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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 June 30, 2009

[ ] 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, 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) 0; 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 57,676,987 common units of Duncan Energy Partners L.P. outstanding at August 1, 2009. 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. Background and Basis of Financial Statement Presentation	7
	2. General Accounting Matters	8
	3. Accounting for Equity Awards	10
	4. Derivative Instruments and Hedging Activities	11
	5. Inventories	16
	6. Property, Plant and Equipment	16
	7. Investments in Unconsolidated Affiliate	17
	8. Intangible Assets and Goodwill	17
	9. Debt Obligations	18
	10. Equity and Distributions	19
	11. Noncontrolling Interest in Subsidiaries	20
	12. Business Segments	23
	13. Related Party Transactions	25
	14. Earnings Per Unit	29
	15. Commitments and Contingencies	30
	16. Supplemental Cash Flow Information	32

Item 2.	Management’s Discussion and Analysis of Financial Condition	33
	and Results of Operations.
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	51
Item 4.	Controls and Procedures.	52

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings.	53
Item 1A.	Risk Factors.	53
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	53
Item 3.	Defaults upon Senior Securities.	53
Item 4.	Submission of Matters to a Vote of Unit Holders.	53
Item 5.	Other Information.	53
Item 6.	Exhibits.	54

Signatures		56

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DUNCAN ENERGY PARTNERS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	June 30,			December 31,
	2009			2008
ASSETS
Current assets
Cash and cash equivalents	$	16.4		$	13.0
Accounts receivable – trade, net of allowance for doubtful accounts		90.4			117.3
Gas imbalance receivables		27.6			35.7
Accounts receivable – related parties		5.7			3.3
Inventories		7.2			28.0
Prepaid and other current assets		8.4			4.3
Total current assets		155.7			201.6
Property, plant and equipment, net		4,482.1			4,330.2
Investments in unconsolidated affiliate		5.0			4.5
Intangible assets, net of accumulated amortization of $38.4 at June 30, 2009
and $34.1 at December 31, 2008		48.0			52.3
Goodwill		4.9			4.9
Other assets		1.1			1.2
Total assets	$	4,696.8		$	4,594.7

LIABILITIES AND EQUITY
Current liabilities
Accounts payable – trade	$	69.5		$	45.2
Accounts payable – related parties		28.4			48.5
Accrued product payables		58.7			109.7
Accrued property taxes		11.7			8.3
Other current liabilities		18.9			41.6
Total current liabilities		187.2			253.3
Long-term debt (see Note 9)		466.8			484.3
Deferred tax liabilities		6.0			5.7
Other long-term liabilities		8.1			7.2
Commitments and contingencies
Equity: (see Note 10)
Duncan Energy Partners L.P. partners’ equity:
Limited partners
Common units (57,676,987 common units outstanding at June 30, 2009 and
20,343,100 common units outstanding at December 31, 2008)		768.1			308.2
Class B units (37,333,887 Class B units outstanding at December 31, 2008)		--			453.8
General partner		0.3			0.4
Accumulated other comprehensive loss		(6.5	)		(9.6	)
Total Duncan Energy Partners L.P. partners’ equity		761.9			752.8
Noncontrolling interest in subsidiaries: (see Note 11)
DEP I Midstream Businesses – Parent		483.8			478.4
DEP II Midstream Businesses – Parent		2,783.0			2,613.0
Total noncontrolling interest		3,266.8			3,091.4
Total equity		4,028.7			3,844.2
Total liabilities and equity	$	4,696.8		$	4,594.7

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						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008*			2009			2008*
Revenues
Third parties	$	106.9		$	275.3		$	220.5		$	508.1
Related parties		119.8			203.5			263.0			334.3
Total revenues (see Note 12)		226.7			478.8			483.5			842.4
Costs and Expenses
Operating costs and expenses:
Third parties		177.1			400.8			372.4			707.4
Related parties		38.4			57.9			82.5			88.8
Total operating costs and expenses		215.5			458.7			454.9			796.2
General and administrative costs:
Third parties		--			0.7			0.7			1.7
Related parties		2.8			3.8			4.9			8.0
Total general and administrative costs		2.8			4.5			5.6			9.7
Total costs and expenses		218.3			463.2			460.5			805.9
Equity in income of unconsolidated affiliate		0.3			0.2			0.5			0.4
Operating income		8.7			15.8			23.5			36.9
Other income (expense)
Interest expense		(3.4	)		(2.7	)		(7.2	)		(5.5	)
Other, net		--			0.2			0.1			0.3
Other expense, net		(3.4	)		(2.5	)		(7.1	)		(5.2	)
Income before provision for income taxes		5.3			13.3			16.4			31.7
Provision for income taxes		(0.8	)		(0.6	)		(0.9	)		(0.1	)
Net income		4.5			12.7			15.5			31.6
Net loss (income) attributable to noncontrolling interest (see Note 11):
DEP I Midstream Businesses - Parent		(3.0	)		0.6			(4.6	)		(5.0	)
DEP II Midstream Businesses - Parent		21.7			--			32.2			--
Total net loss (income) attributable to noncontrolling interest		18.7			0.6			27.6			(5.0	)
Net income attributable to Duncan Energy Partners L.P.: (see Note 1)	$	23.2		$	13.3		$	43.1		$	26.6

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	$	23.0		$	6.5		$	42.8		$	12.4
General partner interest in net income	$	0.2		$	0.1		$	0.3		$	0.2
Former owners of DEP II Midstream Businesses				$	6.7					$	14.0

Basic and Diluted earnings per unit (see Note 14)	$	0.40		$	0.32		$	0.74		$	0.61

See Notes to Unaudited Condensed Consolidated Financial Statements.

*See Note 1 for information regarding these recasted amounts and

basis of financial statement presentation.

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DUNCAN ENERGY PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME

(Dollars in millions)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008*			2009			2008*

Net income	$	4.5		$	12.7		$	15.5		$	31.6
Other comprehensive income:
Cash flow hedges:
Interest rate derivative instrument gains (losses) during period		(0.5	)		4.1			0.2			(1.1	)
Reclassification adjustment for (gains) losses included in net
income related to interest rate derivative instruments		1.5			0.9			2.9			0.8
Commodity derivative instrument gains (losses) during period		--		♦				--			(0.1	)
Reclassification adjustment for (gains) losses included in net
income related to commodity derivative instruments		--		♦				--			0.1
Total cash flow hedges		1.0			5.0			3.1			(0.3	)
Comprehensive income		5.5			17.7			18.6			31.3
Comprehensive loss (income) attributable to noncontrolling interest:
DEP I Midstream Businesses – Parent		(3.0	)		0.6			(4.6	)		(5.0	)
DEP II Midstream Businesses – Parent		21.7			--			32.2			--
Total comprehensive loss (income) attributable to noncontrolling interest		18.7			0.6			27.6			(5.0	)
Comprehensive loss (income) allocated to former owners of DEP II Midstream Businesses		--			(6.7	)		--			(14.0	)
Comprehensive income attributable to Duncan Energy Partners L.P.	$	24.2		$	11.6		$	46.2		$	12.3

See Notes to Unaudited Condensed Consolidated Financial Statements.

*See Note 1 for information regarding these recasted amounts and

basis of financial statement presentation.

♦ Amount is negligible.

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DUNCAN ENERGY PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in millions)

	For the Six Months
	Ended June 30,
	2009			2008*
Operating activities:
Net income	$	15.5		$	31.6
Adjustments to reconcile net income to net cash flows provided
by operating activities:
Depreciation, amortization and accretion		91.2			82.6
Equity in income of unconsolidated affiliate		(0.5	)		(0.4	)
Gain on sale of assets and related transactions		(0.3	)		(0.5	)
Deferred income tax expense		0.2			(0.3	)
Changes in fair market value of derivative instruments		(0.1	)		--
Net effect of changes in operating accounts (see Note 16)		(23.6	)		(43.8	)
Net cash flows provided by operating activities		82.4			69.2
Investing activities:
Capital expenditures		(226.3	)		(431.4	)
Contributions in aid of construction costs		2.7			6.0
Proceeds from sale of assets and related transactions		0.4			0.4
Other		--			(0.3	)
Cash used in investing activities		(223.2	)		(425.3	)
Financing activities:
Repayments of debt		(55.5	)		(61.0	)
Borrowings under debt agreements		38.0			69.0
Debt issuance costs		(0.4	)		--
Distributions to Duncan Energy Partners’ unitholders and general partner		(38.1	)		(17.0	)
Distributions to noncontrolling interest (see Note 11)		(29.2	)		(18.0	)
Contributions from noncontrolling interest (see Note 11)		229.1			127.4
Net proceeds from Duncan Energy Partners’ common unit offerings		123.2			--
Common units repurchased from EPO and retired (see Note 10)		(122.9	)		--
Net cash contributions from former owners of the DEP II Midstream
Businesses prior to December 8, 2008		--			266.9
Cash provided by financing activities		144.2			367.3
Net changes in cash and cash equivalents		3.4			11.2
Cash and cash equivalents, beginning of period		13.0			2.2
Cash and cash equivalents, end of period	$	16.4		$	13.4

See Notes to Unaudited Condensed Consolidated Financial Statements.

*See Note 1 for information regarding these recasted amounts and

basis of financial statement presentation.

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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
	Partners			Partner			Loss			In Subsidiaries			Total
Balance, December 31, 2008	$	762.0		$	0.4		$	(9.6	)	$	3,091.4		$	3,844.2
Net income (loss)		42.8			0.3			--			(27.6	)		15.5
Amortization of equity awards		1.2			--			--			--			1.2
Net proceeds from Duncan Energy Partners’
common unit offerings		122.7			--			--			--			122.7
Contributions from noncontrolling interest		--			--			--			228.4			228.4
Distributions to unitholders and general partner		(37.7	)		(0.4	)		--			--			(38.1	)
Distributions to noncontrolling interest		--			--			--			(25.4	)		(25.4	)
Common units repurchased from EPO
and retired (See Note 10)		(122.9	)		--			--			--			(122.9	)
Cash flow hedges		--			--			3.1			--			3.1
Balance, June 30, 2009	$	768.1		$	0.3		$	(6.5	)	$	3,266.8		$	4,028.7

	DEP II		Duncan Energy Partners L.P.
	Midstream								Accumulated
	Businesses								Other			Noncontrolling
	Former		Limited			General			Comprehensive			Interest
	Owners		Partners			Partner			Loss			In Subsidiaries			Total
Balance, December 31, 2007 *	$	2,880.1	$	317.7		$	0.6		$	(3.6	)	$	355.1		$	3,549.9
Net income		14.0		12.4			0.2			--			5.0			31.6
Amortization of equity awards		--		0.1			--			--			--			0.1
Contributions from noncontrolling interest		--		--			--			--			118.5			118.5
Contributions from former owners		267.1		--			--			--			--			267.1
Distributions to unitholders and general partner		--		(16.6	)		(0.4	)		--			--			(17.0	)
Distributions to noncontrolling interest		--		--			--			--			(18.0	)		(18.0	)
Cash flow hedges		--		--			--			(0.3	)		--			(0.3	)
Balance, June 30, 2008*	$	3,161.2	$	313.6		$	0.4		$	(3.9	)	$	460.6		$	3,931.9

See Notes to Unaudited Condensed Consolidated Financial Statements.

*See Note 1 for information regarding these recasted amounts and

basis of financial statement presentation.

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1. Background and Basis of Financial Statement Presentation

Partnership Organization and Background

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

At June 30, 2009, Duncan Energy Partners was owned 99.3% by its limited partners and 0.7% by its general partner, DEP Holdings, LLC (“DEP GP”), which is a wholly owned subsidiary of Enterprise Products Operating LLC (“EPO” or “Parent”). EPO is the primary operating subsidiary of Enterprise Products Partners L.P. (“Enterprise Products Partners”). Enterprise Products Partners is a publicly traded partnership, the common units of which are listed on the NYSE under the ticker symbol “EPD.” At August 1, 2009, EPO owned approximately 58% 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. See Note 10 for information regarding the repurchase of common units from EPO in June 2009 and subsequent cancellation of such units.

A privately-held affiliate, EPCO, Inc. (“EPCO”), provides all of Duncan Energy Partners’ employees and certain administrative services to the partnership. EPCO is the ultimate parent company of Duncan Energy Partners, EPO and Enterprise Products Partners, all of which are affiliates under common control of Mr. Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.

Basis of Financial Statement Presentation

Effective February 1, 2007, Duncan Energy Partners acquired controlling ownership interests in five midstream energy companies (the “DEP I Midstream Businesses”) from EPO in a dropdown transaction. The DEP I Midstream Businesses consist of (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”).

On December 8, 2008, Duncan Energy Partners entered into a Purchase and Sale Agreement (the “DEP II Purchase Agreement”) with EPO and Enterprise GTM Holdings L.P. (“Enterprise GTM”), a wholly owned subsidiary of EPO. Pursuant to the DEP II Purchase Agreement, DEP Operating Partnership L.P. (“DEP OLP”) acquired 100% of the membership interests in Enterprise Holding III, LLC (“Enterprise III”) from Enterprise GTM, thereby acquiring a 66% general partner interest in Enterprise GC, L.P. (“Enterprise GC”), a 51% general partner interest in Enterprise Intrastate L.P. (“Enterprise Intrastate”) and a 51% membership interest in Enterprise Texas Pipeline LLC (“Enterprise Texas”). Collectively, we refer to Enterprise GC, Enterprise Intrastate and Enterprise Texas as the “DEP II Midstream Businesses.” EPO was the sponsor of this second dropdown transaction.

Prior to the dropdown of controlling ownership interests in the DEP I and DEP II Midstream Businesses to Duncan Energy Partners, EPO owned these businesses and directed their respective activities for all periods presented (to the extent such businesses were in existence during such periods). Each of the dropdown transactions was accounted for at EPO’s historical costs as a reorganization of entities under common control in a manner similar to a pooling of interests. On a standalone basis, Duncan Energy Partners did not own any assets prior to February 1, 2007.

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

References to the “former owners” of the DEP I and DEP II Midstream Businesses represent the ownership of EPO in these businesses prior to the effective date of the related dropdown transactions. References to “Duncan Energy Partners” mean the registrant and its consolidated subsidiaries since February 2007. Generic references to “we,” “us,” and “our” mean the combined and/or consolidated businesses included in these financial statements for each reporting period.

For additional information regarding the dropdowns of the DEP I and DEP II Midstream Businesses as well as the recast of our historical financial information in connection with the DEP II dropdown transaction, please read Note 1 of the Notes to Consolidated Financial Statements included under Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2008.

Our results of operations for the three and six months ended June 30, 2009 are not necessarily indicative of results expected for the full year.

In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These Unaudited Condensed Consolidated Financial Statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2008 (Commission File No. 1-33266).

Effective January 1, 2009, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51 (FASB Accounting Standards Codification (“ASC”) 810). SFAS 160 established accounting and reporting standards for noncontrolling interests, which were previously identified as Parent interest in our financial statements. This new standard requires, among other things, that (i) noncontrolling interests be presented as a component of equity on our consolidated balance sheet (i.e., elimination of the “mezzanine” presentation previously used for Parent interest); (ii) elimination of “Parent interest in income of subsidiaries” amounts as a deduction in deriving net income or loss and, as a result, that net income or loss be allocated between controlling and noncontrolling interests; and (iii) comprehensive income or loss to be allocated between controlling and noncontrolling interest. Earnings per unit amounts are not affected by these changes.

The consolidated financial statements included in this Quarterly Report on Form 10-Q have been retrospectively adjusted to reflect the changes required by SFAS 160. As a result, net income reported for the three and six months ended June 30, 2008 in these financial statements is higher than that disclosed previously; however, the allocation of such net income results in our unitholders, general partner and Parent (i.e., the noncontrolling interest) receiving the same amounts as they did previously.

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.

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Information

Cash and cash equivalents, accounts receivable, accounts payable, accrued expenses and other current liabilities 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 fair value information associated with our derivative instruments.

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

	June 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
Financial Instruments	Value		Value		Value		Value
Financial assets:
Cash and cash equivalents	$	16.4	$	16.4	$	13.0	$	13.0
Accounts receivable		123.7		123.7		156.3		156.3
Financial liabilities:
Accounts payable and accrued expenses	$	168.3	$	168.3	$	211.7	$	211.7
Other current liabilities		18.9		18.9		41.6		41.6
Variable-rate revolving credit facility		184.5		184.5		202.0		202.0
Variable-rate term loan		282.3		282.3		282.3		282.3

Recent Accounting Developments

The following information summarizes recently issued accounting guidance since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008 that will or may affect our future financial statements.

In April 2009, the Financial Accounting Standards Board (“FASB”) issued new guidance in the form of FASB Staff Positions (“FSPs”) in an effort to clarify certain fair value accounting rules. FSP FAS 157-4 (ASC 820), Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, establishes a process to determine whether a market is not active and a transaction is not distressed. FSP FAS 157-4 states that companies should look at several factors and use judgment to ascertain if a formerly active market has become inactive. When estimating fair value, FSP FAS 157-4 requires companies to place more weight on observable transactions determined to be orderly and less weight on transactions for which there is insufficient information to determine whether the transaction is orderly (entities do not have to incur undue cost and effort in making this determination). The FASB also issued FSP FAS 107-1 and APB 28-1 (ASC 825), Interim Disclosures About Fair Value of Financial Instruments. This FSP requires that companies provide qualitative and quantitative information about fair value estimates for all financial instruments not measured on the balance sheet at fair value in each interim report. Previously, this was only an annual requirement. We adopted these FSPs effective June 30, 2009. Our adoption of this new guidance did not have a material impact on our financial statements or related disclosures.

In May 2009, the FASB issued SFAS 165 (ASC 855), Subsequent Events, which establishes general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. We adopted SFAS 165 on June 30, 2009. Our adoption of this guidance did not have any impact on our financial position, results of operations or cash flows.

In June 2009, the FASB issued SFAS 167 (ASC 810), Amendments to FASB Interpretation No. 46(R), which amended consolidation guidance for variable interest entities (“VIEs”) under FASB Interpretation (“FIN”) No. 46(R) (“FIN 46(R)”) (ASC 810-10), Consolidation of Variable Interest Entities. VIEs are entities whose equity investors do not have sufficient equity capital at risk such that the entity

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

cannot finance its own activities. When a business has a controlling financial interest in a VIE, the assets, liabilities and profit or loss of that entity must be included in consolidation. A business enterprise must consolidate a VIE when that enterprise has a variable interest that will cover most of the entity’s expected losses and or receive most of the entity’s anticipated residual return. SFAS 167, among other things, eliminates the scope exception for qualifying special-purpose entities, amends certain guidance for determining whether an entity is a variable interest entity, expands the list of events that trigger reconsideration of whether an entity is a VIE, requires a qualitative rather than a quantitative analysis to determine the primary beneficiary of a VIE, requires continuous assessments of whether a company is the primary beneficiary of a VIE and requires enhanced disclosures about a company’s involvement with a VIE. SFAS 167 is effective for us on January 1, 2010. At June 30, 2009, we did not have any VIEs; therefore, our adoption of this new guidance is not expected to have a material impact on our consolidated financial statements.

In June 2009, the FASB issued SFAS 168 (ASC 105), The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162, which establishes the ASC as the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. The ASC is a reorganization of current GAAP into a topical format that eliminates the current GAAP hierarchy and establishes two levels of guidance — authoritative and nonauthoritative. All guidance contained in the ASC carries an equal level of authority. Rules and interpretive releases of the SEC under federal securities laws are also sources of authoritative GAAP for SEC registrants. The new standard identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. The new standard is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We will adopt this new standard on September 30, 2009. Our adoption of this new guidance is not expected to have any impact on our financial position, results of operations or cash flows. References to specific GAAP in our consolidated financial statements after our adoption of this new guidance will refer exclusively to the ASC. We have elected to provide references to the ASC parenthetically in this Quarterly Report on Form 10-Q.

Subsequent Events

We have evaluated subsequent events through August 10, 2009, which is the date our Unaudited Condensed Consolidated Financial Statements and Notes are being issued.

Note 3. Accounting for Equity Awards

We account for equity awards in accordance with SFAS 123(R) (ASC 505 and 718), Share-Based Payment. Such awards were not material to our consolidated financial position, results of operations, or cash flows for all periods presented. The amount of equity-based compensation allocable to our businesses was $0.7 million and $0.2 million for the three months ended June 30, 2009 and 2008, respectively. The amount of equity-based compensation allocable to our businesses for the six months ended June 30, 2009 and 2008 was $1.2 million and $0.3 million, respectively.

Certain key employees of EPCO participate in long-term incentive compensation plans managed by EPCO. The compensation expense we record related to unit-based awards (which awards currently relate to units of affiliates other than Duncan Energy Partners L.P.) is based on an allocation of the total cost of such incentive plans to EPCO. We record our pro rata share of such costs based on the percentage of time each employee spends on our consolidated business activities.

EPCO 1998 Long-Term Incentive Plan (“EPCO 1998 Plan”)

At June 30, 2009, the estimated total unrecognized compensation cost related to nonvested unit option awards and restricted unit awards granted under the EPCO 1998 Plan was $1.3 million and $44.2 million, respectively. We expect to recognize our share of these costs in accordance with the EPCO

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administrative services agreement (the “ASA”) (see Note 13) over a weighted-average period of 2.0 years (for unit options) and 2.5 years (for restricted units).

Enterprise Products 2008 Long-Term Incentive Plan (“EPD 2008 LTIP”)

At June 30, 2009, the estimated total unrecognized compensation cost related to nonvested unit options granted under the EPD 2008 LTIP was $7.1 million. We expect to recognize our share of this cost over a weighted-average period of 3.6 years in accordance with the ASA.

Employee Partnerships

As of June 30, 2009, the estimated total unrecognized compensation cost related to profits interests awards was $39.9 million. We will recognize our share of these costs in accordance with the ASA over a weighted-average period of 4.5 years.

Note 4. Derivative Instruments and Hedging Activities

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 or commodity prices. Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics. All of our derivatives are used for non-trading activities.

SFAS 133 (ASC 815), Accounting for Derivative Instruments and Hedging Activities, requires companies to recognize derivative instruments at fair value as either assets or liabilities on the balance sheet. While the standard requires that all derivatives be reported at fair value on the balance sheet, changes in fair value of the derivative instruments will be 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, all gains and losses (of 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 and is reclassified into earnings when the forecasted transaction affects earnings.

An effective hedge 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 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 is recognized in earnings immediately. Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item.

On January 1, 2009, we adopted the disclosure requirements of SFAS 161 (ASC 815), Disclosures About Derivative Financial Instruments and Hedging Activities. SFAS 161 requires enhanced qualitative and quantitative disclosure requirements regarding derivative instruments. This footnote reflects the new disclosure standard.

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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.

The following table summarizes our interest rate derivative instruments outstanding at June 30, 2009, all of which were designated as hedging instruments under SFAS 133:

	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	0.6% to 4.6%	Cash flow

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.

Commodity Derivative Instruments

The price of natural gas is subject to fluctuations in response to changes in supply, demand, general market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risk associated with such products, Acadian Gas enters into commodity derivative instruments such as forwards, basis swaps and futures contracts. The following table summarizes our commodity derivative instruments outstanding at June 30, 2009:

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

Derivatives not designated as hedging instruments under SFAS 133:
Acadian Gas:
Natural gas risk management activities (2)	1.6 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 June 30, 2009, none of Acadian Gas’ derivative instruments met the hedge accounting requirements of SFAS 133 and are accounted for as economic hedges using mark-to-market accounting.

Acadian Gas’ hedging strategy is to reduce the variability of its future earnings and cash flows resulting from changes in natural gas prices. Acadian Gas enters into a limited number of offsetting mark-to-market derivatives that effectively fix the price of natural gas for certain of its customers. Acadian Gas may also enter into a small number of cash flow hedges in connection with its purchase of natural gas held-for-sale to third parties.

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 June 30, 2009, our derivative instruments in a net liability position were $0.2 million; however, such instruments were not subject to these contingent features. 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
	June 30, 2009			December 31, 2008			June 30, 2009			December 31, 2008
	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 under SFAS 133
Interest rate derivatives	Other current assets	$	--	Other current assets	$	--	Other current liabilities	$	5.3	Other current liabilities	$	5.9

Interest rate derivatives	Other assets		--	Other assets		--	Other liabilities		1.4	Other liabilities		3.9

Total interest rate derivatives			--			--			6.7			9.8
Total derivatives
designated as hedging
instruments		$	--		$	--		$	6.7		$	9.8

Derivatives not designated as hedging instruments under SFAS 133
Commodity derivatives	Other current assets	$	0.2	Other current assets	$	1.9	Other current liabilities	$	0.2	Other current liabilities	$	2.0
Total derivatives not
designated as hedging
instruments		$	0.2		$	1.9		$	0.2		$	2.0

The following tables present the effect of our derivative instruments designated as cash flow hedges under SFAS 133 on our condensed consolidated statements of operations for the periods presented:

	Change in Value					Change in Value
Derivatives	Recognized in OCI on					Recognized in OCI on
in SFAS 133 Cash Flow	Derivative					Derivative
Hedging Relationships	(Effective Portion)					(Effective Portion)
	For the Three Months					For the Six Months
	Ended June 30,					Ended June 30,
	2009			2008		2009		2008
Interest rate derivatives	$	(0.5	)	$	4.1	$	0.2	$	(1.1	)
Commodity derivatives		--			*		--		(0.1	)
Total	$	(0.5	)	$	4.1	$	0.2	$	(1.2	)

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

		Amount of Gain/(Loss)						Amount of Gain/(Loss)
Derivatives	Location of Gain/(Loss)	Reclassified from AOCI						Reclassified from AOCI
in SFAS 133 Cash Flow	Reclassified from AOCI	to Income						to Income
Hedging Relationships	into Income (Effective Portion)	(Effective Portion)						(Effective Portion)
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2009			2008			2009			2008
Interest rate derivatives	Interest expense	$	(1.5	)	$	(0.9	)	$	(2.9	)	$	(0.8	)
Commodity derivatives	Operating Revenue		--			*			--			(0.1	)
Total		$	(1.5	)	$	(0.9	)	$	(2.9	)	$	(0.9	)

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

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Over the next twelve months, we expect to reclassify $5.3 million of accumulated other comprehensive loss attributable to interest rate derivative instruments to earnings as an increase to interest expense, based on the current level of interest rates.

The following table presents the effect of our derivative instruments not designated as hedging instruments under SFAS 133 on our condensed consolidated statements of operations for the periods presented:

Derivatives Not		Gain/(Loss) Recognized in
Designated as SFAS 133		Income on Derivative
Hedging Instruments	Location	Amount
		For the Three Months				For the Six Months
		Ended June 30,				Ended June 30,
		2009		2008		2009			2008
Commodity derivatives	Revenue	$	*	$	0.1	$	(0.2	)	$	0.1
Total		$	*	$	0.1	$	(0.2	)	$	0.1

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

SFAS 157 - Fair Value Measurements

SFAS 157 (ASC 820) defines fair value 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.

SFAS 157 established a three-tier hierarchy 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 SFAS 157 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 than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values

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primarily 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. Our interest rate derivatives are valued by using appropriate financial models with the implied forward LIBOR yield curve for the same period as the future interest swap settlements.

Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally developed data. The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort. Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value. Level 3 generally includes specialized or unique financial instruments that are tailored to meet a customer’s specific needs. At June 30, 2009, 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 June 30, 2009. 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.

	Level 1		Level 2		Total
Financial assets:
Commodity derivatives	$	0.1	$	0.1	$	0.2

Financial liabilities:
Commodity derivatives	$	0.1	$	0.1	$	0.2
Interest rate derivatives		--		6.7		6.7
Total derivative liabilities	$	0.1	$	6.8	$	6.9

We adopted the provisions of SFAS 157 that apply to nonfinancial assets and liabilities on January 1, 2009. Our adoption of this guidance had no impact on our financial position, results of operations or cash flows. Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances (for example, when there is evidence of impairment). There were no fair value adjustments for such assets or liabilities reflected in our consolidated financial statements for the three and six months ended June 30, 2009.

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Note 5. Inventories

Our inventory amounts were as follows at the dates indicated:

	June 30,		December 31,
	2009		2008
Working inventory (1)	$	1.4	$	18.3
Forward sales inventory (2)		5.8		9.7
Total inventory	$	7.2	$	28.0

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

Our cost of sales amounts were $108.2 million and $354.9 million for the three months ended June 30, 2009 and 2008, respectively. In comparison, our cost of sales amounts were $247.3 million and $603.4 million for the six months ended June 30, 2009 and 2008, respectively. Cost of sales is a component of operating costs and expenses in the period in which they are recognized, as presented on our Unaudited Condensed Statements of Consolidated Operations.

Due to fluctuating market prices, we record non-cash, lower of average cost or market (“LCM”) adjustments in connection with our available-for-sale inventory when the carrying value of such inventory exceeds its net realizable value. Our LCM adjustments were immaterial for the six months ended June 30, 2009. We had no LCM adjustments for the three months ended June 30, 2009 and 2008, and for the six months ended June 30, 2008.

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	June 30,		December 31,
	Life in Years	2009		2008
Plant and pipeline facilities (1)	3-45 (4)	$	4,618.8	$	4,175.0
Underground storage wells and related assets (2)	5-35 (5)		421.3		407.9
Transportation equipment (3)	3-10		10.4		10.3
Land			27.8		23.9
Construction in progress			235.0		459.0
Total			5,313.3		5,076.1
Less: accumulated depreciation			831.2		745.9
Property, plant and equipment, net		$	4,482.1	$	4,330.2

(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).

Depreciation expense for the three months ended June 30, 2009 and 2008 was $43.4 million and $40.0 million, respectively. Depreciation expense for the six months ended June 30, 2009 and 2008 was $85.7 million and $77.5 million, respectively.

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Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of a tangible long-lived asset that results from its acquisition, construction, development and/or normal operation. The following table presents information regarding our AROs since December 31, 2008.

ARO liability balance, December 31, 2008	$	4.6
Accretion expense		0.2
Revisions in estimated cash flows		3.0
ARO liability balance, June 30, 2009	$	7.8

Net property, plant and equipment at June 30, 2009 and December 31, 2008 includes $3.7 million and $1.3 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.

Note 7. Investments in Unconsolidated Affiliate

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 Evangeline Gas Pipeline, L.P. (“EGP”) and a 45.05% direct interest in Evangeline Gas Corp. (“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.

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

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
INCOME STATEMENT DATA:
Revenues	$	42.2	$	125.8	$	78.7	$	185.2
Operating income		1.0		1.9		1.7		3.6
Net income		0.6		0.5		1.0		0.8

Note 8. Intangible Assets and Goodwill

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

	At June 30, 2009							At December 31, 2008
	Gross		Accum.			Carrying		Gross		Accum.			Carrying
	Value		Amort.			Value		Value		Amort.			Value
NGL Pipelines & Services:
Customer relationship intangibles	$	24.6	$	(7.7	)	$	16.9	$	24.6	$	(6.4	)	$	18.2
Contract-based intangibles		40.8		(22.4	)		18.4		40.8		(20.1	)		20.7
Natural Gas Pipelines & Services:
Customer relationship intangibles		21.0		(8.3	)		12.7		21.0		(7.6	)		13.4
Total all segments	$	86.4	$	(38.4	)	$	48.0	$	86.4	$	(34.1	)	$	52.3

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

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
NGL Pipelines & Services	$	1.8	$	1.9	$	3.6	$	3.9
Natural Gas Pipelines & Services		0.3		0.4		0.7		0.8
Total all segments	$	2.1	$	2.3	$	4.3	$	4.7

Based on information currently available, we estimate that amortization expense will approximate $4.2 million for the last six months of 2009, $8.0 million for 2010, $7.6 million for 2011, $4.0 million for 2012 and $2.7 million for 2013.

Goodwill

Our goodwill totaled $4.9 million at both June 30, 2009 and December 31, 2008. Our goodwill was allocated $0.5 million and $4.4 million to our NGL Pipelines & Services segment and our Natural Gas Pipelines & Services segment, respectively.

Note 9. Debt Obligations

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

	At June 30,		At December 31,
	2009		2008
Revolving Credit Facility, variable rate, due February 2011	$	184.5	$	202.0
Term Loan Agreement, variable rate, due December 2011		282.3		282.3
Total principal amount of long-term debt obligations	$	466.8	$	484.3

Standby letter of credit outstanding	$	1.0	$	1.0

There have been no changes in the terms of our Revolving Credit Facility and our Term Loan Agreement since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008.

Covenants

We were in compliance with the covenants of our consolidated debt agreements at June 30, 2009.

Information regarding variable interest rates paid

The following table presents the weighted-average interest rate paid on our consolidated variable-rate debt obligations during the six months ended June 30, 2009.

	Weighted-average
	interest rate paid
Revolving Credit Facility	1.89%
Term Loan Agreement	1.31%

Evangeline joint venture debt obligation

At June 30, 2009, Evangeline’s debt consisted of $8.2 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 June 30, 2009. There have been no changes in the terms of Evangeline’s debt agreements since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008. The

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Partnership has furnished a letter of credit on behalf of Evangeline’s debt service requirements. At June 30, 2009, the letter of credit amount was $1.0 million.

Note 10. Equity and Distributions

Capital accounts, as defined in our Partnership Agreement, are maintained by us for our general partner and our limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in our financial statements. Earnings and cash distributions are allocated to our partners in accordance with their respective percentage interests.

Registration Statement

We have a universal shelf registration statement on file with the SEC that allows us to periodically issue up to $1.0 billion in debt and equity securities. In June 2009, we issued 8,000,000 common units to the public at an offering price of $16.00 per common unit under this universal shelf registration statement. We granted the underwriters a 30-day option to purchase up to 1,200,000 additional common units to cover over-allotments, which they exercised for 943,400 common units in July 2009. After taking into account issuances of securities under this registration statement, we can issue approximately $856.4 million of additional securities under this registration statement.

Unit History

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

	Limited						Total
	Partner			Treasury			Outstanding
	Units			Units			Units
Common units outstanding, December 31, 2008		20,343,100			--			20,343,100
Conversion of Class B units to common units on February 1, 2009		37,333,887			--			37,333,887
June underwritten offering		8,000,000			--			8,000,000
Acquisition of common units from EPO in June 2009		(8,000,000	)		8,000,000			--
Cancellation of treasury units in June 2009		--			(8,000,000	)		(8,000,000	)
Common units outstanding, June 30, 2009		57,676,987			--			57,676,987

In June 2009, we completed a common unit offering of 8,000,000 units that generated net proceeds of approximately $123.2 million after underwriting discounts and other expenses. In July 2009, the underwriters to this offering exercised their option to purchase an additional 943,400 common units, which generated approximately $14.5 million of additional net proceeds. The total net proceeds from this offering, including the overallotment amount, were used to repurchase an equal number of our common units beneficially owned by EPO – 8,000,000 units were repurchased in June 2009 and 943,400 units were repurchased in July 2009. The repurchased common units were subsequently cancelled.

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.

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The following table summarizes the amount, record date and payment date of the quarterly distributions we paid with respect to our common units for the six months ended June 30, 2009:

	Cash Distributions
	Per		Record	Payment
	Unit		Date	Date
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
(1) We issued 37,333,887 Class B units in connection with the DEP II dropdown. The Class B units received a prorated distribution of $0.1115 per unit with respect to the 24-day period from December 8, 2008 (the closing date of the DEP II dropdown transaction) to December 31, 2008. These units automatically converted to common units on February 1, 2009.

Accumulated Other Comprehensive Loss

Our accumulated other comprehensive loss (“AOCL”) balance at June 30, 2009 and December 31, 2008 was $6.5 million and $9.6 million, respectively. Our AOCL was related to interest rate derivative instruments.

Note 11. Noncontrolling Interest

DEP I Midstream Businesses – Parent

We account for EPO’s 34% ownership interest in the DEP I Midstream Businesses as a noncontrolling interest. EPO’s share (as our Parent) in the net income of the DEP I Midstream Businesses is deducted from net income in deriving net income attributable to Duncan Energy Partners L.P. EPO’s ownership interest in the net assets of the DEP I Midstream Businesses is presented as noncontrolling interest in subsidiaries on our Unaudited Condensed Consolidated Balance Sheets as a component of equity.

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						For the Three Months
	Ended June 30, 2009						Ended June 30, 2008
Mont Belvieu Caverns:
Mont Belvieu Caverns’ net income (loss) (before special allocation of operational
measurement gains and losses)	$	7.6					$	(1.5	)
Add (deduct) operational measurement loss (gain) allocated to Parent		1.3		$	(1.3	)		5.7		$	(5.7	)
Add depreciation expense related to fully funded projects allocated to Parent		1.6			(1.6	)		--
Remaining Mont Belvieu Caverns’ net income to allocate to partners		10.5						4.2
Multiplied by Parent 34% interest in remaining net income		x 34	%					x 34	%
Mont Belvieu Caverns’ net income allocated to Parent	$	3.6			3.6		$	1.4			1.4
Acadian Gas net income multiplied by Parent 34% interest					0.8						1.7
Lou-Tex Propylene net income multiplied by Parent 34% interest					0.5						0.8
Sabine Propylene net income multiplied by Parent 34% interest					0.1						0.1
South Texas NGL net income multiplied by Parent 34% interest					0.9						1.1
Net income (loss) attributable to noncontrolling interest – DEP I Midstream
Businesses – Parent				$	3.0					$	(0.6	)

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 Six Months						For the Six Months
	Ended June 30, 2009						Ended June 30, 2008
Mont Belvieu Caverns:
Mont Belvieu Caverns’ net income (before special allocation of operational
measurement gains and losses)	$	12.1					$	4.0
Add (deduct) operational measurement loss (gain) allocated to Parent		2.6		$	(2.6	)		4.9		$	(4.9	)
Add depreciation expense related to fully funded projects allocated to Parent		3.1			(3.1	)		--
Remaining Mont Belvieu Caverns’ net income to allocate to partners		17.8						8.9
Multiplied by Parent 34% interest in remaining net income		x 34	%					x 34	%
Mont Belvieu Caverns’ net income allocated to Parent	$	6.1			6.1		$	3.0			3.0
Acadian Gas net income multiplied by Parent 34% interest					1.0						2.9
Lou-Tex Propylene net income multiplied by Parent 34% interest					0.8						1.4
Sabine Propylene net income multiplied by Parent 34% interest					0.4						0.2
South Texas NGL net income multiplied by Parent 34% interest					2.0						2.4
Net income attributable to noncontrolling interest – DEP I Midstream
Businesses – Parent				$	4.6					$	5.0

The following table provides a reconciliation of the changes since December 31, 2008 in “Noncontrolling interest in subsidiaries – DEP I Midstream Businesses – Parent,” as presented on our Unaudited Condensed Consolidated Balance Sheets:

December 31, 2008 balance	$	478.4
Net income attributable to noncontrolling interest – DEP I Midstream Businesses – Parent		4.6
Contributions by EPO to DEP I Midstream Businesses:
Contributions from EPO to Mont Belvieu Caverns in connection with capital projects in which
EPO is funding 100% of the expenditures in accordance with the Mont Belvieu Caverns’ LLC
Agreement, including accrued receivables at June 30, 2009 (see Note 13)		12.7
Contributions from EPO to Mont Belvieu Caverns and South Texas NGL in connection with capital
projects in which EPO is funding 100% of the expenditures in excess of certain thresholds in
accordance with the Omnibus Agreement, including accrued receivables at June 30, 2009 (see Note 13)		1.4
Other contributions by EPO to the DEP I Midstream Businesses		0.9
Cash distributions to EPO of operating cash flows of DEP I Midstream Businesses		(14.2	)
June 30, 2009 balance	$	483.8

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

We account for EPO’s ownership interests in the DEP II Midstream Businesses as a noncontrolling interest. EPO’s share (as Parent) of the net income of the DEP II Midstream Businesses is deducted from net income in deriving net income attributable to Duncan Energy Partners L.P. EPO’s ownership interest in the net assets of the DEP II Midstream Businesses is presented as noncontrolling interest in subsidiaries on our Unaudited Condensed Consolidated Balance Sheets as a component of equity. The “Percentage Interest” of Enterprise III in each of the DEP II Midstream Businesses is 22.6%, with EPO retaining the remaining 77.4%. This interest was determined by dividing the aggregate consideration paid or issued by DEP for the DEP II Midstream Businesses, or $730.0 million, by the aggregate value of the DEP II Midstream Businesses of approximately $3.2 billion.

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables present our calculation of net loss of the DEP II Midstream Businesses attributable to EPO as noncontrolling interest as well as the amount of net income of the DEP II Midstream Businesses attributable to Duncan Energy Partners for the periods indicated:

	For the Three Months Ended
	June 30, 2009
	EPO						DEP
Total net income (loss) of DEP II Midstream Businesses				$	(6.4	)	$	(6.4	)
Multiplied by each owner's Percentage Interest					77.4	%		22.6	%
Base earnings allocation to each owner					(5.0	)		(1.4	)
Additional income allocation to Duncan Energy Partners:
Total distributions paid by the DEP II Midstream
Businesses with respect to period	$	21.6
Multiplied by 22.6% - Duncan Energy Partners'
Percentage Interest		22.6	%
Duncan Energy Partners' base allocation of the cash
distributions of the DEP II Midstream Businesses		4.9
Less actual distributions paid to Duncan Energy Partners
with respect to period based on fixed annual return		(21.6	)		(16.7	)		16.7
Net loss attributable to EPO as noncontrolling interest				$	(21.7	)
Net income attributable to Duncan Energy Partners							$	15.3

	For the Six Months Ended
	June 30, 2009
	EPO						DEP
Total net income (loss) of DEP II Midstream Businesses				$	(1.5	)	$	(1.5	)
Multiplied by each owner's Percentage Interest					77.4	%		22.6	%
Base earnings allocation to each owner					(1.1	)		(0.4	)
Additional income allocation to Duncan Energy Partners:
Total distributions paid by the DEP II Midstream
Businesses with respect to period	$	54.2
Multiplied by 22.6% - Duncan Energy Partners'
Percentage Interest		22.6	%
Duncan Energy Partners' base allocation of the cash
distributions of the DEP II Midstream Businesses		12.2
Less actual distributions paid to Duncan Energy Partners
with respect to period based on fixed annual return		(43.3	)		(31.1	)		31.1
Net loss attributable to EPO as noncontrolling interest				$	(32.2	)
Net income attributable to Duncan Energy Partners							$	30.7

The DEP II Midstream Businesses distributed an aggregate $21.6 million and $54.2 million to owners with respect to the three and six months ended June 30, 2009, respectively. Of these amounts, EPO received $13 thousand and $10.9 million for the three and six months ended June 30, 2009, respectively. Duncan Energy Partners L.P. received its full priority return amount of $21.6 million with respect to each of the first and second quarters of 2009.

The following table provides a reconciliation of the changes since December 31, 2008 in “Noncontrolling interest in subsidiaries – DEP II Midstream Businesses – Parent,” as presented on our Unaudited Condensed Consolidated Balance Sheets:

December 31, 2008 balance	$	2,613.0
Allocated loss from DEP II Midstream Businesses to EPO as Parent		(32.2	)
Contributions by EPO in connection with expansion cash calls		192.1
Distributions to noncontrolling interest of subsidiary operating cash flows		(11.2	)
Other general cash contributions from noncontrolling interest		21.3
June 30, 2009 balance	$	2,783.0

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise III has not yet participated in expansion project spending with respect to the DEP II Midstream Businesses, although it may elect to invest in existing or future expansion projects at a later date. As a result, Enterprise GTM has funded 100% of such growth capital spending, which amounts to $78.6 million and $192.1 million for the three and six months ended June 30, 2009, respectively.

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.

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

		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2009			2008			2009			2008
Revenues		$	226.7		$	478.8		$	483.5		$	842.4
Less:	Operating costs and expenses (1)		(215.5	)		(458.7	)		(454.9	)		(796.2	)
Add:	Equity in income of unconsolidated affiliate (1)		0.3			0.2			0.5			0.4
	Depreciation, amortization and accretion in
	operating costs and expenses (2)		45.7			42.3			90.3			82.4
	Gain on asset sales and related transactions
	in operating costs and expenses (3)		(0.2	)		(0.5	)		(0.3	)		(0.5	)
Total segment gross operating margin		$	57.0		$	62.1		$	119.1		$	128.5

(1) These amounts are taken from our Unaudited Condensed Statements of Consolidated Operations. (2) These non-cash expenses are components of depreciation, amortization and accretion as reflected on our Unaudited Condensed Statements of Consolidated Cash Flows. (3) These non-cash expenses are taken from the operating activities section of our Unaudited Condensed Statements of Consolidated Cash Flows.

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

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Total segment gross operating margin	$	57.0		$	62.1		$	119.1		$	128.5
Adjustments to reconcile total segment gross operating margin
to operating income:
Depreciation, amortization and accretion in
operating costs and expenses		(45.7	)		(42.3	)		(90.3	)		(82.4	)
Gain on asset sales and related transactions
in operating costs and expenses		0.2			0.5			0.3			0.5
General and administrative costs		(2.8	)		(4.5	)		(5.6	)		(9.7	)
Operating income		8.7			15.8			23.5			36.9
Other expense, net		(3.4	)		(2.5	)		(7.1	)		(5.2	)
Provision for income taxes		(0.8	)		(0.6	)		(0.9	)		(0.1	)
Net income	$	4.5		$	12.7		$	15.5		$	31.6

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DUNCAN ENERGY PARTNERS L.P.

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 June 30, 2009	$	80.0	$	23.6	$	3.3	$	--	$	106.9
Three months ended June 30, 2008		252.4		18.7		4.2		--		275.3
Six months ended June 30, 2009		172.5		41.3		6.7		--		220.5
Six months ended June 30, 2008		463.4		36.7		8.0		--		508.1
Revenues from related parties:
Three months ended June 30, 2009		85.9		33.9		--		--		119.8
Three months ended June 30, 2008		159.3		44.2		--		--		203.5
Six months ended June 30, 2009		196.0		67.0		--		--		263.0
Six months ended June 30, 2008		253.2		81.1		--		--		334.3
Total revenues:
Three months ended June 30, 2009		165.9		57.5		3.3		--		226.7
Three months ended June 30, 2008		411.7		62.9		4.2		--		478.8
Six months ended June 30, 2009		368.5		108.3		6.7		--		483.5
Six months ended June 30, 2008		716.6		117.8		8.0		--		842.4
Equity in income of unconsolidated affiliate:
Three months ended June 30, 2009		0.3		--		--		--		0.3
Three months ended June 30, 2008		0.2		--		--		--		0.2
Six months ended June 30, 2009		0.5		--		--		--		0.5
Six months ended June 30, 2008		0.4		--		--		--		0.4
Gross operating margin:
Three months ended June 30, 2009		30.2		24.2		2.6		--		57.0
Three months ended June 30, 2008		43.9		14.8		3.4		--		62.1
Six months ended June 30, 2009		69.0		45.0		5.1		--		119.1
Six months ended June 30, 2008		84.7		37.5		6.3		--		128.5
Segment assets:
At June 30, 2009		3,256.5		905.6		85.0		235.0		4,482.1
At December 31, 2008		2,887.6		897.0		86.6		459.0		4,330.2
Investments in unconsolidated affiliate (see Note 7):
At June 30, 2009		5.0		--		--		--		5.0
At December 31, 2008		4.5		--		--		--		4.5
Intangible assets:
At June 30, 2009		12.7		35.3		--		--		48.0
At December 31, 2008		13.4		38.9		--		--		52.3
Goodwill:
At June 30, 2009		4.4		0.5		--		--		4.9
At December 31, 2008		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 adjustments and eliminations) and expenses for the periods noted:

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Natural Gas Pipelines & Services:
Sales of natural gas	$	91.8		$	326.1		$	216.7		$	555.3
Natural gas transportation services		69.8			83.8			145.0			158.2
Natural gas storage services		4.3			1.8			6.8			3.1
Total		165.9			411.7			368.5			716.6
NGL Pipelines & Services:
Sales of NGLs		8.7			16.9			14.9			28.5
Sales of other products		2.5			5.5			6.3			8.8
NGL and petrochemical storage services		25.6			21.3			49.7			40.7
NGL fractionation services		7.4			7.8			14.8			15.6
NGL transportation services		12.5			10.9			21.2			23.0
Other services		0.8			0.5			1.4			1.2
Total		57.5			62.9			108.3			117.8
Petrochemical Services:
Propylene transportation services		3.3			4.2			6.7			8.0
Total consolidated revenues	$	226.7		$	478.8		$	483.5		$	842.4

Consolidated costs and expenses
Operating costs and expenses:
Cost of natural gas and NGL sales	$	96.0		$	337.1		$	227.4		$	572.5
Depreciation, amortization and accretion		45.7			42.3			90.3			82.4
Gain on asset sales and related transactions		(0.2	)		(0.5	)		(0.3	)		(0.5	)
Other operating expenses		74.0			79.8			137.5			141.8
General and administrative costs		2.8			4.5			5.6			9.7
Total consolidated costs and expenses	$	218.3		$	463.2		$	460.5		$	805.9

Changes in our revenues and operating costs and expenses period-to-period are explained in part by changes in energy commodity prices. In general, lower energy commodity prices result in a decrease in our revenues attributable to the sale of natural gas and NGLs; however, these lower commodity prices also decrease the associated cost of sales as purchase prices fall.

Note 13. Related Party Transactions

The following information summarizes our business relationships and transactions with related parties during the three and six months ended June 30, 2009. 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.

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes our consolidated balance sheet amounts with related parties for the periods indicated:

	June 30,		December 31,
	2009		2008
Accounts receivable – related parties
EPO and affiliates	$	5.1	$	2.3
Energy Transfer Equity and affiliates (1)		0.6		0.9
Other		--		0.1
Total	$	5.7	$	3.3

Accounts payable – related parties
EPO and affiliates	$	19.2	$	46.1
EPCO and affiliates		9.2		1.9
TEPPCO and affiliates (2)		--		0.5
Total	$	28.4	$	48.5

(1) Refers to Energy Transfer Equity, L.P. (“Energy Transfer Equity”) and its consolidated subsidiaries. (2) Refers to TEPPCO Partners, L.P. (“TEPPCO”) and its consolidated subsidiaries.

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

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Revenue:
Revenues from EPO
Sales of natural gas	$	34.2		$	50.3		$	77.5		$	79.0
Natural gas transportation services		11.2			14.1			23.9			26.0
Natural gas storage services		0.8			--			1.2			--
Sales of NGLs		8.1			16.1			13.6			27.6
NGL and petrochemical storage services		7.5			8.3			17.7			16.5
NGL fractionation services		6.4			7.3			13.5			14.6
NGL transportation services		8.6			7.7			14.3			15.5
Other natural gas and NGL related services		2.7			4.5			6.9			6.5
Sales of natural gas – Evangeline		39.9			94.6			93.5			147.7
Natural gas transportation services – Energy Transfer Equity		--			0.2			0.1			0.5
NGL and petrochemical storage services – TEPPCO		0.4			0.4			0.8			0.4
Total related party revenues	$	119.8		$	203.5		$	263.0		$	334.3

Operating costs and expenses:
EPCO administrative services agreement	$	19.3		$	17.0		$	39.1		$	36.1
Expenses with EPO:
Purchases of natural gas		14.5			34.5			34.5			36.5
Operational measurement losses		1.3			5.7			2.6			4.9
Other expenses with EPO		3.6			3.5			8.8			6.0
Purchases of natural gas – Nautilus		(0.1	)		1.3			1.8			3.7
Expenses with Energy Transfer Equity:
Purchases of natural gas		0.5			(4.3	)		(3.2	)		1.7
Operating cost reimbursements for shared facilities		(1.1	)		0.3			(1.7	)		(0.4	)
Other expenses with Energy Transfer Equity		0.4			--			0.7			0.4
Expenses with TEPPCO		--			(0.1	)		(0.1	)		(0.1	)
Total related party operating costs and expenses	$	38.4		$	57.9		$	82.5		$	88.8

General and administrative costs:
EPCO administrative services agreement	$	2.6		$	4.0		$	4.9		$	8.4
Other related party general and administrative		0.2			(0.2	)		--			(0.4	)
Total related party general and administrative costs	$	2.8		$	3.8		$	4.9		$	8.0

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

One of our principal advantages is our relationship with EPO and EPCO. EPO is a wholly owned subsidiary of Enterprise Products Partners through which Enterprise Products Partners conducts its business. Enterprise Products Partners is controlled by its general partner, Enterprise Products GP, LLC (“EPGP”), which in turn is a wholly owned subsidiary of Enterprise GP Holdings L.P. (“Enterprise GP Holdings”). The general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”), which is a wholly owned subsidiary of a privately-held company controlled by Dan L. Duncan. Mr. Duncan is Chairman of our general partner and is the Group Co-Chairman and the controlling shareholder of EPCO. Our general partner is wholly owned by EPO and EPCO provides all of our employees, including our executive officers.

Significant Relationships and Agreements with EPO

At August 1, 2009, EPO owned approximately 58% 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 varying 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 obligations or commitment to make such contributions or sales to us, nor do we have any obligation or commitments 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 is owned by us.

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 Note 14 of the Notes to Consolidated Financial Statements under Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2008.

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 terminate on February 5, 2010. We made no claims to EPO during the six months ended June 30, 2009.

Under the Omnibus Agreement, EPO agreed to make additional cash contributions to South Texas NGL and Mont Belvieu Caverns to fund 100% of certain post-February 5, 2007 capital expenditures of South Texas NGL and Mont Belvieu Caverns. EPO made cash contributions to our subsidiaries of $1.4 million and $36.7 million in connection with the Omnibus Agreement during the six months ended June 30, 2009 and 2008, respectively.

Mont Belvieu Caverns’ LLC Agreement. The Mont Belvieu Caverns’ Limited Liability Company 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 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. EPO made cash contributions of $12.7 million and $68.1 million in connection with the Caverns LLC Agreement for the six months ended June 30, 2009 and 2008, respectively. We expect additional contributions of approximately $22.4 million from EPO to fund such projects for the remainder of 2009. The constructed assets will be the property of Mont Belvieu Caverns.

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 the three months ended June 30, 2009 and 2008, we allocated losses of $1.3 million and $5.7 million, respectively. We allocated operational measurement losses of $2.6 million and $4.9 million for the six months ended June 30, 2009 and 2008, respectively.

In November 2008, the Caverns LLC Agreement was amended to provide that EPO would prospectively receive a special allocation (through noncontrolling interest) of 100% of the depreciation related to projects that it has fully funded. For the three and six month periods ended June 30, 2009, EPO was allocated $1.6 million and $3.1 million, respectively, of depreciation expense related to such projects.

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 14 of Item 8 in our Annual Report on Form 10-K for the year ended December 31, 2008 for more information on these agreements.

Enterprise III has not yet participated in expansion project spending with respect to the DEP II Midstream Businesses, although it may elect to invest in existing or future expansion projects at a later date. As a result, Enterprise GTM has funded 100% of such growth capital spending and its Distribution Base has increased from $473.4 million at December 31, 2008 to $665.5 million at June 30, 2009. The Enterprise III Distribution Base was unchanged at $730.0 million at June 30, 2009.

Common Unit Purchase Agreement – June 2009 equity offering. Pursuant to a common unit purchase agreement, we repurchased 8,000,000 of our common units beneficially owned by EPO in June 2009. We repurchased an additional 943,400 of our common units beneficially owned by EPO in July 2009. The repurchase of common units beneficially owned by EPO was reviewed and approved by each of the ACG Committees of EPGP and DEP GP. See Note 10 for additional information regarding our June 2009 equity offering.

Relationship with EPCO

We have no employees. Substantially all of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to the ASA. We, Enterprise Products Partners, Enterprise GP Holdings, TEPPCO and our respective general partners are among the parties to the ASA.

Our operating costs and expenses for the three months ended June 30, 2009 include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including compensation of EPCO’s employees to the extent that such employees spend time on our businesses. For the three months ended June 30, 2009, we reimbursed EPCO $19.3 million for operating costs and expenses and $2.6 million for general and administrative costs. For the three months ended June 30, 2008, we reimbursed EPCO $17.0 million for operating costs and expenses and $4.0 million for general and administrative costs. For the six months ended June 30, 2009 and 2008, we reimbursed EPCO $39.1 million and $36.1 million, respectively, for operating costs and expenses along with $4.9 million and $8.4 million, respectively, for general and administrative costs.

Relationship with Evangeline

Evangeline has entered into a natural gas purchase contract with Acadian Gas that contains annual purchase provisions. The pricing terms of the purchase agreement are based on a monthly weighted-average market price of natural gas (subject to certain market index price ceilings and incentive margins)

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

plus a predetermined margin. Acadian Gas sold $39.9 million and $94.6 million of natural gas to Evangeline during the three months ended June 30, 2009 and 2008, respectively. For the six months ended June 30, 2009 and 2008, Acadian Gas sold $93.5 million and $147.7 million of natural gas, respectively, to Evangeline. The amount of natural gas purchased by Evangeline pursuant to this contract totaled 4.99 trillion British thermal units (“TBtus”) and 5.24 TBtus during the three months ended June 30, 2009 and 2008, respectively. For the six months ended June 30, 2009 and 2008, Acadian Gas sold 8.14 TBtus and 8.58 TBtus, respectively, to Evangeline.

The Partnership has furnished letters of credit on behalf of Evangeline’s debt service requirements. The outstanding letters of credit totaled $1.0 million at June 30, 2009.

Relationship with Energy Transfer Equity

In May 2007, Enterprise GP Holdings acquired equity method investments in, and therefore is a related party to, Energy Transfer Equity and its general partner. 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.

Relationship with TEPPCO

Beginning in 2008, Mont Belvieu Caverns commenced providing NGL and petrochemical storage services to TEPPCO. For the period January 2007 through March 2008, we leased from TEPPCO an 11-mile pipeline that was part of our South Texas NGL System. We discontinued this lease during the first quarter of 2008 when we completed the construction of a parallel pipeline.

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 units (see Note 10) outstanding during a period. The Class B units received a pro-rated distribution of $0.1115 per unit with respect to the fourth quarter of 2008 based on the distribution of $0.4275 per unit paid to our common unitholders. 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						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Net income attributable to Duncan Energy Partners L.P.	$	23.2		$	13.3		$	43.1		$	26.6
Less: Income allocated to former owners of DEP II Midstream Businesses		--			6.7			--			14.0
Net income allocated to Duncan Energy Partners		23.2			6.6			43.1			12.6
Multiplied by DEP GP ownership interest		0.7	%		2.0	%		0.7	%		2.0	%
Net income allocation to DEP GP	$	0.2		$	0.1		$	0.3		$	0.2

From the closing of our IPO on February 5, 2007 through December 7, 2008, DEP GP maintained a 2.0% general partner interest in us. On December 8, 2008, DEP GP elected to forego making a cash contribution to us to maintain its 2.0% general partner interest in connection with the DEP II dropdown transaction. As a result, DEP GP’s general partner interest was reduced to 0.7% beginning December 8, 2008.

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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						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Net income attributable to Duncan Energy Partners L.P. after
allocation to former owners	$	23.2		$	6.6		$	43.1		$	12.6
Less: Income allocation to DEP GP		(0.2	)		(0.1	)		(0.3	)		(0.2	)
Net income allocation to limited partners	$	23.0		$	6.5		$	42.8		$	12.4

Basic and diluted earnings per unit:
Numerator (net income allocation to limited partners)	$	23.0		$	6.5		$	42.8		$	12.4
Denominator (weighted-average units outstanding, in millions):
Common units		57.7			20.3			57.7			20.3

Earnings per unit	$	0.40		$	0.32		$	0.74		$	0.61

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 activities. We are not aware of any litigation, pending or threatened, that may 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 June 30, 2009 and December 31, 2008, NGL and petrochemical products aggregating 27.2 million barrels and 22.5 million barrels, respectively, were due to be redelivered to their owners along with 7.3 TBtus and 6.4 TBtus, respectively, of natural gas.

Regulatory Matters

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” or “GHGs” and including carbon dioxide and methane, may be contributing to climate change. On April 17, 2009, the U.S. Environmental Protection Agency (“EPA”) issued a notice of its proposed finding and determination that emission of carbon dioxide, methane, and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere. The EPA’s finding and determination would allow it to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. Although it may take the EPA several years to adopt and impose regulations limiting emissions of GHGs, any such regulation could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, on June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or “ACESA.” ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances”

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

corresponding to their annual emissions of GHGs. The U.S. Senate has also begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs 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 Annual Report on Form 10-K for the year ended December 31, 2008.

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 Annual Report on Form 10-K for the year ended December 31, 2008.

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. Lease and rental expense was $2.7 million and $3.0 million during the three months ended June 30, 2009 and 2008, respectively. During the six months ended June 30, 2009 and 2008, lease and rental expense was $4.4 million and $5.5 million, respectively.

Purchase obligations. There have been no material changes in our consolidated purchase obligations since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008.

Insurance Matters

EPCO completed its annual insurance renewal process during the second quarter of 2009. In light of recent hurricane and other weather-related events, the renewal of policies for weather-related risks resulted in significant increases in premiums and certain deductibles, as well as changes in the scope of coverage.

EPCO’s deductible for onshore physical damage from windstorms increased from $10.0 million per storm to $25.0 million per storm. EPCO’s onshore program currently provides $150 million per occurrence for named windstorm events compared to $175 million per occurrence in the prior year. With respect to offshore assets, the windstorm deductible increased significantly from $10.0 million per storm (with a one-time aggregate deductible of $15.0 million) to $75.0 million per storm. EPCO’s offshore program currently provides $100 million in the aggregate compared to $175 million in the aggregate for the prior year. For non-windstorm events, EPCO’s deductible for both onshore and offshore physical damage remained at $5.0 million per occurrence.

Business interruption coverage in connection with a windstorm event remained unchanged for onshore assets, but was eliminated for offshore assets. Onshore assets covered by business interruption insurance must be out-of-service in excess of 60 days before any losses from business interruptions will be covered. Furthermore, EPCO will now absorb 50% of the first $50.0 million of any loss in excess of deductible amounts for our onshore assets.

In the third quarter of 2008, certain of our facilities located along the Gulf Coast of Texas and Louisiana were damaged by Hurricanes Gustav and Ike. As a result of our allocated share of EPCO’s

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DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

insurance deductibles for windstorm coverage, we expensed a combined cumulative total of $2.1 million of repair costs for property damage in connection with these two storms through June 30, 2009.

Note 16. Supplemental Cash Flow Information

Third parties may be obligated to reimburse us for all or a portion of expenditures on certain of our capital projects. The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins. We received $2.7 million and $6.0 million as contributions in aid of our construction costs during the six months ended June 30, 2009 and 2008, respectively.

The net effect of changes in operating assets and liabilities is as follows for the periods indicated:

	For the Six Months
	Ended June 30,
	2009			2008
Decrease (increase) in:
Accounts receivable - trade	$	34.9		$	(70.6	)
Accounts receivable - related parties		(3.1	)		(4.5	)
Inventories		20.7			(3.2	)
Prepaid and other current assets		(5.6	)		(0.7	)
Increase (decrease) in:
Accounts payable - trade		0.3			(9.5	)
Accounts payable - related parties		(20.1	)		(29.4	)
Accrued products payable		(47.0	)		75.5
Accrued expenses		2.6			(4.4	)
Accrued property taxes		3.4			2.9
Other current liabilities		(9.6	)		1.2
Other long-term liabilities		(0.1	)		(1.1	)
Net effect of changes in operating accounts	$	(23.6	)	$	(43.8	)

We incurred liabilities for construction in progress that had not been paid at June 30, 2009 and December 31, 2008 of $41.1 million and $30.5 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Unaudited Condensed Statements of Consolidated Cash Flows.

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

	For the Three Months					For the Six Months
	Ended June 30,					Ended June 30,
	2009			2008		2009			2008
Depreciation and amortization:
DEP I Midstream Businesses	$	9.6		$	8.8	$	18.8		$	16.5
DEP II Midstream Businesses		33.9			31.2		66.9			61.0
Accretion expense:
DEP I Midstream Businesses
DEP II Midstream Businesses		(0.3	)		0.1		(0.2	)		0.1
Total	$	43.2		$	40.1	$	85.5		$	77.6

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

For the three and six months ended June 30, 2009 and 2008.

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 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 in our Annual Report on Form 10-K for the year ended December 31, 2008. Our financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).

Key References Used in this Quarterly Report

Unless the context requires otherwise, references to “we,” “us,” “our,” “the Partnership” 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 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 “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners.

References to “Enterprise Products Partners” mean Enterprise Products Partners L.P., which owns Enterprise Products Operating LLC (“EPO”). Enterprise Products Partners is a publicly traded partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” EPO, our Parent, owns our general partner and is a significant owner of our common units. References to “EPGP” mean Enterprise Products GP, LLC, the general partner of Enterprise Products Partners.

References to “TEPPCO” mean TEPPCO Partners, L.P., an affiliated publicly traded partnership, the common units of which are listed on the NYSE under the ticker symbol “TPP.” References to “TEPPCO GP” mean Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO.

References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., a publicly traded affiliate, the units of which are listed on the NYSE under the ticker symbol “EPE.” EPGP and TEPPCO GP are both wholly owned by Enterprise GP Holdings.

References to “EPCO” mean EPCO, Inc., which is a related party affiliate to all of the foregoing named entities.

All of the aforementioned entities are affiliates and under common control of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.

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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
Bcf		= billion cubic feet

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,” “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 expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions as described in more detail in Item 1A “Risk Factors” included in our Annual Report on Form 10-K for 2008. 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.

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 Annual Report on Form 10-K for the year ended December 31, 2008. 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.

Overview of Business

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 (“NGL”) transportation and fractionation; (ii) the storage of NGL and petrochemical products; (iii) the transportation of petrochemical products; (iv) the gathering, transportation and storage of natural gas; and (v) the marketing of NGLs and natural gas.

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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 conduct substantially all of our business through DEP OLP. At June 30, 2009, we were owned 99.3% by our limited partners and 0.7% by DEP GP. At August 1, 2009, EPO owned approximately 58% of our limited partner interests and 100% of our general partner. DEP GP is responsible, as general partner, for managing our business and operations.

Our business purpose is to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO and other commonly-controlled affiliates. One of our principal advantages is our relationship with EPO and EPCO. 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 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 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. See Note 13 of Item 1 of this Quarterly Report for additional information regarding our relationship with EPO and EPCO.

Basis of Financial Statement Presentation

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

§	Mont Belvieu Caverns owns 34 salt dome caverns located in Mont Belvieu, Texas, with an underground NGL and petrochemical 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 gathers, transports, stores and markets natural gas in Louisiana utilizing over 1,000 miles of transmission, lateral and gathering pipelines with an aggregate throughput capacity of one billion cubic feet per day (“Bcf/d”). Acadian Gas also owns a 49.51% equity interest in Evangeline Gas Pipeline Company, L.P. (“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 Duncan Energy Partners’ Shoup and Armstrong NGL fractionation plants located in South Texas to Mont Belvieu, Texas. This pipeline commenced operations in January 2007.

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On December 8, 2008, Duncan Energy Partners entered into a Purchase and Sale Agreement (the “DEP II Purchase Agreement”) with EPO and Enterprise GTM Holdings L.P. (“Enterprise GTM,” a wholly owned subsidiary of EPO). Pursuant to the DEP II Purchase Agreement, DEP OLP acquired 100% of the membership interests in Enterprise Holding III, LLC (“Enterprise III”) from Enterprise GTM, thereby acquiring a 66% general partner interest in Enterprise GC, L.P. (“Enterprise GC”), a 51% general partner interest in Enterprise Intrastate L.P. (“Enterprise Intrastate”) and a 51% membership interest in Enterprise Texas Pipeline LLC (“Enterprise Texas”). Collectively, we refer to Enterprise GC, Enterprise Intrastate and Enterprise Texas as the “DEP II Midstream Businesses.” EPO was the sponsor of this second dropdown transaction.

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

Enterprise GC owns (i) the Shoup and Armstrong NGL fractionation facilities located in South Texas, (ii) a 1,020-mile NGL pipeline system located in South Texas and (iii) 944 miles of natural gas gathering pipelines located in South and West Texas. Enterprise GC’s natural gas gathering pipelines include (i) the 272-mile Big Thicket Gathering System located in Southeast Texas, (ii) the 465-mile Waha system located in the Permian Basin of West Texas and (iii) the 207-mile TPC gathering system.

§	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 6,547-mile Enterprise Texas natural gas pipeline system and leases the Wilson natural gas storage facility. The Enterprise Texas system, along with the Waha, TPC and Channel pipeline systems, comprise the Texas Intrastate System.

References to the “former owners” of the DEP I and DEP II Midstream Businesses represent the ownership of EPO in these businesses prior to the effective date of the related dropdown transactions.

For additional information regarding the dropdowns of the DEP I and DEP II Midstream Businesses, as well as the recast of our historical financial information in connection with the DEP II dropdown transaction, please read Note 1 of the Notes to Consolidated Financial Statements included under Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2008.

Our results of operations for the three and six months ended June 30, 2009 are not necessarily indicative of results expected for the full year.

Recent Developments

June 2009 equity offering

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were used to repurchase an equal number of our common units beneficially owned by EPO. The repurchased common units were subsequently cancelled.

Service Begins on Sherman Extension Pipeline

In late February 2009, we and Enterprise Products Partners announced that construction had been completed on the 174-mile Sherman Extension expansion of our Texas Intrastate System, which extends through the heart of the prolific Barnett Shale natural gas play of North Texas. The completion of the Sherman Extension adds 1.1 Bcf/d of incremental natural gas takeaway capacity from the region, while providing producers in the Barnett Shale, and as far away as the Waha area of West Texas, with greater flexibility to reach the most attractive natural gas markets. The Texas Intrastate System is part of our Natural Gas Pipelines & Services business segment.

Since being placed in service, the Sherman Extension has been in very limited service due to pipeline integrity issues on the connecting third party take-away pipeline, the Gulf Crossing Pipeline owned by Boardwalk Pipeline Partners, LP. The Gulf Crossing Pipeline began ramping up its operations on August 1, 2009. As a result, the Sherman Extension started billing its demand charges at 95% of contracted volumes, which are 950 MMcf/d; however, due to price location differentials, we are currently flowing approximately 650 MMcf/d. The demand charges are approximately $5.0 million a month.

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, which for purposes of this supplemental financial information includes DEP OLP. 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 through DEP OLP.

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 L.P. 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 subsidiaries, including DEP OLP. 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 DEP GP may also affect the distributions Duncan Energy Partners L.P. makes to its unitholders.

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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. This information is not recast to include amounts attributable to the former owners of the DEP II Midstream Businesses. Furthermore, amounts presented for fiscal 2007 represent the eleven-month period from our initial public offering (effective February 1, 2007) through December 31, 2007. Amounts presented for the DEP II Midstream Businesses for fiscal 2008 represent the period from December 8, 2008 to December 31, 2008.

											Twelve		Eleven
	Three Months					Six Months					Months		Months
	Ended June 30,					Ended June 30,					Ended December 31,
	2009			2008		2009			2008		2008		2007
	(Dollars in millions)
Selected income statement information:
Equity in income - DEP I Midstream Businesses	$	11.4		$	10.0	$	19.8		$	19.3	$	37.2	$	30.0
Equity in income - DEP II Midstream Businesses	$	15.3		$	--	$	30.7		$	--	$	4.5	$	--
General and administrative costs	$	0.1		$	0.7	$	0.2		$	1.2	$	1.4	$	1.5
Interest expense	$	3.4		$	2.7	$	7.2		$	5.5	$	11.9	$	9.3
Net income attributable to Duncan Energy Partners L.P.	$	23.2		$	6.6	$	43.1		$	12.6	$	28.4	$	19.2
Selected cash flow statement information:
Cash distributions received from DEP I Midstream Businesses	$	10.1		$	16.5	$	27.6		$	56.3	$	93.7	$	115.3
Cash distributions received from DEP II Midstream Businesses	$	21.6		$	--	$	38.8		$	--	$	4.0	$	--
Investments in DEP I Midstream Businesses:
Payment to EPO for DEP I dropdown	$	--		$	--	$	--		$	--	$	--	$	459.6
Post-DEP I dropdown transactions	$	--		$	11.6	$	1.8		$	40.6	$	54.0	$	110.7
Investments in DEP II Midstream Businesses:	$	--		$	--	$	--		$	--	$	280.5	$	--
Proceeds from the issuance of common units:
Initial public offering in February 2007	$	--		$	--	$	--		$	--	$	--	$	290.5
In connection with DEP II dropdown	$	--		$	--	$	--		$	--	$	0.5	$	--
In connection with June 2009 offering	$	123.2		$	--	$	123.2		$	--	$	--	$	--
Treasury units repurchased and retired	$	122.9		$	--	$	122.9		$	--	$	--	$	--
Cash distributions to partners	$	25.0		$	8.5	$	38.1		$	17.0	$	34.4	$	21.8
Net borrowings (repayments) under loan agreements	$	(3.5	)	$	20.0	$	(17.5	)	$	8.0	$	284.3	$	200.0
Selected balance sheet information at each period end:
Investments in DEP I Midstream Businesses	$	506.7		$	518.8	$	506.7		$	518.8	$	512.7	$	502.7
Investments in DEP II Midstream Businesses	$	723.5		$	--	$	723.5		$	--	$	730.5	$	--
Long-term debt	$	466.8		$	208.0	$	466.8		$	208.0	$	484.3	$	200.0
Partners’ equity	$	761.9		$	310.2	$	761.9		$	310.2	$	752.8	$	314.6

As presented in the preceding table, cash distributions received by Duncan Energy Partners L.P. from the DEP I and DEP II Midstream Businesses reflect actual receipts during each period. The following table presents the amount of distributions paid by each group of businesses with respect to each period. Differences in distributions received during each period and amounts paid to Duncan Energy Partners L.P. with respect to each period are attributed to timing (i.e., amounts paid with respect to each period are generally received in the following period).

									Twelve		Eleven
	Three Months				Six Months				Months		Months
	Ended June 30,				Ended June 30,				Ended December 31,
	2009		2008		2009		2008		2008		2007
	(Dollars in millions)
Distributions paid to Duncan Energy Partners L.P.
with respect to each period from:
DEP I Midstream Businesses	$	10.1	$	16.5	$	27.6	$	56.3	$	93.7	$	115.3
DEP II Midstream Businesses	$	21.6	$	--	$	43.3	$	--	$	5.6	$	--

With respect to the DEP II Midstream Businesses, Duncan Energy Partners L.P. received its full priority return during each applicable period. Including amounts paid to EPO, total cash distributions by the DEP II Midstream Businesses with respect to each period were (i) $21.6 million and $54.2 million for the three and six months ended June 30, 2009, respectively, and (ii) $5.4 million for the period December 8, 2008 to December 31, 2008.

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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 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report on Form 10-Q.

Review of Consolidated Results

Selected Volumetric Data

The following table presents average throughput and fractionation volumes for our principal pipelines and facilities. 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				For the Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
Natural Gas Pipelines & Services, net:
Natural gas throughput volumes (BBtus/d)
Texas Intrastate System		3,982		4,000		4,056		3,901
Acadian Gas System:
Transportation volumes		445		369		414		389
Sales volumes (1)		317		362		302		331
Total natural gas throughput volumes		4,744		4,731		4,772		4,621
NGL Pipelines & Services, net:
NGL throughput volumes (MBPD)
South Texas NGL System - Pipelines		106		127		111		132
NGL fractionation volumes (MBPD)
South Texas NGL System - Fractionators		77		80		78		81
Petrochemical Services, net:
Propylene throughput volumes (MBPD)
Lou-Tex Propylene Pipeline		18		32		15		30
Sabine Propylene Pipeline		10		9		10		10
Total propylene throughput volumes		28		41		25		40

(1) Includes average net sales volumes for Evangeline of 54.8 BBtus/d and 57.6 BBtus/d for the three months ended June 30, 2009 and 2008, respectively. For the six months ended June 30, 2009 and 2008, Evangeline’s sales volumes were 45.0 BBtus/d and 47.2 BBtus/d, respectively.

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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					For the Six Months
	Ended June 30,					Ended June 30,
	2009			2008		2009			2008
Revenues	$	226.7		$	478.8	$	483.5		$	842.4
Operating costs and expenses		215.5			458.7		454.9			796.2
General and administrative costs		2.8			4.5		5.6			9.7
Equity in income of unconsolidated affiliate		0.3			0.2		0.5			0.4
Operating income		8.7			15.8		23.5			36.9
Interest expense		3.4			2.7		7.2			5.5
Provision for income taxes		0.8			0.6		0.9			0.1
Net income		4.5			12.7		15.5			31.6
Net loss (income) attributable to noncontrolling interest:
DEP I Midstream Businesses – Parent		(3.0	)		0.6		(4.6	)		(5.0	)
DEP II Midstream Businesses – Parent		21.7			--		32.2			--
Net income attributable to Duncan Energy Partners L.P.		23.2			13.3		43.1			26.6

Effective January 1, 2009, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) 160, Noncontrolling Interests in Consolidated Financial Statements – an Amendment to ARB No. 51 (Accounting Standards Codification (“ASC”) 810). SFAS 160 established accounting and reporting standards for noncontrolling interests, which were previously identified in our financial statements as Parent interest. This new standard requires, among other things, (i) that noncontrolling interests be presented as a component of equity on our consolidated balance sheet (i.e., elimination of the “mezzanine” presentation previously used for Parent interest); and (ii) the elimination of “Parent interest in income of subsidiaries” amounts as a deduction in deriving net income or loss and, as a result, that net income or loss be allocated between our unitholders and general partner, on one hand, and noncontrolling interests on the other. Earnings per unit amounts are not affected by these changes.

The consolidated financial statements accompanying this Quarterly Report on Form 10-Q reflect the changes required by SFAS 160. As a result, consolidated net income reported for the three and six months ended June 30, 2008 is higher than that previously disclosed; however, the allocation of such net income in accordance with SFAS 160 results in our unitholders, general partner and Parent (i.e., the noncontrolling interest) receiving the same amounts as they did previously. 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.

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

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
Natural Gas Pipelines & Services	$	30.2	$	43.9	$	69.0	$	84.7
NGL Pipelines & Services		24.2		14.8		45.0		37.5
Petrochemical Services		2.6		3.4		5.1		6.3
Total segment gross operating margin	$	57.0	$	62.1	$	119.1	$	128.5

For a reconciliation of non-GAAP gross operating margin to GAAP operating income and further to GAAP net income, 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 (including the effects of eliminations and adjustments) during the periods indicated (dollars in millions):

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
Natural Gas Pipelines & Services:
Sales of natural gas	$	91.8	$	326.1	$	216.7	$	555.3
Natural gas transportation services		69.8		83.8		145.0		158.2
Natural gas storage services		4.3		1.8		6.8		3.1
Total		165.9		411.7		368.5		716.6
NGL Pipelines & Services:
Sales of NGLs		8.7		16.9		14.9		28.5
Sales of other products		2.5		5.5		6.3		8.8
NGL and petrochemical storage services		25.6		21.3		49.7		40.7
NGL fractionation services		7.4		7.8		14.8		15.6
NGL transportation services		12.5		10.9		21.2		23.0
Other services		0.8		0.5		1.4		1.2
Total		57.5		62.9		108.3		117.8
Petrochemical Services:
Propylene transportation services		3.3		4.2		6.7		8.0
Total consolidated revenues	$	226.7	$	478.8	$	483.5	$	842.4

Comparison of the Three Months Ended June 30, 2009 with the Three Months Ended June 30, 2008

Revenues for the second quarter of 2009 were $226.7 million compared to $478.8 million for the second quarter of 2008. The $252.1 million quarter-to-quarter decrease in consolidated revenues is primarily due to lower energy commodity sales prices during the second quarter of 2009 relative to the second quarter of 2008. This factor accounted for a $245.5 million quarter-to-quarter decrease in consolidated revenues from our marketing activities largely due to lower natural gas sales. Revenues from natural gas transportation and storage services decreased $11.5 million quarter-to-quarter primarily due to lower revenues associated with aggregating and bundling services whereby we purchase and resell natural gas for certain producers connected to our Texas Intrastate System and earn a gathering fee based on pricing differentials. The quarter-to-quarter decrease in consolidated revenues attributable to this activity is due to lower natural gas prices. Collectively, revenues from NGL fractionation, transportation and storage services increased $5.8 million quarter-to-quarter primarily due to higher NGL storage volumes and fees during the second quarter of 2009 relative to the second quarter of 2008. Revenues from propylene transportation decreased $0.9 million quarter-to-quarter due to lower transportation volumes.

Operating costs and expenses were $215.5 million for the second quarter of 2009 compared to $458.7 million for the second quarter of 2008, a $243.2 million quarter-to-quarter decrease. The cost of sales of our natural gas and NGL products decreased $241.1 million quarter-to-quarter as a result of lower volumes and energy commodity prices. Costs and expenses of our natural gas transportation and storage

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services decreased $0.6 million quarter-to-quarter. This reflects a $15.7 million quarter-to-quarter decrease in operating costs and expenses associated with aggregating and bundling services on our Texas Intrastate System due to lower natural gas prices, which was partially offset by an increase in expenses for pipeline integrity assessments, maintenance and ad valorem taxes.

Costs and expenses of our NGL fractionation, transportation and storage services decreased $5.2 million quarter-to-quarter primarily due to lower operational measurement losses at our Mont Belvieu Storage complex, which are allocated to EPO through noncontrolling interest. Collectively, the remainder of our consolidated operating costs and expenses increased $3.8 million quarter-to-quarter primarily due to higher depreciation expense attributable to the recently completed Sherman Extension of our Texas Intrastate System.

These changes in our revenues and operating costs and expenses quarter-to-quarter are explained primarily by changes in energy commodity prices. The market price of natural gas (as measured at Henry Hub) decreased 68% to an average of $3.51 per MMBtu during the second quarter of 2009 versus an average of $10.94 per MMBtu during the second quarter of 2008. The weighted-average indicative market price for NGLs was $0.76 per gallon during the second quarter of 2009 versus $1.70 per gallon during the second quarter of 2008 – a 55% decrease quarter-to-quarter. 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 were $2.8 million for the second quarter of 2009 compared to $4.5 million for the second quarter of 2008. The $1.7 million quarter-to-quarter decrease in general and administrative costs is primarily due to lower costs associated with the DEP II Midstream Businesses.

Operating income for the second quarter of 2009 was $8.7 million compared to $15.8 million for the second quarter of 2008. Consolidated revenues and certain operating costs and expenses can fluctuate significantly due to changes in energy commodity prices (e.g., the price of natural gas and NGLs) without necessarily affecting our operating income to the same degree. Consequently, the aforementioned changes in revenues and costs and expenses contributed to the $7.1 million quarter-to-quarter decrease in operating income.

Interest expense increased $0.7 million quarter-to-quarter primarily due to borrowings we made in connection with the DEP II dropdown transaction in December 2008. Provision for income taxes increased $0.2 million quarter-to-quarter.

As a result of items noted in the previous paragraphs, net income decreased $8.2 million quarter-to-quarter to $4.5 million for the second quarter of 2009 compared to $12.7 million for the second quarter of 2008.

We account for EPO’s share of the net income of the DEP I and DEP II Midstream Businesses as noncontrolling interest, which is a deduction from total net income to arrive at the amount of net income attributable to Duncan Energy Partners L.P. EPO was attributed $3.0 million of the net income of the DEP I Midstream Businesses during the second quarter of 2009 compared to a loss of $0.6 million during the second quarter of 2008. EPO benefited from a $4.4 million quarter-to-quarter decrease in operational measurement losses (EPO is allocated 100% of such losses), partially offset by a decrease in overall net income of the DEP I Midstream Businesses for the second quarter of 2009 compared to the same period in 2008.

EPO was attributed $21.7 million of losses in connection with its ownership interests in the DEP II Midstream Businesses during the second quarter of 2009. In the aggregate, the DEP II Midstream Businesses distributed $21.6 million of cash and posted a net loss of $6.4 million with respect to the three months ended June 30, 2009. The net loss is primarily due to lower earnings from the Texas Intrastate System. As a result of its priority return rights in the DEP II Midstream Businesses, Duncan Energy Partners received its full quarterly cash distribution of $21.6 million and was attributed income of $15.3 million from these businesses. EPO is attributed a loss to the extent that aggregate net income for the DEP

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II Midstream Businesses is less than the income attributed by these businesses to Duncan Energy Partners. EPO received $13 thousand in cash distributions from the DEP II Midstream Businesses with respect to the second quarter of 2009. For additional information regarding the calculation of noncontrolling interest, see Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report on Form 10-Q.

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 $30.2 million for the second quarter of 2009 compared to $43.9 million for the second quarter of 2008, a $13.7 million quarter-to-quarter decrease. Total natural gas throughput volumes were 4,744 BBtus/d for the second quarter of 2009 compared to 4,731 BBtus/d for the second quarter of 2008. Gross operating margin from our natural gas pipelines decreased $15.9 million quarter-to-quarter primarily due to lower revenues from condensate sales, a decrease in natural gas sales volumes and sales margins on the Acadian Gas System and higher expenses for pipeline integrity and property taxes on our Texas Intrastate System. Gross operating margin from our Wilson natural gas storage facility increased $2.2 million quarter-to-quarter due to higher firm storage reservation fees earned during the second quarter of 2009 compared to the second quarter of 2008.

NGL Pipelines & Services. Gross operating margin from this business segment was $24.2 million for the second quarter of 2009 compared to $14.8 million for the second quarter of 2008, a $9.4 million quarter-to-quarter increase. Gross operating margin from our Mont Belvieu Storage complex increased $10.0 million quarter-to-quarter, which reflects operational measurement losses of $1.3 million for the second quarter of 2009 compared to operational measurement losses of $5.7 million for the second quarter of 2008. Although operational measurement gains and losses are included in gross operating margin, they are allocated to EPO through noncontrolling interest; thus, such gains and losses are excluded from net income attributable to Duncan Energy Partners. Net of operational measurement gains and losses, gross operating margin from our Mont Belvieu Storage complex increased $5.6 million quarter-to-quarter as a result of higher storage volumes and fees. Collectively, gross operating margin from the remainder of this business segment decreased $0.6 million quarter-to-quarter primarily due to lower NGL sales margins during the second quarter of 2009 relative to the second quarter of 2008.

Petrochemical Services. Gross operating margin from this business segment was $2.6 million for the second quarter of 2009 compared to $3.4 million for the second quarter of 2008. Petrochemical throughput volumes decreased to 28 MBPD during the second quarter of 2009 from 41 MBPD during the second quarter of 2008. The $0.8 million quarter-to-quarter decrease in segment gross operating margin is primarily due to lower throughput volumes on our Lou-Tex Propylene Pipeline.

Comparison of the Six Months Ended June 30, 2009 with the Six Months Ended June 30, 2008

Revenues for the first six months of 2009 were $483.5 million compared to $842.4 million for the first six months of 2008. The $358.9 million period-to-period decrease in consolidated revenues is primarily due to lower energy commodity sales prices during the first six months of 2009 relative to the first six months of 2008. This factor accounted for a $354.7 million period-to-period decrease in consolidated revenues from our marketing activities largely due to lower natural gas sales prices. Revenues from natural gas transportation and storage services decreased $9.5 million period-to-period primarily due to lower revenues associated with aggregating and bundling services we provide to certain producers connected to our Texas Intrastate System. The period-to-period decrease in consolidated revenues attributable to this activity is due to lower natural gas prices. Collectively, revenues from NGL fractionation, transportation and storage services increased $6.6 million period-to-period primarily due to higher NGL storage volumes and fees during the first six months of 2009 relative to the first six months of 2008. Revenues from propylene transportation decreased $1.3 million period-to-period due to lower transportation volumes.

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Operating costs and expenses were $454.9 million for the first six months of 2009 versus $796.2 million for the first six months of 2008, a $341.3 million period-to-period decrease. The cost of sales of our natural gas and NGL products decreased $345.1 million period-to-period as a result of lower volumes and energy commodity prices. Costs and expenses of our natural gas transportation and storage services decreased $1.2 million period-to-period. This reflects an $18.7 million period-to-period decrease in operating costs and expenses associated with aggregating and bundling services on our Texas Intrastate System due to lower natural gas prices, which was partially offset by an increase in expenses for pipeline integrity assessments, maintenance and ad valorem taxes.

Costs and expenses of our NGL fractionation, transportation and storage services decreased $3.1 million period-to-period primarily due to lower operational measurement losses at our Mont Belvieu Storage complex, which are allocated to EPO through noncontrolling interest. Collectively, the remainder of our consolidated operating costs and expenses increased $8.2 million period-to-period primarily due to higher depreciation expense during the first six months of 2009 compared to the first six months of 2008 largely due to our recent completion of the Sherman Extension of our Texas Intrastate System.

These changes in our revenues and operating costs and expenses period-to-period are explained primarily by changes in energy commodity prices. The Henry Hub market price of natural gas decreased 56% to an average of $4.21 per MMBtu during the first six months of 2009 versus an average of $9.49 per MMBtu during the first six months of 2008. The weighted-average indicative market price for NGLs was $0.71 per gallon during the first six months of 2009 versus $1.60 per gallon during the first six months of 2008, a 56% period-to-period decrease.

General and administrative costs were $5.6 million for the first six months of 2009 compared to $9.7 million for the first six months of 2008. The $4.1 million period-to-period decrease in general and administrative costs is primarily due to lower compensation costs associated with the DEP II Midstream Businesses.

Operating income for the first six months of 2009 was $23.5 million compared to $36.9 million for the first six months of 2008. 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. Consequently, the aforementioned changes in revenues and costs and expenses contributed to the $13.4 million period-to-period decrease in operating income.

Interest expense increased $1.7 million period-to-period primarily due to borrowings we made in connection with the DEP II dropdown transaction in December 2008. Provision for income taxes increased $0.8 million period-to-period primarily due to an increase in expenses attributable to the Texas Margin Tax.

As a result of items noted in the previous paragraphs, net income decreased $16.1 million period-to-period to $15.5 million for the first six months of 2009 compared to $31.6 million for the first six months of 2008.

EPO was attributed $4.6 million and $5.0 million of the net income of the DEP I Midstream Businesses during the second quarter of 2009 and 2008, respectively. Although EPO benefited from a $2.3 million period-to-period decrease in operational measurement losses, this benefit was more than offset by the allocation by Mont Belvieu Caverns to EPO of $3.1 million of depreciation expense associated with projects for which EPO had funded 100% of the costs.

EPO was attributed $32.2 million of losses in connection with its ownership interests in the DEP II Midstream Businesses during the six months ended June 30, 2009. In the aggregate, the DEP II Midstream Businesses distributed $54.2 million of cash and posted a net loss of $1.5 million with respect to the six months ended June 30, 2009. The net loss is primarily due to lower earnings from the Texas Intrastate System. As a result of its priority return rights in the DEP II Midstream Businesses, Duncan Energy Partners received its full cash distribution of $43.3 million and was attributed income of $30.7 million from these businesses. EPO is attributed a loss to the extent that aggregate net income for the DEP II Midstream Businesses is less than the income attributed by these businesses to Duncan Energy Partners. EPO received

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$10.9 million in cash distributions from the DEP II Midstream Businesses with respect to the six months ended June 30, 2009. For additional information regarding the calculation of noncontrolling interest, see Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report on Form 10-Q.

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

Natural Gas Pipelines & Services. Gross operating margin from this business segment was $69.0 million for the first six months of 2009 compared to $84.7 million for the first six months of 2008, a $15.7 million period-to-period decrease. Total natural gas throughput volumes were 4,772 BBtus/d for the first six months of 2009 compared to 4,621 BBtus/d for the first six months of 2008. Gross operating margin from our natural gas pipelines decreased $18.6 million period-to-period primarily due to lower revenues from condensate sales, a decrease in natural gas sales volumes and sales margins on the Acadian Gas System and higher operating expenses on our Texas Intrastate System. Collectively, results for the Texas Intrastate and Acadian Gas Systems include $0.4 million of property damage repair expenses during the first six months of 2009 resulting from Hurricanes Gustav and Ike.

Gross operating margin from our Wilson natural gas storage facility increased $2.9 million period-to-period due to higher firm storage reservation fees earned during the first six months of 2009 compared to the first six months of 2008.

NGL Pipelines & Services. Gross operating margin from this business segment was $45.0 million for the first six months of 2009 compared to $37.5 million for the first six months of 2008, a $7.5 million period-to-period increase. Gross operating margin from our Mont Belvieu Storage complex increased $9.7 million period-to-period, which reflects operational measurement losses of $2.6 million for the first six months of 2009 compared to operational measurement losses of $4.9 million for the first six months of 2008. Net of operational measurement gains and losses, gross operating margin from our Mont Belvieu Storage complex increased $7.4 million period-to-period as a result of higher storage revenues due to increased reservation and excess throughput storage fees and increased storage volumes.

Gross operating margin from our South Texas NGL System decreased $1.1 million period-to-period due to lower NGL pipeline transportation and fractionation volumes, which was partially offset by lower fuel costs during the first six moths of 2009 compared to the first six months of 2008. Pipeline transportation volumes on this system decreased to 111 MBPD during the first six months of 2009 from 132 MBPD during the first six months of 2008. NGL fractionation volumes were 78 MBPD during the first six months of 2009 compared to 81 MBPD during the first six months of 2008. Collectively, gross operating margin from the remainder of this business segment decreased $1.1 million period-to-period primarily due to lower NGL sales margins.

Petrochemical Services. Gross operating margin from this business segment was $5.1 million for the first six months of 2009 compared to $6.3 million for the first six months of 2008. Petrochemical throughput volumes decreased to 25 MBPD during the first six months of 2009 from 40 MBPD during the first six months of 2008. The $1.2 million period-to-period decrease in segment gross operating margin is primarily due to lower throughput volumes on our Lou-Tex 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 are expected to be funded by a variety of sources (either separately or in combination) including operating cash flows, borrowings under credit facilities, cash contributions from our Parent, the issuance of additional equity and debt securities and

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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 June 30, 2009, we had approximately $127.8 million of liquidity, which included $16.4 million of unrestricted cash on hand and approximately $111.4 million of credit available under the Revolving Credit Facility. At June 30, 2009, our total debt balance was $466.8 million, which consists of $184.5 million outstanding under the Revolving Credit Facility and $282.3 million under the Term Loan Agreement. In addition, we had a $1.0 million letter of credit outstanding under the Revolving Credit Facility. 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 June 30, 2009.

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 us in meeting our liquidity and capital spending requirements. We have a universal shelf registration statement on file with the Securities Exchange Commission (“SEC”) that allows us to periodically issue up to $1.00 billion in debt and equity securities. We currently expect to use any proceeds from such offerings under this universal shelf registration statement for general partnership purposes or other purposes to be specified in connection with an offering. After taking into account the issuances of securities under this registration statement, with respect to the June and July 2009 issuances of our common units in connection with our June 2009 equity offering, we can issue approximately $856.4 million of additional securities under this registration statement.

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 Six Months
	Ended June 30,
	2009		2008
Net cash flows provided by operating activities	$	82.4	$	69.2
Cash used in investing activities		223.2		425.3
Cash provided by financing activities		144.2		367.3

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 $82.4 million for the six months ended June 30, 2009 compared to $69.2 million for the six months ended June 30, 2008. The change in operating cash flow is primarily due to a $9.4 million decrease in gross operating margin for the six months ended June 30, 2009 in comparison to the six months ended June 30, 2008 adjusted for the timing of related cash receipts and disbursements.

Investing activities. Cash used in investing activities was $223.2 million for the six months ended June 30, 2009 compared to $425.3 million for the six months ended June 30, 2008. The $202.1 million period-to-period decrease is primarily due to a reduction in growth capital spending for both the DEP I and DEP II Midstream Businesses. During the six months ended June 30, 2008, construction was in progress for the Sherman Extension Pipeline on our Texas Intrastate System, which was subsequently completed in February 2009. Also, during the six months ended June 30, 2008, we completed Phase II of our expansion of our South Texas NGL pipeline and had ongoing projects at our Mont Belvieu storage facility. Capital expenditures, net of contribution in aid of construction costs, decreased $201.8 million period-to-period.

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Financing activities. Cash provided by financing activities was $144.2 million for the six months ended June 30, 2009 compared to $367.3 million for the six months ended June 30, 2008. The decrease of $223.1 million is primarily due to the following:

§	Net contributions received from the former owners of the DEP II Midstream Businesses decreased $266.9 million period-to-period. The DEP II Midstream Businesses operated within the EPO cash management program prior to the dropdown transaction date of December 8, 2008.

Contributions from noncontrolling interests increased $101.7 million period-to-period. Contributions received from Enterprise GTM related to expansion capital projects of the DEP II Midstream Businesses were $192.1 million for the six months ended June 30, 2009. Prior to the dropdown of the DEP II Midstream Businesses, capital expenditures for these projects were funded by the former owners of the DEP II Midstream Businesses. Contributions received from EPO (as Parent) in connection with certain growth capital projects on South Texas NGL and Mont Belvieu Caverns decreased by approximately $90.7 million period-to-period.

Distributions to EPO as noncontrolling interest increased $11.2 million period-to-period. Distributions paid to EPO in connection with its noncontrolling interest in the DEP I Midstream Businesses decreased by approximately $3.7 million for the six months ended June 30, 2009 compared to the six months ended June 30, 2008. Distributions paid to EPO by the DEP II Midstream Businesses were $15.0 million for the six months ended June 30, 2009.

§	Distributions to our unitholders and general partner increased approximately $21.1 million period-to-period due to an increase in our distribution rate to unitholders and the number of distribution-bearing units outstanding.

Capital Expenditures

The following table summarizes our consolidated capital spending for property, plant and equipment for the periods indicated (dollars in millions):

	For the Six Months
	Ended June 30,
	2009		2008
DEP I Midstream Businesses:
Expansion capital spending (1)	$	18.1	$	96.6
Sustaining capital expenditures (2)		6.6		5.3
DEP II Midstream Businesses:
Expansion capital spending (1)		185.2		308.2
Sustaining capital expenditures (2)		16.4		21.3
Total capital spending	$	226.3	$	431.4

(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 six months ended June 30, 2009 and 2008 was attributable to ongoing expansions of the Texas Intrastate System, including the Sherman Extension in North Texas.

Our forecasts of capital expenditures are based on current announced plans. For the remainder of 2009, we estimate that our consolidated capital spending for expansion projects will approximate $183 million, all of which is expected to be funded by EPO. We estimate that our sustaining capital spending for

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the remainder of 2009 will approximate $33 million, of which $9 million and $24 million is attributable to the DEP I and DEP II Midstream Businesses, respectively.

At June 30, 2009, we had approximately $108.3 million in purchase commitments outstanding that relate to our capital spending for property, plant and equipment. These commitments primarily relate to expansion projects on our Texas Intrastate System.

Pipeline Integrity Costs

Our NGL, petrochemical and natural gas pipelines are subject to pipeline safety programs administered by the U.S. Department of Transportation, through its Pipeline and Hazardous Materials Safety Administration, and participating state agencies. These federal and state agencies have 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 areas (such as 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				For the Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
Expensed	$	5.1	$	6.3	$	8.5	$	9.4
Capitalized		3.9		8.1		8.6		10.5
Total	$	9.0	$	14.4	$	17.1	$	19.9

We expect the costs of our pipeline integrity program, irrespective of whether such costs are capitalized or expensed, to approximate $30.2 million for the remaining two quarters of 2009.

Other Items

Contractual Obligations

With the exception of routine fluctuations in the balance of our Revolving Credit Facility, there have been no significant changes in our contractual obligations since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008.

Off-Balance Sheet Arrangements

There have been no significant changes with regards to our off-balance sheet arrangements since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008.

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Summary of Related Party Transactions

The following table summarizes our consolidated balance sheet transactions with related parties for the periods indicated (dollars in millions):

	June 30,		December 31,
	2009		2008
Accounts receivable – related parties
EPO and affiliates	$	5.1	$	2.3
Energy Transfer Equity and affiliates (1)		0.6		0.9
Other		--		0.1
Total	$	5.7	$	3.3

Accounts payable – related parties
EPO and affiliates	$	19.2	$	46.1
EPCO and affiliates		9.2		1.9
TEPPCO and affiliates		--		0.5
Total	$	28.4	$	48.5

(1) Refers to Energy Transfer Equity, L.P. (“Energy Transfer Equity”) and its consolidated subsidiaries.

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

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Revenues:
Revenues from EPO	$	79.5		$	108.3		$	168.6		$	185.7
Sales of natural gas – Evangeline		39.9			94.6			93.5			147.7
Natural gas transportation services – Energy Transfer Equity		--			0.2			0.1			0.5
NGL & petrochemical storage services – TEPPCO		0.4			0.4			0.8			0.4
Total	$	119.8		$	203.5		$	263.0		$	334.3

Operating costs and expenses:
EPCO administrative services agreement	$	19.3		$	17.0		$	39.1		$	36.1
Expenses with EPO		19.4			43.7			45.9			47.4
Purchases of natural gas – Nautilus		(0.1	)		1.3			1.8			3.7
Expenses with Energy Transfer Equity		(0.2	)		(4.0	)		(4.2	)		1.7
Expenses with TEPPCO		--			(0.1	)		(0.1	)		(0.1	)
Total	$	38.4		$	57.9		$	82.5		$	88.8
General and administrative expenses:
EPCO administrative services agreement	$	2.6		$	4.0		$	4.9		$	8.4
Other related party general and administrative costs		0.2			(0.2	)		--			(0.4	)
Total	$	2.8		$	3.8		$	4.9		$	8.0

For additional information regarding our relationships with related parties, see Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

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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						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Total non-GAAP segment gross operating margin	$	57.0		$	62.1		$	119.1		$	128.5
Adjustments to reconcile total non-GAAP segment
gross operating margin to GAAP net income:
Depreciation, amortization and accretion in
operating costs and expenses		(45.7	)		(42.3	)		(90.3	)		(82.4	)
Gain on asset sales and related transactions in
operating costs and expenses		0.2			0.5			0.3			0.5
General and administrative costs		(2.8	)		(4.5	)		(5.6	)		(9.7	)
GAAP operating income		8.7			15.8			23.5			36.9
Other expense, net		(3.4	)		(2.5	)		(7.1	)		(5.2	)
Provision for income taxes		(0.8	)		(0.6	)		(0.9	)		(0.1	)
GAAP net income	$	4.5		$	12.7		$	15.5		$	31.6

Recent Accounting Developments

The accounting standard setting bodies have recently issued the following accounting guidance since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008:

·	FASB Staff Position (“FSP”) Financial Accounting Standard (“FAS”) 157-4 (ASC 820), Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly;

·	FSP FAS 107-1 and APB 28-1 (ASC 825), Interim Disclosures About Fair Value of Financial Instruments;

·	SFAS 165 (ASC 855), Subsequent Events;

·	SFAS 167 (ASC 810), Amendments to FASB Interpretation No. 46(R); and

·	SFAS 168 (ASC 105), The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB No. 162.

For additional information regarding recent accounting developments, see Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

Insurance Matters

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Business interruption coverage in connection with a windstorm event remained unchanged for onshore assets, but was eliminated for offshore assets. Onshore assets covered by business interruption insurance must be out-of-service in excess of 60 days before any losses from business interruptions will be covered. Furthermore, EPO will now absorb 50% of the first $50.0 million of any loss in excess of deductible amounts for onshore assets.

For additional information regarding weather-related risks, including insurance matters in connection with Hurricanes Gustav and Ike, see Note 15 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 to the 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 Annual Report on Form 10-K for the year ended December 31, 2008.

Interest Rate Derivative Instruments

The following table shows the effect of hypothetical price movements on the estimated fair value (“FV”) of our interest rate swap portfolio (dollars in millions).

	Resulting	Portfolio FV at
Scenario	Classification	June 30, 2009		July 21, 2009
FV assuming no change in underlying interest rates	Liability	$	6.7	$	7.0
FV assuming 10% increase in underlying interest rates	Liability		6.4		6.7
FV assuming 10% decrease in underlying interest rates	Liability		7.0		7.3

Commodity Risk Program

The price of natural gas is subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risk associated with such products, Acadian Gas enters into commodity derivative instruments such as forwards, basis swaps and futures contracts.

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% increase or decrease in the underlying quoted market prices of the commodity derivative instruments outstanding. At June 30, 2009, our commodity derivative instrument portfolio’s fair value was immaterial. A 10% increase or decrease in commodity prices would have a nominal impact on the fair value of this portfolio.

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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 chief executive officer (the “CEO”) and our general partner’s chief 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) or in other factors during the second quarter of 2009, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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.

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PART II. OTHER INFORMATION.

Item 1. 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 under Item 1 of this Quarterly Report, which is incorporated herein by reference.

Item 1A. Risk Factors.

In general, there have been no significant changes in our risk factors since December 31, 2008. For a detailed discussion of our risk factors, please read, Item 1A “Risk Factors,” in our Annual Report on Form 10-K for 2008.

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

As discussed in Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements, we sold common units to the public under our universal shelf registration statement and used the net proceeds received from our underwritten offering to repurchase an equal amount of our common units pursuant to a common unit purchase agreement with EPO and Enterprise GTM Holdings L.P.

The following table summarizes our repurchase activity during 2009:

Maximum

Total Number of

Number of Units

Average

of Units Purchased

That May Yet

Total Number of

Price Paid

as Part of Publicly

Be Purchased

Period

Units Purchased

per Unit

Announced Plans

Under the Plans

June 2009

8,000,000

15.36

8,000,000

1,200,000

July 2009

943,400

15.36

943,400

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Submission of Matters to a Vote of Unit Holders.

None.

Item 5. Other Information.

None.

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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	First Amendment to Amended and Restated Partnership Agreement of Duncan Energy Partners L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Form 8-K/A filed January 3, 2008).
3.4	Second Amendment to Amended and Restated Partnership Agreement of Duncan Energy Partners L.P. dated as of November 6, 2008 (incorporated by reference to Exhibit 3.4 to Form 10-Q for the period ended September 30, 2008, filed on November 10, 2008).
3.5	Third Amendment to Amended and Restated Partnership Agreement 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 Amended and Restated Partnership Agreement of Duncan Energy Partners L.P. dated as of June 15, 2009 (incorporated by reference to Exhibit 3.1 to Form 8-K filed June 15, 2009)
3.7	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 for the period ended March 31, 2007, filed on May 4, 2007).
3.8	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 for the period ended September 30, 2008, filed on November 10, 2008).
3.9	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).
3.10	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).
3.11	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).
3.12	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).
4.1	Revolving Credit Agreement, dated as of January 5, 2007, among Duncan Energy Partners L.P., as borrower, Wachovia Bank, National Association, as Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.20 to Amendment No. 2 to Form S-1 Registration Statement (Reg. No. 333-138371) filed January 12, 2007).
4.2	First Amendment to Revolving Credit Agreement, dated as of June 30, 2007, among Duncan Energy Partners L.P., as borrower, Wachovia Bank, National Association, as Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.2 to the Form 10-Q filed on August 8, 2007).
4.3	Term Loan Agreement, dated as of April 18, 2008, among Duncan Energy Partners L.P., the lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, SunTrust Bank and The Bank of Nova Scotia, as Co-Syndication Agents, and Mizuho Corporate Bank, Ltd. and The Royal Bank of Scotland plc, as Co-Documentation Agents (incorporated by reference to Exhibit 10.7 of Form 8-K filed December 8, 2008).

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4.4	First Amendment to Term Loan Agreement, dated as of July 11, 2008, among Duncan Energy Partners L.P., Wachovia Bank, National Association, as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.8 of Form 8-K filed December 8, 2008).
10.1	Fifth Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC, Enterprise Products OLPGP, Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership L.P., TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, LLC, TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc. dated January 30, 2009 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by Enterprise Products Partners L.P. on February 5, 2009).
10.2	Common Unit Purchase Agreement, dated June 15, 2009, by and among Enterprise Products Operating LLC, Enterprise GTM Holdings L.P. and Duncan Energy Partners L.P. (incorporated by reference to Exhibit 1.2 to the Form 8-K filed June 18, 2009).
31.1#	Sarbanes-Oxley Section 302 certification of Richard H. Bachmann for Duncan Energy Partners L.P. for the June 30, 2009 Quarterly Report on Form 10-Q
31.2#	Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Duncan Energy Partners L.P. for the June 30, 2009 Quarterly Report on Form 10-Q.
32.1#	Section 1350 certification of Richard H. Bachmann for the June 30, 2009 Quarterly Report on Form 10-Q.
32.2#	Section 1350 certification of W. Randall Fowler for the June 30, 2009 Quarterly Report on Form 10-Q.

*	With respect to exhibits incorporated by reference to Exchange Act filings, the Commission file number for Enterprise Products Partners L.P. is 1-14323; Enterprise GP Holdings L.P., 1-32610; and Duncan Energy Partners L.P., 1-33266.
#	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 August 10, 2009.

					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

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exhibit31_1.htm

EXHIBIT 31.1

CERTIFICATIONS

I, Richard H. Bachmann, 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;

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):

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: August 10, 2009		/s/ Richard H. Bachmann
		Name: Richard H. Bachmann
		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, 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:

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):

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: August 10, 2009		/s/ W. Randall Fowler
		Name: W. Randall Fowler
		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 RICHARD H. BACHMANN, 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 quarterly period ended June 30, 2009 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Richard H. Bachmann, 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/ Richard H. Bachmann

Name: Richard H. Bachmann

Title: Chief Executive Officer of DEP Holdings, LLC,

the General Partner of Duncan Energy Partners L.P.

Date: August 10, 2009

exhibit32_2.htm

EXHIBIT 32.2

SARBANES-OXLEY SECTION 906 CERTIFICATION

CERTIFICATION OF W. RANDALL FOWLER, 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 quarterly period ended June 30, 2009 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, W. Randall Fowler, 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/ W. Randall Fowler

Name: W. Randall Fowler

Title: Chief Financial Officer of DEP Holdings, LLC

the General Partner of Duncan Energy Partners L.P.

Date: August 10, 2009