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4.13	Tenth Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007).
4.14	Eleventh Supplemental Indenture, dated as of September 4, 2007, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed September 5, 2007).
4.15	Twelfth Supplemental Indenture, dated as of April 3, 2008, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed April 3, 2008).
4.16	Thirteenth Supplemental Indenture, dated as of April 3, 2008, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed April 3, 2008).
4.17	Fourteenth Supplemental Indenture, dated as of December 8, 2008, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed December 8, 2008).
4.18	Fifteenth Supplemental Indenture, dated as of June 10, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed June 10, 2009).
4.19	Sixteenth Supplemental Indenture, dated as of October 5, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.20	Seventeenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.21	Eighteenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 28, 2009).
4.22	Nineteenth Supplemental Indenture, dated as of May 20, 2010, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed May 20, 2010).
4.23	Twentieth Supplemental Indenture, dated as of January 13, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.24	Twenty-First Supplemental Indenture, dated as of August 24, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.25#	Twenty-Second Supplemental Indenture, dated as of February 15, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee.
4.26	Global Note representing $350.0 million principal amount of 6.375% Series B Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.27	Global Note representing $499.2 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.5 to Form 10-K filed March 31, 2003).

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4.28	Global Notes representing $450.0 million principal amount of 7.50% Senior Notes due 2011 (incorporated by reference to Exhibit 4.1 to Form 8-K filed January 25, 2001).
4.29	Global Note representing $500.0 million principal amount of 5.60% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.17 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.30	Global Note representing $150.0 million principal amount of 5.60% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.18 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.31	Global Note representing $350.0 million principal amount of 6.65% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.32	Global Note representing $250.0 million principal amount of 5.00% Series B Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.31 to Form 10-Q filed November 4, 2005).
4.33	Global Note representing $250.0 million principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed November 4, 2005).
4.34	Form of Junior Subordinated Note, including Guarantee (incorporated by reference to Exhibit 4.2 to Form 8-K filed July 19, 2006).
4.35	Global Note representing $800.0 million principal amount of 6.30% Senior Notes due 2017 with attached Guarantee (incorporated by reference to Exhibit 4.38 to Form 10-Q filed November 9, 2007).
4.36	Form of Global Note representing $400.0 million principal amount of 5.65% Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed April 3, 2008).
4.37	Form of Global Note representing $700.0 million principal amount of 6.50% Senior Notes due 2019 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed April 3, 2008).
4.38	Form of Global Note representing $500.0 million principal amount of 9.75% Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed December 8, 2008).
4.39	Form of Global Note representing $500.0 million principal amount of 4.60% Senior Notes due 2012 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed June 10, 2009).
4.40	Form of Global Note representing $500.0 million principal amount of 5.25% Senior Notes due 2020 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.41	Form of Global Note representing $600.0 million principal amount of 6.125% Senior Notes due 2039 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.42	Form of Global Note representing $490.5 million principal amount of 7.625% Senior Notes due 2012 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 28, 2009).
4.43	Form of Global Note representing $182.6 million principal amount of 6.125% Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed October 28, 2009).
4.44	Form of Global Note representing $237.6 million principal amount of 5.90% Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 28, 2009).
4.45	Form of Global Note representing $349.7 million principal amount of 6.65% Senior Notes due 2018 with attached Guarantee (incorporated by reference to Exhibit 4.6 to Form 8-K filed October 28, 2009).
4.46	Form of Global Note representing $399.6 million principal amount of 7.55% Senior Notes due 2038 with attached Guarantee (incorporated by reference to Exhibit 4.7 to Form 8-K filed October 28, 2009).

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4.47	Form of Global Note representing $285.8 million principal amount of 7.000% Junior Subordinated Notes due 2067 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Form 8-K filed October 28, 2009).
4.48	Form of Global Note representing $400.0 million principal amount of 3.70% Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed May 20, 2010).
4.49	Form of Global Note representing $1.0 billion principal amount of 5.20% Senior Notes due 2020 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed May 20, 2010).
4.50	Form of Global Note representing $600.0 million principal amount of 6.45% Senior Notes due 2040 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed May 20, 2010).
4.51	Form of Global Note representing $750.0 million principal amount of 3.20% Senior Notes due 2016 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed January 13, 2011).
4.52	Form of Global Note representing $750.0 million principal amount of 5.95% Senior Notes due 2041 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed January 13, 2011).
4.53	Form of Global Note representing $650.0 million principal amount of 4.05% Senior Notes due 2022 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed August 24, 2011).
4.54	Form of Global Note representing $600.0 million principal amount of 5.70% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed August 24, 2011).
4.55	Form of Global Note representing $750.0 million principal amount of 4.85% Senior Notes due 2042 with attached Guarantee (included in Exhibit 4.25 above).
4.56	Replacement Capital Covenant, dated May 24, 2007, executed by Enterprise Products Operating L.P. and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to Form 8-K filed May 24, 2007).
4.57	First Amendment to Replacement Capital Covenant dated August 25, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.2 to Form 8-K filed August 25, 2006).
4.58	Replacement Capital Covenant, dated October 27, 2009, among Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.9 to Form 8-K filed October 28, 2009).
4.59	Indenture, dated February 20, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Subsidiary Guarantors, and First Union National Bank, NA, as Trustee (incorporated by reference to Exhibit 99.2 to the Form 8-K filed by TEPPCO Partners, L.P. on February 20, 2002).
4.60	First Supplemental Indenture, dated February 20, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Subsidiary Guarantors, and First Union National Bank, NA, as Trustee (incorporated by reference to Exhibit 99.3 to the Form 8-K filed by TEPPCO Partners, L.P. on February 20, 2002).
4.61	Second Supplemental Indenture, dated June 27, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.6 to the Form 10-Q filed by TEPPCO Partners, L.P. on August 14, 2002).
4.62	Third Supplemental Indenture, dated January 20, 2003, by and among TEPPCO Partners, L.P. as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. as Subsidiary Guarantors, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.7 to the Form 10-K filed by TEPPCO Partners, L.P. on March 21, 2003).

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4.63	Full Release of Guarantee, dated July 31, 2006, by Wachovia Bank, National Association, as Trustee, in favor of Jonah Gas Gathering Company (incorporated by reference to Exhibit 4.8 to the Form 10-Q filed by TEPPCO Partners, L.P. on November 7, 2006).
4.64	Fourth Supplemental Indenture, dated June 30, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Val Verde Gas Gathering Company, L.P., TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K filed by TE Products Pipeline Company, LLC on July 6, 2007).
4.65	Fifth Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.11 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
4.66	Sixth Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.12 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
4.67	Seventh Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.13 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
4.68	Eighth Supplemental Indenture, dated October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).
4.69	Full Release of Guarantee, dated November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.64 to Form 10-K filed on March 1, 2010).
4.70	Indenture, dated May 14, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 99.1 of the Form 8-K filed by TEPPCO Partners, L.P. on May 15, 2007).
4.71	First Supplemental Indenture, dated May 18, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on May 18, 2007).
4.72	Replacement of Capital Covenant, dated May 18, 2007, executed by TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P. in favor of the covered debt holders described therein (incorporated by reference to Exhibit 99.1 to the Form 8-K of TEPPCO Partners, L.P. on May 18, 2007).
4.73	Second Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Existing Subsidiary Guarantors, TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as New Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TE Products Pipeline Company, LLC on July 6, 2007).

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4.74	Third Supplemental Indenture, dated as of October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).
4.75	Full Release of Guarantee, dated as of November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.70 to Form 10-K filed on March 1, 2010).
12.1#	Computation of ratio of earnings to fixed charges for the three months ended March 31, 2012 and for each of the five years ended December 31, 2011, 2010, 2009, 2008 and 2007.
31.1#	Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P.’s for the March 31, 2012 quarterly report on Form 10-Q.
31.2#	Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s for the March 31, 2012 quarterly report on Form 10-Q.
32.1#	Sarbanes-Oxley Section 906 certification of Michael A. Creel for Enterprise Products Partners L.P.’s for the March 31, 2012 quarterly report on Form 10-Q.
32.2#	Sarbanes-Oxley Section 906 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s for the March 31, 2012 quarterly report on Form 10-Q.
101.CAL#	XBRL Calculation Linkbase Document
101.DEF#	XBRL Definition Linkbase Document
101.INS#	XBRL Instance Document
101.LAB#	XBRL Labels Linkbase Document
101.PRE#	XBRL Presentation Linkbase Document
101.SCH#	XBRL Schema Document

*	With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file numbers for Enterprise Products Partners L.P., Enterprise GP Holdings L.P., TEPPCO Partners, L.P. and TE Products Pipeline Company, LLC are 1-14323, 1-32610, 1-10403 and 1-13603, respectively.
***	Identifies management contract and compensatory plan arrangements.
#	Filed with this report.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on May 10, 2012.

ENTERPRISE PRODUCTS PARTNERS L.P.
(A Delaware Limited Partnership)

By:	Enterprise Products Holdings LLC, as General Partner


By:	/s/ Michael J. Knesek
Name:	Michael J. Knesek
Title:	Senior Vice President, Controller and Principal Accounting Officer of the General Partner