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Document And Entity Information - USD ($) $ in Millions	6 Months Ended
Jun. 30, 2011	Jul. 31, 2011	Jun. 30, 2010
Entity Registrant Name	Duncan Energy Partners L.P.
Entity Central Index Key	0001379378
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 620.5
Entity Common Stock, Shares Outstanding		57,792,270
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2011

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 18.6	$ 32.4
Accounts receivable - trade, net of allowance for doubtful accounts of $0.5 and $0.4 at June 30, 2011 and December 31, 2010, respectively.	77.5	66.0
Accounts receivable - related parties	55.1	21.1
Gas imbalance receivables	2.6	11.5
Inventories	15.9	5.8
Prepaid and other current assets	24.6	19.3
Total current assets	194.3	156.1
Property, plant and equipment, net	6,193.9	5,362.2
Investment in Evangeline	5.6	6.4
Intangible assets, net of accumulated amortization of $54.7 and $50.8 at June 30, 2011 and December 31, 2010, respectively.	34.1	38.0
Goodwill	4.9	4.9
Other assets (see Note 16)	40.4	4.3
Total assets	6,473.2	5,571.9
Current liabilities:
Current maturities of debt	282.3	282.3
Accounts payable - trade	197.1	99.3
Accounts payable - related parties	74.3	26.8
Accrued product payables	50.9	60.5
Accrued costs and expenses	18.4	11.5
Other current liabilities	56.1	47.2
Total current liabilities	679.1	527.6
Long-term debt (see Note 9)	867.5	506.0
Deferred tax liabilities	5.9	5.3
Other long-term liabilities	14.9	13.4
Limited partners:
Common units (57,792,270 and 57,749,158 common units outstanding at June 30, 2011 and December 31, 2010, respectively)	754.2	760.3
General partner	(0.1)	0.1
Total partners' equity	754.1	760.4
Noncontrolling interest in subsidiaries: (see Note 11)
DEP I Midstream Businesses - Parent	875.0	686.7
DEP II Midstream Businesses - Parent	3,276.7	3,072.5
Total noncontrolling interest	4,151.7	3,759.2
Total equity	4,905.8	4,519.6
Total liabilities and equity	$ 6,473.2	$ 5,571.9

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Revenues:
Third parties	$ 140.0	$ 124.2	$ 283.1	$ 282.4
Related parties	162.8	141.0	302.9	273.4
Total revenues (see Note 12)	302.8	265.2	586.0	555.8
Operating costs and expenses:
Third parties	213.2	204.1	403.5	429.8
Related parties	54.6	41.0	121.3	82.5
Total operating costs and expenses	267.8	245.1	524.8	512.3
General and administrative costs:
Third parties	1.7	1.5	2.3	2.2
Related parties	4.8	3.3	8.8	7.5
Total general and administrative costs	6.5	4.8	11.1	9.7
Total costs and expenses (see Note 12)	274.3	249.9	535.9	522.0
Equity in income of Evangeline	0.5	0.0	0.8	0.2
Operating income	29.0	15.3	50.9	34.0
Interest expense	2.9	3.2	6.0	6.3
Income before provision for income taxes	26.1	12.1	44.9	27.7
Provision for income taxes	(0.5)	(0.3)	(1.0)	(0.2)
Net income	25.6	11.8	43.9	27.5
Net loss (income) attributable to noncontrolling interest: (see Note 11)
DEP I Midstream Businesses - Parent	(5.6)	(7.8)	(3.1)	(12.5)
DEP II Midstream Businesses - Parent	2.5	19.3	1.0	29.5
Total net loss (income) attributable to noncontrolling interest	(3.1)	11.5	(2.1)	17.0
Net income attributable to partners (see Note 1)	22.5	23.3	41.8	44.5
Allocation of net income attributable to partners: (see Note 1)
Limited partners' interest in net income	22.3	23.2	41.5	44.2
General partner interest in net income	$ 0.2	$ 0.1	$ 0.3	$ 0.3
Basic and diluted earnings per unit (see Note 14)	$ 0.39	$ 0.40	$ 0.72	$ 0.77

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME [Abstract]
Net income	$ 25.6	$ 11.8	$ 43.9	$ 27.5
Cash flow hedges:
Commodity derivative instrument losses during period	0.0	(0.1)	0.0	(0.1)
Interest rate derivative instrument gains (losses) during period	0.0	0.1	0.0	(0.1)
Reclassification adjustment for losses included in net income related to interest rate derivative instruments	0.0	1.9	0.0	3.8
Total other comprehensive income	0.0	1.9	0.0	3.6
Comprehensive income	25.6	13.7	43.9	31.1
Comprehensive loss (income) attributable to noncontrolling interest:
DEP I Midstream Businesses - Parent	(5.6)	(7.8)	(3.1)	(12.5)
DEP II Midstream Businesses - Parent	2.5	19.3	1.0	29.5
Total comprehensive loss attributable to noncontrolling interest	(3.1)	11.5	(2.1)	17.0
Comprehensive income attributable to partners	$ 22.5	$ 25.2	$ 41.8	$ 48.1

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Operating activities:
Net income	$ 43.9	$ 27.5
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	106.4	100.5
Non-cash asset impairment charges	0.0	1.5
Equity in income of Evangeline	(0.8)	(0.2)
Distribution received from Evangeline	1.5	0.0
Gains from asset sales and related transactions	(0.5)	(1.0)
Deferred income tax expense	0.5	(0.3)
Net effect of changes in operating accounts (see Note 17)	(18.7)	(21.5)
Cash flows provided by operating activities	132.3	106.5
Investing activities:
Capital expenditures	(847.9)	(343.3)
Contributions in aid of construction costs	4.9	4.6
Proceeds from sale of assets and related transactions	0.1	2.3
Other, including loans to EPO (see Note 13)	0.0	45.5
Cash used in investing activities	(842.9)	(290.9)
Financing activities:
Borrowings under bank agreements	419.0	103.1
Repayments of debt under bank agreements	(57.5)	(23.1)
Cash distributions to our unitholders and general partner	(53.1)	(51.9)
Cash distributions to EPO as noncontrolling interest	(62.5)	(40.3)
Cash contributions from EPO as noncontrolling interest	449.4	213.2
Net cash proceeds from the issuance of common units	1.5	0.8
Cash provided by financing activities	696.8	201.8
Net changes in cash and cash equivalents	(13.8)	17.4
Cash and cash equivalents, January 1	32.4	3.9
Cash and cash equivalents, June 30	$ 18.6	$ 21.3

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY - USD ($) $ in Millions	Total	Limited Partners [Member]	General Partner [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest in Subsidiaries [Member]
Balance at Dec. 31, 2009	$ 4,136.9	$ 766.6	$ 0.2	$ (5.4)	$ 3,375.5
Net income (loss)	27.5	44.2	0.3	0.0	(17.0)
Amortization of equity awards	2.0	2.0	0.0	0.0	0.0
Net cash proceeds from the issuance of common units	0.8	0.8	0.0	0.0	0.0
Cash distributions to unitholders and general partner	(51.9)	(51.5)	(0.4)	0.0	0.0
Cash contributions from EPO as noncontrolling interest	213.2	0.0	0.0	0.0	213.2
Cash distributions to EPO as noncontrolling interest	(40.3)	0.0	0.0	0.0	(40.3)
Change in value of cash flow hedges	3.6	0.0	0.0	3.6	0.0
Other	8.1	0.0	0.0	0.0	8.1
Balance at Jun. 30, 2010	4,299.9	762.1	0.1	(1.8)	3,539.5
Balance at Dec. 31, 2010	4,519.6	760.3	0.1	0.0	3,759.2
Net income (loss)	43.9	41.5	0.3		2.1
Amortization of equity awards	3.5	3.5	0.0		0.0
Net cash proceeds from the issuance of common units	1.5	1.5	0.0		0.0
Cash distributions to unitholders and general partner	(53.1)	(52.7)	(0.4)		0.0
Cash contributions from EPO as noncontrolling interest	449.4	0.0	0.0		449.4
Cash distributions to EPO as noncontrolling interest	(62.5)	0.0	0.0		(62.5)
Other	3.5	0.1	(0.1)		3.5
Balance at Jun. 30, 2011	$ 4,905.8	$ 754.2	$ (0.1)	$ 0.0	$ 4,151.7

- Definition

Net of tax effect change in accumulated gains and losses from derivative instruments designated and qualifying as the effective portion of cash flow hedges after taxes. A cash flow hedge is a hedge of the exposure to variability in the cash flows of a recognized asset or liability or a forecasted transaction that is attributable to a particular risk. The change includes an entity's share of an equity investee's increase or decrease in deferred hedging gains or losses. While for technical reasons this element has no balance attribute, the default assumption is a credit balance consistent with its label.

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- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

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+ Details

Partnership Operations, Organization and Basis of Presentation

6 Months Ended

Jun. 30, 2011

Partnership Operations, Organization and Basis of Presentation [Abstract]

Partnership Operations, Organization and Basis of Presentation

Note 1. Partnership Operations, Organization and Basis of Presentation

General

We are a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “DEP.” We were formed in September 2006 and did not own any assets prior to February 5, 2007, which was the date we completed our initial public offering and acquired controlling interests in the DEP I Midstream Businesses from EPO. 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 affiliates of EPCO that are under common control. We are engaged in the business of (i) NGL transportation, fractionation and marketing; (ii) storage of NGL, petrochemical and refined products; (iii) transportation of petrochemical products; and (iv) the gathering, transportation, marketing and storage of natural gas. Our assets, located primarily in Texas and Louisiana, include: 11,201 miles of natural gas, NGL and petrochemical pipelines; two NGL fractionation facilities; approximately 17.3 million barrels (“MMBbls”) of leased NGL storage capacity; 8.1 billion cubic feet (“Bcf”) of leased natural gas storage capacity; and 34 underground salt dome caverns with approximately 100 MMBbls of NGL and related product storage capacity. Our assets are integral to EPO's midstream energy operations and are located near significant natural gas production basins such as the Eagle Ford Shale, Barnett Shale and Haynesville Shale.

We have three reportable business segments: (i) Natural Gas Pipelines & Services; (ii) NGL Pipelines & Services; and (iii) Petrochemical Services. Our business segments reflect the manner in which these businesses are managed and reviewed by the CEO of our general partner. See Note 12 for additional information regarding our business segments.

At June 30, 2011, we are owned 99.3% by our limited partners and 0.7% by our general partner, DEP GP. EPO beneficially owned approximately 58.5% of our limited partner interests and 100% of DEP GP. On April 28, 2011, we and our general partner entered into a definitive merger agreement with Enterprise, Enterprise GP and certain of their subsidiaries. See Note 13 for information regarding the proposed merger with Enterprise.

We, DEP GP, EPO, Enterprise, Enterprise GP, EPCO and Dan Duncan LLC are affiliates and under the collective common control of the DD LLC Trustees and EPCO Trustees. We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. See Note 13 for information regarding the ASA and related party matters.

We acquired controlling ownership interests in our consolidated subsidiaries through two drop down transactions, the DEP I and DEP II drop downs, which were sponsored by EPO. The following information summarizes the businesses acquired in connection with the DEP I and DEP II drop down transactions.

DEP I Drop Down

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

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

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

See Note 16 for information regarding a February 2011 NGL release and fire at the West Storage location of our Mont Belvieu, Texas underground storage facility.

Acadian Gas is engaged in the gathering, transportation, storage and marketing of natural gas in south Louisiana, utilizing over 1,000 miles of pipelines having an aggregate throughput capacity of approximately 1.1 billion cubic feet per day (“Bcf/d”). Acadian Gas also owns a 49.51% equity interest in Evangeline, which owns a 27-mile natural gas pipeline located in southeast Louisiana.

In October 2009, we and EPO announced plans for our jointly owned Acadian Gas system to extend its Louisiana intrastate natural gas pipeline system into northwest Louisiana to provide producers in the Haynesville Shale production area with access to additional markets in central and southern Louisiana and connections to nine third-party major interstate natural gas pipelines. This expansion capital project is referred to as the “Haynesville Extension” of the Acadian Gas System. As currently designed, the Haynesville Extension will have the potential capacity to transport up to 1.8 Bcf/d of natural gas from the Haynesville area through a 270-mile pipeline that will connect with our existing Acadian Gas System. The Haynesville Extension is expected to be completed in September 2011.

The total budgeted cost of the Haynesville Extension is approximately $1.50 billion (including capitalized interest). In June 2010, we agreed to fund 66% of the Haynesville Extension project costs and EPO agreed to fund the remaining 34% of such expenditures; therefore, we estimate that our share of such costs will approximate $990 million. In order to fund our capital spending requirements under the Haynesville Extension project, we entered into long-term senior unsecured credit facilities having an aggregate borrowing capacity of $1.25 billion in October 2010. For information regarding our $1.25 billion credit facilities, see Note 9.

§	Lou-Tex Propylene owns a 267-mile pipeline used to transport chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas.

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

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

DEP II Drop Down

On December 8, 2008, EPO contributed to us the following controlling equity interests in a second drop down transaction: (i) a 66% voting general partner interest in Enterprise GC, (ii) a 51% voting general partner interest in Enterprise Intrastate and (iii) a 51% voting membership interest in Enterprise Texas. The following is a brief description of the assets and operations of the DEP II Midstream Businesses:

Enterprise GC operates and owns: (i) two NGL fractionation facilities, the Shoup and Armstrong facilities, located in South Texas; (ii) a 1,185-mile NGL pipeline system located in South Texas; and (iii) 1,096 miles of natural gas gathering pipelines located in South and West Texas. Enterprise GC's natural gas gathering pipelines include: (i) the 262-mile Big Thicket Gathering System located in southeast Texas; (ii) the 660-mile Waha system located in the Permian Basin of West Texas; and (iii) the 174-mile TPC Offshore gathering system located in South Texas.

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

Enterprise Texas owns the 6,653-mile Enterprise Texas natural gas pipeline system, which includes the Sherman Extension and Trinity River Lateral pipelines, and leases the Wilson natural gas storage facility. The Enterprise Texas pipeline system and the Wilson storage facility, along with the Waha, TPC Offshore and Channel pipeline systems, comprise our Texas Intrastate System.

In July 2010, we completed and placed into service the final segment of our Trinity River Lateral natural gas pipeline. In total, the Trinity River Lateral pipeline extends approximately 40 miles from the Trinity River Basin north of Arlington, Texas to an interconnect near Justin, Texas with our Sherman Extension pipeline. The Trinity River Lateral provides producers in Tarrant and Denton Counties in North Texas with up to 1 Bcf/d of production takeaway capacity.

Our Texas Intrastate System is strategically located to benefit from increasing natural gas production from the Eagle Ford Shale supply basin located in South Texas. We are in the process of expanding this system's natural gas gathering and transportation capabilities as well as increasing our natural gas storage capacity to handle the expected increase in production volumes. EPO is funding 100% of the growth capital spending associated with these expansion projects.

See “DEP II Midstream Businesses – Parent” under Note 11 and “Relationship with EPO – Company and Limited Partnership Agreements – DEP II Midstream Businesses” under Note 13 for additional information regarding the DEP II Midstream Businesses.

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

Net income (or loss) of the DEP II Midstream Businesses is first allocated to us and EPO based on each entity's percentage interest of 22.6% and 77.4%, respectively, and then in a manner that in part follows the cash distributions paid by (or contributions made to) each DEP II Midstream Business. The 22.6% and 77.4% amounts are referred to as the “Percentage Interests,” and represent each owner's initial relative economic investment in the DEP II Midstream Businesses at December 8, 2008.

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

- Definition

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
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+ Details

General Accounting Matters	6 Months Ended
General Accounting Matters	Jun. 30, 2011
General Accounting Matters [Abstract]
General Accounting Matters	Note 2. General Accounting Matters Our results of operations for the three and six months ended June 30, 2011 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These Unaudited Condensed Consolidated Financial Statements and the Notes thereto should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto included in our annual report for the year ended December 31, 2010 (“2010 Form 10-K”), as filed on March 1, 2011. Allowance for Doubtful Accounts Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts. Our procedure for determining the allowance for doubtful accounts is based on: (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research and (iii) the levels of credit we grant to customers. In addition, we may increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. Our allowance also includes estimates for uncollectible natural gas imbalances based on specific identification of accounts. Contingencies Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the need for accounting recognition or disclosure of these contingencies, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 15 for additional information regarding our contingencies. Derivative Instruments We use derivative instruments such as physical forward agreements, futures contracts, floating-to-fixed swaps, basis swaps and options contracts to manage price risks associated with inventories, firm commitments, interest rates and certain anticipated transactions. To qualify for hedge accounting, the item to be hedged must expose us to risk and the related derivative instrument must reduce that exposure and meet specific documentation requirements. We formally designate a derivative instrument as a hedge and document and assess the effectiveness of the hedge at inception and thereafter on a quarterly basis. We apply the normal purchases/normal sales exception for certain of our derivative instruments, which precludes the recognition of changes in mark-to-market values for these items on our balance sheet or income statement. Revenues and costs for these transactions are recognized when volumes are physically delivered or received. See Note 4 for additional information regarding our derivative instruments and related hedging activities. Earnings Per Unit Earnings per unit is based on the amount of net income allocated to limited partners and the weighted-average number of units outstanding during the period. See Note 14 for information regarding our presentation of earnings per unit amounts. Estimates Preparing our financial statements in conformity with GAAP requires management to make estimates and assumptions that affect amounts presented in the financial statements (i.e., assets, liabilities, revenue and expenses) and disclosures about contingent assets and liabilities. Our actual results could differ from these estimates. On an ongoing basis, management reviews its estimates based on currently available information. Any future changes in facts and circumstances may require updated estimates, which, in turn, could have a significant impact on our financial statements. Fair Value Information The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. 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. Recent Accounting Developments Fair Value Measurements. In May 2011, the Financial Accounting Standards Board (or “FASB”) issued an accounting standard update that amended previous fair value measurement and disclosure guidance. These amendments generally involve clarifications on how to measure and disclose fair value amounts recognized in the financial statements. They also expand the disclosure requirements, particularly for Level 3 fair value measurements, to include a description of the valuation processes used and an analysis of the sensitivity of the fair value measurements to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any. We will adopt this guidance on January 1, 2012 and apply its requirements prospectively at that time. We do not believe the adoption of this guidance will have a material impact on our consolidated financial statements. Presentation of Other Comprehensive Income. In June 2011, the FASB issued an accounting standard update that revised the financial statement presentation of other comprehensive income (“OCI”). The amended guidance requires entities to present components of comprehensive income in either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements (i.e., an income statement and a comprehensive income statement, which is our current format). Although the amended guidance does not change the items that must be reported in OCI, reclassification adjustments for each component of OCI will have to be displayed in both net income and OCI. We will adopt this guidance on January 1, 2012 and apply its presentation requirements retrospectively at that time. We do not believe the adoption of this guidance will have a material impact on our consolidated financial statements.

Equity-based Awards

6 Months Ended

Jun. 30, 2011

Equity-based Awards [Abstract]

Equity-based Awards

Note 3. Equity-based Awards

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

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2011		2010		2011		2010
Restricted common unit awards	$	1.8	$	1.0	$	3.3	$	1.6
Unit option awards		0.1		*		0.2		0.1
Other		--		0.2		--		0.3
Total compensation expense	$	1.9	$	1.2	$	3.5	$	2.0

* Amount is negligible.

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

At June 30, 2011, EPCO's significant long-term incentive plans applicable to us were the 2010 Duncan Energy Partners L.P. Long-Term Incentive Plan (the “2010 Plan”), the Enterprise Products 1998 Long-Term Incentive Plan (“1998 Plan”) and the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (“2008 Plan”).

The 2010 Plan provides for awards to employees, directors or consultants providing services to us. Awards under the 2010 Plan may be granted in the form of options to purchase our common units, restricted common units, UARs, phantom units and distribution equivalent rights (“DERs”). Up to 500,000 of our common units may be issued as awards under the 2010 Plan. After giving effect to awards granted under the plan through June 30, 2011, a total of 489,986 additional common units could be issued. The merger agreement governing our proposed merger with Enterprise contains restrictions on the issuance of additional awards under the 2010 Plan. See Note 13 for information regarding the proposed merger with Enterprise.

The 1998 Plan provides for awards of Enterprise's common units and other rights to non-employee directors and to employees of EPCO and its affiliates providing services to us. Awards under the 1998 Plan may be granted in the form of unit options, restricted common units, phantom units and DERs. Up to 7,000,000 of Enterprise's common units may be issued as awards under the 1998 Plan. After giving effect to awards granted under the plan through June 30, 2011, a total of 1,475,190 additional common units of Enterprise could be issued. We are allocated expense associated with certain unit options and restricted common units issued under the 1998 Plan.

The 2008 Plan provides for awards of Enterprise's common units and other rights to non-employee directors and to consultants and employees of EPCO and its affiliates providing services to us. Awards under the 2008 Plan may be granted in the form of unit options, restricted common units, UARs, phantom units and DERs. Up to 10,000,000 of Enterprise's common units may be issued as awards under the 2008 Plan. After giving effect to awards granted under the plan through June 30, 2011, a total of 4,706,877 additional common units of Enterprise could be issued. We are allocated expense associated with certain unit options and restricted common units issued under the 2008 Plan.

Summary of Long-Term Incentive Awards

The following information is being provided regarding the 2010 Plan and EPCO's other long-term incentive awards under which we have received or may receive an allocation of expense. EPCO has certain plans under which liability-classified awards may be issued. As of June 30, 2011, we have not been allocated any costs of liability-classified awards and therefore have not included any discussion of such awards in these disclosures. EPCO may create additional long-term incentive plans in the future that may result in us receiving an allocation of expense based on services rendered to us by the recipients of such awards. Unless noted otherwise, the following information is presented on a gross basis (to EPCO and affiliates) with respect to the type of award granted. To the extent applicable, we have noted our estimated share of unrecognized compensation costs of such awards and the weighted-average period of time over which we expect to recognize such expense.

Restricted Common Unit Awards

Restricted common unit awards allow recipients to acquire (at no cost to the recipient apart from service or other conditions) limited partner units once a defined vesting period expires, subject to customary forfeiture provisions. Restricted common unit awards may be denominated in our common units or those of Enterprise depending on the issuer of the award. Restricted common unit awards issued prior to 2010 generally cliff vest four years from the date of grant. Beginning with awards issued in 2010, restricted common unit awards are typically subject to graded vesting provisions in which one-fourth of each award vests on the first, second, third and fourth anniversaries of the date of grant. As used in the context of EPCO's long-term incentive plans, the term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires.

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

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

	Number of Units			Weighted-Average Grant Date Fair Value per Unit (1)
Enterprise restricted common unit awards
Restricted common units at December 31, 2010		3,561,614		$	29.78
Granted (2)		1,359,230		$	43.68
Vested		(828,545	)	$	31.57
Forfeited		(75,857	)	$	32.67
Restricted common units at June 30, 2011		4,016,442		$	34.06

Duncan Energy Partners restricted common unit awards
Restricted common units at December 31, 2010		--		$	--
Granted (3)		3,666		$	32.56
Vested (3)		(3,666	)	$	32.56
Restricted common units at June 30, 2011		--		$	--

(1) Determined by dividing the aggregate grant date fair value of awards before an allowance for forfeitures by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued in 2011 was $59.4 million based on a grant date market price of Enterprise's common units ranging from $40.54 to $43.70 per unit. An estimated annual forfeiture rate of 4.6% was applied to these awards. (3) The aggregate grant date fair value of restricted common unit awards issued in 2011 was $0.1 million based on a grant date market price of our common units of $32.56 per unit. These awards vested upon issuance.

For the EPCO group of companies, the unrecognized compensation cost associated with restricted common unit awards was an aggregate $73.5 million at June 30, 2011, of which our allocated share of the cost is currently estimated to be $10.0 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.0 years.

Unit Option Awards

EPCO's long-term incentive plans provide for the issuance of non-qualified incentive options. These unit option awards may be denominated in our common units or those of Enterprise depending on the issuer of the award. When issued, the exercise price of each unit option award may be no less than the market price of the underlying security on the date of grant. In general, these unit option awards have a vesting period of four years from the date of grant and expire five years after the date of grant. There were no options granted under our 2010 Plan during the three and six months ended June 30, 2011.

The fair value of each unit option is estimated on the date of grant using a Black-Scholes option pricing model, which incorporates various assumptions including expected life of the options, risk-free interest rates, expected distribution yield of the underlying security, and expected unit price volatility. In general, our assumptions regarding the expected life of the options represent the period of time that the options are expected to be outstanding based on an analysis of our historical option activity. Our selection of the risk-free interest rates is based on published yields for U.S. government securities with comparable terms. The unit price volatility and expected distribution yield assumptions are based on several factors, including an analysis of the underlying security's historical market price and its distribution yield over a period of time equal to the expected life of the option, respectively. Compensation expense recorded in connection with unit options is based on the grant date fair value of such awards, net of an allowance for estimated forfeitures, over the requisite service or vesting period.

The following table presents unit option activity for the period presented. As of June 30, 2011, only Enterprise has issued unit option awards.

	Number of Units		Weighted- Average Strike Price (dollars/unit)		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (1)
Unit options at December 31, 2010		3,753,420	$	28.08		3.6	$	--
Unit options at June 30, 2011		3,753,420	$	28.08		3.1	$	7.3
Unit options exercisable at June 30, 2011 (2)		--				--	$	--

(1) Aggregate intrinsic value reflects fully vested unit options at the date indicated. There were no vested unit options outstanding at December 31, 2010. (2) Enterprise was committed to issue 3,753,420 common units at June 30, 2011 if all outstanding options awarded were exercised. Option awards outstanding at June 30, 2011 include 612,280 awards that vested during the first six months of 2011. Of the remaining outstanding option awards at June 30, 2011, 100,000; 736,000; 1,520,140 and 785,000 will vest in 2011, 2012, 2013, and 2014, respectively. These unit option awards become exercisable in the calendar year following the year in which they vest.

In order to fund its unit option-related obligations, EPCO may purchase common units at fair value either in the open market or directly from Enterprise.

For the EPCO group of companies, the unrecognized compensation cost associated with unit option awards was an aggregate $5.0 million at June 30, 2011, of which our allocated share of the cost is currently estimated to be $0.8 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 1.9 years.

- Definition

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Number Topic 14

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Derivative Instruments, Hedging Activities and Fair Value Measurements

6 Months Ended

Jun. 30, 2011

Derivative Instruments, Hedging Activities and Fair Value Measurements [Abstract]

Derivative Instruments, Hedging Activities and Fair Value Measurements

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

In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with certain anticipated future transactions, we use derivative instruments. Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates or commodity prices. Fair value is generally defined as the amount at which a derivative instrument could be exchanged in a current transaction between willing parties, not in a forced sale. Derivative instruments typically include physical forward agreements, futures contracts, floating-to-fixed swaps, basis swaps and options contracts. Substantially all of our derivatives are used for non-trading activities.

We are required to recognize derivative instruments at fair value as either assets or liabilities on our balance sheet. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of the derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. After meeting specified conditions, a qualified derivative may be designated as a total or partial hedge of:

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

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

An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period. Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item. Any ineffectiveness associated with a hedge relationship is recognized in earnings immediately. Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item.

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

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

Interest Rate Derivative Instruments

We have no interest rate derivative instruments outstanding at June 30, 2011. We utilized floating-to-fixed interest rate swaps with a notional value of $175.0 million to manage our exposure to changes in the interest rates charged on borrowings under a then existing $300.0 million unsecured revolving credit facility from September 2007 through September 2010. Our interest rate swaps expired in September 2010. This strategy was a component in controlling our cost of capital associated with such borrowings for the three and six months ended June 30, 2010.

Interest rate swaps exchange the stated interest rate paid on a notional amount of debt for a fixed or floating interest rate stipulated in the derivative instrument. Our interest rate swaps resulted in an increase in interest expense of $1.9 million and $3.8 million for the three and six months ended June 30, 2010, respectively.

Commodity Derivative Instruments

The price of natural gas is subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as forwards, basis swaps and futures contracts. The following table summarizes our commodity derivative instruments outstanding at June 30, 2011:

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

Derivatives not designated as hedging instruments:
Acadian Gas:
Natural gas risk management activities (2)	0.2 Bcf	n/a	Mark-to-market

(1) This reflects the absolute value of derivative notional volumes. (2) Reflects the use of derivative instruments to manage risks associated with natural gas transportation and storage assets.

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

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

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, 2011, we did not have any derivative instruments with contingent features in a net liability position. The potential for derivatives with contingent features to enter a net liability position may change in the future as commodity positions and prices fluctuate.

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, 2011

December 31, 2010

June 30, 2011

December 31, 2010

Balance Sheet

Location

Fair

Value

Balance Sheet

Location

Fair

Value

Balance Sheet

Location

Fair

Value

Balance Sheet

Location

Fair

Value

Derivatives not designated as hedging instruments:

Commodity derivatives

Other current

assets

Other current

assets

0.2

Other current

liabilities

Other current

liabilities

0.2

* Amount is negligible.

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

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income on Derivative (Effective Portion)
	For the Three Months					For the Six Months
	Ended June 30,					Ended June 30,
	2011		2010			2011		2010
Interest rate derivatives	$	--	$	0.1		$	--	$	(0.1	)
Commodity derivatives		--		(0.1	)		--		(0.1	)
Total	$	--	$	*		$	--	$	(0.2	)

* Amount is negligible.

Derivatives in Cash Flow Hedging Relationships	Location	Loss Reclassified from Accumulated Other Comprehensive Loss to Income (Effective Portion)
		For the Three Months					For the Six Months
		Ended June 30,					Ended June 30,
		2011		2010			2011		2010
Interest rate derivatives	Interest expense	$	--	$	(1.9	)	$	--	$	(3.8	)

Derivatives in Cash Flow Hedging Relationships	Location	Gain Recognized in Income on Derivative (Ineffective Portion)
		For the Three Months				For the Six Months
		Ended June 30,				Ended June 30,
		2011		2010		2011		2010
Interest rate derivatives	Interest expense	$	--	$	*	$	--	$	*

* Amount is negligible.

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

Derivatives Not Designated as Hedging Instruments	Location	Loss Recognized in Income on Derivative
		For the Three Months					For the Six Months
		Ended June 30,					Ended June 30,
		2011		2010			2011			2010
Commodity derivatives	Revenue	$	*	$	(0.3	)	$	(0.2	)	$	(0.3	)

* Amount is negligible.

Fair Value Measurements

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

A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. Our Level 1 and 2 assets were nominal amounts at June 30, 2011 and we did not have any Level 3 assets. There were no transfers between Levels 1, 2 or 3 during the six months ended June 30, 2011.

Nonfinancial Assets and Liabilities

Using appropriate valuation techniques, we adjusted the carrying value of certain assets recorded as property, plant and equipment to their estimated fair values during the six months ended June 30, 2010. This resulted in non-cash asset impairment charges of $1.5 million. These impairment charges resulted primarily from the anticipated abandonment of certain pipeline laterals on our TPC Offshore gathering system and the cancellation of a compressor station project on our Texas Intrastate System. Our fair value estimates were based primarily on an evaluation of the future cash flows associated with each asset (Level 3). The non-cash asset impairment charges we recorded during the three and six months ended June 30, 2010 are a component of operating costs and expenses. We did not have any non-cash impairment charges during the six months ended June 30, 2011.

- Definition

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 45
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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+ Details

Equity and Distributions

6 Months Ended

Jun. 30, 2011

Equity and Distributions [Abstract]

Equity and Distributions

Note 10. Equity and Distributions

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

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

Registration Statements and Equity Offerings

At June 30, 2011, we have two active registration statements on file with the SEC: the first covers our distribution reinvestment plan (“DRIP”), and the second covers both our employee unit purchase plan (“EUPP”) and the 2010 Plan. After taking into account limited partner units issued under our active registration statements through June 30, 2011, we may issue an additional 1,939,272 units under the DRIP, 455,459 units under the EUPP and 489,986 units under the 2010 Plan.

The following table reflects the number of common units issued and the net cash proceeds received in connection with the DRIP and EUPP during the six months ended June 30, 2011:

	Number of
	Common Units		Net Cash
	Issued		Proceeds

February DRIP		10,319	$	0.3
February EUPP		7,385		0.3
May DRIP		9,118		0.4
May EUPP		12,624		0.5
Total		39,446	$	1.5

Net cash proceeds received from our DRIP and EUPP were used for general partnership purposes.

Unit History

The following table summarizes changes in our outstanding units since December 31, 2010:

			Restricted
	Common		Common
	Units		Units
Balance, December 31, 2010		57,749,158		--
Common units issued in connection with DRIP and EUPP		39,446		--
Restricted common units issued to independent directors under our 2010 Plan		--		3,666
Conversion of restricted units to common units		3,666		(3,666	)
Balance, June 30, 2011		57,792,270		--

Cash Distributions

We are required to distribute 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 any set rate per unit. Our general partner has no incentive distribution rights.

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

	Distribution Per Common Unit		Record Date	Payment Date
2011
1st Quarter	$	0.4575	04/29/2011	05/06/2011
2nd Quarter	$	0.4600	07/29/2011	08/10/2011

- Definition

The entire disclosure for shareholders' equity, comprised of portions attributable to the parent entity and noncontrolling interest, if any, including other comprehensive income (as applicable). Including, but not limited to: (1) balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings; (2) accumulated balance for each classification of other comprehensive income and total amount of comprehensive income; (3) amount and nature of changes in separate accounts, including the number of shares authorized and outstanding, number of shares issued upon exercise and conversion, and for other comprehensive income, the adjustments for reclassifications to net income; (4) rights and privileges of each class of stock authorized; (5) basis of treasury stock, if other than cost, and amounts paid and accounting treatment for treasury stock purchased significantly in excess of market; (6) dividends paid or payable per share and in the aggregate for each class of stock for each period presented; (7) dividend restrictions and accumulated preferred dividends in arrears (in aggregate and per share amount); (8) retained earnings appropriations or restrictions, such as dividend restrictions; (9) impact of change in accounting principle, initial adoption of new accounting principle and correction of an error in previously issued financial statements; (10) shares held in trust for Employee Stock Ownership Plan (ESOP); (11) deferred compensation related to issuance of capital stock; (12) note received for issuance of stock; (13) unamortized discount on shares; (14) description, terms, and number of warrants or rights outstanding; (15) shares under subscription and subscription receivables, effective date of new retained earnings after quasi-reorganization and deficit eliminated by quasi-reorganization and, for a period of at least ten years after the effective date, the point in time from which the new retained dates; and (16) retroactive effective of subsequent change in capital structure.

+ References

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-Number 12
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-Name Regulation S-X (SX)
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+ Details

Noncontrolling Interest

6 Months Ended

Jun. 30, 2011

Noncontrolling Interest [Abstract]

Noncontrolling Interest

Note 11. Noncontrolling Interest

We account for EPO's retained ownership interests in each of the DEP I and DEP II Midstream Businesses as noncontrolling interest. Under this method of presentation, all revenues and expenses of these businesses are included in our consolidated net income and EPO's share (as Parent) of the earnings of these businesses is deducted from consolidated net income to derive net income attributable to Duncan Energy Partners L.P. EPO's share of the net assets of the DEP I and DEP II Midstream Businesses is presented as noncontrolling interest in subsidiaries (a component of equity) on our Unaudited Condensed Consolidated Balance Sheets. See Note 1 for a general description of the DEP I and DEP II Midstream Businesses.

DEP I Midstream Businesses – Parent

The DEP I Midstream Businesses allocate their net income (or loss) to EPO and us based on our respective sharing ratios, which are currently 34% for EPO and 66% for us. In deriving the net income (or loss) of Mont Belvieu Caverns to be allocated between EPO and us, certain special allocations are required: (i) EPO is allocated all operational measurement gains and losses and (ii) EPO is allocated 100% of the depreciation expense related to capital projects that it has fully funded.

Cash distributions by the DEP I Midstream Businesses to EPO and us are paid in accordance with each owner's respective sharing ratio. Likewise, cash contributions by EPO and us to the DEP I Midstream Businesses are made in accordance with the same sharing ratios; however, special funding arrangements exist with respect to certain capital projects under the terms of the limited liability company agreement of Mont Belvieu Caverns (the “Caverns LLC Agreement”) and an Omnibus Agreement. See Note 13 for additional information regarding these related party agreements. No capital spending for the DEP I Midstream Businesses was funded by EPO under the Omnibus Agreement during the three and six months ended June 30, 2011 and 2010.

Caverns LLC Agreement. EPO made cash contributions of $1.8 million and $3.1 million under the Caverns LLC Agreement during the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, EPO made cash contributions of $5.8 million and $13.1 million, respectively, under the Caverns LLC Agreement to fund 100% of certain storage-related infrastructure projects sponsored by and for the benefit of EPO's NGL marketing activities. Duncan Energy Partners elected to not participate in these projects. Although Mont Belvieu Caverns owns the constructed assets, it is not expected to benefit economically from these specific capital improvements. Therefore, EPO is not expected to receive an increased allocation of earnings or cash flows from Mont Belvieu Caverns as a result of these contributed capital expenditures. EPO will, however, be allocated the depreciation expense attributable to these projects. EPO's NGL marketing activities receive economic benefit directly from these expansion projects via increased marketing revenues. Additional contributions of approximately $26.2 million are expected from EPO to fund these specific projects for the remainder of 2011.

Operational measurement gains and losses are created when product is moved between storage wells and are attributable to pipeline and well connection measurement variances. The Caverns LLC Agreement allocates to EPO any items of income or loss relating to net operational measurement gains and losses, including amounts that Mont Belvieu Caverns may retain for handling losses. As such, EPO is required to contribute cash to Mont Belvieu Caverns for net operational measurement losses and is entitled to receive cash distributions from Mont Belvieu Caverns for net operational measurement gains. Operational measurement gains and losses are reflected in our consolidated operating costs and expenses and gross operating margin amounts; however, these gains and losses do not impact net income attributable to Duncan Energy Partners since they are allocated to EPO through noncontrolling interest. In addition, operational measurement gains or losses do not have a significant impact on us with respect to the timing of our net cash flows provided by operating activities. Accordingly, we have not established a reserve for operational measurement losses on our balance sheet.

Amended Acadian LLC Agreement. On June 1, 2010, we entered into a second amended and restated limited liability company agreement for Acadian Gas (the “Amended Acadian LLC Agreement”) with EPO. As part of this agreement, we and EPO agreed to fund the construction of the Haynesville Extension in accordance with our respective sharing ratios in Acadian Gas (i.e., 66% for us and 34% for EPO). EPO made cash contributions of $117.8 million and $30.9 million to Acadian Gas under the Amended Acadian LLC Agreement in connection with the Haynesville Extension project during the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, EPO made cash contributions of $175.7 million and $30.9 million, respectively, to Acadian Gas under the Amended Acadian LLC Agreement in connection with the Haynesville Extension project. For additional information regarding the Amended Acadian LLC Agreement, see “Relationship with EPO – Amended Acadian LLC Agreement” under Note 13.

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

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2011			2010			2011			2010

Total net income of DEP I Midstream Businesses, after special allocations	$	15.9		$	17.6		$	29.2		$	33.2
Multiplied by Parent 34% interest in net income		x 34%			x 34%			x 34%			x 34%
Parent 34% interest in net income, after special allocations		5.4			5.9			9.9			11.2
Add (deduct) operational measurement gains (losses) allocated to Parent		1.9			3.5			(3.4	)		4.4
Less depreciation expense related to fully funded projects allocated to Parent		(1.7	)		(1.6	)		(3.4	)		(3.1	)
Net income attributable to noncontrolling interest – DEP I Midstream Businesses – Parent	$	5.6		$	7.8		$	3.1		$	12.5

The following table provides a reconciliation of the amount presented as “Noncontrolling interest in subsidiaries – DEP I Midstream Businesses – Parent,” on our Unaudited Condensed Consolidated Balance Sheets at June 30, 2011:

Balance, December 31, 2010	$	686.7
Net income attributable to noncontrolling interest – DEP I Midstream Businesses – Parent		3.1
Contributions made by EPO to Mont Belvieu Caverns in connection with the Caverns LLC Agreement		5.8
Contributions made by EPO to Acadian Gas in connection with the Amended Acadian LLC Agreement		175.7
Other contributions made by EPO to the DEP I Midstream Businesses		11.5
Distributions to EPO by the DEP I Midstream Businesses		(7.8	)
Balance, June 30, 2011	$	875.0

For additional information regarding our agreements with EPO in connection with the DEP I drop down transaction, see “Relationship with EPO” under Note 13.

DEP II Midstream Businesses – Parent

At the time of the DEP II drop down transaction, the total estimated fair value of the DEP II Midstream Businesses was approximately $3.2 billion. The total value of the consideration we provided to EPO in the DEP II drop down transaction was $730.0 million and represented, at the time of the transaction, the acquisition of controlling voting interests along with an initial 22.6% of the equity of the DEP II Midstream Businesses. EPO retained the remaining 77.4% of equity.

The initial annualized return rate from December 8, 2008 through December 31, 2009 was 11.85%, which was based on our estimated weighted-average cost of capital at December 8, 2008 plus 1.0%. The annualized return rate increases by 2.0% on January 1 of each year. As a result, the annualized return rate for 2010 was 12.087% and for 2011 is 12.329%. If we participate in an expansion capital project involving the DEP II Midstream Businesses, we may request an incremental adjustment to the then-applicable annualized return rate to reflect our weighted-average cost of capital associated with such contribution.

The annualized return rate is applied to each party's aggregate investment (or “Distribution Base”) in the DEP II Midstream Businesses. To the extent that we and/or EPO make capital contributions to fund expansion capital projects involving the DEP II Midstream Businesses, the Distribution Base of the contributing member will be increased by that member's capital contribution at the time such contribution is made. Our Distribution Base has remained at $730.0 million from December 8, 2008 through June 30, 2011. EPO's Distribution Base was $452.1 million, $1.10 billion and $1.39 billion at December 8, 2008, December 31, 2010 and June 30, 2011, respectively. The increase in EPO's Distribution Base is the result of its funding 100% of the expansion capital projects of the DEP II Midstream Businesses since December 8, 2008. For the three and six months ended June 30, 2011, EPO funded $104.5 million and $256.4 million, respectively, of expansion capital spending for the DEP II Midstream Businesses. This spending primarily relates to natural gas pipeline projects in the Barnett Shale and ongoing expansions of our pipeline network in the Eagle Ford Shale region. We have not yet participated in the expansion capital project spending of the DEP II Midstream Businesses, although we may elect to invest in existing or future expansion projects at a later date.

Net income (or loss) of the DEP II Midstream Businesses is first allocated to us and EPO based on each entity's Percentage Interest and then in a manner that in part follows the cash distributions paid by (or contributions made to) each of the DEP II Midstream Business. Under our income sharing arrangement with EPO, we are allocated additional income (in excess of our Percentage Interest) to the extent that the cash distributions we receive (or contributions made) exceed the amount we would have been entitled to receive (or required to fund) based solely on our Percentage Interest. This additional earnings allocation to us reduces the amount of income allocated to EPO by an equal amount and may result in EPO being allocated a loss when we are allocated income. Our participation in the expected future increase in cash flow from such projects after EPO receives its full Tier II distribution is limited (beyond our annualized return amount) to 2% of such upside, with EPO receiving 98% of the benefit.

The following table presents the allocation of net income of the DEP II Midstream Businesses for the three months ended June 30, 2011:

				EPO			DEP
Total net income of DEP II Midstream Businesses				$	13.2		$	13.2
Multiplied by each owner's Percentage Interest					77.4%			22.6%
Base earnings allocation to each owner					10.2			3.0
Additional earnings allocation to Duncan Energy Partners:
Total distributions paid by the DEP II Midstream Businesses with respect to period	$	43.4
Multiplied by 22.6% Percentage Interest of Duncan Energy Partners		22.6%
Duncan Energy Partners' Percentage Interest in the total cash distributions paid by the DEP II Midstream Businesses with respect to period		9.8
Less actual distributions paid to Duncan Energy Partners with respect to period based on annualized return for period		(22.5	)		(12.7	)		12.7
Net loss attributable to EPO as noncontrolling interest				$	(2.5	)
Net income attributable to Duncan Energy Partners							$	15.7

The following table presents the allocation of net loss of the DEP II Midstream Businesses for the three months ended June 30, 2010:

				EPO			DEP
Total net loss of DEP II Midstream Businesses				$	(3.6	)	$	(3.6	)
Multiplied by each owner's Percentage Interest					77.4%			22.6%
Base earnings allocation to each owner					(2.8	)		(0.8	)
Additional earnings allocation to Duncan Energy Partners:
Total distributions paid by the DEP II Midstream Businesses with respect to period	$	24.5
Multiplied by 22.6% Percentage Interest of Duncan Energy Partners		22.6%
Duncan Energy Partners' Percentage Interest in the total cash distributions paid by the DEP II Midstream Businesses with respect to period		5.5
Less actual distributions paid to Duncan Energy Partners with respect to period based on annualized return for period		(22.0	)		(16.5	)		16.5
Net loss attributable to EPO as noncontrolling interest				$	(19.3	)
Net income attributable to Duncan Energy Partners							$	15.7

The following table presents the allocation of net income of the DEP II Midstream Businesses for the six months ended June 30, 2011:

				EPO			DEP
Total net income of DEP II Midstream Businesses				$	28.8		$	28.8
Multiplied by each owner's Percentage Interest					77.4%			22.6%
Base earnings allocation to each owner					22.3			6.5
Additional earnings allocation to Duncan Energy Partners:
Total distributions paid by the DEP II Midstream Businesses with respect to period	$	96.2
Multiplied by 22.6% Percentage Interest of Duncan Energy Partners		22.6%
Duncan Energy Partners' Percentage Interest in the total cash distributions paid by the DEP II Midstream Businesses with respect to period		21.7
Less actual distributions paid to Duncan Energy Partners with respect to period based on annualized return for period		(45.0	)		(23.3	)		23.3
Net loss attributable to EPO as noncontrolling interest				$	(1.0	)
Net income attributable to Duncan Energy Partners							$	29.8

The following table presents the allocation of net income of the DEP II Midstream Businesses for the six months ended June 30, 2010:

				EPO			DEP
Total net income of DEP II Midstream Businesses				$	0.8		$	0.8
Multiplied by each owner's Percentage Interest					77.4%			22.6%
Base earnings allocation to each owner					0.6			0.2
Additional earnings allocation to Duncan Energy Partners:
Total distributions paid by the DEP II Midstream Businesses with respect to period	$	62.0
Multiplied by 22.6% Percentage Interest of Duncan Energy Partners		22.6%
Duncan Energy Partners' Percentage Interest in the total cash distributions paid by the DEP II Midstream Businesses with respect to period		14.0
Less actual distributions paid to Duncan Energy Partners with respect to period based on annualized return for period		(44.1	)		(30.1	)		30.1
Net loss attributable to EPO as noncontrolling interest				$	(29.5	)
Net income attributable to Duncan Energy Partners							$	30.3

The DEP II Midstream Businesses distributed an aggregate of $43.4 million and $24.5 million for the three months ended June 30, 2011 and 2010, respectively. Of these amounts, EPO received $20.9 million and $2.5 million for the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, the DEP II Midstream Businesses distributed an aggregate of $96.2 million and $62.0 million, respectively. EPO received $51.2 million and $17.9 million for the six months ended June 30, 2011 and 2010, respectively.

The $22.5 million and $22.0 million received by us from the DEP II Midstream Businesses with respect to the three months ended June 30, 2011 and 2010, respectively, represent approximately one-quarter of the annualized return rate for 2011 of 12.329% and 2010 of 12.087%, respectively, multiplied by our Distribution Base of $730.0 million. For the six months ended June 30, 2011 and 2010, we received $45.0 million and $44.1 million, respectively, which represents approximately one-half of each respective year's annualized return rate. As a result, we received our expected Tier I distributions for the periods indicated. Based on EPO's Distribution Base, it was entitled to $42.9 million and $29.3 million of Tier II distributions for the three months ended June 30, 2011 and 2010, respectively, of which it received $20.9 million and $2.5 million, respectively. EPO was entitled to $82.7 million and $55.9 million of Tier II distributions for the six months ended June 30, 2011 and 2010, respectively, of which it received $51.2 million and $17.9 million, respectively. No Tier III distributions were paid by the DEP II Midstream Businesses with respect to the three and six months ended June 30, 2011.

The following table provides a reconciliation of the amount presented as “Noncontrolling interest in subsidiaries – DEP II Midstream Businesses – Parent,” on our Unaudited Condensed Consolidated Balance Sheets at June 30, 2011:

Balance, December 31, 2010	$	3,072.5
Allocated loss from DEP II Midstream Businesses to EPO as Parent		(1.0	)
Contributions by EPO in connection with expansion cash calls		256.4
Distributions to noncontrolling interest of subsidiary operating cash flows		(55.0	)
Other general contributions from noncontrolling interest, net		3.8
Balance, June 30, 2011	$	3,276.7

For additional information regarding our agreements with EPO in connection with the DEP I or II drop down transaction, see “Relationship with EPO” under Note 13.

- Definition

The entire disclosure for noncontrolling interest in consolidated subsidiaries, which could include the name of the subsidiary, the ownership percentage held by the parent, the ownership percentage held by the noncontrolling owners, the amount of the noncontrolling interest, the location of this amount on the balance sheet (when not reported separately), an explanation of the increase or decrease in the amount of the noncontrolling interest, the noncontrolling interest share of the net Income or Loss of the subsidiary, the location of this amount on the income statement (when not reported separately), the nature of the noncontrolling interest such as background information and terms, the amount of the noncontrolling interest represented by preferred stock, a description of the preferred stock, and the dividend requirements of the preferred stock.

+ References + Details

Business Segments

6 Months Ended

Jun. 30, 2011

Business Segments [Abstract]

Business Segments

Note 12. Business Segments

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

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by our management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The GAAP financial measure most directly comparable to total segment gross operating margin is operating income. Our non-GAAP financial measure of total segment gross operating margin should not be considered an alternative to GAAP operating income.

We define total segment gross operating margin as operating income before: (i) depreciation, amortization and accretion expenses; (ii) non-cash asset impairment charges; (iii) gains and losses from asset sales and related transactions and (iv) general and administrative costs. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of any intersegment and intrasegment transactions. In accordance with GAAP, intercompany accounts and transactions are eliminated in the preparation of our consolidated financial statements. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before the allocation of earnings to noncontrolling interest.

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

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2011			2010			2011			2010
Revenues	$	302.8		$	265.2		$	586.0		$	555.8
Less: Operating costs and expenses		(267.8	)		(245.1	)		(524.8	)		(512.3	)
Add: Equity in income of Evangeline		0.5			--			0.8			0.2
Depreciation, amortization and accretion in operating costs and expenses (1)		52.0			51.5			102.9			99.1
Non-cash asset impairment charges included in operating costs and expenses (2)		--			--			--			1.5
Gains from asset sales and related transactions in operating costs and expenses		(0.3	)		(0.1	)		(0.5	)		(1.0	)
Total segment gross operating margin	$	87.2		$	71.5		$	164.4		$	143.3

(1) Amount is a component of “Depreciation, amortization and accretion” as presented on the Unaudited Condensed Statements of Consolidated Cash Flows. (2) See Note 4 for additional information regarding non-cash asset impairment charges.

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

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2011			2010			2011			2010
Total segment gross operating margin	$	87.2		$	71.5		$	164.4		$	143.3
Adjustments to reconcile total segment gross operating margin to operating income:
Depreciation, amortization and accretion in operating costs and expenses		(52.0	)		(51.5	)		(102.9	)		(99.1	)
Non-cash asset impairment charges included in operating costs and expenses		--			--			--			(1.5	)
Gains from asset sales and related transactions in operating costs and expenses		0.3			0.1			0.5			1.0
General and administrative costs		(6.5	)		(4.8	)		(11.1	)		(9.7	)
Operating income		29.0			15.3			50.9			34.0
Interest expense		(2.9	)		(3.2	)		(6.0	)		(6.3	)
Income before provision for income taxes	$	26.1		$	12.1		$	44.9		$	27.7

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

	Reportable Segments
	Natural Gas		NGL				Adjustments
	Pipelines		Pipelines		Petrochemical		and		Consolidated
	& Services		& Services		Services		Eliminations		Total
Revenues from third parties:
Three months ended June 30, 2011	$	109.1	$	26.9	$	4.0	$	--	$	140.0
Three months ended June 30, 2010		92.1		28.6		3.5		--		124.2
Six months ended June 30, 2011		222.1		54.9		6.1		--		283.1
Six months ended June 30, 2010		223.4		52.3		6.7		--		282.4

Revenues from related parties:
Three months ended June 30, 2011		112.4		50.4		--		--		162.8
Three months ended June 30, 2010		108.1		32.9		--		--		141.0
Six months ended June 30, 2011		204.9		98.0		--		--		302.9
Six months ended June 30, 2010		204.7		68.7		--		--		273.4

Total revenues:
Three months ended June 30, 2011		221.5		77.3		4.0		--		302.8
Three months ended June 30, 2010		200.2		61.5		3.5		--		265.2
Six months ended June 30, 2011		427.0		152.9		6.1		--		586.0
Six months ended June 30, 2010		428.1		121.0		6.7		--		555.8

Equity in income of Evangeline:
Three months ended June 30, 2011		0.5		--		--		--		0.5
Three months ended June 30, 2010		--		--		--		--		--
Six months ended June 30, 2011		0.8		--		--		--		0.8
Six months ended June 30, 2010		0.2		--		--		--		0.2

Gross operating margin:
Three months ended June 30, 2011		51.2		33.0		3.0		--		87.2
Three months ended June 30, 2010		37.1		31.6		2.8		--		71.5
Six months ended June 30, 2011		102.9		57.3		4.2		--		164.4
Six months ended June 30, 2010		79.6		58.5		5.2		--		143.3

Segment assets:
At June 30, 2011		3,600.1		1,006.8		78.8		1,552.8		6,238.5
At December 31, 2010		3,527.6		996.1		80.4		807.4		5,411.5

Property, plant and equipment: (see Note 6)
At June 30, 2011		3,580.0		982.3		78.8		1,552.8		6,193.9
At December 31, 2010		3,506.1		968.3		80.4		807.4		5,362.2

Investment in Evangeline: (see Note 7)
At June 30, 2011		5.6		--		--		--		5.6
At December 31, 2010		6.4		--		--		--		6.4

Intangible assets: (see Note 8)
At June 30, 2011		10.1		24.0		--		--		34.1
At December 31, 2010		10.7		27.3		--		--		38.0

Goodwill: (see Note 8)
At June 30, 2011		4.4		0.5		--		--		4.9
At December 31, 2010		4.4		0.5		--		--		4.9

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

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2011			2010			2011			2010
Natural Gas Pipelines & Services:
Sales of natural gas	$	135.4		$	127.4		$	256.8		$	280.6
Natural gas transportation services		82.4			68.2			162.8			139.0
Natural gas storage services		3.7			4.6			7.4			8.5
Total segment revenues		221.5			200.2			427.0			428.1
NGL Pipelines & Services:
Sales of NGLs		18.9			11.0			35.8			21.0
Sales of other products		7.6			4.5			14.4			8.2
NGL and related product storage services		28.8			28.8			60.1			55.9
NGL fractionation services		8.2			6.4			16.6			14.1
NGL transportation services		13.1			10.3			24.8			20.8
Other services		0.7			0.5			1.2			1.0
Total segment revenues		77.3			61.5			152.9			121.0
Petrochemical Services:
Propylene transportation services		4.0			3.5			6.1			6.7
Total consolidated revenues	$	302.8		$	265.2		$	586.0		$	555.8

Consolidated costs and expenses:
Operating costs and expenses:
Cost of natural gas and NGL sales	$	151.9		$	134.5		$	289.3		$	295.7
Depreciation, amortization and accretion		52.0			51.5			102.9			99.1
Gains from asset sales and related transactions		(0.3	)		(0.1	)		(0.5	)		(1.0	)
Other operating expenses		64.2			59.2			133.1			118.5
General and administrative costs		6.5			4.8			11.1			9.7
Total consolidated costs and expenses	$	274.3		$	249.9		$	535.9		$	522.0

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

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-SubTopic 10
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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+ Details

Related Party Transactions

6 Months Ended

Jun. 30, 2011

Related Party Transactions

Note 13. Related Party Transactions

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

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2011			2010			2011			2010
Revenue:
Revenues from EPO:
Sales of natural gas	$	33.0		$	29.5		$	65.8		$	62.1
Natural gas transportation services		29.1			28.5			57.4			54.3
Natural gas storage services		--			1.0			--			1.3
Sales of NGLs		22.1			10.6			40.8			20.4
NGL and related product storage services		11.1			9.4			23.8			18.3
NGL fractionation services		8.1			6.4			16.2			14.1
NGL transportation services		9.1			6.5			17.1			15.9
Sales of natural gas – Evangeline		49.6			49.0			80.3			86.8
Natural gas transportation services – Energy Transfer Equity		0.7			0.1			1.4			0.2
NGL and related product storage services – Energy Transfer Equity		--			--			0.1			--
Total related party revenues	$	162.8		$	141.0		$	302.9		$	273.4

Operating costs and expenses:
EPCO administrative services agreement	$	23.3		$	22.1		$	44.0		$	43.4
Expenses with EPO:
Purchases of natural gas		30.2			15.7			54.3			29.3
Operational measurement losses (gains)		(1.9	)		(3.5	)		3.4			(4.4	)
Other expenses with EPO		5.0			4.3			10.9			8.8
Purchases of natural gas – Nautilus		0.1			0.2			0.1			0.2
Expenses with Energy Transfer Equity:
Purchases of natural gas		(1.0	)		2.0			6.1			5.8
Operating cost reimbursements for shared facilities		(0.7	)		(0.9	)		(1.8	)		(1.9	)
Other expenses with Energy Transfer Equity		(0.4	)		1.1			4.3			1.3
Total related party operating costs and expenses	$	54.6		$	41.0		$	121.3		$	82.5

General and administrative costs:
EPCO ASA	$	4.4		$	3.4		$	8.1		$	7.5
Other related party general and administrative		0.4			(0.1	)		0.7			--
Total related party general and administrative costs	$	4.8		$	3.3		$	8.8		$	7.5

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

	June 30,		December 31,
	2011		2010
Accounts receivable – related parties
EPO and affiliates	$	54.2	$	19.5
Energy Transfer Equity and affiliates		0.9		1.6
Total	$	55.1	$	21.1

Accounts payable – related parties
EPO and affiliates	$	61.1	$	13.6
EPCO and affiliates		13.1		13.2
Energy Transfer Equity and affiliates		0.1		--
Total	$	74.3	$	26.8

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

Relationship with EPO

One of our primary business purposes is to support the growth objectives of EPO and other affiliates of EPCO that are under common control. Our assets are integral to EPO's midstream energy operations. We believe that the operational significance of our assets to EPO, as well as the alignment of our economic interests in these assets with EPO, will result in a collaborative effort to promote their operational efficiency and maximize value. In addition, we believe our relationship with EPO provides us with a distinct benefit in the identification and execution of potential future acquisitions that are not otherwise taken by Enterprise.

At June 30, 2011, EPO beneficially owned approximately 58.5% of our limited partner interests and 100% of our general partner.

EPO was the sponsor of the DEP I and DEP II drop down transactions and owns noncontrolling economic interests in the DEP I and DEP II Midstream Businesses. For a description of EPO's noncontrolling interest in the income and net assets of the DEP I and DEP II Midstream Businesses, see Note 11. EPO may contribute or sell other equity interests or assets to us; however, EPO has no obligation or commitment to make such contributions or sales to us, nor do we have any obligation or commitment to accept such contributions or make such acquisitions.

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

Agreement and Plan of Merger with Enterprise. On April 28, 2011, we entered into an Agreement and Plan of Merger (the “Merger Agreement”), by and among Enterprise, Enterprise GP, EPD MergerCo LLC, a Delaware limited liability company and a wholly owned subsidiary of Enterprise (“MergerCo”), Duncan Energy Partners and DEP GP. At the effective time of the merger and pursuant to the Merger Agreement, MergerCo will merge with and into Duncan Energy Partners, with Duncan Energy Partners surviving the merger as a wholly owned subsidiary of Enterprise (the “DEP Merger”), and all of our common units outstanding at the effective time of the merger will be cancelled and converted into the right to receive common units representing limited partner interests in Enterprise based on an exchange rate of 1.01 Enterprise common units for each of our common units. However, in lieu of Enterprise common units, Enterprise GTM Holdings L.P. (“Enterprise GTM”), an indirect wholly owned subsidiary of Enterprise, would exchange its right to merger consideration with respect to 33,783,587 of our common units currently directly owned by it (representing approximately 58.5% of our outstanding common units) for retaining an equivalent limited partner interest in Duncan Energy Partners. No fractional Enterprise common units would be issued in the proposed DEP Merger, and our unitholders would receive cash in lieu of fractional Enterprise common units, if any.

The Audit, Conflicts and Governance (“ACG”) Committee of DEP GP unanimously determined that the DEP Merger, the Merger Agreement and the transactions contemplated thereby are fair and reasonable to us and our unitholders that are unaffiliated with Enterprise, with such approval constituting “Special Approval” under our Partnership Agreement. The ACG Committee of DEP GP also recommended that the DEP Merger be approved by our unaffiliated unitholders and DEP GP's board of directors. Based on such determination, Special Approval and related recommendations, DEP GP's board of directors approved the DEP Merger and recommended that our unaffiliated unitholders vote in favor of the DEP Merger proposal. In addition, the board of directors of the general partner of Enterprise approved the transaction.

On September 7, 2011, we will host a special meeting of unitholders to consider and vote upon approval of the Merger Agreement and the DEP Merger. The Merger Agreement and the DEP Merger must be approved by the affirmative vote or consent of holders of (i) a majority of our outstanding common units and (ii) a majority of our common units owned by the Duncan unitholders unaffiliated with Enterprise that actually vote for or against such approval. In connection with the Merger Agreement, we, Enterprise and Enterprise GTM entered into a Voting Agreement, dated as of April 28, 2011 (the “Voting Agreement”), pursuant to which Enterprise GTM and Enterprise agreed to vote all of our common units owned by them or their subsidiaries in favor of the adoption of the Merger Agreement and the DEP Merger at any meeting of our unitholders, including the 33,783,587 of our common units currently directly owned by Enterprise GTM (representing approximately 58.5% of our outstanding common units). The Voting Agreement will terminate upon the termination of the Merger Agreement.

The Merger Agreement contains customary representations, warranties and covenants by each of the parties. Completion of the proposed DEP Merger is conditioned upon, among other things: (i) requisite Duncan Energy Partners' unitholder approval of the Merger Agreement and the DEP Merger as described above; (ii) applicable regulatory approvals; (iii) the absence of certain legal injunctions or impediments prohibiting the transactions; (iv) the effectiveness of a registration statement on Form S-4 with respect to the issuance by Enterprise of the Enterprise common units in connection with the DEP Merger (the Form S-4 was declared effective by the SEC on August 1, 2011); (v) the receipt of certain tax opinions; and (vi) approval for the listing of the Enterprise common units to be issued in connection with the DEP Merger on the NYSE. Subject to the satisfaction of these conditions, completion of the DEP Merger is expected to occur during the third quarter of 2011. See Note 15 for information regarding litigation matters associated with the proposed DEP Merger.

The Merger Agreement contains provisions granting both us and Enterprise the right to terminate the Merger Agreement for certain reasons, including (i) if the DEP Merger has not occurred on or before October 31, 2011 and (ii) our failure to obtain the requisite unitholder approvals as described above.

Master Intercompany Loan Agreement. On December 31, 2009, we and EPO entered into a master intercompany loan agreement with the DEP I and DEP II Midstream Businesses. This agreement will be used from time to time to facilitate cash management efforts in connection with the DEP I and DEP II Midstream Businesses. On December 31, 2009, we and EPO borrowed $1.3 million and $45.6 million, respectively, under the agreement at a market rate of interest. These amounts were subsequently repaid on January 4, 2010.

Omnibus Agreement. On December 8, 2008, we entered into an amended and restated Omnibus Agreement (the “Omnibus Agreement”) with EPO that addressed various matters. The key provisions of this agreement at June 30, 2011 are summarized as follows:

§	EPO agreed to fund 100% of the post-February 5, 2007 capital expenditures incurred by South Texas NGL and Mont Belvieu Caverns with respect to certain expansion projects under construction at the time of our initial public offering;

§	EPO agreed to fund 100% of post-December 8, 2008 capital expenditures to complete the Sherman Extension natural gas pipeline (a component of our Texas Intrastate System);

§	EPO was granted a right of first refusal in our current and future subsidiaries and a right of first refusal on the material assets of such subsidiaries, other than sales of inventory and other assets in the ordinary course of business;

§	EPO was granted a preemptive right with respect to any equity securities issued by certain of our subsidiaries, other than those that may be issued as consideration in an acquisition or in connection with a loan or debt financing;

§	Neither EPO nor any of its affiliates are restricted under the Omnibus Agreement from competing against us;

§	We and EPO agreed to negotiate in good faith any necessary amendments to the partnership or company agreements of the DEP II Midstream Businesses when either party believes that business circumstances have changed; and

§	Our general partner's ACG Committee must approve amendments to the Omnibus Agreement when such amendments would adversely affect our unitholders.

Mont Belvieu Caverns' LLC Agreement. The Caverns LLC Agreement states that if Duncan Energy Partners elects to not participate in the expansion 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 expansion projects from EPO within 90 days of such projects being placed in service. Effective November 2008, the Caverns LLC Agreement provides for EPO to prospectively receive a special allocation of 100% of the depreciation expense related to expansion projects that it has fully funded.

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

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

Company and Limited Partnership Agreements – DEP II Midstream Businesses. On December 8, 2008, the DEP II Midstream Businesses amended and restated their governing documents in connection with the DEP II drop down transaction. Collectively, these amended and restated agreements provided for (i) the acquisition by us of a 66% general partner interest in Enterprise GC, a 51% general partner interest in Enterprise Intrastate and a 51% member interest in Enterprise Texas; (ii) the payment of cash distributions by the DEP II Midstream Businesses to us and EPO in accordance with a waterfall approach; (iii) the funding of operating cash flow deficits of the DEP II Midstream Businesses in accordance with each owner's respective partner or member interest; and (iv) the election by either owner to participate in the funding of expansion capital projects of the DEP II Midstream Businesses. See Note 11 for information regarding EPO's noncontrolling interest and related matters involving the DEP II Midstream Businesses.

Amended Acadian LLC Agreement. On June 1, 2010, we entered into the Amended Acadian LLC Agreement with EPO. This document includes the agreement between us and EPO regarding funding arrangements for the Haynesville Extension project. As part of this agreement, we and EPO agreed to fund the construction of the Haynesville Extension in accordance with our respective sharing ratios in Acadian Gas (i.e., 66% for us and 34% for EPO). The total expected cost of the Haynesville Extension is approximately $1.50 billion (including capitalized interest); therefore, we estimate that our share of such costs will approximate $990 million. In order to address our funding requirements under the Haynesville Extension project, we entered into new long-term senior unsecured credit facilities in October 2010 having an aggregate borrowing capacity of $1.25 billion (see Note 9).

As part of the agreement, we reimbursed EPO for 66% of certain construction expenses it paid related to the Haynesville Extension project from the inception of the project through the date of the agreement (plus interest).

The Amended Acadian LLC Agreement also includes provisions related to future expansion projects of Acadian Gas other than the Haynesville Extension. When such projects are presented for funding, Acadian Gas will request additional capital contributions from us and EPO based on our respective sharing ratios. Acadian Gas will provide us and EPO with written notice of the due date for our initial contributions and we and EPO will have 20 days to give a written reply as to whether we elect to participate in the expansion project. We or EPO may propose to contribute an amount less than that requested by Acadian Gas, at which time we and EPO will decide whether to proceed with the expansion project.

Relationship with EPCO

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

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

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

§	EPCO will allow us to participate as a named insured in its overall insurance program, with the associated premiums and other costs being allocated to us. See Note 16 for additional information regarding our insurance programs.

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

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2011		2010		2011		2010
Operating costs and expenses	$	23.3	$	22.1	$	44.0	$	43.4
General and administrative expenses		4.4		3.4		8.1		7.5
Total costs and expenses	$	27.7	$	25.5	$	52.1	$	50.9

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

The ASA also addresses potential conflicts that may arise among Enterprise and Enterprise GP, Duncan Energy Partners and DEP GP, and the EPCO Group with respect to business opportunities (as defined within the ASA) with third parties. The EPCO Group includes EPCO and its other affiliates, but excludes Enterprise, Duncan Energy Partners and our respective general partners.

Relationship with Evangeline

Acadian Gas sold $49.6 million and $49.0 million of natural gas to Evangeline, under its natural gas purchase contract with Evangeline, during the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, Acadian Gas sold $80.3 million and $86.8 million, respectively, of natural gas to Evangeline. The amount of natural gas purchased by Evangeline pursuant to this contract averaged approximately 114.4 BBtus per day (“BBtus/d”) and 94.5 BBtus/d during the three months ended June 30, 2011 and 2010, respectively, and 95.2 BBtus/d and 83.3 BBtus/d during the six months ended June 30, 2011 and 2010, respectively.

Relationship with Energy Transfer Equity

Enterprise has a noncontrolling ownership interest in Energy Transfer Equity that is accounted for using the equity method. Since we are under common control with Enterprise, Energy Transfer Equity is considered a related party to us. Our revenues from Energy Transfer Equity are attributable to natural gas transportation services and NGL and petrochemical storage 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 East Texas.

Enterprise Texas, a DEP II Midstream Business, is party to a lease of certain capacity rights from an ETP subsidiary with respect to a 240-mile, 24-inch diameter natural gas pipeline located in East Texas (the “Leased Pipeline”). Enterprise Texas currently utilizes a portion of this pipeline for existing services. Lease payments to ETP were approximately $1.5 million for the year ended December 31, 2010 and $0.8 million for the six months ended June 30, 2011.

- Definition

The entire disclosure for related party transactions, including the nature of the relationship(s), a description of the transactions, the amount of the transactions, the effects of any change in the method of establishing the terms of the transaction from the previous period, stated interest rate, expiration date, terms and manner of settlement per the agreement with the related party, and amounts due to or from related parties. If the entity and one or more other entities are under common ownership or management control and this control affects the operating results or financial position, disclosure includes the nature of the control relationship even if there are no transactions between the entities. Disclosure may also include the aggregate amount of current and deferred tax expense for each statement of earnings presented where the entity is a member of a group that files a consolidated tax return, the amount of any tax related balances due to or from affiliates as of the date of each statement of financial position presented, the principal provisions of the method by which the consolidated amount of current and deferred tax expense is allocated to the members of the group and the nature and effect of any changes in that method. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
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-Article 4
-Section 08
-Paragraph k

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 3A
-Section 04
-Paragraph b

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 57
-Paragraph 1-4
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 850
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-Section 50
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-Section 50
-Paragraph 3
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(k))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39678-107864

+ Details

Commitments and Contingencies	6 Months Ended
Commitments and Contingencies	Jun. 30, 2011
Commitments and Contingencies [Abstract]
Commitments and Contingencies	Note 15. Commitments and Contingencies Litigation As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the possible need for accounting recognition or disclosure of these contingencies. We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. We will vigorously defend the partnership in litigation matters. Based on a consideration of all relevant known facts and circumstances (including insurance coverage), we do not believe the ultimate outcome of any currently pending lawsuit against us will have a material impact on our financial statements individually or in the aggregate. See Note 16 for information regarding insurance matters. At both June 30, 2011 and December 31, 2010, litigation accruals on an undiscounted basis of $6.8 million were recorded in our consolidated balance sheets as a component of other current liabilities. Our evaluation of litigation contingencies is based on the facts and circumstances of each case and predicting the outcome of these matters involves substantial uncertainties. In the event the assumptions we use to evaluate these matters change in future periods or new information becomes available, we may be required to record additional accruals. In an effort to mitigate expenses associated with litigation, we may settle legal proceedings out of court. Litigation related to proposed merger with Enterprise. The following information pertains to litigation filed by plaintiffs in connection with our proposed merger with Enterprise. We do not believe that any expenditures related to such matters will be material to our financial statements. We will continue to vigorously defend the partnership in these matters. On March 8, 2011, Michael Crowley, a purported unitholder of Duncan Energy Partners, filed a complaint in the Court of Chancery of the State of Delaware, as a putative class action on behalf of the public unitholders of Duncan Energy Partners, captioned Michael Crowley v. Duncan Energy Partners L.P., DEP Holdings, LLC, W. Randall Fowler, Bryan F. Bulawa, William A. Bruckmann, III, Larry J. Casey, Richard S. Snell, Enterprise Products Partners L.P., Enterprise Products Holdings LLC, and Enterprise Products Operating LLC (the “Crowley Complaint”). The Crowley Complaint alleges, among other things, that the named directors of DEP GP have breached fiduciary duties in connection with Enterprise's proposal to acquire our outstanding publicly-held common units and that we and DEP GP aided and abetted in these alleged breaches of fiduciary duties and that Enterprise, as the majority and controlling unitholder, along with EPO, have breached fiduciary duties by not acting in the minority unitholders' best interest to ensure the transaction resulting from Enterprise's proposal is entirely fair. On March 11, 2011, Sanjay Israni, a purported unitholder of Duncan Energy Partners, filed a complaint in the Court of Chancery of the State of Delaware, as a putative class action on behalf of the public unitholders of Duncan Energy Partners, captioned Sanjay Israni v. Duncan Energy Partners L.P., DEP Holdings, LLC, Enterprise Products Partners L.P., Enterprise Product Holdings LLC, Enterprise Production Operating LLC, W. Randall Fowler, Bryan F. Bulawa, William A. Bruckmann, III, Larry J. Casey, and Richard S. Snell (the “Israni Complaint II”). The Israni Complaint II alleges, among other things, that the named directors of DEP GP have breached fiduciary duties in connection with Enterprise's proposal to acquire our outstanding publicly-held common units and that we along with all of the other named defendants aided and abetted in these alleged breaches of fiduciary duties. On March 28, 2011, Michael Rubin, a purported unitholder of Duncan Energy Partners, filed a complaint in the Court of Chancery of the State of Delaware, as a putative class action on behalf of the public unitholders of Duncan Energy Partners, captioned Michael Rubin v. Duncan Energy Partners L.P., DEP Holdings, LLC, W. Randall Fowler, Bryan F. Bulawa, William A. Bruckmann, III, Larry J. Casey, Richard S. Snell, Enterprise Products Partners L.P., Enterprise Products Holdings LLC, and Enterprise Products Operating LLC (the “Rubin Complaint”). The Rubin Complaint alleges, among other things, that the named directors of DEP GP have breached fiduciary duties in connection with Enterprise's proposal to acquire our outstanding publicly-held common units, that we and DEP GP aided and abetted in these alleged breaches of fiduciary duties and that Enterprise, as the majority and controlling unitholder, along with EPO, have breached fiduciary duties by not acting in the best interests of the minority unitholders to ensure the transaction resulting from Enterprise's proposal is entirely fair. On April 5, 2011, the plaintiffs in the Crowley Complaint, the Israni Complaint II, and the Rubin Complaint filed a Proposed Order of Consolidation and Appointment of Lead Counsel in the Court of Chancery of the State of Delaware. The court granted that order on the same day consolidating the three actions into a single consolidated action, captioned In re Duncan Energy Partners L.P. Unitholders Litigation. On June 3, 2011 the Delaware plaintiffs filed a consolidated amended complaint which alleges, among other things, breach of express and implied contractual duties contained in our partnership agreement by DEP GP and the named directors of DEP GP and that all defendants have aided and abetted these alleged breaches. The consolidated amended complaint also alleges that the defendants failed to provide full and fair disclosures regarding the proposed transaction. On March 7, 2011, Merle Davis, a purported unitholder of Duncan Energy Partners, filed a petition in the 269th District Court of Harris County, Texas, as a putative class action on behalf of the unitholders of Duncan Energy Partners, captioned Merle Davis, on Behalf of Himself and All Others Similarly Situated v. Duncan Energy Partners L.P., W. Randall Fowler, Bryan F. Bulawa, William A. Bruckmann, III, Larry J. Casey, Richard S. Snell, DEP Holdings, LLC, and Enterprise Products Partners L.P. (the “Davis Petition”). The Davis Petition alleges, among other things, that Enterprise and the named directors of DEP GP have breached fiduciary duties in connection with Enterprise's proposal to acquire our outstanding publicly-held common units and that we and Enterprise aided and abetted in these alleged breaches of fiduciary duties. On March 9, 2011, Donald Weilersbacher, a purported unitholder of Duncan Energy Partners, filed a petition in the 334th District Court of Harris County, Texas, as a putative class action on behalf of the unitholders of Duncan Energy Partners, captioned Donald Weilersbacher, on Behalf of Himself and All Others Similarly Situated v. Duncan Energy Partners L.P., Enterprise Products Partners L.P., DEP Holdings, LLC, W. Randall Fowler, Bryan F. Bulawa, William A. Bruckmann, III, Larry J. Casey, and Richard S. Snell (the “Weilersbacher Petition”). The Weilersbacher Petition alleges, among other things, that the named directors of DEP GP have breached fiduciary duties in connection with Enterprise's proposal to acquire our outstanding publicly-held common units and that Enterprise aided and abetted in these alleged breaches of fiduciary duties. On March 17, 2011, the plaintiffs in the Davis Petition and the Weilersbacher Petition filed a motion and proposed Order for Consolidation of Related Actions, Appointment of Interim Co-Lead Counsel, and Order Compelling Limited Expedited Discovery. Plaintiffs and defendants subsequently agreed to postpone discovery until after the plaintiffs file a consolidated petition. On March 28, 2011, the plaintiffs filed an amended motion and proposed Order for Consolidation of Related Actions and Appointment of Interim Co-Lead Counsel. On May 4, 2011, the court entered an order consolidating the cases and appointing interim lead counsel. On May 11, 2011, plaintiffs filed their consolidated petition. On June 23, 2011, the plaintiffs filed a Notice of Nonsuit Without Prejudice and the cases were dismissed without prejudice. On July 5, 2011, Merle Davis and Donald Weilersbacher, purported unitholders of Duncan Energy Partners, filed a complaint in the United States District Court of the Southern District of Texas, Houston Division, as a putative class action on behalf of the unitholders of Duncan Energy Partners, captioned Merle Davis and Donald Weilersbacher, on Behalf of Themselves and All Others Similarly Situated vs. Duncan Energy Partners, L.P., W. Randall Fowler, Bryan F. Bulawa, William A. Bruckmann, III, Larry J. Casey, Richard Snell, DEP Holdings, LLC, and Enterprise Products Partners L.P. (the “Davis/Weilersbacher Federal Complaint”). The Davis/Weilersbacher Federal Complaint alleged, among other things, that we, DEP GP and the named directors of DEP GP breached express and implied contractual duties in connection with Enterprise's proposal to acquire our outstanding publicly held common units, that all defendants aided and abetted in these alleged breaches, and that we and Enterprise violated Section 14(a) and Section 20(a) of the Exchange Act. On August 3, 2011, John Rinker and Arthur H. Speier, purported unitholders of Duncan Energy Partners, filed a complaint in the United States District Court of the Southern District of Texas, Houston Division, as a putative class action on behalf of the unitholders of Duncan Energy Partners, captioned John Rinker and Arthur H. Speier, on Behalf of Themselves and All Others Similarly Situated v. Duncan Energy Partners L.P., DEP Holdings, LLC, W. Randall Fowler, Bryan F. Bulawa, William A. Bruckmann, III, Larry J. Casey, Richard S. Snell and Enterprise Products Partners L.P. The Rinker/Speier complaint alleges, among other things, that we, DEP GP and the named directors of DEP GP breached express and implied contractual duties in connection with Enterprise's proposal to acquire our outstanding publicly held common units, that all defendants aided and abetted in these alleged breaches, and that we and Enterprise violated Section 14(a) and Section 20(a) of the Exchange Act. Redelivery Commitments We store natural gas, NGLs and certain petrochemicals that are owned by third parties. In accordance with the underlying agreements, we are generally required to redeliver such volumes to the owners on demand. At June 30, 2011, we had approximately 18.4 million barrels of NGL and petrochemical products and 4.0 TBtus of natural gas in our custody that were owned by third parties. We maintain insurance coverage related to such volumes that we believe is consistent with our exposures. See Note 16 for information regarding insurance matters. Regulatory Matters Responding to scientific reports regarding threats posed by global warming, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases. In addition, some states (e.g., California and New Mexico) have individually or in regional cooperation, imposed restrictions on greenhouse gas emissions under various policies and approaches, including establishing a cap on emissions, requiring efficiency measures, or providing incentives for pollution reduction, use of renewable energy, or use of fuels with lower carbon content. The U.S. Environmental Protection Agency (“EPA”) has taken action under the federal Clean Air Act (“CAA”) to regulate greenhouse gas emissions. In November 2010, the EPA finalized rules expanding its Mandatory Greenhouse Gas Reporting Rule, originally promulgated in October 2009, to be applicable to the oil and natural gas industry, including certain onshore oil and natural gas production activities, which may affect certain of our existing or future operations and require the inventory and reporting of emissions. In addition, the EPA has taken the position that existing CAA provisions require an assessment of greenhouse gas emissions within the permitting process for certain large new or modified stationary sources under the EPA's Prevention of Significant Deterioration and Title V permit programs beginning in 2011. Facilities triggering permit requirements may be required to reduce greenhouse gas emissions consistent with “best available control technology” standards if deemed to be cost-effective. These or other federal, regional and state measures could increase the operating and compliance costs of our pipelines, fractionation plants and other facilities, and could by affecting the price of, or reducing the demand for, fossil fuels or providing competitive advantages to competing fuels and energy sources, adversely affect market demand or pricing for our products or products served by our midstream infrastructure. In addition, there have been several court cases implicating greenhouse gas emissions and climate change issues that could establish precedent that may indirectly affect our business, customers or the energy sector generally. Any of these climate change legislative or judicial initiatives or developments could have a material impact on our financial statements; however, we are unable to provide a range of estimated future costs due to the extreme uncertainty of such matters. There is considerable public and private debate over global warming and the environmental effects of greenhouse gas emissions. Contractual Obligations Scheduled maturities of long-term debt. Amounts owed under our debt agreements have increased since December 31, 2010 primarily due to borrowings to fund construction costs of the Haynesville Extension. 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 2010 Form 10-K. Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. We are generally required to perform routine maintenance on the underlying leased assets. In addition, certain leases give us the option to make leasehold improvements. Maintenance and repairs of leased assets resulting from our operations are charged to expense as incurred. Lease and rental expense was $3.3 million and $3.2 million during the three months ended June 30, 2011 and 2010, respectively, and $6.3 million and $6.5 million during the six months ended June 30, 2011 and 2010, respectively. Purchase obligations. There have been no material changes in our consolidated purchase obligations since those reported in our 2010 Form 10-K, except for short-term payment obligations relating to capital projects initiated by us. These commitments represent unconditional payment obligations that we have agreed to pay vendors for services to be rendered or products to be delivered in connection with our capital spending programs. Our consolidated capital expenditure commitments outstanding increased from $285.3 million at December 31, 2010 to $441.3 million at June 30, 2011. At June 30, 2011, these commitments primarily relate to the Haynesville Extension and projects on the Texas Intrastate System (e.g., Eagle Ford Shale expansion projects). Other Claims As part of our normal business activities with joint venture partners, customers and suppliers, we occasionally have claims made against us as a result of disputes related to contractual agreements or similar arrangements. As of June 30, 2011, claims against us totaled approximately $0.1 million. These matters are in various stages of assessment and the ultimate outcome of such disputes cannot be reasonably estimated at this time; however, in our opinion, the likelihood of a material impact on our consolidated financial statements from such disputes is remote. Accordingly, accruals for loss contingencies related to these matters have not been reflected in our consolidated financial statements. Commitments under Equity Compensation Plans of EPCO In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for us (see Note 13). See Note 3 for additional information regarding accounting for equity awards.

- Definition

The entire disclosure for commitments and contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9, 10, 11, 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.25)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14435-108349

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 460
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6398077&loc=d3e12565-110249

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 440
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6394976&loc=d3e25287-109308

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

+ Details

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS Parenthetical - USD ($) $ in Millions	Jun. 30, 2011	Dec. 31, 2010
Current assets:
Allowance for doubtful accounts	$ 0.5	$ 0.4
Accumulated amortization of intangible assets	$ 54.7	$ 50.8

Significant Risks and Uncertainties	6 Months Ended
Significant Risks and Uncertainties	Jun. 30, 2011
Concentration Of Risk Disclosure [Abstract]
Significant Risks and Uncertainties	Note 16. Significant Risks and Uncertainties Insurance Matters We participate as a named insured in EPCO's insurance program, which provides us with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. While we believe EPCO maintains adequate insurance coverage on our behalf, insurance may not fully cover every type of damage, interruption or other loss that might occur. If we were to incur a significant loss for which we were not fully insured, it could have a material impact on our financial position, results of operations and cash flows. In addition, there may be a timing difference between amounts we are required to pay in connection with a loss and amounts we receive from insurance as reimbursement. Any event that materially interrupts the revenues generated by our consolidated operations, or other losses that require us to make material expenditures not covered by insurance, could reduce our ability to pay distributions to our partners and, accordingly, adversely affect the market price of our common units. From a financial accounting perspective, we expense losses up to our deductible amount, which can range from $5.0 million to $75.0 million depending on the nature of the loss (windstorm or non-windstorm) and the assets involved (onshore or offshore). With respect to property damage insurance claims in excess of our deductible, we record a claim receivable from our insurers for our actual costs to repair the asset (or the carrying value of damaged assets we elect not to repair) when the recovery of such amounts is probable. To the extent that any of our property damage claims are later judged not recoverable, such amounts are expensed. If property damage insurance proceeds exceed our claim receivable, such excess amount is recognized as income (a gain) when either the non-refundable cash is received or we have a binding settlement agreement with a carrier that clearly states that the payment will be made. With respect to business interruption insurance claims, we recognize income only when we receive non-refundable cash proceeds from insurers. February 2011 West Storage Incident. On February 8, 2011, we experienced a NGL release and fire at the West Storage location of our Mont Belvieu, Texas underground storage facility. West Storage consists of ten underground salt dome storage caverns with a storage capacity of approximately 15 MMBbls. As a result of reconfiguring certain storage-related assets, we have restored most of the receipt and delivery capability we had prior to the incident; however, our West Storage location and associated underground storage wells remain partially non-operative at this time. Remaining repairs to this location are underway and are expected to be completed in stages by early 2012. Our insurance deductible for such property damage events was $5.0 million, which expense was recognized in the first quarter of 2011. Based on current information, we estimate that the total cost of repairs and other rebuilding activities related to this incident will approximate $150 million. Our Mont Belvieu, Texas underground storage facility is owned by Mont Belvieu Caverns, which is part of the DEP I Midstream Businesses. We own 66% of the member interests of Mont Belvieu Caverns and EPO owns the remaining 34%. Prior to the receipt of insurance recoveries for this incident anticipated to occur in 2012 and 2013, the initial funding of the repairs and other rebuilding projects is expected to be made by us and EPO in accordance with our ownership interests in Mont Belvieu Caverns. We expect to fund our share of such costs through borrowings under the Multi-Year Revolving Credit Facility. At June 30, 2011, we had $37.3 million of estimated property damage insurance claims outstanding associated with the fire at West Storage, which is included in “Other assets” on our Unaudited Condensed Consolidated Balance Sheets. Interest Rate Risk We are exposed to changes in interest rates charged on our variable rate debt obligations. We cannot predict the costs of refinancing, at maturity, our existing credit facilities or the costs of new credit agreements. The inability to refinance or enter into new credit arrangements with favorable terms could impede our ability to fund capital requirements or to make distributions on our common units.