Edgar Filing: ENTERPRISE PRODUCTS PARTNERS L P

epdform10q_063012.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___ to ___.

Commission file number: 1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact Name of Registrant as Specified in Its Charter)

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

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

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

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

Yes þ No o

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

Yes þ No ¨

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

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

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

Yes o No þ

There were 884,165,626 common units and 4,520,431 Class B units (which generally vote together with the common units) of Enterprise Products Partners L.P. outstanding at July 31, 2012. Our common units trade on the New York Stock Exchange under the ticker symbol “EPD.”

Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.

TABLE OF CONTENTS

		Page No.
PART I. FINANCIAL INFORMATION.
Item 1.	Financial Statements.
	Unaudited Condensed Consolidated Balance Sheets	2
	Unaudited Condensed Statements of Consolidated Operations	3
	Unaudited Condensed Statements of Consolidated Comprehensive Income	4
	Unaudited Condensed Statements of Consolidated Cash Flows	5
	Unaudited Condensed Statements of Consolidated Equity	6
	Notes to Unaudited Condensed Consolidated Financial Statements:
	1. Partnership Operations, Organization and Basis of Presentation	7
	2. General Accounting Matters	8
	3. Equity-based Awards	11
	4. Derivative Instruments, Hedging Activities and Fair Value Measurements	13
	5. Inventories	22
	6. Property, Plant and Equipment	23
	7. Investments in Unconsolidated Affiliates	24
	8. Intangible Assets and Goodwill	27
	9. Debt Obligations	29
	10. Equity and Distributions	31
	11. Business Segments	34
	12. Related Party Transactions	38
	13. Earnings Per Unit	39
	14. Commitments and Contingencies	40
	15. Supplemental Cash Flow Information	41
	16. Insurance Matters	42
	17. Condensed Consolidating Financial Information	43
	18. Subsequent Events	50
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	51
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	73
Item 4.	Controls and Procedures.	76

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.	76
Item 1A.	Risk Factors.	76
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	77
Item 3.	Defaults Upon Senior Securities.	77
Item 4.	Mine Safety Disclosures.	77
Item 5.	Other Information.	77
Item 6.	Exhibits.	77

Signatures		85

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PART I. FINANCIAL INFORMATION.

Item 1. Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	June 30,			December 31,
ASSETS	2012			2011
Current assets:
Cash and cash equivalents	$	14.5		$	19.8
Restricted cash		--			38.5
Accounts receivable – trade, net of allowance for doubtful accounts of $13.0 at June 30, 2012 and $13.4 at December 31, 2011		3,724.9			4,501.8
Accounts receivable – related parties		2.3			43.5
Inventories		892.9			1,111.7
Prepaid and other current assets		434.8			353.4
Total current assets		5,069.4			6,068.7
Property, plant and equipment, net		23,760.6			22,191.6
Investments in unconsolidated affiliates		913.2			1,859.6
Intangible assets, net of accumulated amortization of $1,019.3 at June 30, 2012 and $990.4 at December 31, 2011		1,619.2			1,656.2
Goodwill		2,092.3			2,092.3
Other assets		212.4			256.7
Total assets	$	33,667.1		$	34,125.1

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	1,700.0		$	500.0
Accounts payable – trade		762.6			773.0
Accounts payable – related parties		70.2			211.6
Accrued product payables		4,039.7			5,047.1
Accrued interest		289.1			288.1
Other current liabilities		756.7			612.6
Total current liabilities		7,618.3			7,432.4
Long-term debt (see Note 9)		13,346.7			14,029.4
Deferred tax liabilities		23.8			91.2
Other long-term liabilities		202.2			352.8
Commitments and contingencies (see Note 14)
Equity: (see Note 10)
Partners’ equity:
Limited partners:
Common units (884,174,991 units outstanding at June 30, 2012 and 881,620,418 units outstanding at December 31, 2011)		12,566.5			12,346.3
Class B units (4,520,431 units outstanding at June 30, 2012 and December 31, 2011)		118.5			118.5
Accumulated other comprehensive loss		(318.7	)		(351.4	)
Total partners’ equity		12,366.3			12,113.4
Noncontrolling interests		109.8			105.9
Total equity		12,476.1			12,219.3
Total liabilities and equity	$	33,667.1		$	34,125.1

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(Dollars in millions, except per unit amounts)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
Revenues:
Third parties	$	9,764.2		$	11,072.3		$	20,985.9		$	21,005.9
Related parties		25.6			144.2			56.4			394.3
Total revenues (see Note 11)		9,789.8			11,216.5			21,042.3			21,400.2
Costs and expenses:
Operating costs and expenses:
Third parties		8,788.0			10,140.6			19,106.8			19,252.1
Related parties		221.5			392.7			369.9			818.3
Total operating costs and expenses		9,009.5			10,533.3			19,476.7			20,070.4
General and administrative costs:
Third parties		16.7			16.3			40.3			29.2
Related parties		25.8			34.1			48.5			59.1
Total general and administrative costs		42.5			50.4			88.8			88.3
Total costs and expenses (see Note 11)		9,052.0			10,583.7			19,565.5			20,158.7
Equity in income of unconsolidated affiliates		11.3			11.1			21.2			27.3
Operating income		749.1			643.9			1,498.0			1,268.8
Other income (expense):
Interest expense		(186.6	)		(188.3	)		(373.1	)		(372.1	)
Interest income		0.1			0.3			0.4			0.6
Other, net (see Note 2)		13.1			--			71.5			0.2
Total other expense, net		(173.4	)		(188.0	)		(301.2	)		(371.3	)
Income before income taxes		575.7			455.9			1,196.8			897.5
Benefit from (provision for) income taxes (see Note 2)		(8.5	)		(7.4	)		25.9			(14.5	)
Net income		567.2			448.5			1,222.7			883.0
Net income attributable to noncontrolling interests (see Note 10)		(0.9	)		(14.8	)		(5.1	)		(28.6	)
Net income attributable to limited partners	$	566.3		$	433.7		$	1,217.6		$	854.4

Earnings per unit: (see Note 13)
Basic earnings per unit	$	0.66		$	0.53		$	1.42		$	1.05
Diluted earnings per unit	$	0.64		$	0.51		$	1.37		$	1.00

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME

(Dollars in millions)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011

Net income	$	567.2		$	448.5		$	1,222.7		$	883.0
Other comprehensive income (loss):
Cash flow hedges:
Commodity derivative instruments:
Changes in fair value of cash flow hedges		105.0			(21.7	)		45.4			(173.1	)
Reclassification of gains and losses to net income		14.2			74.8			36.2			143.7
Interest rate derivative instruments:
Changes in fair value of cash flow hedges		(84.0	)		(60.1	)		(55.1	)		(46.0	)
Reclassification of gains and losses to net income		3.7			1.5			6.4			3.0
Total cash flow hedges		38.9			(5.5	)		32.9			(72.4	)
Change in funded status of pension and postretirement plans, net of tax		--			(0.9	)		(1.2	)		(0.6	)
Proportionate share of other comprehensive income (loss) of unconsolidated affiliate		--			0.3			1.0			(0.7	)
Change in fair value of available-for-sale equity securities		(15.8	)		--			--			--
Total other comprehensive income (loss)		23.1			(6.1	)		32.7			(73.7	)
Comprehensive income		590.3			442.4			1,255.4			809.3
Comprehensive income attributable to noncontrolling interests		(0.9	)		(14.8	)		(5.1	)		(28.6	)
Comprehensive income attributable to limited partners	$	589.4		$	427.6		$	1,250.3		$	780.7

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in millions)

	For the Six Months
	Ended June 30,
	2012			2011
Operating activities:
Net income	$	1,222.7		$	883.0
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		537.7			484.8
Non-cash asset impairment charges		14.5			--
Equity in income of unconsolidated affiliates		(21.2	)		(27.3	)
Distributions received from unconsolidated affiliates		50.5			84.8
Gains related to asset sales		(3.8	)		(23.6	)
Gains related to property damage insurance recoveries (see Note 16)		(27.7	)		--
Gains related to sales of Energy Transfer Equity common units (see Note 7)		(68.8	)		--
Deferred income tax expense (benefit)		(64.9	)		2.3
Changes in fair market value of derivative instruments		(21.6	)		(10.7	)
Net effect of changes in operating accounts (see Note 15)		(280.3	)		361.4
Other operating activities		1.2			(0.2	)
Net cash flows provided by operating activities		1,338.3			1,754.5
Investing activities:
Capital expenditures		(1,813.1	)		(1,716.2	)
Contributions in aid of construction costs		10.0			6.4
Decrease (increase) in restricted cash		38.5			(17.5	)
Investments in unconsolidated affiliates		(125.5	)		(11.8	)
Proceeds from asset sales (see Note 15)		1,129.0			250.5
Proceeds from property damage insurance recoveries (see Note 16)		27.7			--
Other investing activities		(16.4	)		(3.6	)
Cash used in investing activities		(749.8	)		(1,492.2	)
Financing activities:
Borrowings under debt agreements		2,414.6			3,791.1
Repayments of debt		(1,891.0	)		(3,033.5	)
Debt issuance costs		(7.5	)		(12.8	)
Monetization of interest rate derivative instruments (see Note 4)		(77.6	)		(5.7	)
Cash distributions paid to limited partners (see Note 10)		(1,068.6	)		(966.5	)
Cash distributions paid to noncontrolling interests (see Note 10)		(8.1	)		(34.8	)
Cash contributions from noncontrolling interests (see Note 10)		5.9			2.6
Net cash proceeds from issuance of common units		57.7			45.1
Other financing activities		(19.2	)		(4.2	)
Cash used in financing activities		(593.8	)		(218.7	)
Net change in cash and cash equivalents		(5.3	)		43.6
Cash and cash equivalents, January 1		19.8			65.5
Cash and cash equivalents, June 30	$	14.5		$	109.1

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(See Note 10 for Unit History, Accumulated Other Comprehensive

Income (Loss) and Noncontrolling Interests)

(Dollars in millions)

	Partners’ Equity
	Limited Partners			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
Balance, December 31, 2011	$	12,464.8		$	(351.4	)	$	105.9		$	12,219.3
Net income		1,217.6			--			5.1			1,222.7
Cash distributions paid to limited partners		(1,068.6	)		--			--			(1,068.6	)
Cash distributions paid to noncontrolling interests		--			--			(8.1	)		(8.1	)
Cash contributions from noncontrolling interests		--			--			5.9			5.9
Net cash proceeds from issuance of common units		57.7			--			--			57.7
Amortization of fair value of equity-based awards		31.8			--			--			31.8
Cash flow hedges		--			32.9			--			32.9
Other		(18.3	)		(0.2	)		1.0			(17.5	)
Balance, June 30, 2012	$	12,685.0		$	(318.7	)	$	109.8		$	12,476.1

	Partners’ Equity
	Limited Partners			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
Balance, December 31, 2010	$	11,406.7		$	(32.5	)	$	526.6		$	11,900.8
Net income		854.4			--			28.6			883.0
Cash distributions paid to limited partners		(966.5	)		--			--			(966.5	)
Cash distributions paid to noncontrolling interests		--			--			(34.8	)		(34.8	)
Cash contributions from noncontrolling interests		--			--			2.6			2.6
Net cash proceeds from issuance of common units		45.1			--			--			45.1
Amortization of fair value of equity-based awards		25.2			--			0.1			25.3
Cash flow hedges		--			(72.4	)		--			(72.4	)
Other		(4.5	)		(1.3	)		(2.0	)		(7.8	)
Balance, June 30, 2011	$	11,360.4		$	(106.2	)	$	521.1		$	11,775.3

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

stated in millions of dollars.

KEY REFERENCES USED IN THESE

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

References to “Holdings Merger” mean the merger of Enterprise GP Holdings L.P. with and into a wholly owned subsidiary of ours, with our subsidiary surviving such merger. The Holdings Merger and related transactions were completed in November 2010.

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

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries. We sold the remainder of our limited partner interests in Energy Transfer Equity in April 2012 (see Note 7).

Note 1. Partnership Operations, Organization and Basis of Presentation

General

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” We were formed in April 1998

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are now a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, refined products and petrochemicals. Our midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our assets include approximately 50,700 miles of onshore and offshore pipelines; 190 million barrels (“MMBbls”) of storage capacity for NGLs, crude oil, refined products and petrochemicals; and 14 billion cubic feet (“Bcf”) of natural gas storage capacity.

Our integrated midstream energy operations include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and import and export terminals; crude oil and refined products transportation, storage, and terminals; offshore production platforms; petrochemical transportation and services; and a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway systems and in the Gulf of Mexico. We currently have five active reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; and (v) Petrochemical & Refined Products Services. All activities included in our sixth reportable business segment, Other Investments, ceased on January 18, 2012, which was the date we discontinued using the equity method to account for our previously held investment in Energy Transfer Equity (see “Liquidation of Investment in Energy Transfer Equity” under Note 7).

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

Completion of Duncan Merger

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

Note 2. General Accounting Matters

Our results of operations for the three and six months ended June 30, 2012 are not necessarily indicative of results expected for the full year of 2012. In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”).

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Contingencies

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

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

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

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

Derivative Instruments

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

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

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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Estimates

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

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

Income Tax Benefit

For the six months ended June 30, 2012, we recognized a net income tax benefit of $25.9 million, which was primarily due to a $46.5 million net income tax benefit related to the conversion of certain of our subsidiaries to limited liability companies during the first quarter of 2012, partially offset by accruals for the Texas Margin Tax. The $46.5 million net income tax benefit is attributable to the difference between deferred income taxes accrued by the applicable subsidiaries through the date of conversion and any current income tax due in connection with the conversions.

Other Non-Operating Income

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

	For the Three Months					For the Six Months
	Ended June 30,					Ended June 30,
	2012			2011		2012			2011
Gain on sales of Energy Transfer Equity common units (1)	$	15.5		$	--	$	68.8		$	--
Distribution income from Energy Transfer Equity		--			--		4.1			--
Other		(2.4	)		--		(1.4	)		0.2
Total	$	13.1		$	--	$	71.5		$	0.2

(1) See Note 7 for information regarding our previously held investment in Energy Transfer Equity.

Recent Accounting Developments

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

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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,
	2012		2011		2012		2011
Restricted common unit awards	$	15.7	$	12.1	$	30.5	$	23.5
Unit option awards		0.3		0.8		1.0		1.7
Other (1)		0.5		0.3		1.4		(0.2	)
Total compensation expense	$	16.5	$	13.2	$	32.9	$	25.0

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

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

At June 30, 2012, EPCO’s significant long-term incentive plans applicable to us were the Enterprise Products 1998 Long-Term Incentive Plan (“1998 Plan”) and the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (“2008 Plan”). In addition, there were unvested awards outstanding under an inactive plan, the Enterprise Products 2006 TPP Long-Term Incentive Plan (“2006 Plan”). After giving effect to awards granted under the 1998 Plan and 2008 Plan through June 30, 2012, a total of 749,016 and 5,038,468 additional common units could be issued under these plans, respectively.

Restricted Common Unit Awards

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

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

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

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Restricted common units at December 31, 2011		3,868,216		$	34.22
Granted (2,3)		1,538,438		$	51.92
Vested (3)		(1,236,352	)	$	34.77
Forfeited		(95,575	)	$	38.43
Restricted common units at June 30, 2012		4,074,727		$	40.64

(1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued in 2012 was $79.9 million based on a grant date market price ranging from $51.92 to $52.26 per unit. An estimated annual forfeiture rate of 3.25% was applied to these awards. (3) Includes awards granted to the independent directors of the board of directors of Enterprise GP as part of their annual compensation for 2012. A total of 10,038 restricted common units were issued in February 2012 to the independent directors of Enterprise GP that immediately vested upon issuance.

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

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

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2012		2011		2012		2011
Cash distributions paid to restricted common unit holders	$	3.0	$	2.7	$	5.4	$	4.8
Total intrinsic value of our restricted common unit awards vesting during period		30.1		20.5		62.7		35.2

For the EPCO group of companies, the unrecognized compensation cost associated with restricted common unit awards was an aggregate $90.3 million at June 30, 2012, of which our allocated share of the cost is currently estimated to be $85.7 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 are denominated in our common units. When issued, the exercise price of each unit option grant may be no less than the market price of our common units on the date of grant. In general, option grants have a vesting period of four years from the date of grant and expire at the end of the calendar year following the year of vesting (e.g., an option vesting on May 29, 2011 will expire on December 31, 2012). However, unit options only become exercisable at certain times during the calendar year following the year in which they vest (typically the months of February, May, August and November).

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

	Number of Units			Weighted- Average Strike Price (dollars/unit)		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (1)
Unit options at December 31, 2011		3,753,420		$	28.08		2.6	$	11.1
Exercised		(712,280	)	$	30.76
Forfeited		(130,000	)	$	27.12
Unit options at June 30, 2012		2,911,140		$	27.46		2.5	$	14.4
Options exercisable at June 30, 2012		--					--		--

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

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

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

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2012		2011		2012		2011
Total intrinsic value of unit option awards exercised during period	$	--	$	--	$	14.0	$	--
Cash received from EPCO in connection with the exercise of unit option awards		--		--		10.2		--
Unit option-related reimbursements to EPCO		--		--		14.0		--

For the EPCO group of companies, the unrecognized compensation cost associated with unit option awards was an aggregate $2.2 million at June 30, 2012, of which our allocated share of the cost is currently estimated to be $2.0 million. We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 1.1 years.

Unit Appreciation Rights

At December 31, 2011, there were 107,328 UARs outstanding that had been granted under the 2006 Plan. The accrued liability for UARs at December 31, 2011 was $0.5 million. All of these awards vested in May 2012. The accrued liability for UARs in May 2012 (i.e., immediately before vesting) was $1.4 million. While these awards were outstanding, they were accounted for as liability awards.

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

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

We are required to recognize derivative instruments at fair value as either assets or liabilities on our balance sheet unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of derivative

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instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. Any ineffectiveness associated with a hedge relationship is recognized in earnings immediately. Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item.

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

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

Interest Rate Hedging Activities

We may utilize interest rate swaps, forward starting swaps and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. The following table summarizes our portfolio of interest rate swaps at June 30, 2012:

Hedged Transaction	Number and Type of Derivatives Outstanding	Notional Amount	Period of Hedge	Rate Swap	Accounting Treatment
Senior Notes AA	10 fixed-to-floating swaps	$750.0	1/2011 to 2/2016	3.2% to 1.5%	Fair value hedge
Undesignated swaps	6 floating-to-fixed swaps	$600.0	5/2010 to 7/2014	0.5% to 2.0%	Mark-to-market

Interest expense for the three months ended June 30, 2012 and 2011 reflects a benefit of $2.2 million and an expense of $2.2 million, respectively, attributable to interest rate swaps. For the six months ended June 30, 2012 and 2011, such swaps resulted in a benefit in interest expense of $5.0 million and $7.5 million, respectively.

In February 2012, we settled 11 fixed-to-floating interest rate swaps having an aggregate notional amount of $800.0 million, resulting in gains totaling $37.7 million. As fair value hedges, the unamortized portion of these gains are a component of long-term debt (see Note 9) and are being amortized to earnings (as a decrease in interest expense) using the effective interest method over the forecasted hedged period of approximately three years.

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The following table summarizes our portfolio of forward starting swaps outstanding at June 30, 2012. Forward starting swaps hedge the expected underlying benchmark interest rates related to future issuances of debt.

Hedged Transaction	Number and Type of Derivatives Outstanding	Notional Amount	Expected Termination Date	Average Rate Locked	Accounting Treatment
Future debt offering	7 forward starting swaps	$350.0	8/2012	3.7%	Cash flow hedge
Future debt offering	16 forward starting swaps	$1,000.0	3/2013	3.7%	Cash flow hedge

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

In connection with EPO’s agreement to issue Senior Notes FF and Senior Notes GG in August 2012 (see Note 18), we settled seven forward starting swaps having an aggregate notional amount of $350.0 million, resulting in cash losses of $70.2 million. Accumulated other comprehensive income as of June 30, 2012 includes $63.9 million of the loss, with the remaining $6.3 million of loss attributable to the period June 30, 2012 through the settlement date of August 1, 2012. The total loss recorded in accumulated other comprehensive income will be amortized to earnings (as an increase in interest expense) over the forecasted hedged period of ten years using the effective interest method.

Although we incurred cash losses upon settlement of our forward starting swaps in February 2012 and August 2012, we benefited from the exceptionally low interest rate environment during these periods relative to the interest rates in effect at the time we entered into the swaps.

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Commodity Hedging Activities

The prices of natural gas, NGLs, crude oil, refined products and certain petrochemical products are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps, basis swaps and options contracts. The following table summarizes our commodity derivative instruments outstanding at June 30, 2012:

	Volume (1)		Accounting
Derivative Purpose	Current (2)	Long-Term (2)	Treatment
Derivatives designated as hedging instruments:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction (“PTR”) (3)	15.3 Bcf	n/a	Cash flow hedge
Forecasted sales of NGLs (4)	1.6 MMBbls	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchases of NGLs	0.2 MMBbls	n/a	Cash flow hedge
Forecasted sales of octane enhancement products	2.0 MMBbls	n/a	Cash flow hedge
Natural gas marketing:
Forecasted sales of natural gas	1.2 Bcf	n/a	Cash flow hedge
Natural gas storage inventory management activities (Bcf)	11.1 Bcf	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products	3.2 MMBbls	0.5 MMBbls	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products	3.7 MMBbls	0.5 MMBbls	Cash flow hedge
Refined products marketing:
Forecasted purchases of refined products	0.1 MMBbls	n/a	Cash flow hedge
Forecasted sales of refined products	0.5 MMBbls	n/a	Cash flow hedge
Refined products inventory management activities	0.2 MMBbls	n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil	2.8 MMBbls	n/a	Cash flow hedge
Forecasted sales of crude oil	4.1 MMBbls	n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (5,6)	241.0 Bcf	56.0 Bcf	Mark-to-market
Refined products risk management activities (6)	1.1 MMBbls	n/a	Mark-to-market
Crude oil risk management activities (6)	5.7 MMBbls	n/a	Mark-to-market
(1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2013, March 2013 and October 2015, respectively. (3) PTR represents the British thermal unit (“Btu”) equivalent of the NGLs extracted from natural gas by a processing plant, and includes the natural gas used as plant fuel to extract those liquids, plant flare and other shortages. (4) Forecasted sales of NGL volumes under natural gas processing exclude 2.2 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements. (5) Current volumes include approximately 62.5 Bcf of physical derivative instruments that are predominantly priced at an index plus a premium or minus a discount related to location differences. (6) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

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

§	The objective of our natural gas processing strategy is to hedge an amount of gross margin associated with our natural gas processing activities. We achieve this objective by using physical and financial instruments to lock in the purchase prices of natural gas consumed as PTR and the

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

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

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

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

Derivative Instruments and Related Hedged Items

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

	Asset Derivatives						Liability Derivatives
	June 30, 2012			December 31, 2011			June 30, 2012			December 31, 2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Interest rate derivatives	Other current assets	$	18.6	Other current assets	$	43.7	Other current liabilities	$	230.6	Other current liabilities	$	163.6
Interest rate derivatives	Other assets		26.6	Other assets		44.2	Other liabilities		--	Other liabilities		127.1
Total interest rate derivatives			45.2			87.9			230.6			290.7
Commodity derivatives	Other current assets		127.4	Other current assets		20.3	Other current liabilities		74.6	Other current liabilities		30.3
Commodity derivatives	Other assets		4.8	Other assets		--	Other liabilities		2.1	Other liabilities		0.2
Total commodity derivatives (1)			132.2			20.3			76.7			30.5
Total derivatives designated as hedging instruments		$	177.4		$	108.2		$	307.3		$	321.2

Derivatives not designated as hedging instruments
Interest rate derivatives	Other current assets	$	--	Other current assets	$	--	Other current liabilities	$	11.0	Other current liabilities	$	10.1
Interest rate derivatives	Other assets		--	Other assets		--	Other liabilities		8.6	Other liabilities		10.6
Total interest rate derivatives			--			--			19.6			20.7
Commodity derivatives	Other current assets		26.0	Other current assets		34.4	Other current liabilities		19.4	Other current liabilities		32.5
Commodity derivatives	Other assets		4.4	Other assets		12.6	Other liabilities		1.8	Other liabilities		2.0
Total commodity derivatives			30.4			47.0			21.2			34.5
Total derivatives not designated as hedging instruments		$	30.4		$	47.0		$	40.8		$	55.2

(1) Represents commodity derivative instrument transactions that have either not settled or have settled and cash has not been paid or received. Settled and unpaid or unreceived amounts are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.

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

Derivatives in Fair Value Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Derivative
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	4.6		$	21.1		$	3.1		$	8.8
Commodity derivatives	Revenue		(16.4	)		(1.6	)		(15.7	)		(1.3	)
Total		$	(11.8	)	$	19.5		$	(12.6	)	$	7.5

Derivatives in Fair Value Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Hedged Item
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	(4.5	)	$	(21.0	)	$	(3.4	)	$	(9.7	)
Commodity derivatives	Revenue		15.9			0.2			16.3			(1.1	)
Total		$	11.4		$	(20.8	)	$	12.9		$	(10.8	)

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

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income/(Loss) on Derivative (Effective Portion)
	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
Interest rate derivatives	$	(84.0	)	$	(60.1	)	$	(55.1	)	$	(46.0	)
Commodity derivatives – Revenue		99.8			(19.4	)		60.2			(174.8	)
Commodity derivatives – Operating costs and expenses		5.2			(2.3	)		(14.8	)		1.7
Total	$	21.0		$	(81.8	)	$	(9.7	)	$	(219.1	)

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income (Effective Portion)
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	(3.7	)	$	(1.5	)	$	(6.4	)	$	(3.0	)
Commodity derivatives	Revenue		(2.6	)		(79.3	)		(12.6	)		(148.5	)
Commodity derivatives	Operating costs and expenses		(11.6	)		4.5			(23.6	)		4.8
Total		$	(17.9	)	$	(76.3	)	$	(42.6	)	$	(146.7	)

Derivatives in Cash Flow Hedging Relationships	Location	Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
		For the Three Months				For the Six Months
		Ended June 30,				Ended June 30,
		2012		2011		2012		2011
Commodity derivatives	Revenue	$	0.9	$	0.3	$	0.9	$	0.2
Commodity derivatives	Operating costs and expenses		--		--		0.3		--
Total		$	0.9	$	0.3	$	1.2	$	0.2

Over the next twelve months, we expect to reclassify $26.2 million of losses attributable to interest rate derivative instruments from accumulated other comprehensive loss to earnings as an increase in interest expense. Likewise, we expect to reclassify $57.6 million of gains attributable to commodity

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derivative instruments from accumulated other comprehensive income (loss) to earnings, $59.4 million as an increase in revenue and $1.8 million as an increase in operating costs and expenses.

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

Derivatives Not Designated as Hedging Instruments	Location	Gain/(Loss) Recognized in Income on Derivative
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2012			2011			2012			2011
Interest rate derivatives	Interest expense	$	(1.1	)	$	(11.9	)	$	(3.3	)	$	(10.5	)
Commodity derivatives	Revenue		9.3			9.5			30.1			13.3
Commodity derivatives	Operating costs and expenses		--			--			(2.8	)		--
Total		$	8.2		$	(2.4	)	$	24.0		$	2.8

Fair Value Measurements

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

A three-tier hierarchy has been established that classifies fair value amounts recognized 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.

Recurring Fair Value Measurements

The following table sets forth, by level within the fair value hierarchy, the carrying values of our financial assets and liabilities at June 30, 2012. These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input that is significant to their respective fair value. Our assessment of the relative significance of such inputs requires judgment.

	Fair Value Measurements Using
	Quoted Prices
	in Active
	Markets for		Significant		Significant		Carrying
	Identical Assets		Observable		Unobservable		Value
	and Liabilities		Inputs		Inputs		at June 30,
	(Level 1)		(Level 2)		(Level 3)		2012
Financial assets:
Interest rate derivatives	$	--	$	45.2	$	--	$	45.2
Commodity derivatives		81.6		73.1		7.9		162.6
Total	$	81.6	$	118.3	$	7.9	$	207.8

Financial liabilities:
Interest rate derivatives	$	--	$	250.2	$	--	$	250.2
Commodity derivatives		39.1		55.8		3.0		97.9
Total	$	39.1	$	306.0	$	3.0	$	348.1

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

		For the Six Months
		Ended June 30,
	Location	2012			2011
Balance, January 1		$	0.4		$	(25.9	)
Total gains (losses) included in:
Net income (1)	Revenue		0.5			(0.5	)
Other comprehensive income (loss)	Commodity derivative instruments – changes in fair value of cash flow hedges		0.5			16.2
Settlements			(0.5	)		0.8
Transfers out of Level 3 (2)			--			9.8
Balance, March 31			0.9			0.4
Total gains (losses) included in:
Net income (1)	Revenue		(1.3	)		1.9
Other comprehensive income (loss)	Commodity derivative instruments – changes in fair value of cash flow hedges		6.0			--
Settlements			(0.7	)		(0.2	)
Balance, June 30		$	4.9		$	2.1

(1) There were $2.0 million and $1.9 million of unrealized losses included in these amounts for the three and six months ended June 30, 2012, respectively. There were $2.0 million and $1.8 million of unrealized gains included in these amounts for the three and six months ended June 30, 2011, respectively. (2) Transfers out of Level 3 into Level 2 during 2011 were primarily due to the change in observability of forward NGL prices.

The following table provides quantitative information about our recurring Level 3 fair value measurements at June 30, 2012:

	Fair Value
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives – Propane	$	4.7	$	0.9	Discounted cash flow	Forward commodity price	$0.86-$0.92 /gallon
Commodity derivatives – Natural gasoline		2.7		--	Discounted cash flow	Forward commodity price	$1.83-$1.83 /gallon
Commodity derivatives – Crude oil		0.3		2.0	Discounted cash flow	Forward commodity price	$84.96-$88.71 /barrel
Commodity derivatives – Natural gas		0.2		0.1	Discounted cash flow	Forward commodity price	$3.90-$4.13 /million Btu
Total	$	7.9	$	3.0

We believe certain forward commodity prices are the most significant unobservable inputs in determining our recurring Level 3 fair value measurements at June 30, 2012. In general, changes in the price of the underlying commodity increases or decreases the fair value of a commodity derivative depending on whether the derivative was purchased or sold. We generally expect changes in the fair value of our derivative instruments to be offset by corresponding changes in the fair value of our hedged exposures.

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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Nonrecurring Fair Value Measurements

The following table presents information regarding certain long-lived asset amounts measured at fair value on a nonrecurring basis during the six months ended June 30, 2012. The estimated fair values are based on the present value of expected future cash flows (Level 3).

	Fair Value Measurements Using								Total
									Non-Cash Asset
	Quoted Prices								Impairment
	in Active		Significant		Significant		Carrying		Charges for the
	Markets for		Observable		Unobservable		Value at		Six Months
	Identical Assets		Inputs		Inputs		June 30,		Ended
	(Level 1)		(Level 2)		(Level 3)		2012		June 30, 2012
NGL Pipelines & Services
Property, plant and equipment, net	$	--	$	--	$	--	$	--	$	8.0
Onshore Crude Oil Pipelines & Services
Property, plant and equipment, net		--		--		--		--		6.2
Petrochemical & Refined Products Services
Long-lived fixed assets held for sale		--		--		0.5		0.5		0.3
Total	$	--	$	--	$	0.5	$	0.5	$	14.5

During the six months ended June 30, 2012, property, plant and equipment with no future value and a carrying amount of $14.2 million was written-off, resulting in non-cash asset impairment charges for the period. In addition, long-lived assets held for sale with a carrying value of $0.8 million were written down to their fair value of $0.5 million, resulting in non-cash asset impairment charges of $0.3 million, which were included in earnings for the period. Long-lived assets held for sale are a component of “Other assets” as presented on our Unaudited Condensed Consolidated Balance Sheets. We did not record any non-cash asset impairment charges during the six months ended June 30, 2011.

Forecast data and other assumptions supporting the fair value of long-lived assets being tested for impairment are based on the nonfinancial assets’ highest and best use, which includes estimated probabilities where multiple cash flow outcomes are possible. Such probability weights are generally obtained from business management personnel having oversight responsibilities for the assets in question. Key commercial assumptions (e.g., anticipated operating margins, throughput or processing volume growth rates and timing of cash flows) that represent Level 3 unobservable inputs and test results are reviewed and certified by members of senior management.

Other Fair Value Information

The carrying amounts of cash and cash equivalents (including restricted cash balances), accounts receivable and accounts payable approximate their fair values based on their short-term nature. The estimated total fair value of our fixed-rate debt obligations was approximately $16.27 billion and $15.76 billion at June 30, 2012 and December 31, 2011, respectively. The aggregate carrying value of these debt obligations was $14.58 billion and $14.33 billion at June 30, 2012 and December 31, 2011, respectively. These values are based on quoted market prices for such debt or debt of similar terms and maturities (Level 2), our credit standing and the credit standing of our counterparties. Changes in market rates of interest affect the fair value of our fixed-rate debt. The carrying values of our variable-rate long-term debt obligations approximate their fair values since the associated interest rates are market-based. We do not have any long-term investments in debt or equity securities recorded at fair value.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 5. Inventories

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

Available-for-Sale Inventory by Product Type	June 30, 2012		December 31, 2011
NGLs	$	553.4	$	563.6
Petrochemicals and refined products		246.1		443.4
Crude oil		46.5		39.2
Natural gas		46.9		65.5
Total	$	892.9	$	1,111.7

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

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

The following table presents our total cost of sales amounts and lower of cost or market adjustments for the periods indicated:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Cost of sales (1)	$	8,195.2	$	9,790.3	$	17,861.0	$	18,609.6
Lower of cost or market adjustments		8.0		0.5		13.9		1.7
(1) Cost of sales is a component of “Operating costs and expenses,” as presented on our Unaudited Condensed Statements of Consolidated Operations. Period-to-period fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 6. Property, Plant and Equipment

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

	Estimated Useful Life in Years	June 30, 2012		December 31, 2011
Plants, pipelines and facilities (1)	3-45 (6)	$	24,105.7	$	22,354.4
Underground and other storage facilities (2)	5-40 (7)		1,455.9		1,388.6
Platforms and facilities (3)	20-31		637.5		637.5
Transportation equipment (4)	3-10		158.4		151.5
Marine vessels (5)	15-30		660.3		615.9
Land			141.7		136.1
Construction in progress			2,275.7		2,145.6
Total			29,435.2		27,429.6
Less accumulated depreciation			5,674.6		5,238.0
Property, plant and equipment, net		$	23,760.6	$	22,191.6

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

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Depreciation expense (1)	$	222.0	$	189.8	$	434.0	$	376.3
Capitalized interest (2)		29.5		24.8		60.1		42.0
(1) Depreciation expense is a component of “Costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations. (2) We capitalize interest cost incurred on funds used to construct property, plant and equipment. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life as a component of depreciation expense. Capitalized interest reduces interest expense during the period it is recorded.

Asset Retirement Obligations

We record asset retirement obligations (“AROs”) related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-term asset. Property, plant and equipment at June 30, 2012 and December 31, 2011 includes $42.5 million and $37.7 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes changes in our ARO liability balance during the six months ended June 30, 2012:

ARO liability balance, December 31, 2011	$	112.0
Liabilities incurred during period		1.1
Liabilities settled during period		(5.9	)
Revisions in estimated cash flows		8.9
Accretion expense		2.7
ARO liability balance, June 30, 2012	$	118.8

The following table presents our forecast of accretion expense for the periods indicated:

Remainder of 2012				2013				2014				2015				2016
$	2.8			$	6.0			$	6.5			$	6.2			$	6.5

Note 7. Investments in Unconsolidated Affiliates

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

Ownership

Interest at

June 30,