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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2010

[ ] 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: 1-33266

DUNCAN ENERGY PARTNERS L.P.

(Exact name of Registrant as Specified in Its Charter)

Delaware		20-5639997
(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 ¨ 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 o	Accelerated filer þ
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 57,693,720 common units of Duncan Energy Partners L.P. outstanding at May 3, 2010. These common units trade on the New York Stock Exchange under the ticker symbol “DEP.”

Table of Contents

DUNCAN ENERGY 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, Primary Operations and Basis of Financial Statement Presentation		9
	2. General Accounting Matters		11
	3. Equity-based Awards		12
	4. Derivative Instruments, Hedging Activities and Fair Value Measurements		14
	5. Inventories		20
	6. Property, Plant and Equipment		20
	7. Investment in Evangeline		21
	8. Intangible Assets and Goodwill		22
	9. Debt Obligations		23
	10. Equity and Distributions		24
	11. Noncontrolling Interest		26
	12. Business Segments		29
	13. Related Party Transactions		33
	14. Earnings Per Unit		36
	15. Commitments and Contingencies		37
	16. Significant Risks and Uncertainties		39
	17. Supplemental Cash Flow Information		39

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.		41
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.		55
Item 4.	Controls and Procedures.		56

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.		57
Item 1A.	Risk Factors.		57
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.		57
Item 3.	Defaults upon Senior Securities.		58
Item 4.	(Removed and Reserved).		58
Item 5.	Other Information.		58
Item 6.	Exhibits.		58

Signatures			61

Table of Contents

PART I. FINANCIAL INFORMATION.

Item 1. Financial Statements.

DUNCAN ENERGY PARTNERS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	At March 31,			At December 31,
	2010			2009
ASSETS
Current assets
Cash and cash equivalents	$	21.7		$	3.9
Accounts receivable – trade, net of allowance for doubtful accounts		84.0			77.7
Accounts receivable – related parties		15.7			54.5
Gas imbalance receivables		5.7			9.8
Inventories		9.1			10.5
Prepaid and other current assets		12.3			9.8
Total current assets		148.5			166.2
Property, plant and equipment, net		4,601.8			4,549.6
Investments in Evangeline		5.8			5.6
Intangible assets, net of accumulated amortization of $44.7 at March 31, 2010 and $42.6 at December 31, 2009		42.7			43.8
Goodwill		4.9			4.9
Other assets		0.6			0.7
Total assets	$	4,804.3		$	4,770.8

LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	175.0		$	--
Accounts payable – trade		40.7			54.5
Accounts payable – related parties		25.3			13.6
Accrued product payables		56.1			59.9
Accrued property taxes		7.2			9.1
Accrued taxes – other		7.9			8.4
Other current liabilities		15.0			18.9
Total current liabilities		327.2			164.4
Long-term debt (see Note 9)		282.3			457.3
Deferred tax liabilities		5.5			5.8
Other long-term liabilities		6.6			6.4
Commitments and contingencies
Equity:
Duncan Energy Partners L.P. partners’ equity: (see Note 10)
Limited partners
Common units (57,693,720 common units outstanding at March 31, 2010 and 57,676,987 common units outstanding at December 31, 2009)		763.2			766.6
General partner		--			0.2
Accumulated other comprehensive loss		(3.7	)		(5.4	)
Total Duncan Energy Partners L.P. partners’ equity		759.5			761.4
Noncontrolling interest in subsidiaries: (see Note 11)
DEP I Midstream Businesses – Parent		497.8			487.3
DEP II Midstream Businesses – Parent		2,925.4			2,888.2
Total noncontrolling interest		3,423.2			3,375.5
Total equity		4,182.7			4,136.9
Total liabilities and equity	$	4,804.3		$	4,770.8

See Notes to Unaudited Condensed Consolidated Financial Statements.

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DUNCAN ENERGY PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(Dollars in millions)

	For the Three Months
	Ended March 31,
	2010			2009
Revenues
Third parties	$	158.2		$	113.6
Related parties		132.4			143.2
Total revenues (see Note 12)		290.6			256.8
Costs and Expenses
Operating costs and expenses:
Third parties		225.7			195.3
Related parties		41.5			44.1
Total operating costs and expenses		267.2			239.4
General and administrative costs:
Third parties		0.7			0.7
Related parties		4.2			2.1
Total general and administrative costs		4.9			2.8
Total costs and expenses		272.1			242.2
Equity in income of Evangeline		0.2			0.2
Operating income		18.7			14.8
Other income (expense)
Interest expense		(3.1	)		(3.8	)
Other, net		--			0.1
Total other expense, net		(3.1	)		(3.7	)
Income before income taxes		15.6			11.1
Benefit from (provision for) income taxes		0.1			(0.1	)
Net income		15.7			11.0
Net loss (income) attributable to noncontrolling interest: (see Note 11)
DEP I Midstream Businesses - Parent		(4.7	)		(1.6	)
DEP II Midstream Businesses - Parent		10.2			10.5
Total net loss attributable to noncontrolling interest		5.5			8.9
Net income attributable to Duncan Energy Partners L.P. (see Note 1)	$	21.2		$	19.9

Allocation of net income attributable to Duncan Energy Partners L.P.: (see Note 1)
Duncan Energy Partners L.P.:
Limited partners’ interest in net income	$	21.0		$	19.8
General partner interest in net income	$	0.2		$	0.1

Basic and diluted earnings per unit (see Note 14)	$	0.37		$	0.34

See Notes to Unaudited Condensed Consolidated Financial Statements.

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DUNCAN ENERGY PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME

(Dollars in millions)

	For the Three Months
	Ended March 31,
	2010			2009

Net income	$	15.7		$	11.0
Other comprehensive income:
Cash flow hedges:
Interest rate derivative instrument gains (losses) during period		(0.2	)		0.7
Reclassification adjustment for losses included in net income related to interest rate derivative instruments		1.9			1.4
Total cash flow hedges		1.7			2.1
Comprehensive income		17.4			13.1
Comprehensive loss (income) attributable to noncontrolling interest:
DEP I Midstream Businesses – Parent		(4.7	)		(1.6	)
DEP II Midstream Businesses – Parent		10.2			10.5
Total comprehensive loss attributable to noncontrolling interest		5.5			8.9
Comprehensive income attributable to Duncan Energy Partners L.P.	$	22.9		$	22.0

See Notes to Unaudited Condensed Consolidated Financial Statements.

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DUNCAN ENERGY 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	$	15.7		$	11.0
Adjustments to reconcile net income to net cash flows provided
by operating activities:
Depreciation, amortization and accretion		48.2			45.0
Equity in income of Evangeline		(0.2	)		(0.2	)
Gain from sale of assets and related transactions		(0.9	)		(0.1	)
Deferred income tax expense		(0.3	)		(0.2	)
Non-cash asset impairment		1.5			--
Changes in fair market value of derivative instruments		--			(0.1	)
Net effect of changes in operating accounts (see Note 17)		(2.5	)		(35.6	)
Net cash flows provided by operating activities		61.5			19.8
Investing activities:
Capital expenditures		(119.9	)		(116.2	)
Contributions in aid of construction costs		2.6			1.2
Proceeds from sale of assets and related transactions		2.0			0.1
Other, including loans to affiliates		45.6			(0.1	)
Cash used in investing activities		(69.7	)		(115.0	)
Financing activities:
Repayments of debt		(15.1	)		(31.6	)
Borrowings under debt agreements		15.1			17.6
Debt issuance costs		--			(0.4	)
Net proceeds from Duncan Energy Partners’ issuance of common units		0.2			--
Cash distributions to Duncan Energy Partners’ unitholders and general partner		(25.9	)		(13.1	)
Cash distributions to noncontrolling interest		(27.1	)		(15.7	)
Cash contributions from noncontrolling interest		78.8			147.2
Cash provided by financing activities		26.0			104.0
Net changes in cash and cash equivalents		17.8			8.8
Cash and cash equivalents, January 1		3.9			13.0
Cash and cash equivalents, March 31	$	21.7		$	21.8

See Notes to Unaudited Condensed Consolidated Financial Statements.

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DUNCAN ENERGY PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(Dollars in millions)

	Duncan Energy Partners L.P.
							Accumulated
							Other			Noncontrolling
	Limited			General			Comprehensive			Interest in
	Partners			Partner			Income (Loss)			Subsidiaries			Total
Balance, December 31, 2009	$	766.6		$	0.2		$	(5.4	)	$	3,375.5		$	4,136.9
Net income (loss)		21.0			0.2			--			(5.5	)		15.7
Amortization of equity awards		1.0			(0.2	)		--			--			0.8
Net cash proceeds from the issuance of common units		0.2			--			--			--			0.2
Cash contributions from noncontrolling interest		--			--			--			78.8			78.8
Cash distributions to unitholders and general partner		(25.7	)		(0.2	)		--			--			(25.9	)
Cash distributions to noncontrolling interest		--			--			--			(27.1	)		(27.1	)
Cash flow hedges		--			--			1.7			--			1.7
Other		0.1			--			--			1.5			1.6
Balance, March 31, 2010	$	763.2		$	--		$	(3.7	)	$	3,423.2		$	4,182.7

	Duncan Energy Partners L.P.
							Accumulated
							Other			Noncontrolling
	Limited			General			Comprehensive			Interest in
	Partners			Partner			Income (Loss)			Subsidiaries			Total
Balance, December 31, 2008	$	762.0		$	0.4		$	(9.6	)	$	3,091.4		$	3,844.2
Net income (loss)		19.8			0.1			--			(8.9	)		11.0
Amortization of equity awards		0.5			--			--			--			0.5
Cash contributions from noncontrolling interest		--			--			--			147.2			147.2
Cash distributions to unitholders and general partner		(12.9	)		(0.2	)		--			--			(13.1	)
Cash distributions to noncontrolling interest		--			--			--			(15.7	)		(15.7	)
Cash flow hedges		--			--			2.1			--			2.1
Other		--			--			--			(5.2	)		(5.2	)
Balance, March 31, 2009	$	769.4		$	0.3		$	(7.5	)	$	3,208.8		$	3,971.0

See Notes to Unaudited Condensed Consolidated Financial Statements.

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Except unit-related amounts, or as noted within the context of each footnote disclosure, 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 “Duncan Energy Partners” are intended to mean the business and operations of Duncan Energy Partners L.P. and its consolidated subsidiaries. References to “DEP GP” mean DEP Holdings, LLC, which is our general partner. References to “DEP OLP” mean DEP Operating Partnership, L.P., which is a wholly owned subsidiary of Duncan Energy Partners through which Duncan Energy Partners conducts substantially all of its business.

References to “Enterprise Products Partners” mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. Enterprise Products 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 “EPD.” References to “EPGP” mean Enterprise Products GP, LLC, which is the general partner of Enterprise Products Partners. References to “EPO” mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enter prise Products Partners through which Enterprise Products Partners conducts substantially all of its business, and that of its consolidated subsidiaries. EPO beneficially owns 100% of DEP GP and is a significant owner of our common units. Enterprise Products Partners consolidates our financial statements with those of its own.

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 EPE Holdings, EPGP 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

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

majority or, if less than three children of Mr. Duncan are then living, unanimously. Ms. Williams is currently the Duncan Voting Trustee.

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 provisi ons 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 “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 (“LE GP”). Enterprise GP Holdings owns noncontrolling interests in both Energy Transfer Equity and LE GP.

References to the “DEP I Midstream Businesses” collectively refer to (i) Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”); (ii) Acadian Gas, LLC (“Acadian Gas”); (iii) Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), including its general partner; (iv) Sabine Propylene Pipeline L.P. (“Sabine Propylene”), including its general partner; and (v) South Texas NGL Pipelines, LLC (“South Texas NGL”). We acquired controlling ownership interests in the DEP I Midstream Businesses from EPO effective February 1, 2007 in a drop down transaction (the “DEP I drop down”) in connection with our initial public offering.

References to the “DEP II Midstream Businesses” collectively refer to (i) Enterprise GC, L.P. (“Enterprise GC”); (ii) Enterprise Intrastate L.P. (“Enterprise Intrastate”); and (iii) Enterprise Texas Pipeline LLC (“Enterprise Texas”). We acquired controlling ownership interests in the DEP II Midstream Businesses from EPO on December 8, 2008 in a drop down transaction (the “DEP II drop down”). Our ownership interests in the DEP II Midstream Businesses are held by Enterprise Holding III, LLC, which is a wholly owned subsidiary of DEP OLP. Ownership interests in the DEP II Midstream Businesses that were retained by EPO are held by its wholly owned subsidiary, Enterprise GTM Holdings L.P.

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

References to “Evangeline” mean our aggregate 49.51% equity method investment in Evangeline Gas Pipeline Company, L.P. (“EGP”) and Evangeline Gas Corp (“EGC”).

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, Enterprise Products Partners, EPO, 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 Tru st 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 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, Primary Operations

and Basis of Financial Statement Presentation

Duncan Energy Partners is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “DEP.” Duncan Energy Partners is engaged in the business of: (i) natural gas liquids (“NGLs”) transportation, fractionation and marketing; (ii) storage of NGL and petrochemical products; (iii) transportation of petrochemical products; and (iv) the gathering, transportation, marketing and storage of natural gas.

At March 31, 2010, Duncan Energy Partners was owned 99.3% by its limited partners and 0.7% by its general partner, DEP GP, which is a wholly owned subsidiary of EPO. At March 31, 2010, EPO owned approximately 58.6% of Duncan Energy Partners’ limited partner interests and 100% of DEP GP. DEP GP is responsible for managing the business and operations of Duncan Energy Partners.

A privately held affiliate, EPCO, provides all of our employees and certain operational and administrative services to the partnership.

The following information summarizes the businesses acquired in connection with the DEP I and DEP II drop down transactions.

DEP I Drop Down

Effective February 1, 2007, EPO contributed a 66% controlling equity interest in each of the DEP I Midstream Businesses to us in a drop down transaction. EPO retained the remaining 34% noncontrolling equity interest in each of these businesses.

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following is a brief description of the assets and operations of the DEP I Midstream Businesses:

Mont Belvieu Caverns owns 34 underground salt dome storage caverns located in Mont Belvieu, Texas, having an NGL and related product storage capacity of approximately 100 million barrels (“MMBbls”), and a brine system with approximately 20 MMBbls of above ground storage capacity and two brine production wells.

Acadian Gas is engaged in the gathering, transportation, storage and marketing of natural gas in south Louisiana, utilizing over 1,000 miles of pipelines having an aggregate throughput capacity of 1.0 billion cubic feet per day (“Bcf/d”). Acadian Gas also owns a 49.51% equity interest in Evangeline, which owns a 27-mile natural gas pipeline located in southeast Louisiana.

§	Lou-Tex Propylene owns a 263-mile pipeline used to transport chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas.

§	Sabine Propylene owns a 21-mile pipeline used to transport polymer-grade propylene from Port Arthur, Texas to a pipeline interconnect in Cameron Parish, Louisiana.

§	South Texas NGL owns a 297-mile pipeline system used to transport NGLs from our Shoup and Armstrong NGL fractionation facilities in south Texas to Mont Belvieu, Texas.

DEP II Drop Down

Enterprise GC operates and owns: (i) two NGL fractionation facilities, the Shoup and Armstrong facilities, located in south Texas; (ii) a 1,020-mile NGL pipeline system located in south Texas; and (iii) 1,112 miles of natural gas gathering pipelines located in south and west Texas. Enterprise GC’s natural gas gathering pipelines include: (i) the 258-mile Big Thicket Gathering System located in southeast Texas; (ii) the 660-mile Waha system located in the Permian Basin of west Texas; and (iii) the 190-mile TPC Offshore gathering system located in south Texas.

§	Enterprise Intrastate operates and owns an undivided 50% interest in the assets comprising the 641-mile Channel natural gas pipeline, which extends from the Agua Dulce Hub in south Texas to Sabine, Texas located on the Texas/Louisiana border.

Enterprise Texas owns the 6,560-mile Enterprise Texas natural gas pipeline system, which includes the Sherman Extension, and leases the Wilson natural gas storage facility. The Enterprise Texas system, along with the Waha, TPC Offshore and Channel pipeline systems, comprise our Texas Intrastate System.

See “Noncontrolling Interest – DEP II Midstream Businesses – Parent” under Note 11 and “Significant Relationships and Agreements with EPO – Company and Limited Partnership Agreements – DEP II Midstream Businesses” under Note 13 for additional information.

Generally, to the extent that the DEP II Midstream Businesses collectively generate cash sufficient to pay distributions to EPO and us, such cash will be distributed first to us (based on an initial defined investment of $730.0 million) and then to EPO in amounts sufficient to generate an aggregate initial annualized return on their respective investments of 11.85%. Effective January 1, 2010, the annualized return increased by 2.0% to 12.087%. Distributions in excess of these amounts will be distributed 98% to EPO and 2% to us. Income and loss of the DEP II Midstream Businesses are first allocated to EPO and us

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based on each entity’s percentage interest of 77.4% and 22.6%, respectively, and then in a manner that in part follows the cash distributions.

See Note 11 for detailed information regarding EPO’s noncontrolling interest in the DEP I and DEP II Midstream Businesses.

Basis of Financial Statement Presentation

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 generally accepted accounting principles (“GAAP”) in the United States have been condensed or omitted pursuant to the rules and regulations of the U.S. S ecurities and Exchange Commission (“SEC”). These Unaudited Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with our annual report on Form 10-K for the year ended December 31, 2009 (“2009 Form 10-K”) (Commission File No. 1-33266).

Note 2. General Accounting Matters

Estimates

Preparing our financial statements in conformity with GAAP requires management to make estimates and assumptions that affect: (i) reported amounts of assets and liabilities; (ii) disclosure of contingent assets and liabilities at the date of the financial statements; and (iii) the reported amounts of revenues and expenses during a given period. 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.

Fair Value Information

Cash and cash equivalents, 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 carrying amounts of our variable-rate debt obligations reasonably approximate their fair values due to their variable interest rates. See Note 4 for additional 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	$	21.7	$	21.7	$	3.9	$	3.9
Accounts receivable		105.4		105.4		142.0		142.0
Financial liabilities:
Accounts payable and accrued expenses	$	137.2	$	137.2	$	145.5	$	145.5
Other current liabilities (excluding derivative instruments)		10.9		10.9		13.3		13.3
Variable-rate revolving credit facility		175.0		175.0		175.0		175.0
Variable-rate term loan		282.3		282.3		282.3		282.3

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Note 3. Equity-based Awards

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,
	2010		2009
Restricted unit awards (1)	$	0.6	$	0.3
Unit option awards (1)		0.1		*
Profits interests awards (1)		0.1		0.1
Total compensation expense	$	0.8	$	0.4

(1) Accounted for as equity-classified awards. The fair value of an equity-classified award is amortized to earnings on a straight-line basis over the requisite service or vesting period. * Indicates that amounts are negligible and less than $0.1 million.

At March 31, 2010, the Duncan Energy Partners L.P. Long-Term Incentive Plan (“2010 Plan”) was our only active long-term incentive plan. However, we are charged certain amounts associated with EPCO’s other long-term incentive plans and other long-term incentive arrangements. The expense we recognized in connection with equity-based awards includes amounts primarily associated with the following plans and arrangements of EPCO: (i) the Enterprise Products 1998 Long-Term Incentive Plan; (ii) the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan; and (iii) profits interests awards associated with the Employee Partnerships.

An allocated portion of the non-cash amortization expense of these awards is charged to us under the administrative services agreement (“ASA”) with EPCO. We recognize a non-cash expense for our allocated share of the amortized grant date fair value of such awards, with an offsetting amount recorded in equity. See Note 13 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 other expenses associated with such awards. 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 for the three months ended March 31, 2010 and 2009 were $25 thousand and $27 thousand, respectively.

DEP Unit Purchase Plan (“EUPP”) and the 2010 Plan

On December 10, 2009, the board of directors of our general partner (the “Board”) unanimously approved a resolution adopting both the 2010 Plan and the EUPP. The 2010 Plan provides for awards of options to purchase common units, restricted common units, unit appreciation rights, phantom units and distribution equivalent rights to employees, directors or consultants providing services to us and our subsidiaries. The EUPP provides eligible employees the opportunity to purchase common units at a discount through withholdings from eligible compensation. On December 30, 2009, the action taken by the Board regarding the plans was approved by written consent of a subsidiary of EPO, which held of record approximately 58.6% of our outstanding common units as of that date. Because EPO’s subsidiary held a majority of our common units as of December 30, 2009, no other votes were necessary to adopt the plans. In February 2010, we filed a registration statement with the SEC authorizing the issuance of up to an aggregate 500,000 common units in connection with the 2010 Plan and an aggregate 500,000 common units in connection with the EUPP. The plans became effective on February 11, 2010. After giving effect to awards granted under the 2010 Plan through March 31, 2010, we may issue a total of 493,652 additional common units under the 2010 Plan. As of March 31, 2010, we had not issued any common units under the EUPP.

Summary of Long-Term Incentive Awards

The following information is being provided regarding our 2010 Plan and EPCO’s long-term incentive awards under which we have or may receive an allocation of expense. EPCO has certain plans under which liability-classified awards may be issued. As of March 31, 2010, we have not been allocated

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any costs of liability-classified awards and therefore have not included any discussion of such plans in these disclosures. EPCO may create additional long-term incentive plans in the future that may result in us receiving an allocation of expense based on services rendered to us by the recipients of such awards. Unless noted otherwise, the following information is presented on a gross basis (to EPCO and affiliates) with respect to the type of award granted. To the extent applicable, we have noted our estimated share of unrecognized compensation costs of such awards and the weighted-average period of time over which we expect to recognize such expense.

Restricted Unit Awards

Restricted unit awards allow recipients to acquire common units of Enterprise Products Partners under the EPCO long-term incentive plans and to acquire our common units under our 2010 Plan (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 and 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 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 three months ended March 31, 2010:

				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 restricted unit awards issued during 2010 was $41.6 million based on grant date market prices of Enterprise Products Partners’ 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 restricted unit awards issued during 2010 was $0.2 million based on grant date market prices of our common units of $25.26 per unit.

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 $7.3 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.2 years.

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Unit Option Awards

Our 2010 Plan and the long-term incentive plans of EPCO provide for the issuance of non-qualified incentive options to purchase a fixed number of our common units or the common units of Enterprise Products Partners, respectively. 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 these plans have a vesting period of four years and remain exercisable for five to ten years, as applicable, from the date of grant. There were no options granted under our 2010 Plan during the three months ended March 31, 2010.

The following table presents unit option activity for the three months ended March 31, 2010:

						Weighted-
				Weighted-		Average
				Average		Remaining		Aggregate
	Number of			Strike Price		Contractual		Intrinsic
	Units			(dollars/unit)		Term (in years)		Value (1)
EPCO Plans outstanding unit options
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 the first quarter of 2010 was $2.2 million based on the following assumptions: (i) a grant date market price of Enterprise Products Partners’ 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 Enterprise Products Partners’ common units of 6.9%; and (v) expected unit price volatility on Enterprise Products Partners’ common units of 23.2%. An estimated forfeiture rate of 17% was applied to awards granted during 2010.

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 $0.7 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.9 years.

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 privately held 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 in which our named executive officers participate 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 $3.9 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

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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.

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 by, among other thi ngs, 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 to manage our exposure to changes in the interest rates of our $300.0 million unsecured revolving credit facility (the “Revolving Credit Facility”). 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 issued by the Financial Accounting Standards Board (“FASB”):

	Number and Type of	Notional		Length of	Rate	Accounting
Hedged Transaction	Derivative Employed	Amount		Hedge	Swap	Treatment
Revolving Credit Facility:
Variable-interest rate borrowings	3 floating-to-fixed swaps		$ 175.0	9/07 to 9/10	0.3% to 4.6%	Cash flow hedge

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/decrease to interest expense. This combined activity resulted in an increase of interest expense of $1.9 million and $1.4 million, respectively, for the three months ended March 31, 2010 and 2009.

For information regarding consolidated fair value amounts and gains and losses on interest rate derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note 4.

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Commodity Derivative Instruments

The price of natural gas is 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 and futures contracts. The following table summarizes the absolute notional amount of our commodity derivative instruments outstanding at March 31, 2010:

	Volume (1)			Accounting
Derivative Purpose	Current	Long-Term		Treatment

Derivatives not designated as hedging instruments:
Acadian Gas:
Natural gas risk management activities (2)	1.4 Bcf		n/a	Mark-to-market

(1) Volume for derivatives not designated as hedging instruments reflect the absolute value of derivative notional volumes. (2) Reflects the use of derivative instruments to manage risks associated with natural gas transportation, processing and storage assets.

At March 31, 2010, none of our derivative instruments met hedge accounting requirements; therefore, they are accounted for as economic hedges using mark-to-market accounting.

Our hedging strategy is intended to reduce the variability of future earnings and cash flows resulting from changes in natural gas prices. We enter into a limited number of forward transactions that effectively fix the price of natural gas for certain customers and hedge the resulting exposure with derivative instruments. We may also enter into a small number of cash flow hedges in connection with our purchases of natural gas held-for-sale to third parties.

Our general partner monitors the hedging strategies associated with these physical and financial risks, approves specific activities subject to the policy (including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and ensuring compliance with the policy.

For information regarding consolidated fair value amounts and gains and losses on commodity derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note 4.

Credit-Risk Related Contingent Features in Derivative Instruments

Commodity derivative instruments can include provisions related to minimum credit ratings and/or adequate assurance clauses. At March 31, 2010, we did not have any derivative instruments in a net liability position. 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

Other current assets

Other current liabilities

3.8

Other current liabilities

5.5

Derivatives not designated as hedging instruments:

Commodity derivatives

Other current assets

0.3

Other current assets

0.1

Other current liabilities

0.3

Other current liabilities

0.1

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

	Change in Value
Derivatives in	Recognized in OCI on
Cash Flow	Derivative
Hedging Relationships	(Effective Portion)
	For the Three Months
	Ended March 31,
	2010	2009
Interest rate	$ (0.2)	$ 0.7

		Amount of Loss
Derivatives in	Location of Loss	Reclassified from AOCI
Cash Flow	Reclassified from AOCI	to Income
Hedging Relationships	into Income (Effective Portion)	(Effective Portion)
		For the Three Months
		Ended March 31,
		2010	2009
Interest rate	Interest expense	$ (1.9)	$ (1.4)

	Location of Gain Recognized	Amount of Gain
Derivatives in Cash Flow	in Income on Ineffective	Recognized in Income on
Hedging Relationships	Portion of Derivative	Ineffective Portion of Derivative
		For the Three Months
		Ended March 31,
		2010		2009
Interest rate	Interest expense		$ *		$ *

* Indicates that amounts are negligible and less than $0.1 million.

Over the next twelve months, we expect to reclassify $3.7 million of accumulated other comprehensive income (loss) (“AOCI”) attributable to interest rate derivative instruments to earnings as an increase to interest expense, based on the current level of interest rates.

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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:

		Gain/(Loss) Recognized in
Derivatives Not Designated		Income on Derivative
as Hedging Instruments	Location	Amount
		For the Three Months
		Ended March 31,
		2010		2009
Commodity derivatives	Revenue	$	*	$	(0.1	)

* Indicates that amounts are negligible and less than $0.1 million.

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 financial 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 t han quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values primarily consist of interest rate swaps. Our interest rate derivatives are valued by using appropriate financial models with the implied forward London Interbank Offered Rate (“LIBOR”) yield curve for the same period as the future interest swap settlements. Our commodity financial instruments can consist of commodity financial instruments such as forwards, swaps and other instruments transacted on an exchange or over the counter. The fair values of these derivatives are based on observable price quotes for similar products and locations.

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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 inpu ts are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value. Level 3 generally includes specialized or unique financial instruments that are tailored to meet a customer’s specific needs. At March 31, 2010, we did not have any Level 3 financial assets or liabilities.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured on a recurring basis at the dates indicated. 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 transfers between levels during the three months ended March 31, 2010.

	At March 31, 2010
	Level 1		Level 2		Total
Financial assets:
Commodity derivative instruments	$	--	$	0.3	$	0.3

Financial liabilities:
Commodity derivative instruments	$	0.3	$	--	$	0.3
Interest rate derivative instruments		--		3.8		3.8
Total derivative liabilities	$	0.3	$	3.8	$	4.1

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 Sheets 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 Natural Gas Pipelines and Services segment assets when we recorded a non-cash asset impairment charge of $1.1 million due to the cancellation of a compressor station project on our Texas Intrastate System. We also adjusted the carrying value of certain pipeline segments of the TPC Offshore gathering system to fair value during the first quarter of 2010. Anticipated abandonment activities related to a portion of this system led to a non-cash impairment charge of $0.4 million. These impairment charges are reflected in operating costs and expenses for 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)	$	5.3	$	4.4
Forward sales inventory (2)		3.8		6.1
Total inventory	$	9.1	$	10.5

(1) Working inventory is comprised of inventories of natural gas that are used in the provision for services. (2) Forward sales inventory consists of identified natural gas volumes dedicated to the fulfillment of forward sales contracts.

Working inventory includes natural gas volumes held for operational system balancing on the Texas Intrastate System. These natural gas inventories fluctuate as a result of imbalances with shippers and are valued based on a twelve-month rolling average of posted industry prices. When such volumes are delivered out of inventory, the average cost of these volumes is charged against our accrued gas imbalance payables. At March 31, 2010 and December 31, 2009, the value of natural gas held in inventory for operational system balancing was $2.3 million and $2.8 million, respectively.

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

	For the Three Months
	Ended March 31,
	2010		2009
Cost of sales (1)	$	162.8	$	139.1
LCM adjustments		0.1		*
(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 natural gas prices. * We recognized nominal LCM adjustments.

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		March 31,		December 31,
	Life in Years		2010		2009
Plant and pipeline facilities (1)		3-45 (4)	$	4,770.6	$	4,767.0
Underground storage wells and related assets (2)		5-35 (5)		437.4		432.5
Transportation equipment (3)		3-10		11.5		11.3
Land				27.8		27.8
Construction in progress				322.4		233.6
Total				5,569.7		5,472.2
Less: accumulated depreciation				967.9		922.6
Property, plant and equipment, net			$	4,601.8	$	4,549.6

(1) Includes natural gas, NGL and petrochemical pipelines, NGL fractionation plants, office furniture and equipment, buildings and related assets. (2) Underground storage facilities include underground product storage caverns and related assets such as pipes and compressors. (3) Transportation equipment includes vehicles and similar assets used in our operations. (4) In general, the estimated useful life of major components of this category is: pipelines, 18-45 years (with some equipment at 5 years); office furniture and equipment, 3-20 years; buildings 20-35 years; and fractionation facilities, 28 years. (5) In general, the estimated useful life of underground storage facilities is 20-35 years (with some components at 5 years).

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Depreciation expense for the three months ended March 31, 2010 and 2009 was $45.1 million and $42.3 million, respectively. Depreciation expense is a component of “Costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations.

Asset Retirement Obligations

We have recorded conditional asset retirement obligations (“AROs”) in connection with certain right-of-way agreements, leases and regulatory requirements. Conditional AROs are obligations in which the timing and/or amount of settlement are uncertain. None of our assets are legally restricted for purposes of settling AROs.

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

ARO liability balance, December 31, 2009	$	10.4
Accretion expense		0.2
Revisions in estimated cash flows		0.8
ARO liability balance, March 31, 2010	$	11.4

Net property, plant and equipment at March 31, 2010 and December 31, 2009 includes $5.9 million and $5.5 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 years presented:

2010 (1)		2011		2012		2013		2014
$	0.5	$	0.6	$	0.6	$	0.7	$	0.8
(1) Amount represents the estimate for the remainder of 2010.

Note 7. Investment in Evangeline

Acadian Gas, through a wholly owned subsidiary, owns a collective 49.51% equity interest in Evangeline, which consists of a 45% direct ownership interest in EGP and a 45.05% direct interest in EGC. EGC also owns a 10% direct interest in EGP. Third parties own the remaining equity interests in EGP and EGC. Acadian Gas does not have a controlling interest in the Evangeline entities, but does exercise significant influence on Evangeline’s operating policies. Acadian Gas accounts for its financial investment in Evangeline using the equity method. Our investment in Evangeline is classified within our Natural Gas Pipelines & Services business segment.

Evangeline owns a 27-mile natural gas pipeline system extending from Taft, Louisiana to Westwego, Louisiana that connects three electric generation stations owned by Entergy Louisiana (“Entergy”). Evangeline’s most significant contract is a 21-year natural gas sales agreement with Entergy. Evangeline is obligated to make available for sale and deliver to Entergy certain specified minimum contract quantities of natural gas on an hourly, daily, monthly and annual basis. The sales contract provides for minimum annual quantities of 36.8 billion British thermal units (“BBtus”), until the contract expires on January 1, 2013.

In connection with the Entergy sales contract, Evangeline has entered into a natural gas purchase contract with a subsidiary of Acadian Gas that contains annual purchase provisions. The pricing terms of the sales agreement with Entergy and Evangeline’s purchase agreement with Acadian Gas are based on a weighted-average cost of natural gas each month (subject to certain market index price ceilings and incentive margins) plus a predetermined margin, creating an essentially fixed monthly net sales margin.

In 1991, Evangeline entered into an agreement with Entergy whereby Entergy was granted the right to acquire Evangeline’s pipeline system for a nominal price, plus the assumption of all of Evangeline’s obligations under the natural gas sales contract. The option period begins the earlier of July 1, 2010 or upon the payment in full of Evangeline’s Series B senior notes and terminates on

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December 31, 2012. While Entergy has expressed an interest in exercising this purchase option, we cannot ascertain when, or if, it will be exercised. This uncertainty results from various factors, including decisions by Entergy’s management and regulatory approvals that may be required for Entergy to acquire Evangeline’s assets.

We have received no distributions from Evangeline since we acquired our interest in Evangeline in April 2001. The trust indenture governing Evangeline’s senior notes places restrictions on the payment of distributions to Evangeline’s partners. Evangeline is permitted to pay distributions if, after giving effect to the distribution, no default or event of default has occurred and is continuing, funds held in its restricted cash account equals or exceeds its debt service requirement and the holders of the senior notes are cash secured. Our share of undistributed earnings of Evangeline totaled approximately $3.9 million at March 31, 2010. See Note 9 for a description of Evangeline’s outstanding debt obligations.

The following table presents unaudited summarized income statement data of Evangeline for the periods indicated (on a 100% basis):

	For the Three Months
	Ended March 31,
	2010		2009
INCOME STATEMENT DATA:
Revenues	$	39.7	$	36.6
Operating income		0.6		0.8
Net income		0.5		0.4

Note 8. Intangible Assets and Goodwill

The following table summarizes our intangible asset balances by segment at the dates indicated:

	At March 31, 2010							At December 31, 2009
	Gross		Accum.			Carrying		Gross		Accum.			Carrying
	Value		Amort.			Value		Value		Amort.			Value
NGL Pipelines & Services:
Customer relationship intangibles	$	24.6	$	(9.4	)	$	15.2	$	24.6	$	(8.9	)	$	15.7
Contract-based intangibles		41.8		(26.0	)		15.8		40.8		(24.7	)		16.1
Natural Gas Pipelines & Services:
Customer relationship intangibles		21.0		(9.3	)		11.7		21.0		(9.0	)		12.0
Total all segments	$	87.4	$	(44.7	)	$	42.7	$	86.4	$	(42.6	)	$	43.8

The values assigned to our customer relationship intangible assets are being amortized to earnings using methods that closely resemble the pattern in which the economic benefits of the underlying natural resource basins from which the customers produce are estimated to be consumed or otherwise used (based on proved reserves). Our estimate of the useful life of each natural resource basin is based on a number of factors, including third-party reserve estimates, our view of the economic viability of production and exploration activities and other industry factors.

The following table presents amortization expense attributable to our intangible assets (by segment) for the periods indicated:

	For the Three Months
	Ended March 31,
	2010		2009
NGL Pipelines & Services	$	1.8	$	1.8
Natural Gas Pipelines & Services		0.3		0.4
Total all segments	$	2.1	$	2.2

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Based on information currently available, the following table presents an estimate of future amortization expense associated with our intangible assets at March 31, 2010:

	For the Year Ended December 31,
	2010 (1)		2011		2012		2013		2014
NGL Pipelines & Services	$	5.0	$	6.5	$	3.0	$	1.7	$	1.5
Natural Gas Pipelines & Services		0.9		1.2		1.1		1.0		0.9
Total segments	$	5.9	$	7.7	$	4.1	$	2.7	$	2.4

(1) Amounts represent the estimate for the remainder of 2010.

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. Goodwill is not amortized; however, it is subject to annual impairment testing at the beginning of each fiscal year. Our goodwill represents an allocation to the DEP II Midstream Businesses of the goodwill recorded by Enterprise Products Partners in connection with its merger with a third-party partnership in September 2004. The carrying value of our goodwill does not include any accumulated impairment charges. There have been no changes in our goodwill amounts since those reported in our 2009 Form 10-K.

Note 9. Debt Obligations

Our consolidated debt obligations consisted of the following at the dates indicated:

	At March 31,			At December 31,
	2010			2009
Revolving Credit Facility, variable rate, due February 2011	$	175.0		$	175.0
Term Loan Agreement, variable rate, due December 2011 (1)		282.3			282.3
Total principal amount of debt obligations		457.3			457.3
Less: Current maturities of debt (2)		(175.0	)		--
Total long-term debt	$	282.3		$	457.3

(1) Refers to our $300.0 million standby term loan agreement which we entered into in April 2008. The commitments under the Term Loan Agreement were decreased to $282.3 million due to the bankruptcy of one of the lenders and we borrowed the full amount available to fund the cash consideration due to EPO in connection with the DEP II drop down in December 2008. (2) We plan to refinance our Revolving Credit Facility with a new or amended multi-year credit facility.

There have been no changes in the terms of our Revolving Credit Facility and our Term Loan Agreement since those reported in our 2009 Form 10-K.

Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at March 31, 2010.

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 obligations during the three months ended March 31, 2010.

	Range of		Weighted-average
	Interest Rates Paid		Interest Rates Paid
Revolving Credit Facility	0.80% to 0.86%			0.83%
Term Loan Agreement		0.93%		0.93%

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Evangeline Joint Venture Debt Obligation

At March 31, 2010, Evangeline’s debt consisted of $3.2 million of 9.9% fixed rate senior notes due 2010 and a $7.5 million subordinated note payable due 2011. Evangeline was in compliance with its debt covenants at March 31, 2010. There have been no changes in the terms of Evangeline’s debt agreements since those reported in our 2009 Form 10-K. At March 31, 2010 and December 31, 2009, the amount of accrued but unpaid interest on the subordinated note payable was approximately $2.7 and $10.2 million, respectively.

Note 10. Equity and Distributions

Our common units represent limited partner interests, which give holders thereof the right to participate in cash distributions and to exercise the other rights or privileges available to them under our Amended and Restated Agreement of Limited Partnership (as amended from time to time, the “Partnership Agreement”).

In accordance with the Partnership Agreement, capital accounts are maintained for our general partner and our limited partners. The capital account provisions of the Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to GAAP-based equity amounts presented in our consolidated financial statements. Earnings and cash distributions are allocated to holders of our common units in accordance with their respective percentage interests.

Class B Units

In December 2008, we issued 37,333,887 Class B units, which were used along with proceeds borrowed under the Term Loan Agreement to acquire the DEP II Midstream Businesses. In February 2009, the Class B units were converted on a one-to-one basis into common units and received a pro-rated cash distribution. See “– Distributions” within this Note 10 for additional information.

Registration Statements

We have a universal shelf registration statement on file with the SEC that allows us to issue up to an aggregate $1 billion in debt and equity securities for general partnership purposes. After taking into account past issuances made under this registration statement, we can issue approximately $856.4 million of additional securities under this registration statement in the future.

We filed a registration statement with the SEC authorizing the issuance of up to an aggregate 2,000,000 common units in connection with a distribution reinvestment plan (“DRIP”). The DRIP gives unitholders of record and beneficial owners of our common units the ability to increase the number of our common units they own through voluntarily reinvesting their quarterly cash distributions into the purchase of additional common units. Plan participants may purchase our common units at a discount ranging from 0% to 5% (currently set at 5%), which will be set from time to time by us. We issued 10,385 common units under the DRIP during the three months ended March 31, 2010.

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The following table reflects the number of common units issued and the net cash proceeds received from common unit offerings during the three months ended March 31, 2010:

Net Cash Proceeds from Issuance of Common Units

Number of

Contributed

Contributed by

Total

Common Units

by Limited

General

Net Cash

Issued

Partners

Partner

Proceeds

February DRIP

10,385

0.2

* Amount is negligible and less than $0.1 million.

Net cash proceeds received were used for general partnership purposes.

Unit History

The following table details changes in our outstanding common units for the period indicated.

			Restricted
	Common		Common
	Units		Units
Balance, December 31, 2009		57,676,987		--
Common units issued in connection with DRIP		10,385		--
Restricted units issued to independent directors under our 2010 Plan		--		6,348
Conversion of restricted units to common units		6,348		(6,348	)
Balance, March 31, 2010		57,693,720		--

Distributions

Our partnership agreement requires us to distribute all of our available cash (as defined in our Partnership Agreement) to our partners on a quarterly basis. Such distributions are not cumulative. In addition, we do not have a legal obligation to pay distributions at our initial distribution rate or at any other rate. Our general partner has no incentive distribution rights. The following table summarizes the amount, record date and payment date of the quarterly distributions we paid with respect to our common units:

	Cash Distribution History
	Per		Record	Payment
	Unit		Date	Date
2008
1st Quarter		0.4100	April 30, 2008	May 7, 2008
2nd Quarter		0.4200	July 31, 2008	August 7, 2008
3rd Quarter		0.4200	October 31, 2008	November 12, 2008
4th Quarter (1)		0.4275	January 30, 2009	February 9, 2009
2009
1st Quarter		0.4300	April 30, 2009	May 8, 2009
2nd Quarter		0.4350	July 31, 2009	August 7, 2009
3rd Quarter		0.4400	October 30, 2009	November 5, 2009
4th Quarter		0.4450	January 29, 2010	February 5, 2010
2010
1st Quarter		0.4475	April 30, 2010	May 6, 2010
(1) We issued 37.3 million Class B units in connection with the DEP II drop down. The Class B units received a cash distribution of $0.1115 per unit for the distribution that Duncan Energy Partners paid with respect to the fourth quarter of 2008, which represented the regular quarterly distribution pro-rated for the 24-day period from December 8, 2008, the closing date of the DEP II drop down transaction, to December 31, 2008. These units automatically converted on a one-for-one basis to common units on February 1, 2009.

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Accumulated Other Comprehensive Income (Loss)

Our AOCI balance, which relates to interest rate derivative instruments, reflects losses of $3.7 million and $5.4 million at March 31, 2010 and December 31, 2009, respectively.

Note 11. Noncontrolling Interest

We account for EPO’s retained ownership interests in each of the DEP I and DEP II Midstream Businesses as a noncontrolling interest. Under this method of presentation, all revenues and expenses of these businesses are included in consolidated net income and EPO’s share (as Parent) of the income of these businesses is deducted from consolidated net income to derive net income attributable to Duncan Energy Partners L.P. EPO’s share of the net assets of the DEP I and DEP II Midstream Businesses is presented as noncontrolling interest in subsidiaries (a component of equity) on our Unaudited Condensed Consolidated Balance Sheets.

DEP I Midstream Businesses – Parent

The DEP I Midstream Businesses allocate their net income (or loss) to us and EPO based on our respective sharing ratios, which are currently 66% to us and 34% to EPO. In deriving the net income (or loss) of Mont Belvieu Caverns to be allocated between us and EPO, certain special allocations are required as follows:

§	EPO is allocated all operational measurement gains and losses; and

§	EPO is allocated 100% of the depreciation expense related to capital projects that it has fully funded.

Distributions paid to us and EPO by the DEP I Midstream Businesses are in accordance with each owner’s respective sharing ratio. In general, contributions made by us and EPO to the DEP I Midstream Businesses are in accordance with the previously noted sharing ratios. However, special funding arrangements exist under the terms of an Omnibus Agreement and the limited liability company agreement of Mont Belvieu Caverns (the “Caverns LLC Agreement”). See Note 13 for additional information regarding these related party agreements.

In accordance with the Omnibus Agreement, EPO agreed to fund all of the capital expenditures incurred by South Texas NGL and Mont Belvieu Caverns with respect to certain expansion projects that were underway at the time of our initial public offering in February 2007. These projects were completed in 2008 and there were no contributions related to the Omnibus Agreement for the three months ended March 31, 2010. EPO made aggregate cash contributions to South Texas NGL and Mont Belvieu Caverns of $1.4 million in connection with these capital projects during the three months ended March 31, 2009. The majority of these contributions related to funding Phase II expansion costs of the South Texas NGL pipeline. EPO has not received an increased allocation of in come or cash distributions as a result of these contributions to South Texas NGL and Mont Belvieu Caverns.

EPO made cash contributions of $10.0 million and $9.4 million under the Caverns LLC Agreement during the three months ended March 31, 2010 and 2009, respectively, to fund 100% of certain storage-related projects sponsored by EPO’s NGL marketing activities. We elected to not participate in such projects. Except for depreciation expense adjustments as noted, EPO is not expected to receive an increased allocation of earnings or cash flows as a result of these contributions to Mont Belvieu Caverns. Additional contributions of approximately $23.5 million are expected from EPO to fund such projects for the remainder of 2010. The constructed assets will be the property of Mont Belvieu Caverns.

In accordance with the Caverns LLC Agreement, EPO is required each period to contribute cash to Mont Belvieu Caverns for net operational measurement losses and is entitled to receive distributions from Mont Belvieu Caverns for net operational measurement gains. We continue to record operational

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measurement gains and losses associated with our Mont Belvieu storage complex. Such amounts are included in operating costs and expenses and gross operating margin. Gross operating margin is a non-GAAP financial measure, which is discussed in Note 12. These operational measurement gains and losses do not impact net income attributable to Duncan Energy Partners since they are allocated to EPO. We have not established a reserve for operational measurement losses on our balance sheet.

The following table presents our calculation of “Net income (loss) attributable to noncontrolling interest – DEP I Midstream Businesses – Parent” for the periods indicated:

	For the Three Months
	Ended March 31,
	2010			2009

Total net income of DEP I Midstream Businesses, prior to special allocations	$	15.6		$	12.8
Multiplied by Parent 34% interest in net income		x 34	%		x 34	%
Parent 34% interest in net income, prior to special allocations		5.3			4.4
Add (deduct) operational measurement gain (loss) allocated to Parent		0.9			(1.3	)
Less depreciation expense related to fully funded projects allocated to Parent		(1.5	)		(1.5	)
Net income attributable to noncontrolling interest – DEP I Midstream Businesses – Parent	$	4.7		$	1.6

The following table provides a reconciliation of the amount presented as “Noncontrolling interest in subsidiaries – DEP I Midstream Businesses – Parent,” on our Unaudited Condensed Consolidated Balance Sheets at March 31, 2010:

December 31, 2009 balance	$	487.3
Net income attributable to noncontrolling interest – DEP I Midstream Businesses – Parent		4.7
Contributions made by EPO to Mont Belvieu Caverns in connection with the Caverns LLC Agreement		10.0
Other contributions made by EPO to the DEP I Midstream Businesses		6.1
Cash distributions paid to EPO by the DEP I Midstream Businesses		(10.3	)
March 31, 2010 balance	$	497.8

For additional information regarding our agreements with EPO in connection with the DEP I dropdown transaction, see “Significant Relationships and Agreements with EPO – Omnibus Agreement” and “Significant Relationships and Agreements with EPO – Mont Belvieu Caverns’ LLC Agreement” under Note 13.

DEP II Midstream Businesses – Parent

At the time of the DEP II drop down transaction, the total estimated fair value of the DEP II Midstream Businesses was approximately $3.2 billion. The total value of the consideration we provided to EPO in the DEP II drop down transaction was $730.0 million and represented, at the time of the transaction, the acquisition of controlling voting interests along with an initial 22.6% of the equity of the DEP II Midstream Businesses. EPO retained the remaining 77.4% of equity. The 22.6% and 77.4% amounts are referred to as the “Percentage Interests,” and represent each owner’s initial relative economic investment in the DEP II Midstream Businesses at December 8, 2008.

Generally, to the extent that the DEP II Midstream Businesses collectively generate cash sufficient to pay distributions to EPO and us, such cash will be distributed first to us (the “Tier I distribution,” based on our $730.0 million aggregate investment) and then to EPO (the “Tier II distribution”), in amounts sufficient to generate an annualized return to both owners based on their respective investments. Distributions in excess of these amounts (the “Tier III distributions”) will be distributed 98% to EPO and 2% to us.

The initial annualized return rate for 2009 was 11.85%, and was determined by EPO and us based on our estimated weighted-average cost of capital at December 8, 2008, plus 1.0%. The annualized return rate increases by 2.0% on January 1 of each year. As a result, the annualized return rate for 2010 will be 12.087%. If we participate in an expansion capital project involving the DEP II Midstream Businesses, we

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may request an incremental adjustment to the then-applicable annualized return rate to reflect our weighted-average cost of capital associated with such contribution.

The annualized return rate is applied to each party’s aggregate investment (or “Distribution Base”) in the DEP II Midstream Businesses. To the extent that we and/or EPO make capital contributions to fund expansion capital projects involving the DEP II Midstream Businesses, the Distribution Base of the contributing member will be increased by that member’s capital contribution at the time such contribution is made. At December 8, 2008 and March 31, 2010, our Distribution Base was $730.0 million. EPO’s Distribution Base was $452.1 million and $880.6 million at December 8, 2008 and March 31, 2010, respectively. The increase in EPO’s Distribution Base is the result of its funding100% of the expansion capital proj ects of the DEP II Midstream Businesses since December 8, 2008. We have not yet participated in the expansion capital project spending of the DEP II Midstream Businesses, although we may elect to invest in existing or future expansion projects at a later date.

Net income (or loss) of the DEP II Midstream Businesses is first allocated to us and EPO based on each entity’s Percentage Interest of 22.6% and 77.4%, respectively, and then in a manner that in part follows the cash distributions paid by (or contributions made to) each DEP II Midstream Business. Under our income sharing arrangement with EPO, we are allocated additional income (in excess of our Percentage Interest) to the extent that the cash distributions we receive (or contributions made) exceed the amount we would have been entitled to receive (or required to fund) based solely on our Percentage Interest. This additional earnings allocation to us reduces the amount of income allocated to EPO by an equal amount and may result in EPO being allocated a loss wh en we are allocated income. It is our expectation that EPO will be allocated a loss by the DEP II Midstream Businesses until such time as expansion capital projects such as the Sherman Extension and Trinity River Lateral realize their income and cash flow potential. Our participation in the expected future increase in cash flow from such projects is limited (beyond our annualized return amount) to 2% of such upside, with EPO receiving 98% of the benefit.

The following table presents the allocation of net income of the DEP II Midstream Businesses for the three months ended March 31, 2010:

				EPO			DEP
Total net income of DEP II Midstream Businesses				$	4.4		$	4.4
Multiplied by each owner's Percentage Interest					77.4	%		22.6	%
Base earnings allocation to each owner					3.4			1.0
Additional earnings allocation to Duncan Energy Partners:
Total distributions paid by the DEP II Midstream Businesses with respect to period	$	37.5
Multiplied by 22.6% Percentage Interest of Duncan Energy Partners		22.6	%
Duncan Energy Partners’ Percentage Interest in the total cash distributions paid by the DEP II Midstream Businesses with respect to period		8.5
Less actual distributions paid to Duncan Energy Partners with respect to period based on annualized return for period		22.1			(13.6	)		13.6
Net loss attributable to EPO as noncontrolling interest				$	(10.2	)
Net income attributable to Duncan Energy Partners							$	14.6

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The following table presents the allocation of net income of the DEP II Midstream Businesses for the three months ended March 31, 2009:

				EPO			DEP
Total net income of DEP II Midstream Businesses				$	4.9		$	4.9
Multiplied by each owner's Percentage Interest					77.4	%		22.6	%
Base earnings allocation to each owner					3.8			1.1
Additional earnings allocation to Duncan Energy Partners:
Total distributions paid by the DEP II Midstream Businesses with respect to period	$	32.6
Multiplied by 22.6% Percentage Interest of Duncan Energy Partners		22.6	%
Duncan Energy Partners’ Percentage Interest in the total cash distributions paid by the DEP II Midstream Businesses with respect to period		7.3
Less actual distributions paid to Duncan Energy Partners with respect to period based on annualized return for period		21.6			(14.3	)		14.3
Net loss attributable to EPO as noncontrolling interest				$	(10.5	)
Net income attributable to Duncan Energy Partners							$	15.4

We and EPO received $22.1 million and $15.4 million, respectively, in cash distributions from the DEP II Midstream Businesses for the three months ended March 31, 2010. For the three months ended March 31, 2009, we and EPO received $21.6 million and $11.0 million, respectively, in cash distributions from the DEP II Midstream Businesses. The $22.1 million received by us with respect to the first quarter of 2010 represents approximately one-fourth of the annualized return rate for 2010 of 12.087% multiplied by our Distribution Base of $730.0 million. As a result, we received our expected Tier I distributions for the period. Based on EPO’s Distribution Base for the first quarter of 2010, it was entitled to $26.6 million of Tier II distributi ons, of which it received $15.4 million. No Tier III distributions were paid by the DEP II Midstream Businesses with respect to 2010.

The following table provides a reconciliation of the amount presented as “Noncontrolling interest in subsidiaries – DEP II Midstream Businesses – Parent,” on our Unaudited Condensed Consolidated Balance Sheets at March 31, 2010:

December 31, 2009 balance	$	2,888.2
Allocated loss from DEP II Midstream Businesses to EPO as Parent		(10.2	)
Contributions by EPO in connection with expansion cash calls		62.7
Distributions to noncontrolling interest of subsidiary operating cash flows		(16.9	)
Other general contributions from noncontrolling interest, net		1.6
March 31, 2010 balance	$	2,925.4

For additional information regarding our agreements with EPO in connection with the DEP II dropdown transaction, see “Significant Relationships and Agreements with EPO – Company and Limited Partnership Agreements – DEP II Midstream Businesses” under Note 13.

Note 12. Business Segments

We have three reportable business segments: (i) Natural Gas Pipelines & Services; (ii) NGL Pipelines & Services; and (iii) Petrochemical Services. Our business 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 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 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 c onsidered an alternative to GAAP operating income.

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We define total segment gross operating margin as operating income before: (i) depreciation, amortization and accretion expense; (ii) non-cash consolidated asset impairment charges; (iii) gains and losses from asset sales and related transactions and (iv) 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 any intersegment and intrasegment transactions. In accordance with GAAP, intercompany accounts and transactions are eliminated in consolidation. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes , extraordinary charges and the cumulative effect of changes in accounting principles. Gross operating margin is presented on a 100% basis before the allocation of earnings to noncontrolling interests.

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

		For the Three Months
		Ended March 31,
		2010			2009
Revenues		$	290.6		$	256.8
Less:	Operating costs and expenses		(267.2	)		(239.4	)
Add:	Equity in income of Evangeline		0.2			0.2
	Depreciation, amortization and accretion in operating costs and expenses (1)		47.6			44.6
	Non-cash impairment charge		1.5			--
Less:	Gain from asset sales and related transactions in operating costs and expenses		(0.9	)		(0.1	)
Total segment gross operating margin		$	71.8		$	62.1

(1) Amount is a component of “Depreciation, amortization and accretion” as presented on our Unaudited Condensed Statements of Consolidated Cash Flows.

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

	For the Three Months
	Ended March 31,
	2010			2009
Total segment gross operating margin	$	71.8		$	62.1
Adjustments to reconcile total segment gross operating margin to operating income:
Depreciation, amortization and accretion in operating costs and expenses		(47.6	)		(44.6	)
Non-cash impairment charge		(1.5	)		--
Gain from asset sales and related transactions in operating costs and expenses		0.9			0.1
General and administrative costs		(4.9	)		(2.8	)
Operating income		18.7			14.8
Other expense, net		(3.1	)		(3.7	)
Income before income taxes	$	15.6		$	11.1

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Natural Gas		NGL				Adjustments
	Pipelines		Pipelines		Petrochemical		and		Consolidated
	& Services		& Services		Services		Eliminations		Totals
Revenues from third parties:
Three months ended March 31, 2010	$	131.3	$	23.7	$	3.2	$	--	$	158.2
Three months ended March 31, 2009		89.3		20.9		3.4		--		113.6

Revenues from related parties:
Three months ended March 31, 2010		96.6		35.8		--		--		132.4
Three months ended March 31, 2009		113.3		29.9		--		--		143.2

Total revenues:
Three months ended March 31, 2010		227.9		59.5		3.2		--		290.6
Three months ended March 31, 2009		202.6		50.8		3.4		--		256.8

Equity in income of Evangeline:
Three months ended March 31, 2010		0.2		--		--		--		0.2
Three months ended March 31, 2009		0.2		--		--		--		0.2

Gross operating margin:
Three months ended March 31, 2010		42.5		26.9		2.4		--		71.8
Three months ended March 31, 2009		38.8		20.8		2.5		--		62.1

Segment assets:
At March 31, 2010		3,312.0		938.3		82.5		322.4		4,655.2
At December 31, 2009		3,340.8		946.1		83.4		233.6		4,603.9

Property, plant and equipment: (see Note 6)
At March 31, 2010		3,290.1		906.8		82.5		322.4		4,601.8
At December 31, 2009		3,318.8		913.8		83.4		233.6		4,549.6

Investment in Evangeline: (see Note 7)
At March 31, 2010		5.8		--		--		--		5.8
At December 31, 2009		5.6		--		--		--		5.6

Intangible assets: (see Note 8)
At March 31, 2010		11.7		31.0		--		--		42.7
At December 31, 2009		12.0		31.8		--		--		43.8

Goodwill: (see Note 8)
At March 31, 2010		4.4		0.5		--		--		4.9
At December 31, 2009		4.4		0.5		--		--		4.9

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table provides additional information regarding our consolidated revenues (net of eliminations and adjustments) and expenses for the periods noted:

	For the Three Months
	Ended March 31,
	2010			2009
Natural Gas Pipelines & Services:
Sales of natural gas	$	153.2		$	136.9
Natural gas transportation services		70.8			63.2
Natural gas storage services		3.9			2.5
Total		227.9			202.6
NGL Pipelines & Services:
Sales of NGLs		10.0			6.2
Sales of other products		3.7			3.8
NGL and petrochemical storage services		27.1			24.1
NGL fractionation services		7.7			7.4
NGL transportation services		10.5			8.7
Other services		0.5			0.6
Total		59.5			50.8
Petrochemical Services:
Propylene transportation services		3.2			3.4
Total consolidated revenues	$	290.6		$	256.8

Consolidated costs and expenses:
Operating costs and expenses:
Cost of natural gas and NGL sales	$	161.2		$	143.0
Depreciation, amortization and accretion		47.6			44.6
Gain from asset sales and related transactions		(0.9	)		(0.1	)
Other operating expenses		59.3			51.9
General and administrative costs		4.9			2.8
Total consolidated costs and expenses	$	272.1		$	242.2

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

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DUNCAN ENERGY PARTNERS L.P.

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Note 13. Related Party Transactions

The following table summarizes our consolidated revenue and expense transactions with related parties for the periods indicated:

	For the Three Months
	Ended March 31,
	2010			2009
Revenue:
Revenues from EPO:
Sales of natural gas	$	32.6		$	46.5
Natural gas transportation services		25.8			12.7
Natural gas storage services		0.3			0.4
Sales of NGLs		9.8			5.9
NGL and petrochemical storage services		8.9			10.6
NGL fractionation services		7.7			7.1
NGL transportation services		9.4			6.3
Sales of natural gas – Evangeline		37.8			53.6
Natural gas transportation services – Energy Transfer Equity		0.1			0.1
Total related party revenues	$	132.4		$	143.2

Operating costs and expenses:
EPCO administrative services agreement	$	21.3		$	19.8
Expenses with EPO:
Purchases of natural gas		13.6			20.0
Operational measurement losses (gains)		(0.9	)		1.3
Other expenses with EPO		4.5			5.2
Purchases of natural gas – Nautilus		--			1.9
Expenses with Energy Transfer Equity:
Purchases of natural gas (1)		3.8			(3.7	)
Operating cost reimbursements for shared facilities		(1.0	)		(0.6	)
Other expenses with Energy Transfer Equity		0.2			0.3
Other related party expenses, primarily with Evangeline		--			(0.1	)
Total related party operating costs and expenses	$	41.5		$	44.1

General and administrative costs:
EPCO administrative services agreement	$	4.1		$	2.3
Other related party general and administrative		0.1			(0.2	)
Total related party general and administrative costs	$	4.2		$	2.1

(1) Amounts include gas imbalances of $0.2 million and $(4.4) million with Energy Transfer Equity for the three months ended March 31, 2010 and 2009, respectively.

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

	March 31,		December 31,
	2010		2009
Accounts receivable – related parties
EPO and affiliates (1)	$	3.8	$	47.0
Evangeline		11.4		7.3
Energy Transfer Equity and affiliates		0.5		0.2
Total	$	15.7	$	54.5

Accounts payable – related parties
EPO and affiliates	$	20.6	$	5.5
EPCO and affiliates		4.7		8.1
Total	$	25.3	$	13.6

(1) In December 2009, EPO borrowed $45.6 million under a Master Intercompany Loan Agreement, which was subsequently repaid in January 2010. See “Significant Relationships and Agreements with EPO” under this Note 13 for more information.

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

Significant Relationships and Agreements with EPO

Our assets connect to various midstream energy assets of EPO and form integral links within EPO’s value chain. We believe that the operational significance of our assets to EPO, as well as the alignment of our respective economic interests in these assets, will result in a collaborative effort to promote their operational efficiency and maximize value. In addition, we believe our relationship with EPO and EPCO provides us with a distinct benefit in both the operation of our assets and in the identification and execution of potential future acquisitions that are not otherwise taken by Enterprise Products Partners or Enterprise GP Holdings in accordance with our business opportunity agreements. One of our primary business purposes is to support the gr owth objectives of EPO and other affiliates under common control.

At March 31, 2010, EPO owned approximately 58.6% of our limited partner interests and 100% of our general partner. EPO was the sponsor of the DEP I and DEP II dropdown transactions and owns noncontrolling but varying economic interests (as Parent) in the DEP I and DEP II Midstream Businesses. For a description of EPO’s noncontrolling interest in the income and net assets of the DEP I and DEP II Midstream Businesses, see Note 11. EPO may contribute or sell other equity interests or assets to us; however, EPO has no obligation or commitment to make such contributions or sales to us, nor do we have any obligation or commitment to accept such contributions or make such purchases.

EPO has continued involvement with all of our subsidiaries, including the following types of transactions: (i) it utilizes our storage services to support its Mont Belvieu fractionation and other businesses; (ii) it buys from, and sells to, us natural gas in connection with its normal business activities; and (iii) it is currently the sole shipper on an NGL pipeline system located in south Texas that we own.

On December 31, 2009, we and EPO entered into a master intercompany loan agreement with the DEP I and DEP II Midstream Businesses. This agreement will be used from time to time to facilitate cash management efforts in connection with the DEP I and DEP II Midstream Businesses. On December 31, 2009, we borrowed $1.3 million and EPO borrowed $45.6 million under the agreement at a market rate of interest. EPO’s intercompany borrowing is a component of “Accounts receivable – related parties” on our Unaudited Condensed Consolidated Balance Sheets. These amounts were subsequently repaid on January 4, 2010. The interest rate applicable to these short-term borrowings was 0.73%. Amounts borrowed by us and the related interest eliminate in consolidation. There were no loans issued under this agreement during the three months ended March 31, 2010.

Omnibus Agreement. On December 8, 2008, we entered into an amended and restated Omnibus Agreement (the “Omnibus Agreement”) with EPO. The provisions of the Omnibus Agreement have not changed since reported in our 2009 Form 10-K.

EPO indemnified us for certain environmental liabilities, tax liabilities and right-of-way defects associated with the assets it contributed to us in connection with the DEP I and DEP II dropdown transactions. These indemnifications terminated on February 5, 2010. We made no claims to EPO during the three months ended March 31, 2010.

For information regarding the funding by EPO of 100% of certain post-February 5, 2007 capital expenditures of South Texas NGL and Mont Belvieu Caverns, see “Noncontrolling Interest – DEP I Midstream Businesses – Parent” under Note 11.

Mont Belvieu Caverns’ LLC Agreement. The Caverns LLC Agreement states that if Duncan Energy Partners elects to not participate in certain projects of Mont Belvieu Caverns, then EPO is responsible for funding 100% of such projects. To the extent such non-participated projects generate identifiable incremental cash flows for Mont Belvieu Caverns in the future, the earnings and cash flows of

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DUNCAN ENERGY PARTNERS L.P.

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Mont Belvieu Caverns will be adjusted to allocate such incremental amounts to EPO, by special allocation or otherwise. Under the terms of the Caverns LLC Agreement, Duncan Energy Partners may elect to acquire a 66% share of these projects from EPO within 90 days of such projects being placed in service. In November 2008, the Caverns LLC Agreement was amended to provide that EPO would prospectively receive a special allocation of 100% of the depreciation related to projects that it has fully funded.

The Caverns LLC Agreement also requires the allocation to EPO of operational measurement gains and losses. Operational measurement gains and losses are created when product is moved between storage wells and are attributable to pipeline and well connection measurement variances.

For information regarding capital expenditures funded 100% by EPO under the Caverns LLC Agreement as well as operational measurement gains and losses allocated to EPO, see “Noncontrolling Interest – DEP I Midstream Businesses – Parent” under Note 11.

Company and Limited Partnership Agreements – DEP II Midstream Businesses. On December 8, 2008, the DEP II Midstream Businesses amended and restated their governing documents in connection with the DEP II dropdown transaction. Collectively, these amendments include, but are not limited to, (i) the payment of cash distributions in accordance with an overall “waterfall” approach, (ii) the funding of operating cash flow deficits and (iii) the election by either owner to fund cash calls associated with expansion capital projects. See Note 15 under Item 8 of our 2009 Form 10-K for more information on these agreements. See Note 11 for information reg arding EPO’s noncontrolling interest and related matters involving the DEP II Midstream Businesses.

Relationship with EPCO

We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant the ASA. We, Enterprise Products Partners, Enterprise GP Holdings and our respective general partners are parties to the ASA. The significant terms of the ASA are as follows:

EPCO will provide selling, general and administrative services, and management and operating services, as may be necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel as may be necessary to provide such services.

We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including expenses reasonably allocated to us by EPCO). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time in respect of the services provided to us by EPCO.

§	EPCO will allow us to participate as named insureds in its overall insurance program, with the associated premiums and other costs being allocated to us.

Our operating costs and expenses include amounts paid to EPCO for the costs it incurs to operate our facilities, including compensation of employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. Likewise, our general and administrative costs include amounts paid to EPCO for administrative services, including compensation of employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA based on the estimated use of such services by each party (e.g., the allocation of general le gal or accounting salaries based on estimates of time spent on each entity’s business and affairs). The following table presents a breakout of costs and expenses related to the ASA and other EPCO transactions for the periods indicated:

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	For the Three Months
	Ended March 31,
	2010		2009
Operating costs and expenses	$	21.3	$	19.8
General and administrative expenses		4.1		2.3
Total costs and expenses	$	25.4	$	22.1

Since the vast majority of expenses charged to us under the ASA are on an actual basis (i.e. no mark-up or subsidy is charged or received by EPCO), we believe that such expenses are representative of what the amounts would have been on a standalone basis. With respect to allocated costs, we believe that the proportional direct allocation method employed by EPCO is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis.

The ASA also addresses potential conflicts that may arise among Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), and the EPCO Group. The EPCO Group includes EPCO and its other affiliates, but excludes Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners and their respective general partners.

Relationship with Evangeline

Acadian Gas sold $37.8 million and $53.6 million of natural gas to Evangeline, under its natural gas purchase contract with Evangeline, during the three months ended March 31, 2010 and 2009, respectively. The amount of natural gas purchased by Evangeline pursuant to this contract averaged approximately 72.1 BBtus per day (“BBtus/d”) and 70.7 BBtus/d during the three months ended March 31, 2010 and 2009, respectively.

Relationship with Energy Transfer Equity

Enterprise GP Holdings acquired equity method investments in Energy Transfer Equity and its general partner in May 2007. As a result of the common control of Enterprise GP Holdings and us, Energy Transfer Equity became a related party to us. Our revenues from Energy Transfer Equity are attributable to natural gas transportation services. Our related party expenses with Energy Transfer Equity primarily include natural gas purchases for pipeline imbalances, reimbursements of operating costs for shared facilities and the lease of a pipeline in South Texas.

Note 14. Earnings Per Unit

Basic earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the weighted-average number of distribution-bearing common and Class B units (see Note 10) outstanding during a period. On February 1, 2009, the Class B units automatically converted on a one-for-one basis to common units and are paid distributions on the same basis as our other common units. We have no dilutive securities.

The amount of net income or loss allocated to limited partner interests is net of our general partner’s share of such earnings. The following table presents the allocation of net income to DEP GP for the periods indicated:

	For the Three Months
	Ended March 31,
	2010			2009
Net income attributable to Duncan Energy Partners L.P.	$	21.2		$	19.9
Multiplied by DEP GP ownership interest		0.7	%		0.7	%
Net income allocation to DEP GP	$	0.2		$	0.1

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	For the Three Months
	Ended March 31,
	2010		2009
Net income allocation to Duncan Energy Partners	$	21.2	$	19.9
Less: Income allocation to DEP GP		0.2		0.1
Net income allocation to limited partners	$	21.0	$	19.8

Basic and diluted earnings per unit:
Numerator (net income allocation to limited partners)	$	21.0	$	19.8
Denominator (weighted-average units outstanding):
Common units		57.7		44.8
Class B units		--		12.9
Total units		57.7		57.7

Earnings per unit	$	0.37	$	0.34

Note 15. Commitments and Contingencies

Litigation

On occasion, we are named as a defendant in litigation relating to our normal business operations, including regulatory and environmental matters. Although we insure against various business 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 indemnify us against liabilities arising from future legal proceedings as a result of our ordinary business activity. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows.

Redelivery Commitments

We transport and store natural gas and NGLs and store petrochemical products for customers under various contracts. These volumes are (i) accrued as product payables on our Unaudited Condensed Consolidated Balance Sheets, (ii) in transit for delivery to our customers or (iii) held at our storage facilities for redelivery to our customers. We are insured against any physical loss of such volumes due to catastrophic events. Under the terms of our NGL and petrochemical product storage agreements, we are generally required to redeliver volumes to the owner on demand. At March 31, 2010 and December 31, 2009, NGL and petrochemical products aggregating 15.1 million barrels and 20.9 million barrels, respectively, were due to be redelivered to their owners along with 2,984 BBtus and 5,015 BBtus, resp ectively, of natural gas.

Regulatory Matters

Certain recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to climate change. On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program intended to reduce the emissions of greenhouse gases in the United States and would require most sources of greenhouse gas emissions to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The U.S. Senate has also begun work on its own legislation for controlling and reducing emission s of greenhouse gases in the United States. In addition, on December 7, 2009, the U.S. Environmental Protection Agency (“EPA”) announced its finding that emissions of greenhouse gases presented an endangerment to human health and the environment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Although it may take the EPA

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

several years to adopt and impose regulations limiting emissions of greenhouse gases, any such regulation could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases would likely require us to incur increased operating costs, and may have an adverse effect on our business, financial position, demand for our operations, results of operations and cash flows.

Contractual Obligations

Scheduled maturities of long-term debt. With the exception of routine fluctuations in the balance of our Revolving Credit Facility, there have been no significant changes in our scheduled maturities of long-term debt since those reported in our 2009 Form 10-K.

Operating lease obligations. We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Our significant lease agreements involve (i) the lease of underground caverns for the storage of natural gas and NGLs, primarily our lease for the Wilson natural gas storage facility and (ii) land held pursuant to right-of-way agreements. There have been no material changes in our operating lease commitments since those reported in our 2009 Form 10-K.

Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. We are generally required to perform routine maintenance on the underlying leased assets. In addition, certain leases give us the option to make leasehold improvements. Maintenance and repairs of leased assets resulting from our operations are charged to expense as incurred. Lease and rental expense was $2.9 million and $1.7 million during the three months ended March 31, 2010 and 2009, respectively.

Purchase obligations. There have been no material changes in our consolidated purchase obligations since those reported in our 2009 Form 10-K, except for short-term payment obligations relating to capital projects initiated by us. These commitments represent unconditional payment obligations that we have agreed to pay vendors for services to be rendered or products to be delivered in connection with our capital spending programs. Our consolidated capital expenditure commitments outstanding increased from $175.3 million at December 31, 2009 to $373.1 million at March 31, 2010. At March 31, 2010, these commitments primarily relate to announced expansions of the Acadian Gas System (i.e., the Haynesville Extension) and the Texas Intrastate System (i.e., the Trinity River Lateral, Wilson Storage Expansion and Eagle Ford Shale Projects). We have elected to participate in the 270-mile Haynesville Extension pipeline project. The total expected cost of this project is approximately $1.55 billion including capitalized interest, of which our 66 percent share of the project is $1.02 billion.

Commitments under Equity Compensation Plans of EPCO

In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for us (see Note 13). See Note 3 for additional information regarding accounting for equity awards.

Other Claims

As part of our normal business activities with joint venture partners, customers and suppliers, we occasionally have claims made against us as a result of disputes related to contractual agreements or other communications. As of March 31, 2010, claims against us totaled approximately $1.2 million. These matters are in various stages of assessment and the ultimate outcome of such disputes cannot be reasonably estimated. However, in our opinion, the likelihood of a material adverse outcome related to such disputes against us is remote. Accordingly, accruals for loss contingencies related to these matters that might result from the resolution of such disputes have not been reflected in our unaudited consolidated financial statements.

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 16. Significant Risks and Uncertainties

Insurance-Related Risks

We participate as a named insured in EPCO’s insurance program, which provides us with property damage, business interruption and other coverages, the scope and amounts of which are customary and sufficient for the nature and extent of our operations. While we believe EPCO maintains adequate insurance coverage on our behalf, insurance will not cover every type of damage or interruption that might occur. If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient to reimburse us for our repair costs or lost income. Any event that interrupts the revenues generated by our consolidated operations, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to pay distributions to our partners and, accordingly, adversely affect the market price of our common units.

Interest Rate Risk

Our Revolving Credit Facility and Term Loan Agreement are variable rate debt obligations, which both mature in 2011. We have outstanding $175 million of variable-to-fixed interest rate swaps, all of which expire in September 2010, that partially hedge our exposure to changes in variable interest rates.

We cannot predict the costs of refinancing, at maturity, our existing credit facilities or the costs of new credit arrangements. A tight credit market, similar to the markets in late 2008 and early 2009, may have an adverse affect on our future ability to refinance our credit facilities at favorable rates or to enter into additional new credit arrangements. In addition, tight credit market conditions may translate into our having to agree to increasingly restrictive lender covenants. The inability to refinance or enter into new credit arrangements with favorable terms could impede our ability to fund capital requirements or to make distributions on our common units.

Note 17. Supplemental Cash Flow Information

The following table provides information regarding the net effect of changes in our operating assets and liabilities.

	For the Three Months
	Ended March 31,
	2010			2009
Decrease (increase) in:
Accounts receivable – trade	$	(2.2	)	$	41.6
Accounts receivable – related parties		(8.3	)		(2.3	)
Inventories		1.3			13.1
Prepaid and other current assets		1.0			(0.2	)
Increase (decrease) in:
Accounts payable – trade		(0.6	)		(3.9	)
Accounts payable – related parties		13.2			(33.5	)
Accrued products payable		(3.3	)		(38.4	)
Accrued property taxes		(1.9	)		(2.0	)
Accrued taxes – other		(0.5	)		(6.5	)
Other current liabilities		(1.2	)		(3.5	)
Net effect of changes in operating accounts	$	(2.5	)	$	(35.6	)

We incurred liabilities for construction in progress that had not been paid at March 31, 2010 and December 31, 2009 of $28.6 million and $41.8 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Unaudited Condensed Statements of Consolidated Cash Flows.

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the components of depreciation, amortization and accretion for the periods indicated:

	For the Three Months
	Ended March 31,
	2010		2009
Depreciation, amortization and accretion expense:
DEP I Midstream Businesses	$	10.0	$	9.4
DEP II Midstream Businesses		37.4		35.2
Duncan Energy Partners L.P. standalone		0.8		0.4
Total	$	48.2	$	45.0

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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, 2010 and 2009.

The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included in this report. The following information and such unaudited condensed consolidated financial statements should also be read in conjunction with the financial statements and related notes, together with our discussion and analysis of financial position and results of operations included under Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2009 (“2009 Form 10-K”). Our financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).

Key References Used in this Quarterly Report

References to “Enterprise Products Partners” mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. Enterprise Products 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 “EPD.” References to “EPGP” mean Enterprise Products GP, LLC, which is the general partner of Enterprise Products Partners. References to “EPO” mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enter prise Products Partners through which Enterprise Products Partners conducts substantially all of its business, and its consolidated subsidiaries. EPO beneficially owns 100% of DEP GP and is a significant owner of our common units. Enterprise Products Partners consolidates our financial statements with those of its own.

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 D uncan 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 under the DD LLC Voting Trust Agreement 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) Ms. 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) Mr. 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 EPE Holdings, EPGP and DEP GP.

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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 (“LE GP”). Enterprise GP Holdings owns noncontrolling interests in both Energy Transfer Equity and LE GP.

References to “Evangeline” mean our aggregate 49.51% equity method investment in Evangeline Gas Pipeline Company, L.P. (“EGP”) and Evangeline Gas Corp (“EGC”).

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, Enterprise Products Partners, EPO, 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 Tru st 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 also the same persons as the individuals appointed on April 27, 2010 as the independent co-executors of the estate of Dan L. Duncan. EPE Holdings, which is the general partner of Enterprise GP Holdings, is a wholly owned subsidiary of Dan Duncan LLC. 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.

As generally used in the energy industry and in this discussion, the identified terms have the following meanings:

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

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Cautionary Note Regarding Forward-Looking Statements

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,” “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 such expectation s 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. Such statements are subject to a variety of risks, uncertainties and assumptions as described in more detail in Item 1A of our 2009 Form 10-K and in Part II Item 1A of this quarterly report on Form 10-Q. 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 NYSE under the ticker symbol “DEP.” Duncan Energy Partners was formed in September 2006 and did not own any assets prior to February 5, 2007, which was the date it completed its initial public offering and acquired controlling interests in the DEP I Midstream Businesses from EPO. The business purpose of Duncan Energy Partners is to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO and other affiliates under common control. Duncan Energy Partners is engaged in the business of: (i) natural gas liquids (“NGLs”) transportation, fractionation and marketing; (ii) storage of NGL and petrochemical products; (iii) transpo rtation of petrochemical products; and (iv) the gathering, transportation, marketing and storage of natural gas. We conduct substantially all of our business through DEP OLP.

As of March 31, 2010, Duncan Energy Partners was owned 99.3% by its limited partners and 0.7% by DEP GP. EPO owned approximately 58.6% of our common units and 100% of DEP GP at March 31, 2010. DEP GP is responsible for managing the business and operations of Duncan Energy Partners. EPCO provides all of our employees and certain operational and administrative services to us.

Our relationship with EPO is one of our principal business advantages. Our assets connect to various midstream energy assets of EPO and form integral links within EPO’s value chain of assets. We believe that the operational significance of our assets to EPO, as well as the alignment of our respective economic interests in these assets, will result in a collaborative effort between us and EPO to promote the operational efficiency of our assets and maximize their value. See Note 13 of Item 1 of this quarterly report on Form 10-Q for additional information regarding our relationship with Enterprise Products Partners, EPO and EPCO.

We have three reportable business segments: Natural Gas Pipelines & Services; NGL Pipelines & Services; and Petrochemical Services. Our business segments are generally organized and managed according to the type of services rendered (or technologies employed) and products produced and/or sold.

DEP I Drop Down

Effective February 1, 2007, EPO contributed to us a 66% controlling equity interest in each of the DEP I Midstream Businesses in a drop down transaction. EPO retained the remaining 34% noncontrolling equity interest in each of these businesses. As consideration for these equity interests, we paid $459.5 million in cash and issued 5,351,571 common units to EPO. The cash portion of this consideration was

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financed with $198.9 million in borrowings under our $300 million unsecured revolving credit facility (the “Revolving Credit Facility”) and $260.6 million of the $290.5 million of net proceeds from our initial public offering. The following is a brief description of the assets and operations of the DEP I Midstream Businesses:

§	Mont Belvieu Caverns owns 34 underground salt dome storage caverns located in Mont Belvieu, Texas, having an NGL and related product storage capacity of approximately 100 MMBbls, and a brine system with approximately 20 MMBbls of above ground storage capacity and two brine production wells.

Acadian Gas is engaged in the gathering, transportation, storage and marketing of natural gas in south Louisiana, utilizing over 1,000 miles of pipelines having an aggregate throughput capacity of 1.0 Bcf/d. Acadian Gas also owns a 49.51% equity interest in Evangeline, which owns a 27-mile natural gas pipeline located in southeast Louisiana.

§	Lou-Tex Propylene owns a 263-mile pipeline used to transport chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas.

§	Sabine Propylene owns a 21-mile pipeline used to transport polymer-grade propylene from Port Arthur, Texas to a pipeline interconnect in Cameron Parish, Louisiana.

§	South Texas NGL owns a 297-mile pipeline system used to transport NGLs from our Shoup and Armstrong NGL fractionation facilities in south Texas to Mont Belvieu, Texas.

DEP II Drop Down

On December 8, 2008, EPO contributed to us the following controlling equity interests in a second drop down transaction: (i) a 66% voting general partner interest in Enterprise GC, (ii) a 51% voting general partner interest in Enterprise Intrastate and (iii) a 51% voting membership interest in Enterprise Texas. As consideration for these equity interests, we paid $280.5 million in cash and issued 37,333,887 Class B units to EPO (which automatically converted on a one-for-one basis to common units in February 2009). The cash portion of this consideration was financed with $280.0 million in borrowings under our $300.0 million senior unsecured term loan agreement (the “Term Loan Agreement”) and $0.5 million of net proceeds from an equity offering to EPO. 60; The market value of the Class B units at the time of issuance was approximately $449.5 million. The following is a brief description of the assets and operations of the DEP II Midstream Businesses:

§	Enterprise Intrastate operates and owns an undivided 50% interest in the assets comprising the 641-mile Channel natural gas pipeline, which extends from the Agua Dulce Hub in south Texas to Sabine, Texas located on the Texas/Louisiana border.

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annualized return on their respective investments of 11.85%. Effective January 1, 2010, the annualized return increased by 2.0% to 12.087%. Distributions in excess of these amounts will be distributed 98% to EPO and 2% to us. Income and loss of the DEP II Midstream Businesses are first allocated to EPO and us based on each entity’s percentage interest of 77.4% and 22.6%, respectively, and then in a manner that in part follows the cash distributions.

For detailed information regarding EPO’s noncontrolling interest in the DEP I and DEP II Midstream Businesses, see Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Our results of operations for the three months ended March 31, 2010 are not necessarily indicative of results expected for the full year.

Basis of Financial Statement Presentation

See Note 1 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report for information regarding the basis for presentation of our general purpose financial statements. Such information is incorporated by reference into this Item 2 discussion.

Supplemental Selected Financial Information of Duncan Energy Partners L.P.

We are providing the following selected financial information to assist investors and other users of our financial statements in understanding the principal sources and uses of cash flows of Duncan Energy Partners L.P. on a standalone basis. Duncan Energy Partners L.P. has no operations apart from its investing activities and indirectly overseeing the management of the DEP I and DEP II Midstream Businesses.

The primary sources of cash flow for Duncan Energy Partners L.P. are the cash distributions it receives from the DEP I and DEP II Midstream Businesses. The primary cash requirements of Duncan Energy Partners are for general and administrative costs, debt service and distributions to partners. The amount of cash distributions that Duncan Energy Partners L.P. is able to pay its unitholders may fluctuate based on the level of distributions it receives from its operating subsidiaries. Factors such as capital contributions, debt service requirements, general and administrative costs, reserves for future distributions and other cash reserves established by the board of directors of our general partner (the “Board”) may also affect the distributions Duncan Energy Partners L.P. makes to its unitholders.

For purposes of this presentation, we have provided information pertaining to the DEP I Midstream Businesses apart from those of the DEP II Midstream Businesses.

	For the Three Months
	Ended March 31,
	2010		2009
	(Dollars in millions)
Selected income statement information:
Equity in income - DEP I Midstream Businesses	$	10.3	$	8.4
Equity in income - DEP II Midstream Businesses	$	14.6	$	15.4
General and administrative costs	$	0.6	$	0.1
Interest expense	$	3.1	$	3.8
Net income attributable to Duncan Energy Partners L.P.	$	21.2	$	19.9
Selected balance sheet information at each period end:
Investments in DEP I Midstream Businesses	$	512.5	$	505.4
Investments in DEP II Midstream Businesses	$	702.4	$	729.8
Total debt principal outstanding	$	457.3	$	470.3
Partners’ equity	$	759.5	$	761.9

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The following table presents the amount of distributions paid by each group of businesses with respect to each period:

	For the Three Months
	Ended March 31,
	2010		2009
	(Dollars in millions)
Distributions paid to Duncan Energy Partners L.P. with respect to each period from:
DEP I Midstream Businesses	$	19.9	$	17.5
DEP II Midstream Businesses	$	22.1	$	21.6

Generally, to the extent that the DEP II Midstream Businesses collectively generate cash sufficient to pay distributions to EPO and us, such cash will be distributed first to us (the “Tier I distribution,” based on our $730.0 million aggregate investment) and then to EPO (the “Tier II distribution”), in amounts sufficient to generate an annualized return to both owners based on their respective investments. Distributions in excess of these amounts (the “Tier III distributions”) will be distributed 98% to EPO and 2% to us.

The initial annualized return rate for 2009 was 11.85%, and was determined by EPO and us based on our estimated weighted-average cost of capital at December 8, 2008, plus 1.0%. The annualized return rate increases by 2.0% on January 1 of each year. As a result, the annualized return rate for 2010 is 12.087%. If we participate in an expansion capital project involving the DEP II Midstream Businesses, we may request an incremental adjustment to the then-applicable annualized return rate to reflect our weighted-average cost of capital associated with such contribution.

The annualized return rate is applied to each party’s aggregate investment (or “Distribution Base”) in the DEP II Midstream Businesses. To the extent that we and/or EPO make capital contributions to fund expansion capital projects involving the DEP II Midstream Businesses, the Distribution Base of the contributing member will be increased by that member’s capital contribution at the time such contribution is made. At December 8, 2008 and March 31, 2010, our Distribution Base was $730.0 million. EPO’s Distribution Base was $452.1 million and $880.6 million at December 8, 2008 and March 31, 2010, respectively. The increase in EPO’s Distribution Base is the result of its funding 100% of the expansion capital pro jects of the DEP II Midstream Businesses since December 8, 2008. We have not yet participated in the expansion capital project spending of the DEP II Midstream Businesses, although we may elect to invest in existing or future expansion projects at a later date.

We and EPO received $22.1 million and $15.4 million, respectively, in cash distributions from the DEP II Midstream Businesses for the three months ended March 31, 2010. The $22.1 million received by us with respect to the first quarter of 2010 represents one fourth of the annualized return rate for 2010 of 12.087% multiplied by our Distribution Base of $730.0 million. As a result, we received our expected Tier I distributions for the period. Based on EPO’s Distribution Base for the three months ended March 31, 2010, it was entitled to $26.6 million of Tier II distributions, of which it received only $15.4 million. As of March 31, 2010, no Tier III distributions were paid by the DEP II Midstream Businesses with respect to 2010.

Net income (or loss) of the DEP II Midstream Businesses is first allocated to us and EPO based on each entity’s percentage interest of 22.6% and 77.4%, respectively, and then in a manner that in part follows the cash distributions paid by (or contributions made to) each DEP II Midstream Business. Under our income sharing arrangement with EPO, we are allocated additional income (in excess of our percentage interest) to the extent that the cash distributions we receive (or contributions made) exceed the amount we would have been entitled to receive (or required to fund) based solely on our percentage interest. This additional earnings allocation to us reduces the amount of income allocated to EPO by an equal amount and may result in EPO being allocated a loss wh en we are allocated income. It is our expectation that EPO will be allocated a loss by the DEP II Midstream Businesses until such time as expansion capital projects such as the Sherman Extension and Trinity River Lateral realize their income and cash flow potential. Our

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participation in the expected future increase in cash flow from such projects is limited (beyond our annualized return amount) to 2% of such upside, with EPO receiving 98% of the benefit.

For information regarding the non-cash depreciation, amortization and accretion amounts of the DEP I and DEP II Midstream Businesses on a 100% basis, see Note 17 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Significant Recent Developments

The following information highlights specified significant developments since January 1, 2010 through the date of this filing, including (i) information relevant to an understanding of our financial condition, changes in financial condition or results of operations, 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.

Updates on Haynesville Extension Project

We and EPO will share in the funding of the Haynesville Extension pipeline in accordance with our ownership percentages in Acadian. Total construction costs are expected to be approximately $1.55 billion. Our 66% share of this project cost is approximately $1.02 billion. See “Liquidity and Capital Resources – Capital Expenditures” under this Item 2 for more information regarding the funding of the Haynesville Extension.

Registration Statements

In February 2010, we filed a registration statement with the Securities Exchange Commission (“SEC”) authorizing the issuance of up to an aggregate 1,000,000 common units in connection with an employee unit purchase plan and a long-term incentive plan that became effective on February 11, 2010. See Notes 3 and 10 under Item 1 of this quarterly report for additional information regarding these plans.

Results of Operations

We have three reportable business segments: Natural Gas Pipelines & Services; NGL Pipelines & Services and Petrochemical Services. Our business 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 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 as an alternative to GAAP operating income.

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Selected Volumetric Data

The following table presents average throughput and fractionation volumes for our principal pipelines and facilities for the periods indicated. These statistics are presented in total for each asset (or asset group) irrespective of ownership interest (i.e., on a 100% basis), with the exception of pipeline throughput volumes for Evangeline (a component of the Acadian Gas System). We report volumes for Evangeline on a net basis to our ownership interest.

	For the Three Months
	Ended March 31,
	2010		2009
Natural Gas Pipelines & Services:
Natural gas throughput volumes (BBtus/d)
Texas Intrastate System		3,736		4,130
Acadian Gas System:
Transportation volumes		409		383
Sales volumes (1)		320		288
Total natural gas throughput volumes		4,465		4,801
NGL Pipelines & Services:
NGL throughput volumes (MBPD)
South Texas NGL System - Pipelines		120		115
NGL fractionation volumes (MBPD)
South Texas NGL System - Fractionators		82		79
Petrochemical Services:
Propylene throughput volumes (MBPD)
Lou-Tex Propylene Pipeline		21		13
Sabine Propylene Pipeline		10		9
Total propylene throughput volumes		31		22

(1) Includes average net sales volumes for Evangeline of 35.7 BBtus/d and 35.0 BBtus/d for the three months ended March 31, 2010 and 2009, respectively.

Comparison of Consolidated Results of Operations

The following table summarizes key components of our consolidated income statement for the periods indicated (dollars in millions):

	For the Three Months
	Ended March 31,
	2010			2009
Revenues	$	290.6		$	256.8
Operating costs and expenses		267.2			239.4
General and administrative costs		4.9			2.8
Equity in income of Evangeline		0.2			0.2
Operating income		18.7			14.8
Interest expense		(3.1	)		(3.8	)
Benefit from (provision for) income taxes		0.1			(0.1	)
Net income		15.7			11.0
Net loss (income) attributable to noncontrolling interest:
DEP I Midstream Businesses – Parent		(4.7	)		(1.6	)
DEP II Midstream Businesses – Parent		10.2			10.5
Net income attributable to Duncan Energy Partners L.P.		21.2			19.9

For information regarding noncontrolling interest, see Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

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

	For the Three Months
	Ended March 31,
	2010		2009
Natural Gas Pipelines & Services	$	42.5	$	38.8
NGL Pipelines & Services		26.9		20.8
Petrochemical Services		2.4		2.5
Total segment gross operating margin	$	71.8	$	62.1

For a reconciliation of non-GAAP gross operating margin to GAAP operating income and further to GAAP income before income taxes, see “Other Items – Non-GAAP Reconciliations” within this Item 2. For additional information regarding our business segments, see Note 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

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

	For the Three Months
	Ended March 31,
	2010		2009
Natural Gas Pipelines & Services:
Sales of natural gas	$	153.2	$	136.9
Natural gas transportation services		70.8		63.2
Natural gas storage services		3.9		2.5
Total		227.9		202.6
NGL Pipelines & Services:
Sales of NGLs		10.0		6.2
Sales of other products		3.7		3.8
NGL and petrochemical storage services		27.1		24.1
NGL fractionation services		7.7		7.4
NGL transportation services		10.5		8.7
Other services		0.5		0.6
Total		59.5		50.8
Petrochemical Services:
Propylene transportation services		3.2		3.4
Total consolidated revenues	$	290.6	$	256.8

Comparison of Three Months Ended March 31, 2010 with Three Months Ended March 31, 2009

Revenues for the first quarter of 2010 were $290.6 million compared to $256.8 million for the first quarter of 2009. The $33.8 million quarter-to-quarter increase in consolidated revenues is primarily due to higher sales volumes and energy commodity prices during the first quarter of 2010 relative to the first quarter of 2009. These factors accounted for a $20.0 million quarter-to-quarter increase in revenues from the sale of natural gas, NGLs and other products. Revenues from natural gas transportation and storage services increased $9.0 million quarter-to-quarter primarily due to firm capacity reservation fees earned by our Sherman Extension pipeline during the first quarter of 2010. The Sherman Extension pipeline, a recently constructed asse t, began earning capacity reservation fees during August 2009. Collectively, revenues from all other services we provide to customers increased $4.8 million quarter-to-quarter primarily due to higher NGL storage volumes and fees during the first quarter of 2010 compared to the first quarter of 2009.

Operating costs and expenses were $267.2 million for the first quarter of 2010 versus $239.4 million for the first quarter of 2009. The $27.8 million quarter-to-quarter increase in our operating costs and expenses is primarily due to an increase in the cost of sales associated with our marketing activities. The cost of sales of our natural gas and NGL products increased $18.2 million quarter-to-quarter primarily as a result of higher sales volumes and energy commodity prices. Costs and expenses related to natural gas transportation and storage services increased $6.8 million quarter-to-quarter primarily due to incremental

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operating costs and expenses associated with the Sherman Extension pipeline and higher expenses at our Wilson natural gas storage facility. Collectively, the remainder of our consolidated operating costs and expenses increased $2.8 million quarter-to-quarter primarily due to an increase in depreciation expense associated with recently completed assets and non-cash asset impairment charges of $1.5 million we recorded during the first quarter of 2010 in connection with the cancellation of a compressor station project on our Texas Intrastate System and anticipated abandonment activities on a portion of the TPC Offshore gathering system.

Changes in our revenues and operating costs and expenses quarter-to-quarter are due in part to changes in energy commodity prices. In general, higher energy commodity prices result in an increase in our revenues attributable to the sale of natural gas and NGLs; however, these higher commodity prices also increase the associated cost of sales as purchase prices rise. The market price of natural gas (as measured at Henry Hub in Louisiana) averaged $5.30 per MMBtu during the first quarter of 2010 versus $4.91 per MMBtu during the first quarter of 2009. The weighted-average indicative market price for NGLs was $1.23 per gallon during the first quarter of 2010 versus $0.66 per gallon during the first quarter of 2009 – an 86% quarter-to-quarter increase.& #160; 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.

General and administrative costs increased $2.1 million quarter-to-quarter to $4.9 million for the first quarter of 2010 from $2.8 million for the first quarter of 2009 primarily due to increases in employee compensation expenses and accrued employee long-term incentive costs.

Operating income for the first quarter of 2010 was $18.7 million compared to $14.8 million for the first quarter of 2009. Consolidated revenues and certain operating costs and expenses can fluctuate significantly due to changes in energy commodity prices without necessarily affecting our operating income to the same degree. Collectively, the changes in revenues and costs and expenses described above contributed to the $3.9 million quarter-to-quarter increase in operating income.

Interest expense decreased $0.7 million quarter-to-quarter primarily due to lower average interest rates and amounts outstanding under our revolving credit facility. Income taxes attributable to the Texas Margin Tax decreased $0.2 million quarter-to-quarter.

As a result of items noted in the previous paragraphs, net income increased $4.7 million quarter-to-quarter to $15.7 million for the first quarter of 2010 compared to $11.0 million for the first quarter of 2009.

We account for EPO’s share of the net income of the DEP I and DEP II Midstream Businesses as noncontrolling interest, which is an adjustment to total net income to arrive at the amount of net income attributable to Duncan Energy Partners L.P. EPO was attributed $4.7 million of the net income of the DEP I Midstream Businesses for the first quarter of 2010 compared to $1.6 million for the first quarter of 2009. The quarter-to-quarter increase in EPO’s share of the net income of the DEP I Midstream Businesses is primarily due to improved earnings from these businesses and changes in the amount of operational measurement gains and losses recorded by Mont Belvieu Caverns (EPO is allocated 100% of such gains and losses). EPO was attributed losses of $10.2 million and $10.5 million in connection with its ownership interests in the DEP II Midstream Businesses during the first quarter of 2010 and 2009, respectively. See Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements for information regarding our determination of net income attributable to EPO’s noncontrolling interest.

The following information highlights significant quarter-to-quarter variances in gross operating margin by business segment:

Natural Gas Pipelines & Services. Gross operating margin from this business segment was $42.5 million for the first quarter of 2010 compared to $38.8 million for the first quarter of 2009, a $3.7 million quarter-to-quarter increase. Total natural gas throughput volumes were 4,465 BBtus/d for the first quarter of 2010 compared to 4,801 BBtus/d for the first quarter of 2009. Gross operating margin from our Texas

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Intrastate System increased $2.1 million quarter-to-quarter primarily due to $15.7 million of firm capacity reservation fees generated by the Sherman Extension pipeline during the first quarter of 2010 and an increase in condensate sales revenues due to higher commodity prices. These benefits were partially offset by the effects of lower throughput volumes on other parts of the Texas Intrastate System and higher operating expenses during the first quarter of 2010 compared to the first quarter of 2009. Collectively, gross operating margin for the remainder of the businesses within this segment increased $1.6 million quarter-to-quarter primarily due to increased natural gas throughput volumes on our Acadian Pipeline System and higher firm storage reservation fees at our Wilson natural gas storage facility.

NGL Pipelines & Services. Gross operating margin from this business segment was $26.9 million for the first quarter of 2010 compared to $20.8 million for the first quarter of 2009, a $6.1 million quarter-to-quarter increase. Mont Belvieu Caverns’ recorded operational measurement gains of $0.9 million for the first quarter of 2010 compared to operational measurement losses of $1.3 million for the first quarter of 2009. Operational measurement gains and losses are included in gross operating margin and subsequently allocated to EPO through noncontrolling interest. Consequently, such gains and losses are excluded from net income attributable to Duncan En ergy Partners. Segment gross operating margin increased $3.9 million quarter-to-quarter, net of operational measurement gains and losses, due to higher storage volumes and fees at Mont Belvieu Caverns’ storage complex.

Petrochemical Services. Gross operating margin from this business segment was $2.4 million for the first quarter of 2010 compared to $2.5 million for the first quarter of 2009. Petrochemical transportation volumes increased to 31 MBPD during the first quarter of 2010 from 22 MBPD during the first quarter of 2009. A quarter-to-quarter increase in gross operating margin from the Lou-Tex Propylene Pipeline as a result of increased transportation volumes was more than offset by lower gross operating margin on the Sabine Propylene Pipeline.

Liquidity and Capital Resources

Our primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, business combinations and distributions to our partners. We expect to fund our short-term needs for such items as operating expenses and sustaining capital expenditures with operating cash flows and borrowings under our Revolving Credit Facility. Capital expenditures for long-term needs resulting from business expansion projects and acquisitions, including our share of the Haynesville Extension project described below under “– Capital Expenditures,” are expected to be funded by a variety of sources (either separately or in combination) including operating cash flows, borrowings under credit facilities, cash contri butions from our Parent, the issuance of additional equity and debt securities and proceeds from divestitures of ownership interests in assets to affiliates or third parties. We expect to fund cash distributions to partners primarily with operating cash flows. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.

At March 31, 2010, we had approximately $135.2 million of liquidity, which includes amounts available under our Revolving Credit Facility. At March 31, 2010, our total debt balance was $457.3 million, which includes $175.0 million outstanding under our Revolving Credit Facility and the $282.3 million under our Term Loan Agreement. Our bank loan agreements require us to maintain certain financial and other customary covenants. We were in compliance with the covenants of our loan agreements at March 31, 2010.

It is our belief that we will continue to have adequate liquidity and capital resources to fund future recurring operating and investing activities.

Registration Statements

We may issue equity or debt securities to assist in meeting our liquidity and capital spending requirements. We have a universal shelf registration statement on file with the SEC that allows us to issue up to an aggregate $1 billion in debt and equity securities for general partnership purposes. After taking

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into account previous issuances of securities made under this registration statement, we can issue approximately $856.4 million of additional securities under this registration statement in the future.

We also have a registration statement on file with the SEC authorizing the issuance of up to an aggregate 2,000,000 common units in connection with the DRIP. The DRIP gives unitholders of record and beneficial owners of our common units the ability to increase the number of our common units they own through voluntarily reinvesting their quarterly cash distributions into the purchase of additional common units. Plan participants may purchase our common units at a discount ranging from 0% to 5% (currently set at 5%), which will be set from time to time by us. We issued 10,385 common units in connection with the DRIP for the three months ended March 31, 2010.

In February 2010, we filed a registration statement with the SEC authorizing the issuance of up to an aggregate 1,000,000 common units in connection with an employee unit purchase plan and a long-term incentive plan. These plans became effective on February 11, 2010. For the three months ended March 31, 2010, we issued 6,348 common units in connection with the 2010 Plan and did not issue common units in connection with the EUPP. See Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements under Item 1 of this quarterly report for additional information.

Consolidated 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 information regarding the individual components of our cash flow amounts, see the Unaudited Condensed Statements of Consolidated Cash Flows.

	For the Three Months
	Ended March 31,
	2010		2009
Net cash flows provided by operating activities	$	61.5	$	19.8
Cash used in investing activities		69.7		115.0
Cash provided by financing activities		26.0		104.0

Comparison of Three Months ended March 31, 2010 with Three Months ended March 31, 2009

The following information highlights the significant period-to-period variances in our consolidated cash flow amounts:

Operating activities. Net cash flows provided by operating activities were $61.5 million for the three months ended March 31, 2010 compared to $19.8 million for the three months ended March 31, 2009. The change in operating cash flow is primarily due to the timing of cash receipts and disbursements, along with a $9.7 million increase in quarter-to-quarter gross operating margin.

Investing activities. Cash used in investing activities was $69.7 million for the three months ended March 31, 2010 compared to $115.0 million for the three months ended March 31, 2009. The $45.3 million decrease is primarily due to a $45.6 million cash inflow in January 2010 attributable to EPO’s repayment of a temporary cash advance made in December 2009.

Financing activities. Cash provided by financing activities was $26.0 million for the three months ended March 31, 2010 compared to $104.0 million for the three months ended March 31, 2009. The quarter-to-quarter decrease of $78.0 million is primarily due to (i) a $50.8 million quarter-to-quarter decrease in contributions from EPO (as noncontrolling interest) related to capital expenditures on the DEP II Midstream Businesses, (ii) a $16.8 million quarter-to-quarter decrease in other contributions from EPO, (iii) a $12.8 million increase in distributions to our unitholders and general partner, (iv) a $11.4 million increase in other distributions to EPO and (v) a $14.0 million decrease in net repayments of debt.

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Capital Expenditures

Part of our business strategy involves expansion through business combinations and growth capital projects. The following table summarizes our consolidated capital spending for property, plant and equipment, net of contributions in aid of constructions costs, for the periods indicated (dollars in millions):

	For the Three Months
	Ended March 31,
	2010		2009
DEP I Midstream Businesses:
Expansion capital spending (1)	$	31.9	$	9.8
Sustaining capital expenditures (2)		3.6		2.5
DEP II Midstream Businesses:
Expansion capital spending (1)		68.5		93.1
Sustaining capital expenditures (2)		13.3		9.6
Total capital spending	$	117.3	$	115.0

(1) EPO funded 100% of expansion capital spending during the periods presented. (2) Sustaining capital expenditures are capital expenditures (as defined by U.S. GAAP) resulting from improvements to and major renewals of existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues. Sustaining capital expenditures reduce the amount of cash distributions paid to Duncan Energy Partners and EPO as owners of these businesses.

The majority of our capital spending during the three months ended March 31, 2010 and 2009 was attributable to ongoing expansions of the Acadian Gas System and the Texas Intrastate System, including the Haynesville Extension pipeline and Trinity River Lateral projects. The total expected cost of the 270-mile Haynesville Extension pipeline project is approximately $1.55 billion including capitalized interest, of which our 66 percent share of the project is $1.02 billion.

Based on information currently available, we estimate our consolidated capital spending for property, plant and equipment for the remainder of 2010 will approximate $688 million, which includes estimated expenditures of approximately $650 million for growth capital projects and approximately $38 million for sustaining capital expenditures.

Our forecast of capital expenditures is based on current announced growth plans. With respect to growth capital spending, EPO (as Parent) has historically funded the majority of such project costs under agreements executed in connection with the DEP I and DEP II drop down transactions. See Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report for information regarding EPO’s funding of certain growth capital spending of South Texas NGL and Mont Belvieu Caverns. For information regarding the expansion capital funding arrangements of the DEP II Midstream Businesses, see “Significant Relationships and Agreements with EPO - Company and Limited Partnership Agreements - DEP II Mid stream Businesses” under Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 within this quarterly report.

In order to fund our share of growth capital spending, we depend on our ability to generate the required funds from either operating cash flows or from other means, including borrowings under debt agreements and the issuance of equity. As a result of our election to fund 66% of the Haynesville Extension pipeline project, we are evaluating possible funding scenarios. We believe, based on preliminary discussions with lenders, that the borrowing capacity under our existing Revolving Credit Facility could potentially be increased from $300 million to at least a $900 million multi-year credit facility. In the interim, until the completion of a new or amended credit facility, EPO has indicated a willingness to provide a $125 million credit facility to us at mar ket terms, subject to the review and approval of the respective Audit, Conflicts and Governance Committees of DEP GP and EPGP.

At March 31, 2010, we had approximately $373.1 million in outstanding purchase commitments that relate to our capital spending for property, plant and equipment. These commitments primarily relate to expansion projects on our Acadian Gas System and Texas Intrastate System.

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Pipeline Integrity Costs

Our NGL, petrochemical and natural gas pipelines are subject to pipeline safety programs administered by the U.S. Department of Transportation. This federal agency has issued safety regulations containing requirements for the development of integrity management programs for hazardous liquid pipelines (which include NGL 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 for the periods indicated (dollars in millions):

	For the Three Months
	Ended March 31,
	2010		2009
Expensed	$	1.8	$	3.4
Capitalized		0.9		4.7
Total	$	2.7	$	8.1

We expect the costs of our pipeline integrity program, irrespective of whether such costs are capitalized or expensed, to approximate $31.6 million for the remainder of 2010.

Critical Accounting Policies and Estimates

A summary of the significant accounting policies we have adopted and followed in the preparation of our financial statements is included in our 2009 Form 10-K. Certain of these accounting policies require the use of estimates. As more fully described therein, the following estimates, in our opinion, are subjective in nature, require the exercise of 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; revenue recognition policies and use of estimates for revenues and expenses; and natural gas imbalances. These estimates are based on our current knowledge and understanding and may change as a result of actions we take in the future. Changes in these estimates 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 financial position, results of operations and cash flows.

Other Items

Contractual Obligations

With the exception of routine fluctuations in the balance of our Revolving Credit Facility and short-term payment obligations relating to capital projects initiated by us, there have been no significant changes in our contractual obligations since those reported in our 2009 Form 10-K. See “Liquidity and Capital Resources – Capital Expenditures” within this Item 2 for more information related to our capital expenditures.

Insurance Matters

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Non-GAAP Reconciliations

A reconciliation of our measurement of total non-GAAP gross operating margin to GAAP operating income and further to GAAP net income is presented in the following table (dollars in millions):

	For the Three Months
	Ended March 31,
	2010			2009
Total non-GAAP segment gross operating margin	$	71.8		$	62.1
Adjustments to reconcile total non-GAAP segment
gross operating margin to GAAP net income:
Depreciation, amortization and accretion in operating costs and expenses		(47.6	)		(44.6	)
Impairment charge included in operating costs and expenses		(1.5	)		--
Gain on asset sales and related transactions in operating costs and expenses		0.9			0.1
General and administrative costs		(4.9	)		(2.8	)
GAAP operating income		18.7			14.8
Other expense, net		(3.1	)		(3.7	)
Income before income taxes	$	15.6		$	11.1

Off-Balance Sheet Arrangements

There have been no significant changes with regards to our off-balance sheet arrangements since those reported in our 2009 Form 10-K.

Related Party Transactions

For information regarding our related party transactions, see Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

In the course of our normal business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with certain identifiable and anticipated transactions, we use derivative instruments. Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates, commodity prices or currency values. Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities. See Note 4 of the Notes to Unaudited Condensed Financial Statements included under Item 1 of this quarterly report for additional information regarding our derivative instruments and hedging activities.

Our exposures to market risk have not changed materially since those reported under Part II, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” of our 2009 Form 10-K.

Interest Rate Derivative Instruments

We utilize interest rate swaps 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.

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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 (dollars in millions).

	Resulting	Portfolio FV at
Scenario	Classification	March 31, 2010		April 20, 2010
FV assuming no change in underlying interest rates	Liability	$	3.8	$	3.8
FV assuming 10% increase in underlying interest rates	Liability		3.8		3.8
FV assuming 10% decrease in underlying interest rates	Liability		3.8		3.8

Commodity Derivative Instruments

The price of natural gas fluctuates in response to changes in supply and demand, market conditions, and a variety of additional factors that are beyond our control. We may use commodity-based derivative instruments such as futures, swaps and forward contracts to mitigate such risks.

We assess the risk of our commodity derivative instrument portfolio using a sensitivity analysis model. The sensitivity analysis applied to this portfolio measures the potential income or loss (i.e., the change in fair value of the portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices of the commodity derivative instruments outstanding at the date indicated within the following table.

The following table presents the effect of hypothetical price movements (a sensitivity analysis) on the estimated fair value of this portfolio at the dates presented (dollars in millions).

	Resulting	Portfolio FV at
Scenario	Classification	March 31, 2010		April 20, 2010
FV assuming no change in underlying commodity prices	Liability	$	*	$	--
FV assuming 10% increase in underlying commodity prices	Liability		*		--
FV assuming 10% decrease in underlying commodity prices	Liability		*		--
* Indicates that amounts are negligible and less than $0.1 million

Item 4. 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 CEO (our principal executive officer) and our general partner’s chief financial officer (our principal financial officer) (the “CFO”), of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based on that evaluation, as of the end of the period covered by this report, the CEO and CFO 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 the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure; and

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

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during the first quarter of 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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The certifications of our general partner’s CEO and CFO required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 have been included as exhibits to this quarterly report.

PART II. OTHER INFORMATION.

Item 1. Legal Proceedings.

For information on legal proceedings, see Part I, Item 1, Financial Statements, Note 15, “Commitments and Contingencies – Litigation,” of the Notes to Unaudited Condensed Consolidated Financial Statements included in 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 2009 Form 10-K and below in addition to other information in such report and in this quarterly report. We have identified these risk factors as 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.

The death of Dan L. Duncan represents a loss of a key member of our senior management team.

Although the remainder of our senior management team remains in place and succession planning regarding control of our general partner exists, we cannot predict the effect of the loss of Mr. Duncan at this time and cannot provide any assurances that his loss will not have any effect on our business, results of operations or cash flows.

Federal and certain state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays incurred by customers in the production of natural gas. A decline caused by these initiatives in the volume of natural gas and NGLs delivered to our facilities could adversely affect our financial position, results of operations and cash flows.

The U.S. Congress is considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells in shale and tight sand formations. Sponsors of these bills, which are currently pending in the Energy and Commerce Committee and the Environmental and Public Works Committee of the House of Representatives and Senate, respectively, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could establish additional Federal regulations that could lead to operational delays or increased operating costs in the production of natural gas incurred by our customers and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing. If these legislative and regulatory initiatives cause a material decrease in crude oil or natural gas production, our profitability could be materially impacted by a decline in the volume of natural gas and NGLs transported, gathered or processed at our facilities.

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

None.

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Item 3. Defaults Upon Senior Securities.

None.

Item 4. (Removed and Reserved).

Item 5. Other Information.

None.

Item 6. Exhibits.

Exhibit Number	Exhibit*
3.1	Certificate of Limited Partnership of Duncan Energy Partners L.P. (incorporated by reference to Exhibit 3.1 to Form S-1 Registration Statement (Reg. No. 333-138371) filed November 2, 2006).
3.2	Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P., dated February 5, 2007 (incorporated by reference to Exhibit 3.1 to Form 8-K filed February 5, 2007).
3.3	Amendment No. 1 to the Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P. dated December 27, 2007 (incorporated by reference to Exhibit 3.1 to Form 8-K/A filed January 3, 2008).
3.4	Amendment No. 2 to the Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P. dated November 6, 2008 (incorporated by reference to Exhibit 3.4 to Form 10-Q filed November 10, 2008).
3.5	Third Amendment to the Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P., dated December 8, 2008 (incorporated by reference to Exhibit 3.1 to Form 8-K filed December 8, 2008).
3.6	Fourth Amendment to the Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P. dated June 15, 2009 (incorporated by reference to Exhibit 3.1 to Form 8-K filed June 15, 2009).
3.7	Certificate of Formation of DEP Holdings, LLC (incorporated by reference to Exhibit 3.3 to Form S-1 Registration Statement (Reg. No. 333-138371) filed November 2, 2006).
3.8	Second Amended and Restated Limited Liability Company Agreement of DEP Holdings, LLC, dated May 3, 2007 (incorporated by reference to Exhibit 3.4 to Form 10-Q filed May 4, 2007).
3.9	First Amendment to the Second Amended and Restated Limited Liability Company Agreement of DEP Holdings, LLC dated November 6, 2008 (incorporated by reference to Exhibit 3.8 to Form 10-Q filed November 10, 2008).
3.10	Certificate of Formation of DEP OLPGP, LLC (incorporated by reference to Exhibit 3.5 to Form S-1 Registration Statement (Reg. No. 333-138371) filed November 2, 2006).
3.11	Amended and Restated Limited Liability Company Agreement of DEP OLPGP, LLC, dated January 19, 2007 (incorporated by reference to Exhibit 3.6 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-138371) filed January 22, 2007).
3.12	Certificate of Limited Partnership of DEP Operating Partnership, L.P. (incorporated by reference to Exhibit 3.7 to Form S-1 Registration Statement (Reg. No. 333-138371) filed November 2, 2006).
3.13	Agreement of Limited Partnership of DEP Operating Partnership, L.P., dated September 29, 2006 (incorporated by reference to Exhibit 3.8 to Amendment No. 1 to Form S-1 Registration Statement (Reg. No. 333-138371) filed December 15, 2006).
10.1***	Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (February 23, 2010) (incorporated by reference to Exhibit 10.7 to Form 8-K filed by Enterprise Products Partners L.P. on February 26, 2010).

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10.2***	Amendment to Form of Option Grant Award under the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan for awards issued before February 23, 2010 (incorporated by reference to Exhibit 10.8 to Form 8-K filed by Enterprise Products Partners L.P. on February 26, 2010).
10.3***	Form of Option Grant Award under the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (incorporated by reference to Exhibit 10.9 to Form 8-K filed by Enterprise Products Partners L.P. on February 26, 2010).
10.4***	Form of Employee Restricted Unit Grant Award under the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (incorporated by reference to Exhibit 10.10 to Form 8-K filed by Enterprise Products Partners L.P. on February 26, 2010).
10.5***	Form of Non-Employee Director Restricted Unit Grant Award under the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (incorporated by reference to Exhibit 10.11 to Form 8-K filed by Enterprise Products Partners L.P. on February 26, 2010).
10.6***	Enterprise Products 1998 Long-Term Incentive Plan (Amended and Restated as of February 23, 2010) (incorporated by reference to Exhibit 10.1 to Form 8-K filed by Enterprise Products Partners L.P. on February 26, 2010).
10.7***	Amendment to Form of Option Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan for awards issued before February 23, 2010 (incorporated by reference to Exhibit 10.2 to Form 8-K filed by Enterprise Products Partners L.P. on February 26, 2010).
10.8***	Form of Option Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 8-K filed by Enterprise Products Partners L.P. on February 26, 2010).
10.9***	Amendment to Form of Restricted Unit Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan for awards issued before February 23, 2010 (incorporated by reference to Exhibit 10.4 to Form 8-K filed by Enterprise Products Partners L.P. on February 26, 2010).
10.10***	Form of Employee Restricted Unit Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to Form 8-K filed by Enterprise Products Partners L.P. on February 26, 2010).
10.11***	Form of Non-Employee Director Restricted Unit Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.6 to Form 8-K filed by Enterprise Products Partners L.P. on February 26, 2010).
10.12***	Enterprise Products Company 2005 EPE Long-Term Incentive Plan (amended and restated as of February 23, 2010) (incorporated by reference to Exhibit 10.1 to Form 8-K filed by Enterprise GP Holdings L.P. on February 26, 2010).
10.13***	Form of Option Grant Award under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Form 8-K filed by Enterprise GP Holdings L.P. on February 26, 2010).
10.14***	Form of Employee Restricted Unit Grant Award under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 8-K filed by Enterprise GP Holdings L.P. on February 26, 2010).
10.15***	Form of Non-Employee Director Restricted Unit Grant Award under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to Form 8-K filed by Enterprise GP Holdings L.P. on February 26, 2010).
10.16***	Form of Phantom Unit Grant Award under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to Form 8-K filed by Enterprise GP Holdings L.P. on February 26, 2010).
10.17***	2010 Duncan Energy Partners L.P. Long-Term Incentive Plan (Amended and Restated as of February 23, 2010) (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 26, 2010).
10.18***	Form of Option Award under the 2010 Duncan Energy Partners L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Form 8-K filed February 26, 2010).
10.19***	Form of Employee Restricted Unit Grant Award under the 2010 Duncan Energy Partners L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 8-K filed February 26, 2010).
10.20***	Form of Non-Employee Director Restricted Unit Grant Award under the 2010 Duncan Energy

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Partners L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to Form 8-K filed February 26, 2010).

31.1#	Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Duncan Energy Partners L.P. for the March 31, 2010 quarterly report on Form 10-Q.
31.2#	Sarbanes-Oxley Section 302 certification of Bryan F. Bulawa for Duncan Energy Partners L.P. for the March 31, 2010 quarterly report on Form 10-Q.
32.1#	Section 1350 certification of W. Randall Fowler for the March 31, 2010 quarterly report on Form 10-Q.
32.2#	Section 1350 certification of Bryan F. Bulawa for the March 31, 2010 quarterly report on Form 10-Q.

*	With respect to exhibits incorporated by reference to Exchange Act filings, the Commission file numbers for Enterprise Products Partners L.P. and Enterprise GP Holdings L.P. are 1-14323 and 1-32610, 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 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, 2010.

					DUNCAN ENERGY PARTNERS L.P.
					(A Delaware Limited Partnership)

					By: DEP 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

exhibit31_1.htm

EXHIBIT 31.1

CERTIFICATIONS

I, W. Randall Fowler, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Duncan Energy Partners L.P.;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 10, 2010

	/s/ W. Randall Fowler
	Name:	W. Randall Fowler
	Title:	Chief Executive Officer of DEP Holdings, LLC, the General Partner of Duncan Energy Partners L.P.

exhibit31_2.htm

EXHIBIT 31.2

CERTIFICATIONS

I, Bryan F. Bulawa, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Duncan Energy Partners L.P.;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 10, 2010

	/s/ Bryan F. Bulawa
	Name:	Bryan F. Bulawa
	Title:	Chief Financial Officer of DEP Holdings, LLC, the General Partner of Duncan Energy Partners L.P.

exhibit32_1.htm

EXHIBIT 32.1

SARBANES-OXLEY SECTION 906 CERTIFICATION

CERTIFICATION OF W. RANDALL FOWLER, CHIEF EXECUTIVE OFFICER

OF DEP HOLDINGS, LLC, THE GENERAL PARTNER OF

DUNCAN ENERGY PARTNERS L.P.

In connection with this quarterly report of Duncan Energy Partners L.P. (the “Registrant”) on Form 10-Q for the three months ended March 31, 2010 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, W. Randall Fowler, Chief Executive Officer of DEP Holdings, LLC, the General Partner of the Registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ W. Randall Fowler
Name:	W. Randall Fowler
Title:	Chief Executive Officer of DEP Holdings, LLC,
	the General Partner of Duncan Energy Partners L.P.

Date: May 10, 2010

exhibit32_2.htm

EXHIBIT 32.2

SARBANES-OXLEY SECTION 906 CERTIFICATION

CERTIFICATION OF BRYAN F. BULAWA, CHIEF FINANCIAL OFFICER

OF DEP HOLDINGS, LLC, THE GENERAL PARTNER OF

DUNCAN ENERGY PARTNERS L.P.

In connection with this quarterly report of Duncan Energy Partners L.P. (the “Registrant”) on Form 10-Q for the three months ended March 31, 2010 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Bryan F. Bulawa, Chief Financial Officer of DEP Holdings, LLC, the General Partner of the Registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ Bryan F. Bulawa
Name:	Bryan F. Bulawa
Title:	Chief Financial Officer of DEP Holdings, LLC
	the General Partner of Duncan Energy Partners L.P.

Date: May 10, 2010