Edgar Filing: ENTERPRISE PRODUCTS PARTNERS L P

epdform_10q.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, 2010

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 634,754,083 common units, including 3,925,381 restricted 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 May 3, 2010. These common units trade on the New York Stock Exchange under the ticker symbol “EPD.”

Table of Contents

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 Organization and Basis of Presentation	9
	2. General Accounting Matters	10
	3. Equity-based Awards	11
	4. Derivative Instruments, Hedging Activities and Fair Value Measurements	15
	5. Inventories	23
	6. Property, Plant and Equipment	24
	7. Investments in Unconsolidated Affiliates	26
	8. Intangible Assets and Goodwill	28
	9. Debt Obligations	30
	10. Equity and Distributions	32
	11. Business Segments	36
	12. Related Party Transactions	40
	13. Earnings Per Unit	44
	14. Commitments and Contingencies	46
	15. Significant Risks and Uncertainties	48
	16. Supplemental Cash Flow Information	49
	17. Condensed Consolidating Financial Information	49
	18. Subsequent Events	55
Item 2.	Management’s Discussion and Analysis of Financial Condition
	and Results of Operations.	56
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	72
Item 4.	Controls and Procedures.	74

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.	75
Item 1A.	Risk Factors.	75
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	76
Item 3.	Defaults upon Senior Securities.	77
Item 4.	(Removed and Reserved).	77
Item 5.	Other Information.	77
Item 6.	Exhibits.	77

Signatures		85

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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	2010			2009
Current assets:
Cash and cash equivalents	$	134.9		$	54.7
Restricted cash		101.7			63.6
Accounts and notes receivable – trade, net of allowance for doubtful accounts of $17.5 at March 31, 2010 and $16.8 at December 31, 2009		3,056.0			3,099.0
Accounts receivable – related parties		26.9			38.4
Inventories		990.9			711.9
Prepaid and other current assets		296.8			279.3
Total current assets		4,607.2			4,246.9
Property, plant and equipment, net		17,735.3			17,689.2
Investments in unconsolidated affiliates		883.5			890.6
Intangible assets, net of accumulated amortization of $824.6 at March 31, 2010 and $795.0 at December 31, 2009		1,035.2			1,064.8
Goodwill		2,018.3			2,018.3
Other assets		221.6			241.8
Total assets	$	26,501.1		$	26,151.6

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	175.0		$	--
Accounts payable – trade		419.0			410.6
Accounts payable – related parties		47.8			69.8
Accrued product payables		3,695.1			3,393.0
Accrued expenses		79.4			108.5
Accrued interest		170.0			228.0
Other current liabilities		354.4			326.1
Total current liabilities		4,940.7			4,536.0
Long-term debt (see Note 9)		10,915.7			11,346.4
Deferred tax liabilities		72.5			71.7
Other long-term liabilities		160.2			155.2
Commitments and contingencies
Equity: (see Note 10)
Enterprise Products Partners L.P. partners’ equity:
Limited Partners:
Common units (617,009,491 units outstanding at March 31, 2010 and 603,202,828 units outstanding at December 31, 2009)		9,575.4			9,173.5
Restricted common units (3,925,881 units outstanding at March 31, 2010 and 2,720,882 units outstanding at December 31, 2009)		43.7			37.7
Class B units (4,520,431 units outstanding at March 31, 2010 and December 31, 2009)		118.5			118.5
General partner		199.1			190.8
Accumulated other comprehensive loss		(54.6	)		(8.4	)
Total Enterprise Products Partners L.P. partners’ equity		9,882.1			9,512.1
Noncontrolling interest		529.9			530.2
Total equity		10,412.0			10,042.3
Total liabilities and equity	$	26,501.1		$	26,151.6

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,
	2010			2009*
Revenues:
Third parties	$	8,312.1		$	4,667.4
Related parties		232.4			219.5
Total revenues (see Note 11)		8,544.5			4,886.9
Costs and expenses:
Operating costs and expenses:
Third parties		7,647.9			4,147.1
Related parties		324.0			229.5
Total operating costs and expenses		7,971.9			4,376.6
General and administrative costs:
Third parties		14.1			7.9
Related parties		23.5			27.0
Total general and administrative costs		37.6			34.9
Total costs and expenses		8,009.5			4,411.5
Equity in income of unconsolidated affiliates		16.0			7.4
Operating income		551.0			482.8
Other income (expense):
Interest expense		(148.6	)		(152.5	)
Interest income		0.2			0.9
Other, net		(0.1	)		0.3
Total other expense, net		(148.5	)		(151.3	)
Income before provision for income taxes		402.5			331.5
Provision for income taxes		(8.7	)		(16.0	)
Net income		393.8			315.5
Net income attributable to noncontrolling interest		(16.0	)		(90.2	)
Net income attributable to Enterprise Products Partners L.P.	$	377.8		$	225.3

Net income allocated to:
Limited partners	$	317.4		$	186.3
General partner	$	60.4		$	39.0

Basic earnings per unit (see Note 13)	$	0.51		$	0.41
Diluted earnings per unit (see Note 13)	$	0.50		$	0.41

See Notes to Unaudited Condensed Consolidated Financial Statements.

*See Note 1 for information regarding these recasted amounts and basis of financial statement presentation.

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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,
	2010			2009*

Net income	$	393.8		$	315.5
Other comprehensive income (loss):
Cash flow hedges:
Commodity derivative instrument losses during period		(58.9	)		(62.0	)
Reclassification adjustment for losses included in net income related to commodity derivative instruments		16.5			32.2
Interest rate derivative instrument losses during period		(5.7	)		(0.7	)
Reclassification adjustment for losses included in net income related to interest rate derivative instruments		3.3			2.3
Foreign currency derivative losses during period		(0.1	)		(10.6	)
Reclassification adjustment for gains included in net income related to foreign currency derivative instruments		(0.3	)		--
Total cash flow hedges		(45.2	)		(38.8	)
Foreign currency translation adjustment		0.6			(0.4	)
Change in funded status of pension and postretirement plans, net of tax		(0.9	)		--
Total other comprehensive loss		(45.5	)		(39.2	)
Comprehensive income		348.3			276.3
Comprehensive income attributable to noncontrolling interest		(16.7	)		(92.2	)
Comprehensive income attributable to Enterprise Products Partners L.P.	$	331.6		$	184.1

See Notes to Unaudited Condensed Consolidated Financial Statements.

*See Note 1 for information regarding these recasted amounts and basis of financial statement presentation.

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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,
	2010			2009*
Operating activities:
Net income	$	393.8		$	315.5
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		217.6			199.1
Non-cash impairment charges		1.5			--
Equity in income of unconsolidated affiliates		(16.0	)		(7.4	)
Distributions received from unconsolidated affiliates		30.2			22.4
Operating lease expenses paid by EPCO		0.2			0.2
Gain from asset sales and related transactions		(7.5	)		(0.2	)
Deferred income tax expense		1.0			0.9
Changes in fair market value of derivative instruments		(7.8	)		(12.6	)
Effect of pension settlement recognition		(0.2	)		(0.1	)
Net effect of changes in operating accounts (see Note 16)		74.1			(145.8	)
Net cash flows provided by operating activities		686.9			372.0
Investing activities:
Capital expenditures		(347.8	)		(513.9	)
Contributions in aid of construction costs		3.6			6.4
Increase in restricted cash		(38.1	)		(40.7	)
Cash used for business combinations		(2.2	)		--
Acquisition of intangible assets		--			(1.4	)
Investments in unconsolidated affiliates		(7.7	)		(7.1	)
Proceeds from asset sales and related transactions		21.7			0.3
Other investing activities		--			3.8
Cash used in investing activities		(370.5	)		(552.6	)
Financing activities:
Borrowings under debt agreements		345.5			1,163.4
Repayments of debt		(595.0	)		(915.9	)
Debt issuance costs		(0.1	)		(0.9	)
Cash distributions paid to partners		(407.3	)		(279.7	)
Cash distributions paid to noncontrolling interest		(17.4	)		(105.5	)
Cash contributions from noncontrolling interest		0.2			(0.6	)
Net cash proceeds from issuance of common units		437.7			310.8
Acquisition of treasury units		(0.2	)		--
Cash provided by (used in) financing activities		(236.6	)		171.6
Effect of exchange rate changes on cash		0.4			(2.0	)
Net change in cash and cash equivalents		79.8			(9.0	)
Cash and cash equivalents, January 1		54.7			61.7
Cash and cash equivalents, March 31	$	134.9		$	50.7

See Notes to Unaudited Condensed Consolidated Financial Statements.

*See Note 1 for information regarding these recasted amounts and basis of financial statement presentation.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(See Note 10 for Unit History, Detail of Changes in Limited Partners’ Equity and Accumulated Other Comprehensive Loss)

(Dollars in millions)

	Enterprise Products Partners L.P.
							Accumulated
							Other
	Limited			General			Comprehensive			Noncontrolling
	Partners			Partner			Loss			Interest			Total
Balance, December 31, 2009	$	9,329.7		$	190.8		$	(8.4	)	$	530.2		$	10,042.3
Net income		317.4			60.4			--			16.0			393.8
Operating lease expenses paid by EPCO		0.2			--			--			--			0.2
Cash distributions paid to partners		(345.5	)		(60.9	)		--			--			(406.4	)
Unit option reimbursements to EPCO		(0.9	)		--			--			--			(0.9	)
Cash distributions paid to noncontrolling interest		--			--			--			(17.4	)		(17.4	)
Net cash proceeds from issuance of common units		428.3			8.8			--			--			437.1
Cash proceeds from exercise of unit options		0.6			--			--			--			0.6
Cash contributions from noncontrolling interest		--			--			--			0.2			0.2
Amortization of equity awards		8.0			--			--			0.2			8.2
Acquisition of treasury units		(0.2	)		--			--			--			(0.2	)
Foreign currency translation adjustment		--			--			0.6			--			0.6
Change in funded status of pension and postretirement plans, net of tax		--			--			(0.9	)		--			(0.9	)
Cash flow hedges		--			--			(45.9	)		0.7			(45.2	)
Balance, March 31, 2010	$	9,737.6		$	199.1		$	(54.6	)	$	529.9		$	10,412.0

	Enterprise Products Partners L.P.
							Accumulated
							Other
	Limited			General			Comprehensive			Noncontrolling
	Partners			Partner			Loss			Interest			Total
Balance, December 31, 2008*	$	6,063.1		$	123.6		$	(97.2	)	$	3,206.4		$	9,295.9
Net income		186.3			39.0			--			90.2			315.5
Operating lease expenses paid by EPCO		0.2			--			--			--			0.2
Cash distributions paid to partners		(239.5	)		(40.1	)		--			--			(279.6	)
Unit option reimbursements to EPCO		(0.1	)		--			--			--			(0.1	)
Cash distributions paid to noncontrolling interest		--			--			--			(105.5	)		(105.5	)
Net cash proceeds from issuance of common units		304.5			6.2			--			--			310.7
Cash proceeds from exercise of unit options		0.1			--			--			--			0.1
Cash contributions from noncontrolling interest		--			--			--			(0.6	)		(0.6	)
Amortization of equity awards		2.7			0.1			--			1.1			3.9
Foreign currency translation adjustment		--			--			(0.4	)					(0.4	)
Cash flow hedges		--			--			(40.8	)		2.0			(38.8	)
Balance, March 31, 2009*	$	6,317.3		$	128.8		$	(138.4	)	$	3,193.6		$	9,501.3

See Notes to Unaudited Condensed Consolidated Financial Statements.

*See Note 1 for information regarding these recasted amounts and basis of financial statement presentation.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Except unit-related amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnotes are stated in millions of dollars.

SIGNIFICANT RELATIONSHIPS REFERENCED IN THESE

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unless the context requires otherwise, references to “we,” “us,” “our,” 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 Products Partners through which Enterprise Products Partners conducts substantially all of its business, and its consolidated subsidiaries.

References to “EPGP” mean Enterprise Products GP, LLC, which is our general partner.

References to “Duncan Energy Partners” mean Duncan Energy Partners L.P., which is a consolidated subsidiary of EPO. Duncan Energy Partners is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “DEP.” References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and is wholly owned by EPO.

References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., a publicly traded Delaware limited partnership, the units of which are listed on the NYSE under the ticker symbol “EPE.” Enterprise GP Holdings owns EPGP. The general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”), a wholly owned subsidiary of Dan Duncan LLC. The membership interests of Dan Duncan LLC are owned of record by a voting trust formed on April 26, 2006, pursuant to the Dan Duncan LLC Voting Trust Agreement dated April 26, 2006 (the “DD LLC Voting Trust Agreement”), among Dan Duncan LLC, Dan L. Duncan, as the record owner of all of the membership interests of Dan Duncan LLC immediately prior to the entering into of the DD LLC Voting Trust Agreement, and Dan L. Duncan, as the initial sole voting trustee. Immediately upon Mr. Duncan’s death on March 29, 2010, voting and dispositive control of all of the membership interests of Dan Duncan LLC was transferred pursuant to the DD LLC Voting Trust Agreement to three voting trustees.

The current voting trustees under the DD LLC Voting Trust Agreement (the “DD LLC Trustees”) are: (1) Randa Duncan Williams, Mr. Duncan’s oldest daughter, who is also an existing director on the board of EPE Holdings; (2) Dr. Ralph S. Cunningham, who is currently the President and Chief Executive Officer (“CEO”) of EPE Holdings; and (3) Richard H. Bachmann, who is currently the Executive Vice President and Chief Legal Officer of EPGP and one of three managers of Dan Duncan LLC. Dr. Cunningham and Mr. Bachmann are also currently directors of EPGP, EPE Holdings and DEP GP.

The DD LLC Voting Trust Agreement requires that there always be two “Independent Voting Trustees” serving. If Mr. Bachmann or Dr. Cunningham fail to qualify or cease to serve, then the substitute or successor Independent Voting Trustee(s) will be appointed by the then-serving Independent Voting Trustee, provided that if no Independent Voting Trustee is then serving or if a vacancy in a trusteeship of an Independent Voting Trustee is not filled within ninety days of the vacancy’s occurrence, the CEO of EPGP will appoint the successor Independent Voting Trustee(s).

The DD LLC Voting Trust Agreement also provides for a “Duncan Voting Trustee.” The Duncan Voting Trustee is appointed by the children of Mr. Duncan acting by a majority or, if less than three children of Mr. Duncan are then living, unanimously. If for any reason no descendent of Mr. Duncan is appointed as the Duncan Voting Trustee, then such trusteeship will remain vacant until such time as a Duncan Voting Trustee is appointed in the manner provided above. If a Duncan Voting Trustee for any reason ceases to serve, his or her successor shall be appointed by the children of Mr. Duncan acting by majority or, if less than three children of Mr. Duncan are then living, unanimously. Ms. Williams is currently the Duncan Voting Trustee.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The DD LLC Trustees are required to treat the member party to the DD LLC Voting Trust Agreement as the beneficial owner for all purposes whatsoever of the membership interests of Dan Duncan LLC. The estate of Dan L. Duncan became the sole member party to the DD LLC Voting Trust Agreement upon the death of Mr. Duncan on March 29, 2010. However, the DD LLC Trustees collectively are the record owners of the Dan Duncan LLC membership interests and possess and are entitled to exercise all rights and powers of absolute ownership thereof and to vote, assent or consent with respect thereto and to take party in and consent to any corporate or members’ actions (except those actions, if any, to which the DD LLC Trustees may not legally consent) and subject to the provisions of the DD LLC Voting Trust Agreement, to receive dividends and distributions on the Dan Duncan LLC membership interests. Except as otherwise provided in the DD LLC Voting Trust Agreement, all actions taken by the DD LLC Trustees are by majority vote.

The DD LLC Trustees serve in such capacity without compensation, but they are entitled to incur reasonable charges and expenses deemed necessary and proper for administering the DD LLC Voting Trust Agreement and to reimbursement and indemnification.

The DD LLC Voting Trust Agreement will terminate when (1) the descendants of Dan L. Duncan, and entities directly or indirectly controlled by or held for the benefit of any such descendant, no longer own any capital stock of EPCO (as defined below); or (2) upon such earlier date designated by the DD LLC Trustees by an instrument in writing delivered to the member party to the DD LLC Voting Trust Agreement.

On April 27, 2010, the independent co-executors for the estate of Dan L. Duncan were appointed by the probate court. The independent co-executors are Mr. Bachmann, Dr. Cunningham and Ms. Williams, who are the same persons as the current DD LLC Trustees and voting trustees under a separate voting trust agreement relating to a majority of EPCO’s outstanding shares with voting rights (as more fully described below).

References to “TEPPCO” and “TEPPCO GP” mean TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (which is the general partner of TEPPCO), respectively, prior to their mergers with our subsidiaries. On October 26, 2009, we completed the mergers with TEPPCO and TEPPCO GP (such related mergers referred to herein individually and together as the “TEPPCO Merger”).

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”). Energy Transfer Equity is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “ETE.” ETP is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “ETP.” The general partner of Energy Transfer Equity is LE GP, LLC.

References to “EPCO” mean Enterprise Products Company (formerly EPCO, Inc.) and its privately held affiliates. Prior to Mr. Duncan’s death on March 29, 2010, we, EPO, Duncan Energy Partners, DEP GP, EPGP, Enterprise GP Holdings and EPE Holdings were affiliates under the common control of Dan L. Duncan, the controlling shareholder of EPCO. A majority of the outstanding voting capital stock of EPCO is owned of record by a voting trust formed on April 26, 2006, pursuant to the EPCO Inc. Voting Trust Agreement dated April 26, 2006 (the “EPCO Voting Trust Agreement”), among EPCO, Dan L. Duncan, as the record owner of a majority of the outstanding voting capital stock of EPCO immediately prior to the entering into of the EPCO Voting Trust Agreement, and Dan L. Duncan, as the initial sole voting trustee. Immediately upon Mr. Duncan’s death, voting and dispositive control of such majority of the outstanding voting capital stock of EPCO included under the EPCO Voting Trust Agreement was transferred pursuant to the EPCO Voting Trust Agreement to three voting trustees (the “EPCO Trustees”). The current EPCO Trustees are: (1) Ms. Williams, who serves as Chairman of EPCO; (2) Dr..Cunningham, who serves as a Vice Chairman of EPCO; and (3) Mr. Bachmann, who serves as the President, CEO and Chief Legal Officer of EPCO. Ms. Williams, Dr. Cunningham and Mr. Bachmann are also currently directors of EPCO. The current EPCO Trustees are the same as the current DD LLC Trustees for the DD LLC Voting Trust, which controls Dan Duncan LLC. The current EPCO Trustees are

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

also the same persons as the individuals appointed on April 27, 2010 as the independent co-executors of the estate of Dan L. Duncan. Dan Duncan LLC and EPCO also beneficially own approximately 18% and 57%, respectively, of the outstanding units representing limited partner interests of Enterprise GP Holdings.

References to the “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P. (“EPE Unit II”), EPE Unit III, L.P. (“EPE Unit III”), Enterprise Unit L.P. (“Enterprise Unit”) and EPCO Unit L.P. (“EPCO Unit”), collectively, all of which are privately held affiliates of EPCO.

Note 1. Partnership Organization and Basis of Presentation

We are a publicly traded Delaware limited partnership, the common units of which are listed on the 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. We conduct substantially all of our business through our wholly owned subsidiary, EPO. We are owned 98% by our limited partners and 2% by our general partner, EPGP. Enterprise GP Holdings owns 100% of EPGP. The general partner of Enterprise GP Holdings is EPE Holdings, a wholly owned subsidiary of Dan Duncan LLC. Mr. Dan L. Duncan owned all of the membership interests of Dan Duncan LLC prior to his death on March 29, 2010. All of the membership interests of Dan Duncan LLC are currently owned of record collectively by the DD LLC Trustees. We, EPGP, Enterprise GP Holdings, EPE Holdings and Dan Duncan LLC are affiliates and under the collective common control of the DD LLC Trustees and the EPCO Trustees. The EPCO Trustees are collectively the controlling record shareholders of EPCO.

For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners with those of our own and reflect its operations in our business segments. We control Duncan Energy Partners through our ownership of its general partner. Also, due to common control of the entities by Dan L. Duncan during his lifetime, and thereafter by the DD LLC Trustees and the EPCO Trustees, collectively, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners. Public ownership of Duncan Energy Partners’ net assets and earnings are presented as a component of noncontrolling interest in our consolidated financial statements. The borrowings of Duncan Energy Partners are presented as part of our consolidated debt. However, neither Enterprise Products Partners nor EPO have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

TEPPCO Merger and Basis of Presentation

Our consolidated financial statements and business segments were recast in connection with the TEPPCO Merger. On October 26, 2009, the related mergers of our wholly owned subsidiaries with TEPPCO and TEPPCO GP were completed. Under terms of the merger agreements, TEPPCO and TEPPCO GP became wholly owned subsidiaries of ours, and each of TEPPCO’s unitholders, except for a privately held affiliate of EPCO, were entitled to receive 1.24 of our common units for each TEPPCO unit. In total, we issued an aggregate of 126,932,318 common units and 4,520,431 Class B units (described below) as consideration in the TEPPCO Merger for both TEPPCO units and the TEPPCO GP membership interests. TEPPCO’s units, which had been trading on the NYSE under the ticker symbol “TPP,” have been delisted and are no longer publicly traded. On October 27, 2009, our TEPPCO and TEPPCO GP equity interests were contributed to EPO, and TEPPCO and TEPPCO GP became wholly owned subsidiaries of EPO.

A privately held affiliate of EPCO exchanged a portion of its TEPPCO units, based on the 1.24 exchange rate, for 4,520,431 of our Class B units in lieu of common units. The Class B units are not entitled to regular quarterly cash distributions for the first 16 quarters following the closing date of the merger. The Class B units automatically convert into the same number of common units on the date immediately following the payment date for the 16th quarterly distribution following the closing date of the merger. The Class B units are entitled to vote together with the common units as a single class on partnership matters and, except for the payment of distributions, have the same rights and privileges as our common units.

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ENTERPRISE PRODUCTS PARTNERS L.P.

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Under the terms of the TEPPCO Merger agreements, Enterprise GP Holdings received 1,331,681 of our common units and an increase in the capital account of EPGP to maintain its 2% general partner interest in us as consideration for 100% of the membership interests of TEPPCO GP.

Since Enterprise Products Partners, TEPPCO and TEPPCO GP were under common control of EPCO and its affiliates, the TEPPCO Merger was accounted for at historical costs as a reorganization of entities under common control in a manner similar to a pooling of interests. The inclusion of TEPPCO and TEPPCO GP in our consolidated financial statements was effective January 1, 2005 since an affiliate of EPCO under common control with Enterprise Products Partners originally acquired ownership interests in TEPPCO GP in February 2005.

Our consolidated financial statements prior to the TEPPCO Merger reflect the combined financial information of Enterprise Products Partners, TEPPCO and TEPPCO GP on a 100% basis. Third-party and related party ownership interests in TEPPCO and TEPPCO GP are reflected as “Former owners of TEPPCO,” a component of noncontrolling interest. The financial statements of TEPPCO and TEPPCO GP were prepared from the separate accounting records maintained by TEPPCO and TEPPCO GP. All intercompany balances and transactions have been eliminated in consolidation.

We revised our business segments and related disclosures to reflect the TEPPCO Merger. Our reorganized business segments reflect the manner in which these businesses are managed and reviewed by the CEO of our general partner. Under our new business segment structure, we have five reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services and (v) Petrochemical & Refined Products Services.

There was no change in net income attributable to Enterprise Products Partners L.P. for periods prior to the merger since net income attributable to TEPPCO and TEPPCO GP was allocated to noncontrolling interests. Additionally, there was no change in our reported earnings per unit for such periods. See Note 11 for a reconciliation of our consolidated revenues and total segment gross operating margin, which is a non-generally accepted accounting principle (“non-GAAP”) financial measure of segment performance, to our pre-merger amounts.

Our results of operations for the three months ended March 31, 2010 are not necessarily indicative of results expected for the full year. 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 to 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 Notes 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, 2009 (our “2009 Form 10-K”).

Note 2. General Accounting Matters

Estimates

Preparing our financial statements in conformity with GAAP requires management to make estimates and assumptions that affect amounts presented in the financial statements (i.e. assets, liabilities, revenue and expenses) and disclosures about contingent assets and liabilities. Our actual results could differ from these estimates. On an ongoing basis, management reviews its estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

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Fair Value Information

Cash and cash equivalents and restricted cash, accounts receivable, accounts payable and accrued expenses, and other current liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values due to their short-term nature. The estimated fair values of our fixed-rate debt are based on quoted market prices for such debt or debt of similar terms and maturities. The carrying amounts of our variable-rate debt obligations reasonably approximate their fair values due to their variable interest rates. See Note 4 for fair value information associated with our derivative instruments.

The following table presents the estimated fair values of our financial instruments at the dates indicated:

	March 31, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
Financial Instruments	Value		Value		Value		Value
Financial assets:
Cash and cash equivalents and restricted cash	$	236.6	$	236.6	$	118.3	$	118.3
Accounts receivable		3,082.9		3,082.9		3,137.4		3,137.4
Financial liabilities:
Accounts payable and accrued expenses		4,411.3		4,411.3		4,209.9		4,209.9
Other current liabilities (excluding derivative instruments)		222.8		222.8		233.1		233.1
Fixed-rate debt (principal amount)		10,532.7		11,156.2		10,586.7		11,056.2
Variable-rate debt		514.8		514.8		710.3		710.3

Restricted Cash

Restricted cash represents amounts held in connection with our commodity derivative instruments portfolio and related physical natural gas and NGL purchases. Additional cash may be restricted to maintain this portfolio as commodity prices fluctuate or deposit requirements change. At March 31, 2010 and December 31, 2009, our restricted cash amounts were $101.7 million and $63.6 million, respectively. See Note 4 for information regarding derivative instruments and hedging activities.

Note 3. Equity-based Awards

The following table summarizes the expense we recognized in connection with equity-based awards for the periods indicated:

	For the Three Months Ended March 31,
	2010		2009
Restricted unit awards (1)	$	5.3	$	2.4
Unit option awards (1)		0.9		0.1
Unit appreciation rights (2)		0.1		--
Profits interests awards (1)		1.8		1.4
Total compensation expense	$	8.1	$	3.9

(1) Accounted for as equity-classified awards. (2) Accounted for as liability-classified awards.

The fair value of an equity-classified award (e.g., a restricted unit award) is amortized to earnings on a straight-line basis over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., unit appreciation rights (“UARs”)) is recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. Liability-classified awards are settled in cash upon vesting.

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At March 31, 2010, the active long-term incentive plans were the Enterprise Products 1998 Long-Term Incentive Plan, the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan and the 2010 Duncan Energy Partners L.P. Long-Term Incentive Plan. In addition, we had unvested awards issued, but are not issuing further awards, under the Enterprise Products 2006 TPP Long-Term Incentive Plan (“2006 Plan”).

An allocated portion of the fair value of these long-term incentive plan equity-based awards is charged to us under the administrative services agreement (“ASA”). See Note 12 for a general description of the ASA with EPCO. With the exception of certain amounts recorded in connection with EPCO Unit, we are not responsible for reimbursing EPCO for any expenses associated with such awards. We recognize an expense for our allocated share of the grant date fair value of such awards, with an offsetting amount recorded in equity. Beginning in February 2009, the ASA was amended to provide that we and other affiliates of EPCO will reimburse EPCO for our allocated share of distributions of cash or securities made to the Class B limited partners of EPCO Unit. Our reimbursements to EPCO in connection with EPCO Unit were $0.1 million during each of the three months ended March 31, 2010 and 2009.

Restricted Unit Awards

Restricted unit awards allow recipients to acquire our common units or common units of Duncan Energy Partners (at no cost to the recipient) once a defined vesting period expires, subject to customary forfeiture provisions. The majority of these awards are subject to cliff vesting, the restrictions on such awards generally lapse four years from the date of grant. There are also awards that are subject to graded vesting provisions by which one-fourth of each award vests on each of the first, second, third and fourth anniversaries of the date of grant. The fair value of restricted units 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. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite period of each separately vesting portion of the award. As used in the context of our long-term incentive plans, the term “restricted unit” represents a time-vested unit. Such awards are non-vested until the required service period expires.

The following table summarizes information regarding restricted unit awards for the periods indicated:

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
Enterprise Products Partners restricted unit awards
Restricted units at December 31, 2009		2,720,882		$	27.70
Granted (2) (3)		1,290,075		$	32.27
Vested (3)		(34,528	)	$	26.62
Forfeited		(50,548	)	$	28.82
Restricted units at March 31, 2010		3,925,881		$	29.35

Duncan Energy Partners restricted unit awards
Restricted units at December 31, 2009		--
Granted (3) (4)		6,348		$	25.26
Vested (3)		(6,348	)	$	25.26
Restricted units at March 31, 2010		--

(1) Determined by dividing the aggregate grant date fair value of awards before an allowance for forfeitures by the number of awards issued. (2) Aggregate grant date fair value of our restricted unit awards issued during 2010 was $41.6 million based on grant date market price of our common units of $32.27 per unit. Estimated forfeiture rates ranging between 4.6% and 17% were applied to these awards. (3) Includes awards granted to the independent directors of the board of directors of EPGP and DEP GP as part of their annual compensation in February 2010 and immediately vested. (4) Aggregate grant date fair value of Duncan Energy Partners’ restricted unit awards issued during 2010 was $0.2 million based on grant date market prices of Duncan Energy Partners’ common units of $25.26 per unit.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On a gross basis, the total unrecognized compensation cost of such awards was $68.0 million at March 31, 2010, of which our share is currently estimated to be $62.1 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

Certain long-term incentive plans provide for the issuance of non-qualified incentive options to purchase a fixed number of our common units or common units of Duncan Energy Partners. When issued, the exercise price of each option award may be no less than the market price of the underlying security on the date of grant. In general, options granted under the EPCO plans have a vesting period of four years and remain exercisable for five to ten years, as applicable, from the date of grant.

The following table presents unit option activity under the long-term incentive plans for the periods indicated:

						Weighted-
				Weighted-		Average
				Average		Remaining		Aggregate
	Number of			Strike Price		Contractual		Intrinsic
	Units			(dollars/unit)		Term (in years)		Value (1)
Outstanding at December 31, 2009		3,825,920		$	26.52
Granted (2)		755,000		$	32.27
Exercised		(97,500	)	$	22.77
Outstanding at March 31, 2010		4,483,420		$	27.57		4.6	$	3.1
Options exercisable at March 31, 2010		350,000		$	25.74		4.9	$	3.1

(1) Aggregate intrinsic value reflects fully vested unit options at the date indicated. (2) Aggregate grant date fair value of these unit options issued during 2010 was $2.2 million based on the following assumptions: (i) a grant date market price of our common units of $32.27 per unit; (ii) expected life of options of 4.9 years; (iii) risk-free interest rate of 2.4%; (iv) expected distribution yield on our common units of 6.9% and (v) expected unit price volatility on our common units of 23.2%. An estimated forfeiture rate of 17% was applied to awards granted during 2010.

The following table presents additional information regarding our unit options for the periods indicated:

	For the Three Months Ended March 31,
	2010		2009
Total intrinsic value of option awards exercised during period	$	0.9	$	0.1
Cash received from EPCO in connection with the exercise of unit option awards		0.6		0.1
Option-related reimbursements to EPCO		0.9		0.1

On a gross basis, the total unrecognized compensation cost of such awards was $10.1 million at March 31, 2010, of which our share is currently estimated to be $9.1 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.9 years.

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ENTERPRISE PRODUCTS PARTNERS L.P.

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Unit Appreciation Rights

UARs entitle a participant to receive a cash payment on the vesting date equal to the excess, if any, of the fair market value of the underlying security (determined as of a future vesting date) over the grant date fair value of the award. UARs are accounted for as liability awards. The following tables present additional information regarding our UARs for the periods indicated:

	UARs Issued by
	Enterprise Products Partners			Enterprise GP Holdings		Total
UARs at December 31, 2009		142,196			90,000		232,196
Settled or forfeited		(10,255	)		--		(10,255	)
UARs at March 31, 2010		131,941			90,000		221,941

	For the Three Months Ended March 31,
	2010		2009
Accrued liability for UARs, at end of period	$	0.4	$	0.1

At March 31, 2010, 131,941 UARs had been granted under the 2006 Plan to certain employees of EPCO who work on our behalf. These awards are subject to five year cliff vesting requirements and are expected to settle in 2012. The grant date fair value with respect to these UARs is based on a unit price of $37.00 for our common units. If the employee resigns prior to vesting, these UAR awards are forfeited.

The non-employee directors of DEP GP, the general partner of Duncan Energy Partners, have been granted UARs in the form of letter agreements. These liability awards are not part of any established long-term incentive plan of EPCO, Enterprise GP Holdings, Duncan Energy Partners or us. The compensation expense associated with these awards is recognized by DEP GP, which is our consolidated subsidiary. At March 31, 2010, there were a total of 90,000 outstanding UARs granted to non-employee directors of DEP GP that cliff vest in 2012. If a director resigns prior to vesting, his UAR awards are forfeited. The grant date fair value with respect to these UARs is based on an Enterprise GP Holdings’ unit price of $36.68.

Phantom Units

Certain of our long-term incentive plans provide for the issuance of phantom unit awards. These awards are automatically redeemed for cash based on the fair value of the vested portion of phantom units at redemption dates in each award. The fair value of each phantom unit award is equal to the closing market price of the underlying security on the redemption date. Each participant is required to redeem their phantom units as they vest, which is typically three to four years from the date the award is granted. Our phantom units are accounted for as liability awards.

The following tables present additional information regarding our phantom unit awards for the periods indicated:

Phantom units at December 31, 2009	14,927
Granted	6,200
Vested	(4,327	)
Phantom units at March 31, 2010	16,800

	For the Three Months Ended March 31,
	2010		2009
Accrued liability for phantom unit awards, at end of period	$	0.1	$	0.4
Liabilities paid for phantom unit awards		0.1		0.8

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The 3,472 phantom units outstanding under the TEPPCO 1999 Phantom Unit Retention Plan at December 31, 2009 vested in January 2010 and the plan was terminated.

Profits Interests Awards

As long-term incentive arrangements, EPCO has granted its key employees who perform services on behalf of us, EPCO and other affiliated companies, “profits interests” in the Employee Partnerships, all of which are private company affiliates of EPCO.

Profits interests awards entitle each holder to participate in the expected long-term appreciation in value of the equity securities owned by each Employee Partnership. The Employee Partnerships own either units of Enterprise GP Holdings or Enterprise Products Partners or a combination of both. The profits interests awards are subject to customary forfeiture provisions.

The total unrecognized compensation cost of the profits interests awards was $52.7 million at March 31, 2010, of which our share is currently estimated to be $43.0 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 5.9 years.

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

In the course of our normal business operations, we are exposed to certain risks, including changes in interest rates, commodity prices and, to a limited extent, foreign exchange rates. In order to manage risks associated with certain identifiable and anticipated transactions, we use derivative instruments. Derivatives are instruments whose fair value is determined by changes in a specified benchmark such as interest rates, commodity prices or currency values. Fair value is generally defined as the amount at which a derivative instrument could be exchanged in a current transaction between willing parties, not in a forced sale. Typical derivative instruments include futures, forward contracts, swaps, options and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities.

We are required to recognize derivative instruments at fair value as either assets or liabilities on the balance sheet. 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 are related. After meeting specified conditions, a qualified derivative may be specifically designated as a total or partial hedge of:

§	Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment - In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change.

§	Variable cash flows of a forecasted transaction - In a cash flow hedge, the effective portion of the hedge is reported in other comprehensive income (loss) (“OCI”) and is reclassified into earnings when the forecasted transaction affects earnings.

§	Foreign currency exposure - A foreign currency hedge can be treated as either a fair value hedge or a cash flow hedge depending on the risk being hedged.

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 changes in the fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period. Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item. Any ineffectiveness associated with a hedge relationship is recognized in earnings immediately. Ineffectiveness can be caused

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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 probable of not occurring is immediately recognized in earnings.

Interest Rate Derivative Instruments

We utilize interest rate swaps, treasury locks and similar derivative instruments to manage our exposure to changes in the interest rates of certain consolidated debt agreements. This strategy is a component in controlling our cost of capital associated with such borrowings.

The following table summarizes our interest rate derivative instruments outstanding at March 31, 2010, all of which were designated as hedging instruments under the derivative and hedging guidance of the Financial Accounting Standards Board (“FASB”):

	Number and Type of	Notional	Period of	Rate	Accounting
Hedged Transaction	Derivative Employed	Amount	Hedge	Swap	Treatment
Enterprise Products Partners:
Senior Notes C	1 fixed-to-floating swap	$100.0	1/04 to 2/13	6.4% to 2.3%	Fair value hedge
Senior Notes G	3 fixed-to-floating swaps	$300.0	10/04 to 10/14	5.6% to 1.5%	Fair value hedge
Senior Notes P	7 fixed-to-floating swaps	$400.0	6/09 to 8/12	4.6% to 2.7%	Fair value hedge
Duncan Energy Partners:
Variable-rate borrowings	3 floating-to-fixed swaps	$175.0	9/07 to 9/10	0.3% to 4.6%	Cash flow hedge

Changes in the fair value of the interest rate swaps and the related hedged items in a fair value hedge were recorded on the balance sheet with the offset recorded as interest expense. Cash flow hedges fix the interest rate paid on floating rate debt with the difference between the floating rate and fixed rate being recorded as an increase or decrease to interest expense. This combined activity resulted in a decrease in interest expense of $4.3 million for the three months ended March 31, 2010 and an increase in interest expense of $0.6 million for the three months ended March 31, 2009.

The following table summarizes our forward starting interest rate swaps outstanding at March 31, 2010, which hedge the underlying benchmark interest payments related to the forecasted issuances of debt:

	Number and Type of	Notional	Period of	Average Rate	Accounting
Hedged Transaction	Derivative Employed	Amount	Hedge	Locked	Treatment
Future debt offering	1 forward starting swap	$50.0	6/10 to 6/20	3.3%	Cash flow hedge
Future debt offering	3 forward starting swaps	$250.0	2/11 to 2/21	3.6%	Cash flow hedge
Future debt offering	6 forward starting swaps	$300.0	2/12 to 2/22	4.7%	Cash flow hedge

In April and May 2010, we entered into four additional forward starting swaps each with a notional amount of $50.0 million. The period hedged by these four forward starting swaps is February 2012 through February 2022.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 the price risk associated with certain exposures, we enter into commodity derivative instruments such as forwards, basis swaps, futures and options contracts. The following table summarizes our commodity derivative instruments outstanding at March 31, 2010:

	Volume (1)		Accounting
Derivative Purpose	Current	Long-Term (2)	Treatment
Derivatives designated as hedging instruments:
Enterprise Products Partners:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction (“PTR”) (3)	26.5 Bcf	n/a	Cash flow hedge
Forecasted NGL sales (4)	6.3 MMBbls	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchases of NGLs	2.1 MMBbls	n/a	Cash flow hedge
NGLs inventory management	0.1 MMBbls	n/a	Cash flow hedge
Forecasted sales of octane enhancement products	3.2 MMBbls	0.4 MMBbls	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities	1.9 Bcf	1.2 Bcf	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products	11.1 MMBbls	0.5 MMBbls	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products	10.9 MMBbls	0.7 MMBbls	Cash flow hedge

Derivatives not designated as hedging instruments:
Enterprise Products Partners:
Natural gas risk management activities (5) (6)	315.4 Bcf	51.2 Bcf	Mark-to-market
NGL risk management activities (6)	0.4 MMBbls	n/a	Mark-to-market
Crude oil risk management activities (6)	9.4 MMBbls	n/a	Mark-to-market
Duncan Energy Partners:
Natural gas risk management activities (6)	1.4 Bcf	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 included in the long-term column is December 2012. (3) PTR represents the British thermal unit 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. See the discussion below for the primary objective of this strategy. (4) Excludes 6.1 million barrels (“MMBbls”) of additional hedges executed under contracts that have been designated as normal sales agreements under the FASB’s derivative and hedging guidance. The combination of these volumes with the 6.3 MMBbls reflected as derivatives in the table above results in a total of 12.4 MMBbls of hedged forecasted NGL sales volumes, which corresponds to the 26.5 billion cubic feet (“Bcf”) of forecasted natural gas purchase volumes for PTR. (5) Current and long-term volumes include approximately 134.9 and 9.9 Bcf, respectively, of physical derivative instruments that are predominantly priced at an index plus a premium or minus a discount. (6) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

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

Our three predominant hedging strategies are hedging natural gas processing margins, hedging anticipated future sales of NGLs, refined products and crude oil associated with volumes held in inventory and hedging the fair value of natural gas in inventory. The objective of our natural gas processing strategy is to hedge an amount of gross margin associated with the gas processing activities. We achieve this by using physical and financial instruments to lock in the prices of natural gas purchases used for PTR and related NGL sales. This program consists of (i) the forward sale of a portion of our expected equity NGL

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production at fixed prices through December 2010, achieved through the use of forward physical sales and commodity derivative instruments and (ii) the purchase of commodity derivative instruments with a notional amount determined by the amount 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 anticipated future sales of inventory by locking in the sales price through the use of forward physical sales 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.

Foreign Currency Derivative Instruments

We are exposed to a nominal amount of foreign currency exchange risk in connection with our NGL and natural gas marketing activities in Canada. As a result, we could be adversely affected by fluctuations in currency rates between the U.S. dollar and Canadian dollar. In order to manage this risk, we may enter into foreign exchange purchase contracts to lock in the exchange rate. Long-term transactions (more than two months) are accounted for as cash flow hedges. Shorter term transactions are accounted for using mark-to-market accounting. At March 31, 2010, we did not have any foreign currency derivative instruments outstanding.

Credit-Risk Related Contingent Features in Derivative Instruments

A limited number of our commodity derivative instruments include provisions related to credit ratings and/or adequate assurance clauses. A credit rating provision provides for a counterparty to demand immediate full or partial payment to cover a net liability position upon the loss of a stipulated credit rating. An adequate assurance clause provides for a counterparty to demand immediate full or partial payment to cover a net liability position should reasonable grounds for insecurity arise with respect to contractual performance by either party. At March 31, 2010, the aggregate fair value of our over-the-counter derivative instruments in a net liability position was $5.8 million, all of which was subject to a credit rating contingent feature. If our credit ratings were downgraded to Ba2/BB, approximately $0.8 million would be payable as a margin deposit to the counterparties, and if our credit ratings were downgraded to Ba3/BB- or below, approximately $5.8 million would be payable as a margin deposit to the counterparties. Currently, no margin is required to be deposited. The potential for derivatives with contingent features to enter a net liability position may change in the future as positions and prices fluctuate.

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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, 2010			December 31, 2009			March 31, 2010			December 31, 2009
	Balance Sheet	Fair		Balance Sheet	Fair		Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value		Location	Value		Location	Value
Derivatives designated as hedging instruments
Interest rate derivatives	Other current assets	$	44.5	Other current assets	$	32.7	Other current liabilities	$	3.8	Other current liabilities	$	5.5
Interest rate derivatives	Other assets		19.7	Other assets		31.8	Other liabilities		0.1	Other liabilities		2.2
Total interest rate derivatives			64.2			64.5			3.9			7.7
Commodity derivatives	Other current assets		47.9	Other current assets		52.0	Other current liabilities		89.4	Other current liabilities		62.6
Commodity derivatives	Other assets		0.9	Other assets		0.5	Other liabilities		2.1	Other liabilities		1.8
Total commodity derivatives (1)			48.8			52.5			91.5			64.4
Foreign currency derivatives	Other current assets		--	Other current assets		0.2	Other current liabilities		--	Other current liabilities		--
Total derivatives designated as hedging instruments		$	113.0		$	117.2		$	95.4		$	72.1

Derivatives not designated as hedging instruments
Commodity derivatives	Other current assets	$	43.0	Other current assets	$	28.9	Other current liabilities	$	38.4	Other current liabilities	$	24.9
Commodity derivatives	Other assets		3.4	Other assets		2.0	Other liabilities		10.3	Other liabilities		2.7
Total commodity derivatives			46.4			30.9			48.7			27.6
Total derivatives not designated as hedging instruments		$	46.4		$	30.9		$	48.7		$	27.6

(1) Represent commodity derivative instrument transactions that either have 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.

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 indicated:


Derivatives in Fair Value		Gain/(Loss) Recognized in
Hedging Relationships	Location	Income on Derivative
		For the Three Months
		Ended March 31,
		2010			2009
Interest rate derivatives	Interest expense	$	7.4		$	(1.3	)
Commodity derivatives	Revenue		(1.8	)		0.3
Total		$	5.6		$	(1.0	)


Derivatives in Fair Value		Gain/(Loss) Recognized in
Hedging Relationships	Location	Income on Hedged Item
		For the Three Months
		Ended March 31,
		2010			2009
Interest rate derivatives	Interest expense	$	(7.4	)	$	1.3
Commodity derivatives	Revenue		1.9			0.1
Total		$	(5.5	)	$	1.4

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	Change in Value
	Recognized in OCI on
Derivatives in Cash Flow	Derivative
Hedging Relationships	(Effective Portion)
	For the Three Months
	Ended March 31,
	2010			2009
Interest rate derivatives	$	(5.7	)	$	(0.7	)
Commodity derivatives – Revenue		(7.1	)		(10.0	)
Commodity derivatives – Operating costs and expenses		(51.8	)		(52.0	)
Foreign currency derivatives		(0.1	)		(10.6	)
Total	$	(64.7	)	$	(73.3	)

		Amount of Gain/(Loss)
	Location of Gain/(Loss)	Reclassified from AOCI
Derivatives in Cash Flow	Reclassified from AOCI	into Income
Hedging Relationships	into Income (Effective Portion)	(Effective Portion)
		For the Three Months
		Ended March 31,
		2010			2009
Interest rate derivatives	Interest expense	$	(3.3	)	$	(2.3	)
Commodity derivatives	Revenue		(15.8	)		15.3
Commodity derivatives	Operating costs and expenses		(0.7	)		(47.5	)
Foreign currency derivatives	Other income		0.3			--
Total		$	(19.5	)	$	(34.5	)

	Location of Loss	Amount of Loss
	Recognized in Income	Recognized in Income on
Derivatives in Cash Flow	on Ineffective Portion	Ineffective Portion of
Hedging Relationships	of Derivative	Derivative
		For the Three Months
		Ended March 31,
		2010			2009
Commodity derivatives	Operating costs and expenses	$	(0.6	)	$	(1.1	)
Total		$	(0.6	)	$	(1.1	)

Over the next twelve months, we expect to reclassify $9.0 million of accumulated other comprehensive income (loss) (“AOCI”) attributable to interest rate derivative instruments into earnings as an increase to interest expense. Likewise, we expect to reclassify $40.8 million of accumulated other comprehensive loss attributable to commodity derivative instruments into earnings, $17.5 million as an increase in operating costs and expenses and $23.3 million as a decrease in revenues.

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 indicated:

	Gain/(Loss) Recognized in
Derivatives Not Designated	Income on Derivative
Hedging Instruments	Amount						Location
	For the Three Months
	Ended March 31,
	2010			2009
Commodity derivatives	$	3.9		$	24.3		Revenue
Commodity derivatives		(1.5	)		--		Operating costs and expenses
Foreign currency derivatives		--			(0.1	)	Other, net
Total	$	2.4		$	24.2

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Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. 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. Recognized valuation techniques employ inputs such as product prices, 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.

The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the New York Mercantile Exchange). Our Level 1 fair values primarily consist of financial assets and liabilities such as exchange-traded commodity derivative instruments.

Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions are: (i) observable in the marketplace throughout the full term of the instrument, (ii) can be derived from observable data or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values consist of commodity derivative instruments such as forwards, swaps and other instruments transacted on an exchange or over the counter and interest rate derivative instruments. The fair values of these derivatives are based on observable price quotes for similar products and locations. The value of our interest rate derivatives are valued by using appropriate financial models with the implied forward London Interbank Offered Rate yield curve for the same period as the future interest swap settlements.

Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally developed data. The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort. Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value. Our Level 3 fair values largely consist of ethane, normal butane and natural gasoline-based contracts

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with a range of two to 12 months in term. We rely on price quotes from reputable brokers in the marketplace who publish price quotes on certain products. Whenever possible, we compare these prices to other reputable brokers for the same product in the same market. These prices, combined with our forward transactions, are used in our model to determine the fair value of such instruments.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured on a recurring basis at March 31, 2010. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value assets and liabilities, in addition to their placement within the fair value hierarchy levels. There were no significant transfers between levels during the three months ended March 31, 2010.

	At March 31, 2010
	Level 1		Level 2		Level 3		Total
Financial assets:
Interest rate derivative instruments	$	--	$	64.2	$	--	$	64.2
Commodity derivative instruments		30.2		33.8		31.2		95.2
Total	$	30.2	$	98.0	$	31.2	$	159.4

Financial liabilities:
Interest rate derivative instruments	$	--	$	3.9	$	--	$	3.9
Commodity derivative instruments		64.8		41.6		33.8		140.2
Total	$	64.8	$	45.5	$	33.8	$	144.1

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

	For the Three Months
	Ended March 31,
	2010			2009
Balance, January 1	$	5.7		$	32.4
Total gains (losses) included in:
Net income (1)		(3.6	)		12.9
Other comprehensive income (loss)		(8.3	)		1.5
Purchases, issuances, settlements - net		3.6			(12.3	)
Balance, March 31	$	(2.6	)	$	34.5

(1) There were $0.5 million of unrealized gains and $0.2 million of unrealized losses included in these amounts for the three months ended March 31, 2010 and 2009, respectively.

Nonfinancial Assets and Liabilities

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment). The following table presents the estimated fair value of certain assets carried on our Unaudited Condensed Consolidated Balance Sheet by caption for which a nonrecurring change in fair value has been recorded during the three months ended March 31, 2010:

		Level 3				Impairment Charges
Property, plant and equipment		$	--			$	1.5

Using appropriate valuation techniques, we adjusted the carrying value of certain of our Onshore Natural Gas Pipelines & Services segment assets and recorded, in operating costs and expenses, non-cash impairment charges of $1.5 million during the three months ended March 31, 2010.

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Note 5. Inventories

Our inventory amounts were as follows at the dates indicated:

	March 31,		December 31,
	2010		2009
Working inventory (1)	$	702.8	$	466.4
Forward sales inventory (2)		288.1		245.5
Total inventory	$	990.9	$	711.9

(1) Working inventory is comprised of inventories of natural gas, NGLs, crude oil, refined products, lubrication oils and certain petrochemical products that are either available-for-sale or used in the provision for services. (2) Forward sales inventory consists of identified natural gas, NGL, refined product and crude oil volumes dedicated to the fulfillment of forward sales contracts.

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.

The following table summarizes our cost of sales and lower of cost or market (“LCM”) adjustment amounts for the periods indicated:

	For the Three Months Ended March 31,
	2010		2009
Cost of sales (1)	$	7,342.3	$	3,817.9
LCM adjustments		5.7		4.3
(1) Cost of sales is included in “Operating costs and expenses,” as presented on our Unaudited Condensed Statements of Consolidated Operations. The fluctuation in this amount quarter-to-quarter is 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

Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates indicated:

	Estimated
	Useful Life	March 31,		December 31,
	in Years	2010		2009
Plants and pipelines (1)	3-45 (5)	$	18,077.8	$	17,681.9
Underground and other storage facilities (2)	5-40 (6)		1,294.6		1,280.5
Platforms and facilities (3)	20-31		637.6		637.6
Transportation equipment (4)	3-10		61.2		60.1
Marine vessels	15-30		559.0		559.4
Land			82.9		82.9
Construction in progress			1,021.8		1,207.2
Total			21,734.9		21,509.6
Less accumulated depreciation			3,999.6		3,820.4
Property, plant and equipment, net		$	17,735.3	$	17,689.2

(1) Plants and pipelines include processing plants; NGL, petrochemical, crude oil and natural gas 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. (4) Transportation equipment includes vehicles and similar assets used in our operations. (5) In general, the estimated useful lives of major components of this category are as follows: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; delivery facilities, 20-40 years; office furniture and equipment, 3-20 years; buildings, 20-40 years; and laboratory and shop equipment, 5-35 years. (6) In general, the estimated useful lives of major components of this category are as follows: 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 indicated:

	For the Three Months
	Ended March 31,
	2010		2009
Depreciation expense (1)	$	180.3	$	158.6
Capitalized interest (2)		10.5		17.4
(1) Depreciation expense is a component of “Costs and expenses” as presented in our Unaudited Condensed Statements of Consolidated Operations. (2) Capitalized interest increases the carrying value of the associated asset and reduces interest expense during the period it is recorded.

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Asset Retirement Obligations

We have recorded asset retirement obligations (“AROs”) related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations. In general, our AROs primarily result from (i) right-of-way agreements associated with our pipeline operations, (ii) leases of plant sites and (iii) regulatory requirements triggered by the abandonment or retirement of certain underground storage assets and offshore facilities. In addition, our AROs may result from the renovation or demolition of certain assets containing hazardous substances such as asbestos.

The following table presents information regarding our AROs since December 31, 2009:

ARO liability balance, December 31, 2009	$	54.8
Revisions in estimated cash flows		4.2
Accretion expense		1.0
ARO liability balance, March 31, 2010	$	60.0

Property, plant and equipment at March 31, 2010 and December 31, 2009 includes $27.8 million and $26.7 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset. The following table presents forecasted accretion expense associated with our AROs for the periods indicated:

Remainder of
2010		2011		2012		2013		2014
$	2.8	$	3.7	$	4.0	$	4.3	$	4.7

Certain of our unconsolidated affiliates have AROs recorded at March 31, 2010 and December 31, 2009 relating to contractual agreements and regulatory requirements. These amounts were immaterial to our financial statements.

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Note 7. Investments in Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for using the equity method of accounting. We group our investments in unconsolidated affiliates according to the business segment to which they relate (see Note 11 for a general discussion of our business segments). The following table shows our ownership interest and investments in unconsolidated affiliates by business segment at the dates indicated:

	Ownership
	Interest at
	March 31,		March 31,		December 31,
	2010		2010		2009
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C.		13.1%	$	31.6	$	32.6
K/D/S Promix, L.L.C. (“Promix”)		50%		50.1		48.9
Baton Rouge Fractionators LLC		32.2%		22.5		22.2
Skelly-Belvieu Pipeline Company, L.L.C.		50%		34.5		37.9
Onshore Natural Gas Pipelines & Services:
Evangeline (1)		49.5%		5.8		5.6
White River Hub, LLC		50%		26.6		26.4
Onshore Crude Oil Pipelines & Services:
Seaway Crude Pipeline Company (“Seaway”)		50%		177.2		178.5
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)		36%		61.0		61.7
Cameron Highway Oil Pipeline Company (“Cameron Highway”)		50%		237.5		239.6
Deepwater Gateway, L.L.C.		50%		100.7		101.8
Neptune Pipeline Company, L.L.C.		25.7%		55.6		53.8
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator, LLC		30%		11.1		11.1
Centennial Pipeline LLC (“Centennial”)		50%		65.6		66.7
Other (2)	Various			3.7		3.8
Total			$	883.5	$	890.6

(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.

On occasion, the price we pay to acquire an ownership interest in a company exceeds the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our investments in unconsolidated affiliates. The following table summarizes the unamortized excess cost amounts by business segment at the dates indicated:

	March 31,		December 31,
	2010		2009
NGL Pipelines & Services	$	26.4	$	27.1
Onshore Crude Oil Pipelines & Services		20.2		20.4
Offshore Pipelines & Services		17.0		17.3
Petrochemical & Refined Products Services		3.3		4.0
Total	$	66.9	$	68.8

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Such excess cost amounts were attributable to the underlying tangible and amortizable intangible assets of certain unconsolidated affiliates. We amortize such excess cost amounts as a reduction in equity earnings in a manner similar to depreciation. The following table presents our amortization of such excess cost amounts by business segment for the periods indicated:

	For the Three Months
	Ended March 31,
	2010		2009
NGL Pipelines & Services	$	0.2	$	0.2
Onshore Crude Oil Pipelines & Services		0.2		0.2
Offshore Pipelines & Services		0.3		0.3
Petrochemical & Refined Products Services		0.7		1.3
Total	$	1.4	$	2.0

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

	For the Three Months
	Ended March 31,
	2010			2009
NGL Pipelines & Services	$	3.3		$	1.2
Onshore Natural Gas Pipelines & Services		1.3			1.1
Onshore Crude Oil Pipelines & Services		2.3			3.3
Offshore Pipelines & Services		11.8			4.7
Petrochemical & Refined Products Services		(2.7	)		(2.9	)
Total	$	16.0		$	7.4

NGL Pipelines & Services

At March 31, 2010, our investees included in our NGL Pipelines & Services segment owned: (i) a natural gas processing facility and related assets located in south Louisiana, (ii) an NGL fractionation facility and related storage and pipeline assets located in south Louisiana, (iii) an NGL fractionation facility located in south Louisiana and (iv) a 572-mile pipeline that transports mixed NGLs to markets in southeast Texas.

Onshore Natural Gas Pipelines & Services

At March 31, 2010, our investees included in our Onshore Natural Gas Pipelines & Services segment owned: (i) a natural gas pipeline located in south Louisiana and (ii) a natural gas hub located in northwest Colorado.

Onshore Crude Oil Pipelines & Services

At March 31, 2010, our investee included in our Onshore Crude Oil Pipelines & Services segment owned a pipeline that transports crude oil from a marine terminal located in Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal located in Texas City, Texas, to refineries in the Texas City and Houston, Texas areas.

Offshore Pipelines & Services

At March 31, 2010, our investees included in our Offshore Pipelines & Services segment owned: (i) a crude oil pipeline that gathers production from the outer continental shelf and deepwater areas of the Gulf of Mexico for delivery to onshore locations in south Louisiana, (ii) a crude oil pipeline that gathers production from deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in southeast Texas, (iii) a crude oil and natural gas platform that processes production from the Marco Polo, K2, K2 North and Genghis Khan fields located in the South

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Green Canyon area of the Gulf of Mexico and (iv) natural gas pipeline systems located in the Gulf of Mexico.