Edgar Filing: ENTERPRISE PRODUCTS PARTNERS L P

epdform10q_093008.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2008

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, 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 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 437,850,289 common units, including 2,239,613 restricted common units, of Enterprise Products Partners L.P. outstanding at November 3, 2008. These common units trade on the New York Stock Exchange under the ticker symbol “EPD.”

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 (Loss)	4
	Unaudited Condensed Statements of Consolidated Cash Flows	5
	Unaudited Condensed Statements of Consolidated Partners’ Equity	6
	Notes to Unaudited Condensed Consolidated Financial Statements:
	1. Partnership Organization	7
	2. General Accounting Policies and Related Matters	8
	3. Accounting for Unit-Based Awards	11
	4. Financial Instruments	16
	5. Inventories	22
	6. Property, Plant and Equipment	23
	7. Investments in and Advances to Unconsolidated Affiliates	24
	8. Business Combinations	26
	9. Intangible Assets and Goodwill	27
	10. Debt Obligations	28
	11. Partners’ Equity and Distributions	30
	12. Business Segments	33
	13. Related Party Transactions	37
	14. Earnings Per Unit	42
	15. Commitments and Contingencies	44
	16. Significant Risks and Uncertainties – Weather-Related Risks	46
	17. Supplemental Cash Flow Information	47
	18. Condensed Financial Information of EPO	48
Item 2.	Management’s Discussion and Analysis of Financial Condition
	and Results of Operations.	50
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	73
Item 4.	Controls and Procedures.	79

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.	80
Item 1A.	Risk Factors.	80
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	81
Item 3.	Defaults upon Senior Securities.	81
Item 4.	Submission of Matters to a Vote of Security Holders.	81
Item 5.	Other Information.	82
Item 6.	Exhibits.	82

Signatures		87

PART I. FINANCIAL INFORMATION.

Item 1. Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	September 30,			December 31,
ASSETS	2008			2007
Current assets:
Cash and cash equivalents	$	55,403		$	39,722
Restricted cash		183,221			53,144
Accounts and notes receivable – trade, net of allowance for doubtful accounts
of $15,781 at September 30, 2008 and $21,659 at December 31, 2007		1,840,584			1,930,762
Accounts receivable – related parties		88,871			79,782
Inventories		653,783			354,282
Prepaid and other current assets		161,233			80,193
Total current assets		2,983,095			2,537,885
Property, plant and equipment, net		12,693,619			11,587,264
Investments in and advances to unconsolidated affiliates		917,193			858,339
Intangible assets, net of accumulated amortization of $408,304 at
September 30, 2008 and $341,494 at December 31, 2007		866,313			917,000
Goodwill		616,996			591,652
Deferred tax asset		2,927			3,522
Other assets, including restricted cash of $17,871 at December 31, 2007		69,067			112,345
Total assets	$	18,149,210		$	16,608,007

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable – trade	$	245,629		$	324,999
Accounts payable – related parties		75,635			24,432
Accrued product payables		2,241,336			2,227,489
Accrued expenses		75,156			47,756
Accrued interest		101,962			130,971
Other current liabilities		430,377			289,036
Total current liabilities		3,170,095			3,044,683
Long-term debt: (see Note 10)
Senior debt obligations – principal		7,184,201			5,646,500
Junior subordinated notes – principal		1,250,000			1,250,000
Other		23,994			9,645
Total long-term debt		8,458,195			6,906,145
Deferred tax liabilities		23,161			21,364
Other long-term liabilities		66,102			73,748
Minority interest		412,911			430,418
Commitments and contingencies
Partners’ equity: (see Note 11)
Limited partners
Common units (435,610,676 units outstanding at September 30, 2008
and 433,608,763 units outstanding at December 31, 2007)		5,990,461			5,976,947
Restricted common units (2,239,613 units outstanding at September 30, 2008
and 1,688,540 units outstanding at December 31, 2007)		23,869			15,948
General partner		122,639			122,297
Accumulated other comprehensive income (loss)		(118,223	)		16,457
Total partners’ equity		6,018,746			6,131,649
Total liabilities and partners’ equity	$	18,149,210		$	16,608,007

See Notes to Unaudited Condensed Consolidated Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(Dollars in thousands, except per unit amounts)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
Revenues:
Third parties	$	5,997,743		$	3,933,157		$	17,498,445		$	11,268,342
Related parties		300,159			178,839			823,607			379,314
Total revenues		6,297,902			4,111,996			18,322,052			11,647,656
Costs and expenses:
Operating costs and expenses:
Third parties		5,806,735			3,815,087			16,766,003			10,730,670
Related parties		165,207			81,324			477,067			250,892
Total operating costs and expenses		5,971,942			3,896,411			17,243,070			10,981,562
General and administrative costs:
Third parties		8,354			7,211			22,307			21,414
Related parties		13,366			11,504			44,594			45,292
Total general and administrative costs		21,720			18,715			66,901			66,706
Total costs and expenses		5,993,662			3,915,126			17,309,971			11,048,268
Equity in earnings of unconsolidated affiliates		14,876			13,960			48,037			13,928
Operating income		319,116			210,830			1,060,118			613,316
Other income (expense):
Interest expense		(102,657	)		(85,075	)		(290,412	)		(219,708	)
Interest income		2,095			2,300			4,708			6,743
Other, net		(917	)		(594	)		(1,968	)		(362	)
Total other expense, net		(101,479	)		(83,369	)		(287,672	)		(213,327	)
Income before provision for income taxes and minority interest		217,637			127,461			772,446			399,989
Provision for income taxes		(6,610	)		(2,073	)		(17,193	)		(9,001	)
Income before minority interest		211,027			125,388			755,253			390,988
Minority interest		(7,946	)		(7,782	)		(29,293	)		(19,183	)
Net income	$	203,081		$	117,606		$	725,960		$	371,805

Net income allocation: (see Note 11)
Limited partners’ interest in net income	$	167,625		$	88,408		$	620,494		$	286,984
General partner’s interest in net income	$	35,456		$	29,198		$	105,466		$	84,821

Earning per unit: (see Note 14)
Basic and diluted income per unit	$	0.38		$	0.20		$	1.42		$	0.66

See Notes to Unaudited Condensed Consolidated Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007

Net income	$	203,081		$	117,606		$	725,960		$	371,805
Other comprehensive income (loss):
Cash flow hedges: (see Note 4)
Foreign currency hedge gains (losses)		--			2,879			(1,308	)		2,879
Net commodity financial instrument losses		(215,540	)		(22,292	)		(108,294	)		(21,446	)
Net interest rate financial instrument gains (losses)		(242	)		373			(21,283	)		40,637
Less: Amortization of cash flow financing hedges		(800	)		(1,096	)		(3,983	)		(3,365	)
Total cash flow hedges		(216,582	)		(20,136	)		(134,868	)		18,705
Foreign currency translation adjustment		377			1,832			452			2,381
Change in funded status of Dixie benefit plans, net of tax		--			--			(264	)		--
Total other comprehensive income (loss)		(216,205	)		(18,304	)		(134,680	)		21,086
Comprehensive income (loss)	$	(13,124	)	$	99,302		$	591,280		$	392,891

See Notes to Unaudited Condensed Consolidated Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in thousands)

	For the Nine Months
	Ended September 30,
	2008			2007
Operating activities:
Net income	$	725,960		$	371,805
Adjustments to reconcile net income to net cash
flows provided by operating activities:
Depreciation, amortization and accretion in operating costs and expenses		408,601			374,522
Depreciation and amortization in general and administrative costs		8,137			7,129
Amortization in interest expense		(3,161	)		432
Equity in earnings of unconsolidated affiliates		(48,037	)		(13,928	)
Distributions received from unconsolidated affiliates		69,852			52,343
Operating lease expense paid by EPCO, Inc.		1,579			1,579
Minority interest		29,293			19,183
Loss (gain) from asset sales and related transactions		(1,710	)		5,445
Deferred income tax expense		5,580			5,542
Changes in fair market value of financial instruments		5,461			3,511
Effect of pension settlement recognition		(114	)		--
Net effect of changes in operating accounts (see Note 17)		(228,397	)		110,272
Net cash flows provided by operating activities		973,044			937,835
Investing activities:
Capital expenditures		(1,485,654	)		(1,684,455	)
Contributions in aid of construction costs		21,215			52,462
Proceeds from asset sales and related transactions		1,685			1,933
Increase in restricted cash		(112,207	)		(79,535	)
Cash used for business combinations		(57,090	)		(785	)
Acquisition of intangible assets		(5,126	)		--
Investments in unconsolidated affiliates		(35,307	)		(318,491	)
Advances to unconsolidated affiliates		(36,719	)		(10,624	)
Cash used in investing activities		(1,709,203	)		(2,039,495	)
Financing activities:
Borrowings under debt agreements		6,360,387			4,926,858
Repayments of debt		(4,824,000	)		(3,459,881	)
Debt issuance costs		(8,793	)		(15,281	)
Distributions paid to partners		(770,848	)		(711,739	)
Distributions paid to minority interests		(39,196	)		(20,485	)
Proceeds from initial public offering of Duncan Energy Partners in minority interest		--			290,466
Other contributions from minority interests		28			12,506
Monetization of interest rate hedging financial instruments (see Note 4)		(22,144	)		48,895
Repurchase of option awards		--			(1,568	)
Acquisition of treasury units		(795	)		--
Net proceeds from issuance of common units		57,181			52,804
Cash provided by financing activities		751,820			1,122,575
Effect of exchange rate changes on cash flows		20			347
Net change in cash and cash equivalents		15,661			20,915
Cash and cash equivalents, January 1		39,722			22,619
Cash and cash equivalents, September 30	$	55,403		$	43,881

See Notes to Unaudited Condensed Consolidated Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY

(See Note 11 for Unit History, Detail of Changes in Limited Partners’ Equity and Accumulated Other Comprehensive Income (Loss))

(Dollars in thousands)

							Accumulated
							Other
	Limited			General			Comprehensive
	Partners			Partner			Income (Loss)			Total
Balance, December 31, 2007	$	5,992,895		$	122,297		$	16,457		$	6,131,649
Net income		620,494			105,466			--			725,960
Operating leases paid by EPCO, Inc.		1,548			31			--			1,579
Cash distributions to partners		(663,946	)		(106,352	)		--			(770,298	)
Unit option reimbursements to EPCO, Inc.		(550	)		--			--			(550	)
Non-cash distributions		(5,006	)		(100	)		--			(5,106	)
Acquisition of treasury units		(779	)		(16	)		--			(795	)
Net proceeds from issuance of common units		55,363			1,130			--			56,493
Proceeds from exercise of unit options		680			8			--			688
Amortization of unit-based awards		13,631			175			--			13,806
Change in funded status of Dixie benefit plans, net of tax		--			--			(264	)		(264	)
Foreign currency translation adjustment		--			--			452			452
Cash flow hedges		--			--			(134,868	)		(134,868	)
Balance, September 30, 2008	$	6,014,330		$	122,639		$	(118,223	)	$	6,018,746

See Notes to Unaudited Condensed Consolidated Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Except 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 thousands of dollars.

Note 1. Partnership Organization

Partnership Organization

Enterprise Products Partners L.P. is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.

We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO, Inc. (“EPCO”). We conduct substantially all of our business through our wholly owned subsidiary, Enterprise Products Operating LLC (“EPO”). We are owned 98% by our limited partners and 2% by Enterprise Products GP, LLC (our general partner, referred to as “EPGP”). EPGP is owned 100% by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded affiliate, the units of which are listed on the NYSE under the ticker symbol “EPE.” The general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”), a wholly owned subsidiary of Dan Duncan LLC, the membership interests of which are owned by Dan L. Duncan. We, EPGP, Enterprise GP Holdings, EPE Holdings and Dan Duncan LLC are affiliates and under common control of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.

References to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the common units of which are listed on the NYSE under the ticker symbol “TPP.” References to “TEPPCO GP” refer to Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly owned by Enterprise GP Holdings.

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to “LE GP” mean LE GP, LLC, which is the general partner of Energy Transfer Equity. On May 7, 2007, Enterprise GP Holdings acquired non-controlling interests in both LE GP and Energy Transfer Equity. Enterprise GP Holdings accounts for its investments in LE GP and Energy Transfer Equity using the equity method of accounting.

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

On February 5, 2007, a consolidated subsidiary of ours, Duncan Energy Partners L.P. (“Duncan Energy Partners”), completed an initial public offering of its common units (see Note 13). Duncan Energy Partners owns equity interests in certain of our midstream energy businesses. References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and is wholly owned by EPO.

For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners with those of our own and reflect its operations in our business segments. We control Duncan Energy Partners through our ownership of its general partner. Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners. Public ownership of Duncan Energy Partners’ net assets and earnings are presented as a component of minority interest in our condensed consolidated financial statements. The borrowings of Duncan Energy Partners are presented as

part of our consolidated debt; however, neither Enterprise Products Partners L.P. nor EPO have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

Basis of Presentation

Our results of operations for the three and nine months ended September 30, 2008 are not necessarily indicative of results expected for the full year.

Essentially all of our assets, liabilities, revenues and expenses are recorded at EPO’s level in our consolidated financial statements. Enterprise Products Partners L.P. acts as guarantor of certain of EPO’s debt obligations. See Note 18 for condensed consolidated financial information of EPO.

In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These Unaudited Condensed Consolidated Financial Statements and notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2007 (Commission File No. 1-14323).

Note 2. General Accounting Policies and Related Matters

Consolidation Policy

Our financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling financial or equity interest, after the elimination of intercompany accounts and transactions. We evaluate our financial interests in companies to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own.

If an investee is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50% and we exercise significant influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. In consolidation we eliminate our proportionate share of profits and losses from transactions with our equity method unconsolidated affiliates to the extent such amounts are material and remain on our balance sheet (or those of our equity method investees) in inventory or similar accounts.

If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.

Dixie Employee Benefit Plans

Dixie Pipeline Company (“Dixie”), a consolidated subsidiary of EPO, directly employs the personnel that operate its pipeline system. Certain of these employees are eligible to participate in Dixie’s defined contribution plan and pension and postretirement benefit plans.

Defined Contribution Plan. Dixie contributed $0.1 million to its company-sponsored defined contribution plan during each of the three month periods ended September 30, 2008 and 2007. During each of the nine month periods ended September 30, 2008 and 2007, Dixie contributed $0.2 million to its company-sponsored defined contribution plan.

Pension and Postretirement Benefit Plans. Dixie’s net pension benefit costs were $0.1 million for each of the three month periods ended September 30, 2008 and 2007. For each of the nine month periods ended September 30, 2008 and 2007, Dixie’s net pension benefit costs were $0.4 million. Dixie’s net postretirement benefit costs were $0.1 million for each of the three month periods ended September 30, 2008 and 2007. For each of the nine month periods ended September 30, 2008 and 2007, Dixie’s net postretirement benefit costs were $0.3 million. During the remainder of 2008, Dixie expects to contribute approximately $0.5 million to its pension plan and approximately $0.1 million to its postretirement benefit plan.

Environmental Costs

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At September 30, 2008, none of our estimated environmental remediation liabilities are discounted to present value since the ultimate amount and timing of cash payments for such liabilities are not readily determinable. Expenditures to mitigate or prevent future environmental contamination are capitalized.

At September 30, 2008 and December 31, 2007, our accrued liabilities for environmental remediation projects totaled $21.2 million and $26.5 million, respectively. These amounts were derived from a range of reasonable estimates based upon studies and site surveys. Unanticipated changes in circumstances and/or legal requirements could result in expenses being incurred in future periods in addition to an increase in actual cash required to remediate contamination for which we are responsible.

Estimates

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

We revised the remaining useful lives of certain assets, most notably the assets that constitute our Texas Intrastate System, effective January 1, 2008. This revision adjusted the remaining useful life of such assets to incorporate recent data showing that proved natural gas reserves supporting throughput and processing volumes for these assets have changed since our original determination made in September 2004. These revisions will prospectively reduce our depreciation expense on assets having carrying values totaling $2.72 billion at January 1, 2008. For additional information regarding this change in estimate, see Note 6.

Minority Interest

As presented in our Unaudited Condensed Consolidated Balance Sheets, minority interest represents third-party and affiliate ownership interests in the net assets of our consolidated subsidiaries. For financial reporting purposes, the assets and liabilities of our controlled subsidiaries, including Duncan Energy Partners, are consolidated with those of our own, with any third-party or affiliate ownership interests in such amounts presented as minority interest.

At September 30, 2008 and December 31, 2007, minority interest includes $281.9 million and $288.6 million, respectively, attributable to third party owners of Duncan Energy Partners. Minority interest expense for the three months ended September 30, 2008 and 2007 includes $2.7 million and $3.2

million, respectively, attributable to third party owners of Duncan Energy Partners. For the nine months ended September 30, 2008 and 2007 minority interest expense attributable to third party owners of Duncan Energy Partners was $11.9 million and $9.4 million, respectively. The remaining minority interest expense amounts for 2008 and 2007 are attributable to our other consolidated affiliates.

Contributions from minority interests for the nine months ended September 30, 2007 includes approximately $291.0 million received from third parties in connection with the initial public offering of Duncan Energy Partners in February 2007.

Recent Accounting Developments

The following information summarizes recently issued accounting guidance since those reported in our Annual Report on Form 10-K for the year ended December 31, 2007 that will or may affect our future financial statements.

Statement of Financial Accounting Standards (“SFAS”) No. 161, Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133. Issued in March 2008, SFAS 161 changes the disclosure requirements for financial instruments and hedging activities with the intent to provide users of financial statements with an enhanced understanding of (i) how and why an entity uses financial instruments, (ii) how financial instruments and related hedged items are accounted for under SFAS 133, Accounting for Derivative Instruments and Hedging Activities, and its related interpretations and (iii) how financial instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS 161 requires qualitative disclosures about objectives and strategies for using financial instruments, quantitative disclosures about fair value amounts of and gains and losses on financial instruments and disclosures about credit-risk-related contingent features in financial instrument agreements. This statement has the same scope as SFAS 133, and accordingly applies to all entities. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. This statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. SFAS 161 only affects disclosure requirements; therefore, our adoption of this statement effective January 1, 2009 will not impact our financial position, results of operations or cash flows.

Emerging Issues Task Force (“EITF”) 07-4, Application of the Two Class Method Under FASB Statement No. 128, Earnings Per Share, to Master Limited Partnerships (“MLP”). EITF 07-4 was issued during the first quarter of 2008 and prescribes the manner in which a MLP should allocate and present earnings per unit using the two-class method set forth in SFAS 128, Earnings Per Share. Under the two-class method, current period earnings are allocated to the general partner (including earnings attributable to any embedded incentive distribution rights) and limited partners according to the distribution formula for available cash set forth in the MLP’s partnership agreement. EITF 07-4 is effective for us on January 1, 2009. We do not believe that EITF 07-4 will have a material impact on our earnings per unit computations and disclosures.

FASB Staff Position (“FSP”) No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. FSP EITF 03-6-1 was issued in June 2008. FSP EITF 03-6-1 clarifies that unvested share-based payment awards constitute participating securities, if such awards include nonforfeitable rights to dividends or dividend equivalents. Consequently, awards that are deemed to be participating securities must be allocated earnings in the computation of earnings per share under the two-class method. FSP EITF 03-6-1 is effective for us on January 1, 2009. We do not believe that FSP EITF 03-6-1 will have a material impact on our earnings per unit computations and disclosures.

FSP No. FAS 157-2, Effective Date of FASB Statement No. 157. FSP 157-2 defers the effective date of SFAS 157, Fair Value Measurements, to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years, for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). As allowed under FSP 157-2, we have not applied the provisions of SFAS 157 to our

nonfinancial assets and liabilities measured at fair value, which include certain assets and liabilities acquired in business combinations. On January 1, 2008, we adopted the provisions of SFAS 157 that apply to financial assets and liabilities. See Note 4 for these fair value disclosures. We do not expect any immediate impact from adoption of the remaining portions of SFAS 157 on January 1, 2009.

In light of current market conditions, the FASB has issued additional clarifying guidance regarding the implementation of SFAS 157, particularly with respect to financial assets that do not trade in active markets such as investments in joint ventures. This clarifying guidance did not result in a change in our accounting, reporting or impairment testing for such investments. We continue to monitor developments at the FASB and SEC for new matters and guidance that may affect our valuation processes.

FSP No. FAS 142-3, Determination of the Useful Life of Intangible Assets. In April 2008, the FASB issued FSP 142-3, which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful lives of recognized intangible assets under SFAS 142, Goodwill and Other Intangible Assets. This change is intended to improve consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of such assets under SFAS 141(R) and other accounting guidance. The requirement for determining useful lives must be applied prospectively to intangible assets acquired after January 1, 2009 and the disclosure requirements must be applied prospectively to all intangible assets recognized as of, and subsequent to, January 1, 2009. We will adopt the provisions of FSP 142-3 on January 1, 2009.

Restricted Cash

Restricted cash represents amounts held in connection with our commodity financial instruments portfolio and New York Mercantile Exchange (“NYMEX”) physical natural gas purchases. Additional cash may be restricted to maintain our positions as commodity prices fluctuate or deposit requirements change. At December 31, 2007, restricted cash also included amounts held by a third party trustee charged with disbursing proceeds from our Petal GO Zone bond offering. As of June 30, 2008, all proceeds from the Petal GO Zone bonds had been released by the trustee to fund construction costs associated with the expansion of our Petal, Mississippi storage facility. The following table presents the components of our restricted cash balances at the periods indicated:

	September 30,		December 31,
	2008		2007
Amounts held in brokerage accounts related to
commodity hedging activities and physical natural gas purchases	$	183,221	$	53,144
Proceeds from Petal GO Zone bonds reserved for construction costs		--		17,871
Total restricted cash	$	183,221	$	71,015

Note 3. Accounting for Unit-Based Awards

We account for unit-based awards in accordance with SFAS 123(R), Share-Based Payment. SFAS 123(R) requires us to recognize compensation expense related to unit-based awards based on the fair value of the award at grant date. The fair value of restricted unit awards is based on the market price of the underlying common units on the date of grant. The fair value of other unit-based awards is estimated using the Black-Scholes option pricing model. The fair value of an equity-classified award (such as a restricted unit award) is amortized to earnings on a straight-line basis over the requisite service or vesting period. Compensation expense for liability-classified awards (such as unit appreciation rights (“UARs”)) is recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. Liability-type awards are settled in cash upon vesting.

The following table summarizes our unit-based compensation expense amounts by plan during each of the periods indicated:

	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2008			2007		2008		2007
EPCO 1998 Long-Term Incentive Plan (“1998 Plan”)
Unit options	$	116		$	139	$	329	$	4,248
Restricted units		2,569			1,981		6,121		5,639
Total 1998 Plan (1)		2,685			2,120		6,450		9,887
Enterprise Products 2008 Long-Term Incentive Plan
(“2008 LTIP”)
Unit options		36			--		50		--
Total 2008 LTIP		36			--		50		--
Employee Partnerships		1,540			1,364		4,099		2,542
DEP GP Unit Appreciation Rights		(1	)		23		5		58
Total consolidated expense	$	4,260		$	3,507	$	10,604	$	12,487

(1) Amounts presented for the nine months ended September 30, 2007 include $4.6 million associated with the resignation of our former Chief Executive Officer.

1998 Plan

The 1998 Plan provides for the issuance of up to 7,000,000 of our common units. After giving effect to outstanding option awards at September 30, 2008 and the issuance and forfeiture of restricted unit awards through September 30, 2008, a total of 771,546 additional common units could be issued under the 1998 Plan.

Unit option awards. Under the 1998 Plan, non-qualified incentive options to purchase a fixed number of our common units may be granted to key employees of EPCO who perform management, administrative or operational functions for us. The following table presents unit option activity under the 1998 Plan for the periods indicated:

						Weighted-
				Weighted-		Average
				Average		Remaining		Aggregate
	Number of			Strike Price		Contractual		Intrinsic
	Units			(dollars/unit)		Term (in years)		Value (1)
Outstanding at December 31, 2007 (2)		2,315,000		$	26.18
Exercised		(61,500	)	$	20.38
Forfeited or terminated		(85,000	)	$	26.72
Outstanding at September 30, 2008		2,168,500		$	26.32		5.44	$	2,356
Options exercisable at
September 30, 2008		548,500		$	21.47		4.33	$	2,356

(1) Aggregate intrinsic value reflects fully vested unit options at September 30, 2008. (2) During 2008, we amended the terms of certain of our outstanding unit options. In general, the expiration dates of these awards were modified from May and August 2017 to December 2012.

The total intrinsic value of unit options exercised during the three and nine months ended September 30, 2008 was $0.1 million and $0.6 million, respectively. At September 30, 2008, there was an estimated $1.9 million of total unrecognized compensation cost related to nonvested unit options granted under the 1998 Plan. We expect to recognize our share of this cost over a weighted-average period of 2.4 years in accordance with the EPCO administrative services agreement (the “ASA”).

During the nine months ended September 30, 2008 and 2007, we received cash of $0.7 million and $7.7 million, respectively, from the exercise of unit options. Conversely, our option-related reimbursements to EPCO were $0.6 million and $2.9 million, respectively.

Restricted unit awards. Under the 1998 Plan, we may also issue restricted common units to key employees of EPCO and directors of our general partner. The following table summarizes information regarding our restricted common units for the periods indicated:

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
Restricted units at December 31, 2007		1,688,540
Granted (2)		750,900		$	25.30
Forfeited		(84,677	)	$	26.83
Vested		(115,150	)	$	22.83
Restricted units at September 30, 2008		2,239,613

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per unit for forfeited and vested awards is determined before an allowance for forfeitures. (2) Aggregate grant date fair value of restricted common unit awards issued during 2008 was $19.0 million based on a grant date market price of our common units ranging from $28.21 to $32.31 per unit and an estimated forfeiture rate of 17.0%.

The total fair value of our restricted unit awards that vested during the three and nine months ended September 30, 2008 was $1.2 million and $2.6 million, respectively. As of September 30, 2008, there was $34.6 million of total unrecognized compensation cost related to restricted common units. We will recognize our share of such costs in accordance with the EPCO ASA. At September 30, 2008, these costs are expected to be recognized over a weighted-average period of 2.4 years.

Phantom unit awards. The 1998 Plan also provides for the issuance of phantom unit awards. These liability awards are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at redemption dates in each award. No phantom unit awards have been issued to date under the 1998 Plan.

2008 LTIP

On January 29, 2008, our unitholders approved the 2008 LTIP, which provides for awards of our common units and other rights to our non-employee directors and to consultants and employees of EPCO and its affiliates providing services to us. Awards under the 2008 LTIP may be granted in the form of unit options, restricted units, phantom units, UARs and distribution equivalent rights. The 2008 LTIP is administered by EPGP’s Audit, Conflicts and Governance (“ACG”) Committee. The 2008 LTIP provides for the issuance of up to 10,000,000 of our common units. After giving effect to option awards outstanding at September 30, 2008, a total of 9,205,000 additional common units could be issued under the 2008 LTIP.

The 2008 LTIP may be amended or terminated at any time by the Board of Directors of EPCO or EPGP’s ACG Committee; however, the rules of the NYSE require that any material amendment, such as a significant increase in the number of common units available under the plan or a change in the types of awards available under the plan, would require the approval of our unitholders. The ACG Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in, awards under the plan in specified circumstances. The 2008 LTIP is effective until the earlier of January 29, 2018 or the time which all available units under the incentive plan have been delivered to participants or the time of termination of the plan by EPCO or EPGP’s ACG Committee.

Unit option awards. The exercise price of unit options awarded to participants is determined by the ACG Committee (at its discretion) at the date of grant and may be no less than the fair market value of our common units at the date of grant. The following table presents unit option activity under the 2008 LTIP for the periods indicated:

Weighted-

Average

Remaining

Number of

Strike Price

Contractual

Units

(dollars/unit)

Term (in years)

Outstanding at January 29, 2008

Granted (1)

795,000

30.93

Outstanding at September 30, 2008

795,000

30.93

5.25

(1) Aggregate grant date fair value of these unit options issued during 2008 was $1.6 million based on the following assumptions: (i) a grant date market price of our common units of $30.93 per unit; (ii) expected life of options of 4.7 years; (iii) risk-free interest rate of 3.3%; (iv) expected distribution yield on our common units of 7.0%; (v) expected unit price volatility on our common units of 19.8%; and (vi) an estimated forfeiture rate of 17.0%.

At September 30, 2008, there was an estimated $1.4 million of total unrecognized compensation cost related to nonvested unit options granted under the 2008 LTIP. We expect to recognize our share of this cost over a remaining period of 3.6 years in accordance with the EPCO ASA.

Employee Partnerships

EPCO formed the Employee Partnerships to serve as an incentive arrangement for key employees of EPCO by providing them a “profits interest” in the Employee Partnerships. Currently, there are four Employee Partnerships: EPE Unit I, EPE Unit II, EPE Unit III and Enterprise Unit. EPE Unit I was formed in August 2005 in connection with Enterprise GP Holdings’ initial public offering, EPE Unit II was formed in December 2006, EPE Unit III was formed in May 2007 and Enterprise Unit was formed in February 2008. For a detailed description of EPE Unit I, EPE Unit II and EPE Unit III, see our Annual Report on Form 10-K for the year ended December 31, 2007.

In July 2008, each of EPE Unit I, EPE Unit II and EPE Unit III entered into a second amendment to its respective agreement of limited partnership (“Second Amendment”). The Second Amendments for EPE Unit I and EPE Unit II provide for the reduction of the rate at which the Class A Limited Partner, Duncan Family Interests, Inc., earns a preferred return on its investment in EPE Unit I and EPE Unit II (“Class A Preference Return Rate”). The Class A Preference Return Rate in each of these two limited partnership agreements was reduced from 6.25% to a floating preference rate to be determined by EPCO (in its sole discretion) that will be between 4.50% and 5.725% per annum. The Second Amendment for EPE Unit I and EPE Unit II also provides that the liquidation date of these partnerships be extended to November 2012 and February 2014, respectively. The Second Amendment for EPE Unit III extends the liquidation date of EPE Unit III to May 2014. Collectively, the Second Amendment to these partnership agreements resulted in an aggregate $18.2 million increase in non-cash compensation costs attributable to the profits interest awards in EPE Unit I, EPE Unit II and EPE Unit III.

As of September 30, 2008, there was $43.4 million of total unrecognized compensation cost related to the four Employee Partnerships. We will recognize our share of these costs in accordance with the EPCO ASA over a weighted-average period of 5.2 years.

Enterprise Unit. On February 20, 2008, EPCO formed Enterprise Unit to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in Enterprise Unit. On that date, EPCO Holdings, Inc. (“EPCO Holdings”) agreed to contribute $18.0 million in the aggregate (the “Initial Contribution”) to Enterprise Unit and was admitted as the Class A limited partner. Certain key employees of EPCO, including our Chief Executive Officer and Chief Financial Officer, were issued Class B limited partner interests and admitted as Class B limited partners of Enterprise Unit without any capital contributions. EPCO Holdings made capital contributions to Enterprise Unit in addition to its Initial

Contribution and may make additional contributions, although it has no legal obligation to do so. As of September 30, 2008, EPCO Holdings has contributed a total of $51.5 million to Enterprise Unit.

As with the awards granted in connection with the other Employee Partnerships, these awards are designed to provide additional long-term incentive compensation for certain employees. The profits interest awards (or Class B limited partner interests) in Enterprise Unit entitle the holder to participate in the appreciation in value of Enterprise GP Holdings’ units and our common units and are subject to early vesting or forfeiture upon the occurrence of certain events.

An allocated portion of the fair value of these equity awards will be charged to us under the EPCO ASA as a non-cash expense. We will not reimburse EPCO, Enterprise Unit or any of their affiliates or partners, through the ASA or otherwise, in cash for any expenses related to Enterprise Unit, including the Initial Contribution by EPCO Holdings.

The Class B limited partner interests in Enterprise Unit that are owned by EPCO employees are subject to forfeiture if the participating employee’s employment with EPCO and its affiliates is terminated prior to February 20, 2014, with customary exceptions for death, disability and certain retirements that will result in early vesting. The risk of forfeiture associated with the Class B limited partner interests in Enterprise Unit will also lapse (i.e. the interests will become vested) upon certain change of control events.

Unless otherwise agreed to by EPCO, EPCO Holdings and a majority in interest of the Class B limited partners of Enterprise Unit, Enterprise Unit will terminate at the earlier of February 20, 2014 (six years from the date of the agreement) or a change in control of us or Enterprise GP Holdings. Enterprise Unit has the following material terms regarding its quarterly cash distribution to partners:

Distributions of cash flow – Each quarter, 100% of the cash distributions received by Enterprise Unit from Enterprise GP Holdings and us will be distributed to the Class A limited partner until EPCO Holdings has received an amount equal to the Class A preferred return (as defined below), and any remaining distributions received by Enterprise Unit will be distributed to the Class B limited partners. The Class A preferred return equals the Class A capital base (as defined below) multiplied by 5.0% per annum. The Class A limited partner’s capital base equals the amount of any contributions of cash or cash equivalents made by the Class A limited partner to Enterprise Unit, plus any unpaid Class A preferred return from prior periods, less any distributions made by Enterprise Unit of proceeds from the sale of units owned by Enterprise Unit (as described below).

Liquidating Distributions – Upon liquidation of Enterprise Unit, units having a fair market value equal to the Class A limited partner capital base will be distributed to EPCO Holdings, plus any accrued and unpaid Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partners.

§	Sale Proceeds – If Enterprise Unit sells any units that it beneficially owns, the sale proceeds will be distributed to the Class A limited partner and the Class B limited partners in the same manner as liquidating distributions described above.

DEP GP UARs

The non-employee directors of DEP GP, the general partner of Duncan Energy Partners, have been granted UARs in the form of letter agreements. These liability awards are not part of any established long-term incentive plan of EPCO, Enterprise GP Holdings, Duncan Energy Partners or us. These UARs entitle each non-employee director to receive a cash payment on the vesting date equal to the excess, if any, of the fair market value of Enterprise GP Holdings’ units (determined as of a future vesting date) over the grant date fair value. These UARs are accounted for similarly to liability awards under SFAS 123(R) since they will be settled with cash. At September 30, 2008 and December 31, 2007, we had a total of 90,000 outstanding UARs granted to non-employee directors of DEP GP that cliff vest in 2012. If a director resigns prior to vesting, his UAR awards are forfeited.

Note 4. Financial Instruments

We are exposed to financial market risks, including changes in commodity prices, interest rates and foreign exchange rates. We may use financial instruments (e.g., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the types of risks we attempt to hedge are those related to (i) the variability of future earnings, (ii) fair values of certain debt instruments and (iii) cash flows resulting from changes in applicable interest rates, commodity prices or exchange rates.

We recognize financial instruments as assets and liabilities on our Unaudited Condensed Consolidated Balance Sheets based on fair value. Fair value is generally defined as the amount at which a financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.

Changes in fair value of financial instrument contracts are recognized in earnings in the current period unless specific hedge accounting criteria are met. If the financial instrument meets the criteria of a fair value hedge, gains and losses incurred on the instrument will be recorded in earnings to offset corresponding losses and gains on the hedged item. If the financial instrument meets the criteria of a cash flow hedge, gains and losses incurred on the instrument are recorded in accumulated other comprehensive income. Gains and losses on cash flow hedges are reclassified from accumulated other comprehensive income to earnings when the forecasted transaction occurs or, as appropriate, over the economic life of the hedged item. A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.

To qualify for hedge accounting, the item to be hedged must expose us to risk and the related hedging instrument must reduce the exposure and meet the formal hedging requirements of SFAS 133, Accounting for Derivative Instruments and Hedging Activities (as amended and interpreted). We formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at its inception and thereafter on a quarterly basis. Any hedge ineffectiveness is immediately recognized in earnings.

We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on the specific hedging criteria. When this occurs, we may enter into a new financial instrument to reestablish the hedge to which the closed instrument relates.

Interest Rate Risk Hedging Program

Our interest rate exposure results from variable and fixed interest rate borrowings under various debt agreements. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt.

Fair Value Hedges – Interest Rate Swaps. As summarized in the following table, we had five interest rate swap agreements outstanding at September 30, 2008 that were accounted for as fair value hedges.

	Number	Period Covered	Termination	Fixed to	Notional
Hedged Fixed Rate Debt	of Swaps	by Swap	Date of Swap	Variable Rate (1)	Value
Senior Notes C, 6.375% fixed rate, due Feb. 2013	1	Jan. 2004 to Feb. 2013	Feb. 2013	6.375% to 5.02%	$100.0 million
Senior Notes G, 5.60% fixed rate, due Oct. 2014	4	4th Qtr. 2004 to Oct. 2014	Oct. 2014	5.60% to 3.63%	$400.0 million
(1) The variable rate indicated is the all-in variable rate for the current settlement period.

The aggregate fair value of the five interest rate swaps at September 30, 2008 was an asset of $13.2 million, with an offsetting increase in the fair value of the underlying debt. There were eleven interest rate swaps outstanding at December 31, 2007 having an aggregate fair value of $14.8 million (an asset). Interest expense for the three months ended September 30, 2008 and 2007 includes a $1.8 million benefit and a $2.3 million loss, respectively, from interest rate swap agreements. For the nine months ended September 30, 2008 and 2007, interest expense reflects a benefit of $3.2 million and a loss of $6.9 million, respectively, from interest rate swap agreements.

The following table summarizes the termination of our interest rate swaps during 2008 (dollars in millions):

	Notional			Cash
	Value			Gains (1)
Interest rate swap portfolio, December 31, 2007	$	1,050.0		$	--
First quarter of 2008 terminations		(200.0	)		6.3
Second quarter of 2008 terminations		(250.0	)		12.0
Third quarter of 2008 terminations (2)		(100.0	)		--
Interest rate swap portfolio, September 30, 2008	$	500.0		$	18.3

(1) Cash gains resulting from the termination, or monetization, of interest rate swaps will be amortized to earnings as a reduction to interest expense over the remaining life of the underlying debt. (2) In early October 2008, one counterparty filed for bankruptcy. At September 30, 2008, the fair value of this interest rate swap was $3.4 million and this amount has been fully reserved. Hedge accounting for this swap has been discontinued.

Cash Flow Hedges – Interest Rate Swaps. Duncan Energy Partners had three floating-to-fixed interest rate swap agreements outstanding at September 30, 2008 that were accounted for as cash flow hedges.

	Number	Period Covered	Termination	Variable to	Notional
Hedged Variable Rate Debt	of Swaps	by Swap	Date of Swap	Fixed Rate (1)	Value
Duncan Energy Partners’ Revolver, due Feb. 2011	3	Sep. 2007 to Sep. 2010	Sep. 2010	3.77% to 4.62%	$175.0 million
(1) Amounts receivable from or payable to the swap counterparties are settled every three months (the “settlement period”).

We recognized losses of $0.8 million and $1.6 million from these swap agreements during the three and nine months ended September 30, 2008, respectively. The aggregate fair values of these interest rate swaps at September 30, 2008 and December 31, 2007 were liabilities of $4.3 million and $3.8 million, respectively. As cash flow hedges, any increase or decrease in fair value of the financial instrument (to the extent effective) would be recorded as other comprehensive income and amortized into earnings based on the settlement period being hedged. Over the next twelve months, we expect to reclassify $1.4 million of losses to earnings as an increase in interest expense.

Cash Flow Hedges – Treasury Locks. We occasionally use treasury lock financial instruments to hedge the underlying U.S. treasury rates related to our anticipated issuances of debt. Cash gains or losses on the termination, or monetization, of such instruments are amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt. Each of our treasury lock transactions were designated as a cash flow hedge. The following table summarizes changes in our treasury lock portfolio since December 31, 2007 (dollars in millions).

	Notional			Cash
	Value			Losses (1)
Treasury lock portfolio, December 31, 2007	$	600.0		$	--
First quarter of 2008 terminations		(350.0	)		27.7
Second quarter of 2008 terminations		(250.0	)		12.7
Treasury lock portfolio, September 30, 2008	$	--		$	40.4

(1) Cash losses are included in net interest rate financial instrument losses in the Unaudited Condensed Statements of Consolidated Comprehensive Income.

We expect to reclassify $1.8 million of cumulative net gains from the monetization of treasury lock financial instruments to earnings (as a decrease in interest expense) over the next twelve months. This includes financial instruments that were settled in years prior to 2008.

Commodity Risk Hedging Program

The prices of natural gas, NGLs and certain petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risks associated with such products, we may enter into commodity financial instruments.

The primary purpose of our commodity risk management activities is to reduce our exposure to price risks associated with (i) natural gas purchases, (ii) the value of NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas, NGLs or certain petrochemical products. From time to time, we inject natural gas into storage and may utilize hedging instruments to lock in the value of our inventory positions. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.

We have segregated our commodity financial instruments portfolio between those financial instruments utilized in connection with our natural gas marketing activities and those used in connection with our NGL and petrochemical operations.

Natural gas marketing activities. At September 30, 2008 and December 31, 2007, the aggregate fair values of those financial instruments utilized in connection with our natural gas marketing activities was an asset of $0.8 million and a liability of $0.3 million, respectively. Our natural gas marketing business and its related use of financial instruments has increased since December 31, 2007. For additional information regarding our natural gas marketing activities, see Note 12. We currently utilize mark-to-market accounting for substantially all of the financial instruments utilized in connection with our natural gas marketing activities. The following table presents gains and losses recognized in earnings from this portion of the commodity financial instruments portfolio for the periods indicated (dollars in millions):

Three months ended September 30, 2008	Gains	$	13.2
Three months ended September 30, 2007	Losses	$	(0.6	)
Nine months ended September 30, 2008	Gains	$	7.8
Nine months ended September 30, 2007	Losses	$	(0.1	)

NGL and petrochemical operations. At September 30, 2008 and December 31, 2007, the aggregate fair values of financial instruments utilized in connection with our NGL and petrochemical operations were liabilities of $116.6 million and $19.0 million, respectively. The change in fair value between December 31, 2007 and September 30, 2008 is primarily due to a decrease in the price of natural gas and an increase in volumes hedged. Almost all of the financial instruments within this portion of the commodity financial instruments portfolio are accounted for as cash flow hedges, with a small number accounted for using mark-to-market accounting.

EPO has employed a program to economically hedge a portion of earnings from its natural gas processing business (a component of its NGL Pipelines & Services business segment). This program consists of (i) the forward sale of a portion of EPO’s expected equity NGL production volumes at fixed prices through 2009 and (ii) the purchase (using commodity financial instruments) of the amount of natural gas expected to be consumed as plant thermal reduction (“PTR”) in the production of such equity NGL volumes. The objective of this strategy is to hedge a level of gross margins (i.e., NGL sales revenues less actual costs for PTR and the gain or loss on the PTR hedge) associated with the forward sales contracts by fixing the cost of natural gas used for PTR, through the use of commodity financial instruments. At September 30, 2008, this hedging program had hedged future gross margins before plant operating expenses of $588.8 million for 28.8 million barrels of forecasted NGL forward sales transactions extending through 2009.

NGL forward sales contracts are not accounted for as financial instruments under SFAS 133; therefore, changes in the aggregate economic value of these sales contracts are not reflected in earnings and comprehensive income until the volumes are delivered to customers. On the other hand, the commodity financial instruments used to purchase the related quantities of PTR (i.e., “PTR hedges”) are accounted for as cash flow hedges; therefore, changes in the aggregate fair value of the PTR hedges are presented in other comprehensive income.

Prior to actual settlement, if the market price of natural gas is less than the price stipulated in a PTR hedge, we recognize an unrealized loss in other comprehensive income for the excess of the natural gas price stated in the PTR hedge over the market price. To the extent that we realize such financial losses upon settlement of the instrument, the losses are added to the actual cost we have to pay for PTR (which would then be based on the lower market price). The end result of this relationship – financial gain/loss on the PTR hedges plus the market price of actual natural gas purchases at the time of consumption – is that our total cost of natural gas used for PTR approximates the amount we originally hedged under this program The converse is true if the price of natural gas decreases. During the third quarter of 2008, the price of natural gas decreased approximately 45% from June 30, 2008. As a result, we recognized unrealized losses in other comprehensive income with respect to the PTR hedges of $258.4 million during the third quarter of 2008. For the nine months ended September 30, 2008, we recognized unrealized losses in other comprehensive income of $126.0 million with respect to the PTR hedging program. Once the forecasted NGL forward sales transactions occur, any realized gains and losses on the cash flow hedges would be reclassified into earnings at that time.

The following table presents gains and losses recognized in earnings from this portion of the commodity financial instruments portfolio for the periods indicated (dollars in millions):

Three months ended September 30, 2008 (1)	Losses	$	(7.2	)
Three months ended September 30, 2007	Losses	$	(10.1	)
Nine months ended September 30, 2008 (2)	Gains	$	1.7
Nine months ended September 30, 2007	Losses	$	(11.9	)
(1) Includes ineffectiveness of $5.6 million (an expense). (2) Includes ineffectiveness of $2.8 million (an expense).

A significant number of the financial instruments in this portfolio hedge the purchase of physical natural gas. If natural gas prices fall below the price stipulated in such financial instruments, we recognize a liability for the difference; however, if prices partially or fully recover, this liability would be reduced or eliminated, as appropriate. Our restricted cash balance at September 30, 2008 was $183.2 million in order to meet commodity exchange deposit requirements and the negative change in the fair value of our commodity positions.

Foreign Currency Hedging Program

We are exposed to foreign currency exchange rate risk primarily through our Canadian NGL marketing subsidiary. As a result, we could be adversely affected by fluctuations in the foreign currency exchange rate between the U.S. dollar and the Canadian dollar. We attempt to hedge this risk using foreign exchange purchase contracts to fix the exchange rate. Mark-to-market accounting is utilized for these contracts, which typically have a duration of one month. For the nine months ended September 30, 2008, we recorded minimal gains from these financial instruments. No such amounts were recorded in the third quarter of 2008.

Adoption of SFAS 157 - Fair Value Measurements

On January 1, 2008, we adopted the provisions of SFAS 157 that apply to financial assets and liabilities. We will adopt the provisions of SFAS 157 that apply to nonfinancial assets and liabilities on January 1, 2009. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date.

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

SFAS 157 established a three-tier hierarchy that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the SFAS 157 hierarchy are described as follows:

Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur in sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the NYSE or NYMEX). Level 1 primarily consists of financial assets and liabilities such as exchange-traded financial instruments, publicly-traded equity securities and U.S. government treasury securities.

Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors for stocks and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are (i) observable in the marketplace throughout the full term of the instrument, (ii) can be derived from observable data or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Level 2 includes non-exchange-traded instruments such as over-the-counter forward contracts, options and repurchase agreements.

§	Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.

Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally-developed data. The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort. Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value. Level 3 generally includes specialized or unique financial instruments that are tailored to meet a customer’s specific needs.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured on a recurring basis at September 30, 2008. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels. At September 30, 2008 there were no Level 1 financial assets or liabilities.

	Level 2		Level 3		Total
Financial assets:
Commodity financial instruments	$	15,320	$	18,445	$	33,765
Interest rate financial instruments		13,151		--		13,151
Total	$	28,471	$	18,445	$	46,916

Financial liabilities:
Commodity financial instruments	$	149,577	$	--	$	149,577
Interest rate financial instruments		4,301		--		4,301
Total	$	153,878	$	--	$	153,878

Fair values associated with our interest rate, commodity and foreign currency financial instrument portfolios were developed using available market information and appropriate valuation techniques in accordance with SFAS 157.

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

Balance, January 1, 2008	$	(4,660	)
Total gains (losses) included in:
Net income (1)		(2,254	)
Other comprehensive income		2,419
Purchases, issuances, settlements		1,861
Balance, March 31, 2008		(2,634	)
Total gains (losses) included in:
Net income (1)		322
Other comprehensive income		(2,428	)
Purchases, issuances, settlements		71
Balance, June 30, 2008		(4,669	)
Total gains (losses) included in:
Net income (1)		(2,190	)
Other comprehensive loss		23,114
Purchases, issuances, settlements		2,190
Balance, September 30, 2008	$	18,445

(1) Net income includes commodity financial instrument losses of $2.2 million and $4.1 million, respectively, recorded in revenue for the three and nine months ended September 30, 2008. There were no unrealized gains included in these amounts.

Note 5. Inventories

Our inventory amounts were as follows at the dates indicated:

	September 30,		December 31,
	2008		2007
Working inventory (1)	$	602,909	$	342,589
Forward-sales inventory (2)		50,874		11,693
Total inventory	$	653,783	$	354,282

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

Our inventory values reflect payments for product purchases, freight charges associated with such purchase volumes, terminal and storage fees, vessel inspection costs, demurrage charges and other related costs. We value our inventories at the lower of average cost or market.

Operating costs and expenses, as presented on our Unaudited Condensed Statements of Consolidated Operations, include cost of sales amounts related to the sale of inventories. Our cost of sales amounts were $5.47 billion and $3.53 billion for the three months ended September 30, 2008 and 2007, respectively. For the nine months ended September 30, 2008 and 2007, our cost of sales were $15.88 billion and $9.89 billion, respectively.

Due to fluctuating commodity prices in the NGL, natural gas and petrochemical industry, we recognize lower of cost or market (“LCM”) adjustments when the carrying value of our inventories exceed their net realizable value. These non-cash charges are a component of cost of sales in the period they are recognized. For the three months ended September 30, 2008 and 2007, we recognized LCM adjustments of approximately $36.4 million and $0.2 million, respectively. We recognized LCM adjustments of $41.3 million and $13.3 million for the nine months ended September 30, 2008 and 2007, respectively.

Note 6. Property, Plant and Equipment

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

	Estimated
	Useful Life	September 30,		December 31,
	in Years	2008		2007
Plants and pipelines (1)	3-35(5)	$	12,019,063	$	10,884,819
Underground and other storage facilities (2)	5-35(6)		784,808		720,795
Platforms and facilities (3)	20-31		634,809		637,812
Transportation equipment (4)	3-10		35,865		32,627
Land			50,560		48,172
Construction in progress			1,417,947		1,173,988
Total			14,943,052		13,498,213
Less accumulated depreciation			2,249,433		1,910,949
Property, plant and equipment, net		$	12,693,619	$	11,587,264

(1) Plants and pipelines include processing plants; NGL, petrochemical, oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment; and related assets. (2) Underground and other storage facilities include underground product storage caverns; storage tanks; water wells; and related assets. (3) Platforms and facilities include offshore platforms and related facilities and other associated assets. (4) Transportation equipment includes vehicles and similar assets used in our operations. (5) In general, the estimated useful lives of major components of this category are as follows: processing plants, 20-35 years; pipelines, 18-35 years (with some equipment at 5 years); terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings, 20-35 years; and laboratory and shop equipment, 5-35 years. (6) In general, the estimated useful lives of major components of this category are as follows: underground storage facilities, 20-35 years (with some components at 5 years); storage tanks, 10-35 years; and water wells, 25-35 years (with some components at 5 years).

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

	For the Three Months				For the Nine Months
	Ended September 30,				Ended September 30,
	2008		2007		2008		2007
Depreciation expense (1)	$	115,517	$	108,692	$	339,332	$	302,758
Capitalized interest (2)	$	17,284	$	18,656	$	53,019	$	59,795

(1) Depreciation expense is a component of costs and expenses as presented in our Unaudited Condensed Statements of Consolidated Operations. (2) Capitalized interest increases the carrying value of the associated asset and reduces interest expense during the period it is recorded.

We reviewed assumptions underlying the estimated remaining useful lives of certain of our assets during the first quarter of 2008. As a result of our review, effective January 1, 2008, we revised the remaining useful lives of these assets, most notably the assets that constitute our Texas Intrastate System. This revision increased the remaining useful life of such assets to incorporate recent data showing that proved natural gas reserves supporting throughput and processing volumes for these assets have changed since our original determination made in September 2004. These revisions will prospectively reduce our depreciation expense on assets having carrying values totaling $2.72 billion as of January 1, 2008. On average, we extended the life of these assets by 3.1 years. As a result of this change in estimate, depreciation expense included in operating income and net income for the three and nine months ended September 30, 2008 decreased by approximately $5.0 million and $15.0 million, respectively, which increased our earnings per unit by $0.01 and $0.03, respectively, from what it would have been absent the change.

Asset retirement obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of a tangible long-lived asset that results from its acquisition, construction, development or normal operation or a combination of these factors. The following table summarizes amounts recognized in connection with AROs since December 31, 2007:

ARO liability balance, December 31, 2007	$	40,614
Liabilities incurred		810
Liabilities settled		(7,154	)
Revisions in estimated cash flows		2,411
Accretion expense		1,660
ARO liability balance, September 30, 2008	$	38,341

Property, plant and equipment at September 30, 2008 and December 31, 2007 includes $8.8 million and $10.6 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.

Note 7. Investments in and Advances to Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for using the equity method of accounting. Our investments in and advances to unconsolidated affiliates are grouped according to the business segment to which they relate. See Note 12 for a general discussion of our business segments. The following table presents our investments in and advances to unconsolidated affiliates at the dates indicated.

	Ownership
	Percentage at
	September 30,	September 30,		December 31,
	2008	2008		2007
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C. (“VESCO”)	13.1%	$	38,542	$	40,129
K/D/S Promix, L.L.C. (“Promix”)	50.0%		47,291		51,537
Baton Rouge Fractionators LLC (“BRF”)	32.2%		25,410		25,423
Onshore Natural Gas Pipelines & Services:
Jonah Gas Gathering Company (“Jonah”)	19.4%		278,736		235,837
Evangeline (2)	49.5%		4,494		3,490
White River Hub, LLC (“White River Hub”) (1)	50.0%		19,654		--
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)	36.0%		59,364		58,423
Cameron Highway Oil Pipeline Company (“Cameron Highway”)	50.0%		260,713		256,588
Deepwater Gateway, L.L.C. (“Deepwater Gateway”)	50.0%		109,263		111,221
Neptune Pipeline Company, L.L.C. (“Neptune”)	25.7%		52,278		55,468
Nemo Gathering Company, LLC (“Nemo”)	33.9%		784		2,888
Texas Offshore Port System (“TOPS”)	33.3%		2,355		--
Petrochemical Services:
Baton Rouge Propylene Concentrator LLC (“BRPC”)	30.0%		14,255		13,282
La Porte (3)	50.0%		4,054		4,053
Total		$	917,193	$	858,339

(1) In February 2008, we acquired a 50.0% ownership interest in White River Hub. (2) Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (3) Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.

On occasion, the price we pay to acquire a non-controlling ownership interest in a company exceeds the underlying book value of the net assets we acquire. Such excess cost amounts are included within the carrying values of our investments in and advances to unconsolidated affiliates. At September 30, 2008 and December 31, 2007, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Jonah included excess cost amounts totaling $44.1 million and $43.8 million, respectively.

These amounts are attributable to the excess of the fair value of each entity’s tangible assets over their respective book carrying values at the time we acquired an interest in each entity. Amortization of such excess cost amounts was $0.5 million during each of the three months ended September 30, 2008 and 2007. For each of the nine months ended September 30, 2008 and 2007, amortization of such amounts was $1.5 million.

The following table presents our equity in earnings of unconsolidated affiliates by business segment for the periods indicated:

	For the Three Months				For the Nine Months
	Ended September 30,				Ended September 30,
	2008		2007		2008		2007
NGL Pipelines & Services	$	3,009	$	2,684	$	2,288	$	4,364
Onshore Natural Gas Pipelines & Services		5,598		2,351		16,883		4,592
Offshore Pipelines & Services		5,987		8,557		27,914		3,786
Petrochemical Services		282		368		952		1,186
Total	$	14,876	$	13,960	$	48,037	$	13,928

On a quarterly basis, we monitor the underlying business fundamentals of our investments in unconsolidated affiliates and test such investments for impairment when impairment indicators are present. As a result of our reviews for the third quarter of 2008, no impairment charges were required. We have the intent and ability to hold these investments, which are integral to our operations.

Summarized Financial Information of Unconsolidated Affiliates

The following tables present unaudited income statement data for our current unconsolidated affiliates, aggregated by business segment, for the periods indicated (on a 100% basis).

	Summarized Income Statement Information for the Three Months Ended
	September 30, 2008						September 30, 2007
			Operating		Net				Operating		Net
	Revenues		Income		Income		Revenues		Income		Income
NGL Pipelines & Services	$	75,108	$	9,742	$	6,788	$	49,579	$	15,435	$	16,118
Onshore Natural Gas Pipelines & Services		188,887		28,953		27,911		126,042		24,659		23,447
Offshore Pipelines & Services		31,926		12,812		11,976