UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A

CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported): May 7, 2007

ENTERPRISE GP HOLDINGS L.P.

(Exact Name of Registrant as Specified in Its Charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)		1-32610 (Commission File Number)		13-4297064 (I.R.S. Employer Identification No.)

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)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨     Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨     Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨     Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨     Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

Item 2.01. Completion of Acquisition or Disposition of Assets.

     On May 7, 2007, Enterprise GP Holdings L.P. completed the acquisition of 4,400,000 common units of TEPPCO Partners, L.P. (“TEPPCO”) and 100% of the membership interests in Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO. This transaction was originally reported on a Current Report on Form 8-K on May 10, 2007. This amendment is being filed to amend Item 9.01 to provide certain required financial information relating to the acquisition of partnership interests in TEPPCO and Texas Eastern Products Pipeline Company, LLC.

Item 9.01. Financial Statements and Exhibits.

(a) Financial statements of businesses acquired.

     The required financial statements are attached hereto as Exhibits 99.1, 99.2 and 99.3 and are incorporated herein by reference.

(b) Pro forma financial information.

     The required pro forma financial information is attached hereto as Exhibit 99.4 and is incorporated herein by reference.

(d) Exhibits.

     The following exhibits are being filed herewith:

Exhibit
Number		Description
23.1		Consent of Deloitte & Touche LLP
99.1		Audited Consolidated Financial Statements of Texas Eastern Products Pipeline Company, LLC and subsidiaries as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006
99.2		Unaudited Consolidated Financial Statements of Texas Eastern Products Pipeline Company, LLC and subsidiaries for the three month periods ended March 31, 2007 and 2006
99.3		Audited Consolidated Financial Statements of Jonah Gas Gathering Company and subsidiary for the year ended December 31, 2006
99.4		Pro Forma Financial Statements

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Exhibit
Number		Description
23.1		Consent of Deloitte & Touche LLP
99.1		Audited Consolidated Financial Statements of Texas Eastern Products Pipeline Company, LLC and subsidiaries as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006
99.2		Unaudited Consolidated Financial Statements of Texas Eastern Products Pipeline Company, LLC and subsidiaries for the three month periods ended March 31, 2007 and 2006
99.3		Audited Consolidated Financial Statements of Jonah Gas Gathering Company and subsidiary for the year ended December 31, 2006
99.4		Pro Forma Financial Statements

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

     We consent to the incorporation by reference in Enterprise GP Holdings L.P.’s Registration Statement No. 333-129668 on Form S-8 of our report dated July 16, 2007, relating to the consolidated financial statements of Texas Eastern Pipeline Company, LLC and subsidiaries and our report dated February 28, 2007, relating to the consolidated financial statements of Jonah Gas Gathering Company and subsidiary, appearing in this Current Report on Form 8-K/A of Enterprise GP Holdings L.P.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

July 16, 2007

Exhibit 99.1

Texas Eastern Products Pipeline Company, LLC and Subsidiaries

Consolidated Financial Statements as of
December 31, 2006 and 2005, and for each of
the three years in the period ended December 31, 2006
Report of Independent Registered Public Accounting Firm

CONSOLIDATED FINANCIAL STATEMENTS
OF TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
Report of Independent Registered Public Accounting Firm			1
Consolidated Balance Sheets as of December 31, 2006 and 2005			2
Statements of Consolidated Income and Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004			3
Statements of Consolidated Cash Flows for the Years Ended December 31, 2006, 2005 and 2004			4
Statements of Consolidated Member’s Equity (Deficit) for the Years Ended December 31, 2006, 2005 and 2004			5
Notes to Consolidated Financial Statements			6
Note 1. Organization			6
Note 2. Summary of Significant Accounting Policies			8
Note 3. Recent Accounting Developments			17
Note 4. Accounting for Equity Awards			19
Note 5. Employee Benefit Plans			23
Note 6. Financial Instruments – Interest Rate Swaps			27
Note 7. Inventories			29
Note 8. Property, Plant and Equipment			29
Note 9. Investments in Unconsolidated Affiliates			31
Note 10. Acquisitions			33
Note 11. Dispositions and Discontinued Operations			35
Note 12. Goodwill and Other Intangible Assets			36
Note 13. Debt Obligations			38
Note 14. Minority Interest			41
Note 15. Member’s Equity (Deficit)			43
Note 16. Business Segments			44
Note 17. Related Party Transactions			47
Note 18. Commitments and Contingencies			53
Note 19. Concentrations of Credit Risk			59
Note 20. Supplemental Cash Flow Information			60
Note 21. Subsequent Events			60

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of
Texas Eastern Products Pipeline Company, LLC:

We have audited the accompanying consolidated balance sheets of Texas Eastern Products Pipeline Company, LLC and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related statements of consolidated income and comprehensive income, consolidated member’s equity (deficit), and consolidated cash flows for each of the three years in the period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Texas Eastern Products Pipeline Company, LLC and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas
July 16, 2007

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

		December 31,
		2006				2005
ASSETS
Current assets:
Cash and cash equivalents		$	119			$	119
Accounts receivable, trade (net of allowance for doubtful accounts of $100 and $250)			852,816				803,373
Accounts receivable, related parties			11,788				5,207
Inventories			72,193				29,069
Other			29,843				61,621
Total current assets			966,759				899,389
Property, plant and equipment, at cost (net of accumulated depreciation and amortization of $509,889 and $474,332)			1,642,095				1,960,068
Equity investments			1,039,710				359,656
Intangible assets			185,410				376,908
Goodwill			15,506				16,944
Other assets			72,661				67,834
Total assets		$	3,922,141			$	3,680,799
LIABILITIES AND MEMBER’S EQUITY (DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities		$	855,306			$	800,033
Accounts payable, related parties			34,885				12,145
Accrued interest			35,523				32,840
Other accrued taxes			14,482				16,532
Other			36,776				75,970
Total current liabilities			976,972				937,520
Senior notes			1,113,287				1,119,121
Other long-term debt			490,000				405,900
Deferred tax liability			652				—
Other liabilities and deferred credits			19,461				16,936
Other liabilities, related party			1,814				—
Minority interest			1,405,559				1,262,846
Commitments and contingencies
Member’s equity (deficit):
Accumulated other comprehensive income			426				11
Member’s equity (deficit)			(86,030	)			(61,535	)
Total member’s equity (deficit)			(85,604	)			(61,524	)
Total liabilities and member’s equity (deficit)		$	3,922,141			$	3,680,799

See Notes to Consolidated Financial Statements.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME AND COMPREHENSIVE INCOME
(Dollars in thousands)

		For Year Ended December 31,
		2006				2005				2004
Operating revenues:
Sales of petroleum products		$	9,080,516			$	8,061,808			$	5,426,832
Transportation – Refined products			152,552				144,552				148,166
Transportation – LPGs			89,315				96,297				87,050
Transportation – Crude oil			38,822				37,614				37,177
Transportation – NGLs			43,838				43,915				41,204
Gathering – Natural gas			123,933				152,797				140,122
Other			78,509				68,051				67,539
Total operating revenues			9,607,485				8,605,034				5,948,090
Costs and expenses:
Purchases of petroleum products			8,967,062				7,986,438				5,367,027
Operating expense			203,015				185,712				191,893
Operating fuel and power			57,450				48,972				48,139
General and administrative			31,683				33,518				28,017
Depreciation and amortization			108,252				110,729				112,284
Taxes – other than income taxes			17,983				20,610				17,425
Gains on sales of assets			(7,404	)			(668	)			(1,053	)
Total costs and expenses			9,378,041				8,385,311				5,763,732
Operating income			229,444				219,723				184,358
Other income (expense):
Interest expense – net			(86,171	)			(81,861	)			(72,053	)
Equity earnings			36,761				20,094				22,148
Interest income, related party			—				—				187
Interest income			2,086				687				467
Other income (expense) – net			888				(9,552	)			853
Income before provision for income taxes			183,008				149,091				135,960
Provision for income taxes			652				3				(1	)
Minority interest			130,484				112,744				96,667
Income from continuing operations			51,872				36,344				39,294
Income from discontinued operations			1,497				3,150				2,689
Gain on sale of discontinued operations			17,872				—				—
Minority interest for discontinued operations			(13,835	)			(2,228	)			(1,913	)
Discontinued operations			5,534				922				776
Net income		$	57,406			$	37,266			$	40,070
Changes in fair values of interest rate cash flow hedges			(248	)			—				—
Changes in fair values of crude oil cash flow hedges			730				11				—
Comprehensive income		$	57,888			$	37,277			$	40,070

See Notes to Consolidated Financial Statements.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in thousands)

		For Year Ended December 31,
		2006				2005				2004
Operating activities:
Net income		$	57,406			$	37,266			$	40,070
Adjustments to reconcile net income to cash provided by continuing operating activities:
Minority interest			144,319				114,972				98,580
Income from discontinued operations			(19,369	)			(3,150	)			(2,689	)
Forgiveness of note receivable, Duke Energy Field Services, L.P.			—				10,000				—
Deferred income tax expense (benefit)			652				—				(1	)
Depreciation and amortization			108,252				110,729				112,284
Earnings in equity investments			(36,761	)			(20,094	)			(22,148	)
Distributions from equity investments			63,483				37,085				47,213
Gains on sales of assets			(7,404	)			(668	)			(1,053	)
Non-cash portion of interest expense			1,676				1,624				(391	)
Net effect of changes in operating accounts			(40,652	)			(37,046	)			(74,868	)
Net cash provided by continuing operating activities			271,602				250,718				196,997
Net cash provided by discontinued operations			1,521				3,782				3,271
Net cash provided by operating activities			273,123				254,500				200,268
Investing activities:
Proceeds from sales of assets			51,558				510				1,226
Acquisition of assets			(20,473	)			(112,231	)			(3,421	)
Investment in Centennial Pipeline LLC			(2,500	)			—				(1,500	)
Investment in Mont Belvieu Storage Partners, L.P.			(4,767	)			(4,233	)			(21,358	)
Investment in Jonah Gas Gathering Company			(121,035	)			—				—
Cash paid for linefill on assets owned			(6,453	)			(14,408	)			(957	)
Capital expenditures			(170,046	)			(220,553	)			(156,749	)
Net cash used in continuing investing activities			(273,716	)			(350,915	)			(182,759	)
Net cash used in discontinued investing activities			—				—				(7,398	)
Net cash used in investing activities			(273,716	)			(350,915	)			(190,157	)
Financing activities:
Proceeds from revolving credit facility			924,125				657,757				324,200
Contributions from minority interest			195,059				278,806				—
Repayments on revolving credit facility			(840,025	)			(604,857	)			(181,200	)
Debt issuance costs			—				(498	)			—
Contribution from member			—				5				—
Distributions paid to minority interest			(196,665	)			(177,916	)			(166,158	)
Distributions paid to member			(81,901	)			(73,185	)			—
Net cash provided by (used in) financing activities			593				80,112				(23,158	)
Net change in cash and cash equivalents			—				(16,303	)			(13,047	)
Cash and cash equivalents, January 1			119				16,422				29,469
Cash and cash equivalents, December 31		$	119			$	119			$	16,422

See Notes to Consolidated Financial Statements.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED MEMBER’S EQUITY (DEFICIT)
(Dollars in thousands)

						Note
						Receivable				Accumulated
						(Duke Energy				Other
		Member’s				Field Services,				Comprehensive
		Equity (Deficit)				L.P.)				(Loss) Income				Total
Balance, December 31, 2003		$	108,695			$	(10,000	)		$	(2,902	)		$	95,793
Net income on cash flow hedge			—				—				2,902				2,902
Net income – year ended December 31, 2004			40,070				—				—				40,070
Balance, December 31, 2004			148,765				(10,000	)			—				138,765
Forgiveness of note receivable, Duke Energy Field Services, L.P.			—				10,000				—				10,000
Contribution from member			5				—				—				5
Changes in fair values of crude oil cash flow hedges			—				—				11				11
Distribution to Duke Energy Field Services, L.P.			(176,046	)			—				—				(176,046	)
Write-off of income tax receivable resulting from acquisition by DFI GP Holdings L.P.			(408	)			—				—				(408	)
Income tax receivable adjustment			260				—				—				260
Write-off of deferred income tax liability resulting from acquisition by DFI GP Holdings L.P.			1,808				—				—				1,808
Distributions paid to member			(73,185	)			—				—				(73,185	)
Net income – year ended December 31, 2005			37,266				—				—				37,266
Balance, December 31, 2005			(61,535	)			—				11				(61,524	)
Distributions paid to member			(81,901	)			—				—				(81,901	)
Changes in fair values of crude oil cash flow hedges			—				—				730				730
Changes in fair values of interest rate cash flow hedges			—				—				(248	)			(248	)
Adjustment to initially apply SFAS No. 158			—				—				(67	)			(67	)
Net income – year ended December 31, 2006			57,406				—				—				57,406
Balance, December 31, 2006		$	(86,030	)		$	—			$	426			$	(85,604	)

See Notes to Consolidated Financial Statements.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION

          Texas Eastern Products Pipeline Company, LLC (the “Company”) is a Delaware limited liability company whose membership interests are owned, as of December 31, 2006, by DFI GP Holdings L.P. (“DFI”), an affiliate of EPCO, Inc. (“EPCO”), a privately held company controlled by Dan L. Duncan, which acquired us on February 24, 2005. Through February 23, 2005, we were a direct wholly owned subsidiary of DCP Midstream Partners, L.P. (formerly Duke Energy Field Services, LLC (“DEFS”)), a joint venture between Duke Energy Corporation (“Duke Energy”) and ConocoPhillips. Duke Energy held an interest of approximately 70% in DEFS, and ConocoPhillips held the remaining interest of approximately 30%. On February 24, 2005, we were acquired by DFI for approximately $1.1 billion. In connection with the transfer of DEFS’ membership interest to DFI effective February 23, 2005, we discharged DEFS’ demand note receivable and declared a distribution of accumulated advances that reduced member’s equity by $186.0 million resulting in a former member deficit capital account of $43.0 million. For the period January 1, 2005 to February 24, 2005, DEFS was allocated a loss of $0.5 million by us, which included $10.0 million of loss related to the discharge of the demand note receivable, partially offset by $9.5 million of earnings for the 2005 period, and received $16.9 million of cash distributions from us.

          Our executive officers are employees of EPCO, and the other personnel working on our behalf also are employees of EPCO. Our sole member, which was DFI as of December 31, 2006, appoints our directors. Mr. Duncan also indirectly controls Enterprise Products Partners L.P. (“Enterprise”) and its affiliates, including Enterprise GP Holdings L.P. (“Enterprise GP Holdings”) and Duncan Energy Partners L.P. Under an amended and restated administrative services agreement (“ASA”), EPCO performs all management, administrative and operating functions required for us and our subsidiaries, and we reimburse EPCO for all direct and indirect expenses that have been incurred in managing us and our subsidiaries. See Note 21 for information regarding the transfer of our member’s interest.

          As used in this Report, “we,” “us,” “our,” and the “Company” mean Texas Eastern Products Pipeline Company, LLC, and where the context requires, include our subsidiaries and their business and operations. References to the “Parent Company” are intended to mean and include Texas Eastern Products Pipeline Company, LLC, in its individual capacity, and not on a consolidated basis.

          We own a 2% general partner interest in TEPPCO Partners, L.P. (“TEPPCO”) and act as the managing general partner of TEPPCO. TEPPCO, a Delaware limited partnership, is a master limited partnership formed in March 1990 and its limited partner units (“Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “TPP”. TEPPCO operates through TE Products Pipeline Company, Limited Partnership (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”). Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the “Operating Partnerships.” We have the right to receive the incentive distribution rights associated with our general partner interest in TEPPCO. Together with other affiliate of Mr. Duncan, we also collectively own 16,691,550 Units of TEPPCO.

Parent Company Financial Information

          The Parent Company has no separate operating activities apart from those conducted by the Operating Partnerships. The principal source of cash flow for the Parent Company is its investment in its general partner ownership interest in TEPPCO. The Parent Company’s primary cash requirements are for general and administrative expenses and distributions to its member. The Parent Company’s assets and liabilities are not available to satisfy the debts and other obligations of TEPPCO.

          In order to fully understand the financial condition and results of operations of the Parent Company, we are providing the financial information of Texas Eastern Products Pipeline Company, LLC apart from that of our

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

consolidated information included within this Report. The following financial statements reflect the transactions of the Parent Company as of and for the years ended December 31, 2006 and 2005.

          The following table presents the Parent Company’s balance sheet data at December 31, 2006 and 2005:

		December 31,
		2006				2005
ASSETS
Current assets		$	49			$	260
Other assets			—				1
Total assets		$	49			$	261
LIABILITIES AND MEMBER’S EQUITY (DEFICIT)
Current liabilities		$	424			$	309
Excess of distributions received over equity in earnings of TEPPCO Partners, L.P. (1)			85,655				61,487
Member’s equity (deficit)			(86,030	)			(61,535	)
Total liabilities and member’s equity (deficit)		$	49			$	261

          The following table presents the Parent Company’s statements of income for the three years ended December 31, 2006, 2005 and 2004:

		For Year Ended
		December 31,
		2006				2005				2004
General and administrative expenses		$	335			$	310			$	1
Taxes – other than income taxes			—				—				85
Operating loss			(335	)			(310	)			(86	)
Equity earnings in TEPPCO Partners, L.P. (1)			57,732				47,579				39,968
Interest income, related party			—				—				187
Other income (expense), net			9				(10,000	)			—
Income before provision for income taxes			57,406				37,269				40,069
Provision for income taxes			—				3				(1	)
Net income		$	57,406			$	37,266			$	40,070

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

          The following table shows the Parent Company’s statements of cash flows for the years ended December 31, 2006, 2005 and 2004:

		For Year Ended
		December 31,
		2006				2005				2004
Cash flows from operating activities:
Net income		$	57,406			$	37,266			$	40,070
Adjustments to reconcile net income to cash provided by operating activities:
Forgiveness of note receivable, Duke Energy Field Services, L.P.			—				10,000				—
Equity earnings in TEPPCO Partners, L.P.			(57,732	)			(47,579	)			(39,968	)
Distributions from TEPPCO Partners, L.P.			81,901				73,185				66,899
Deferred income tax expense (benefit)			—				—				(1	)
Decrease in current assets			261				—				6
Increase in current liabilities			114				309				—
Other			—				(1	)			(67,006	)
Net cash provided by operating activities			81,950				73,180				—
Cash flows from financing activities:
Contribution from member			—				5				—
Distributions paid to member			(81,901	)			(73,185	)			—
Net cash used in financing activities			(81,901	)			(73,180	)			—
Net change in cash and cash equivalents			49				—				—
Cash and cash equivalents, January 1			—				—				—
Cash and cash equivalents, December 31		$	49			$	—			$	—

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

          We adhere to the following significant accounting policies in the preparation of our consolidated financial statements.

Business Segments

          We operate and report in three business segments: transportation, marketing and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals (“Downstream Segment”); gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals (“Upstream Segment”); and gathering of natural gas, fractionation of natural gas liquids (“NGLs”) and transportation of NGLs (“Midstream Segment”). Our reportable segments offer different products and services and are managed separately because each requires different business strategies (see Note 16).

          Our interstate transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission (“FERC”). We refer to refined products, LPGs, petrochemicals, crude oil, lubrication oils and specialty chemicals, NGLs and natural gas in this Report, collectively, as “petroleum products” or “products.”

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Allowance for Doubtful Accounts

          We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. Our procedure for recording an allowance for doubtful accounts is based on (i) our historical experience, (ii) the financial stability of our customers and (iii) the levels of credit granted to customers. In addition, we may also increase the allowance account in response to specific identification of customers involved in bankruptcy proceedings and those experiencing other financial difficulties. We routinely review our estimates in this area to ensure that we have recorded sufficient reserves to cover potential losses. The following table presents the activity of our allowance for doubtful accounts for the years ended December 31, 2006, 2005 and 2004:

		For Year Ended December 31,
		2006				2005				2004
Balance at beginning of period		$	250			$	112			$	4,700
Charges to expense			64				829				536
Deductions and other			(214	)			(691	)			(5,124	)
Balance at end of period		$	100			$	250			$	112

Asset Retirement Obligations

          Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from its acquisition, construction, development and/or normal operation. We record a liability for AROs when incurred and capitalize an increase in the carrying value of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over its useful life. We will either settle our ARO obligations at the recorded amount or incur a gain or loss upon settlement.

          The Downstream Segment assets consist primarily of an interstate trunk pipeline system and a series of storage facilities that originate along the upper Texas Gulf Coast and extend through the Midwest and northeastern United States. We transport refined products, LPGs and petrochemicals through the pipeline system. These products are primarily received in the south end of the system and stored and/or transported to various points along the system per customer nominations. The Upstream Segment’s operations include purchasing crude oil from producers at the wellhead and providing delivery, storage and other services to its customers. The properties in the Upstream Segment consist of interstate trunk pipelines, pump stations, trucking facilities, storage tanks and various gathering systems primarily in Texas and Oklahoma. The Midstream Segment gathers natural gas from wells owned by producers and delivers natural gas and NGLs on its pipeline systems, primarily in Texas, Wyoming, New Mexico and Colorado. The Midstream Segment also owns and operates two NGL fractionator facilities in Colorado.

          We have determined that we are obligated by contractual or regulatory requirements to remove certain facilities or perform other remediation upon retirement of our assets. However, we are not able to reasonably determine the fair value of the AROs for our trunk, interstate and gathering pipelines and our surface facilities, since future dismantlement and removal dates are indeterminate. During 2006, we recorded $0.6 million of expense, included in depreciation and amortization expense, related to conditional AROs related to the retirement of the Val Verde Gas Gathering Company, L.P. (“Val Verde”) natural gas gathering system and to structural restoration work to be completed on leased office space that is required upon our anticipated office lease termination. Additionally, we have recorded a $1.2 million liability, which represents the present values of these conditional AROs. During 2006, we assigned probabilities for settlement dates and settlement methods for use in an expected present value measurement and recorded conditional AROs.

          In order to determine a removal date for our crude oil gathering lines and related surface assets, reserve information regarding the production life of the specific field is required. As a transporter and gatherer of crude oil,

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we are not a producer of the field reserves, and we therefore do not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which we gather crude oil. In the absence of such information, we are not able to make a reasonable estimate of when future dismantlement and removal dates of our crude oil gathering assets will occur. With regard to our trunk and interstate pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease. Our right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, we can evaluate our trunk pipelines for alternative uses, which can be and have been found.

          We will record AROs in the period in which more information becomes available for us to reasonably estimate the settlement dates of the retirement obligations. The adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations and Financial Accounting Standards Board (“FASB”) Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143, (“FIN 47”) did not have a material effect on our financial position, results of operations or cash flows.

Basis of Presentation and Principles of Consolidation

          The consolidated financial statements at December 31, 2006, 2005 and 2004 include the accounts of the Parent Company, its wholly owned subsidiary, TEPPCO Investments, LLC and its 2% general partner interest in TEPPCO. TEPPCO Investments, LLC is an inactive holding company. We have eliminated all significant intercompany items in consolidation and provisions are made for minority interests. Our results for the years ended December 31, 2006, 2005 and 2004 reflect the operations and activities of Jonah Gas Gathering Company’s (“Jonah”) Pioneer plant as discontinued operations.

          We own a 2% general partner interest in TEPPCO, which conducts substantially all of our business. We have no independent operations and no material assets outside those of TEPPCO. The number of reconciling items between our consolidated financial statements and that of TEPPCO are few. The most significant difference is that relating to minority interest ownership in our net assets by the limited partners of TEPPCO, and the elimination of our investment in TEPPCO with our underlying partner’s capital account in TEPPCO (see Note 14 for additional information regarding minority interest ownership in our consolidated subsidiaries).

Cash and Cash Equivalents

          Cash equivalents are defined as all highly marketable securities with maturities of three months or less when purchased. The carrying value of cash equivalents approximate fair value because of the short term nature of these investments. Our Statements of Consolidated Cash Flows are prepared using the indirect method.

Capitalization of Interest

          We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 6.27%, 5.73% and 5.74% for the years ended December 31, 2006, 2005 and 2004, respectively. During the years ended December 31, 2006, 2005 and 2004, the amount of interest capitalized was $10.7 million, $6.8 million and $4.2 million, respectively.

Contingencies

          Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Our management and its legal counsel assess such contingent liabilities, 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

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result in proceedings, our legal counsel evaluates 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.

          If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed.

          Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.

Dollar Amounts

          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.

Environmental Expenditures

          We accrue for environmental costs that relate to existing conditions caused by past operations, including conditions with assets we have acquired. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as damages and other costs, when estimable. We monitor the balance of accrued undiscounted environmental liabilities on a regular basis. We record liabilities for environmental costs at a specific site when our liability for such costs is probable and a reasonable estimate of the associated costs can be made. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation alternatives available and the evolving nature of environmental laws and regulations.

          The following table presents the activity of our environmental reserve for the years ended December 31, 2006, 2005 and 2004:

		For Year Ended December 31,
		2006				2005				2004
Balance at beginning of period		$	2,447			$	5,037			$	7,639
Charges to expense			1,887				2,530				5,178
Deductions and other			(2,532	)			(5,120	)			(7,780	)
Balance at end of period		$	1,802			$	2,447			$	5,037

Estimates

          The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Although we believe these estimates are reasonable, actual results could differ from those estimates.

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Fair Value of Current Assets and Current Liabilities

          The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities, other current liabilities and derivatives approximates their fair value due to their short-term nature. The fair values of these financial instruments are represented in our consolidated balance sheets.

Goodwill

          Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization. Our goodwill amounts are assessed for impairment (i) on an annual basis during the fourth quarter of each year or (ii) on an interim basis when impairment indicators are present. If such indicators are present (e.g., loss of a significant customer, economic obsolescence of plant assets, etc.), the fair value of the reporting unit to which the goodwill is assigned will be calculated and compared to its book value.

          If the fair value of the reporting unit exceeds its book value, the goodwill amount is not considered to be impaired and no impairment charge is required. If the fair value of the reporting unit is less than its book value, a charge to earnings is recorded to adjust the carrying value of the goodwill to its implied fair value. We have not recognized any impairment losses related to our goodwill for any of the periods presented (see Note 12 for a further discussion of our goodwill).

Income Taxes

          Our limited liability company structure is not subject to federal income taxes. As a result, our earnings or losses for federal income tax purposes are included in the tax returns of our member. We are organized as a pass-through entity for federal income tax purposes. As a result, our member is individually responsible for the federal income tax on its allocable share of our taxable income.

     Texas Margin Tax

          In May 2006, the State of Texas enacted a new business tax (the “Texas Margin Tax”) that replaces its existing franchise tax. In general, legal entities that do business in Texas are subject to the Texas Margin Tax. Limited partnerships, limited liability companies, corporations, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the Texas Margin Tax. As a result of the change in tax law, TEPPCO’s tax status in the state of Texas changed from nontaxable to taxable. The Texas Margin Tax is considered an income tax for purposes of adjustments to deferred tax liability, as the tax is determined by applying a tax rate to a base that considers both revenues and expenses. Our deferred income tax expense for state taxes relates only to Texas Margin Tax obligations. The Texas Margin Tax becomes effective for franchise tax reports due on or after January 1, 2008. The Texas Margin Tax due in 2008 will be based on revenues earned during the 2007 fiscal year.

          The Texas Margin Tax is assessed at 1% of Texas-sourced taxable margin measured by the ratio of gross receipts from business done in Texas to gross receipts from business done everywhere. The taxable margin is computed as the lesser of (i) 70% of total revenue or (ii) total revenues less (a) cost of goods sold or (b) compensation. The deferred tax liability shown on our consolidated balance sheet reflects the net tax effect of temporary differences related to items such as property, plant and equipment; therefore, the deferred tax liability is classified as noncurrent. The Texas Margin Tax is calculated, paid and filed at an affiliated unitary group level. Generally, an affiliated group is made up of one or more entities in which a controlling interest of at least 80% is owned by a common owner or owners. Generally, a business is unitary if it is characterized by a sharing or exchange of value between members of the group, and a synergy and mutual benefit all of the members of the group achieved by working together. We have calculated and recorded an estimated deferred tax liability of approximately

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$0.7 million associated with the Texas Margin Tax. The non-cash offsetting charge is shown on our statements of consolidated income as deferred income tax expense for the year ended December 31, 2006.

          Since the Texas Margin Tax is determined by applying a tax rate to a base that considers both revenues and expenses, it has characteristics of an income tax. Accordingly, we determined the Texas Margin Tax should be accounted for as an income tax in accordance with the provisions of SFAS No. 109, Accounting for Income Taxes.

Intangible Assets and Excess Investments

          Intangible assets on the consolidated balance sheets consist primarily of gathering contracts assumed in the acquisition of Val Verde on June 30, 2002, a fractionation agreement and other intangible assets (see Note 12). Included in equity investments on the consolidated balance sheets are excess investments in Centennial Pipeline LLC (“Centennial”), Seaway Crude Pipeline Company (“Seaway”) and Jonah.

          In connection with the acquisition of Val Verde, we assumed fixed-term contracts with customers that gather coal bed methane from the San Juan Basin in New Mexico and Colorado. The value assigned to these intangible assets relates to contracts with customers that are for a fixed term. These intangible assets are amortized on a unit-of-production basis, based upon the actual throughput of the system over the expected total throughput for the lives of the contracts. Revisions to the unit-of-production estimates may occur as additional production information is made available to us (see Note 12).

          In connection with the purchase of the fractionation facilities in 1998, we entered into a fractionation agreement with DEFS. The fractionation agreement is being amortized on a straight-line basis over a period of 20 years, which is the term of the agreement with DEFS.

          In connection with the acquisition of crude supply and transportation assets in November 2003, we acquired intangible customer contracts for $8.5 million, which are amortized on a unit-of-production basis.

          In connection with the formation of Centennial, we recorded excess investment, the majority of which is amortized on a unit-of-production basis over a period of 10 years. In connection with the acquisition of our interest in Seaway, we recorded excess investment, which is amortized on a straight-line basis over a period of 39 years. In connection with the formation of our Jonah joint venture and the construction of its expansion, we recorded excess investment (see Note 12).

Inventories

          Inventories consist primarily of petroleum products, which are valued at the lower of cost (weighted average cost method) or market. Our Downstream Segment acquires and disposes of various products under exchange agreements. Receivables and payables arising from these transactions are usually satisfied with products rather than cash. The net balances of exchange receivables and payables are valued at weighted average cost and included in inventories. Inventories of materials and supplies, used for ongoing replacements and expansions, are carried at cost.

Minority Interest

          Minority interest represents third-party ownership interests in the net assets of TEPPCO through TEPPCO’s publicly traded Units. We own a 2% general partner interest in TEPPCO. For financial reporting purposes, the assets and liabilities of TEPPCO are consolidated with those of our own, with any third-party investor’s interest in our consolidated balance amounts shown as minority interest. Minority interest expense reflects the allocation of earnings to third-party investors. Distributions to and contributions from minority interests represent cash payments and cash contributions, respectively, from such third-party investors.

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          At TEPPCO’s formation in 1990, TEPPCO completed an initial public offering of 26,500,000 Units at $10.00 per Unit. In connection with TEPPCO’s formation, we received 2,500,000 Deferred Participation Interests (“DPIs”). Effective April 1, 1994, the DPIs were converted to Units, but they have not been listed for trading on the New York Stock Exchange. These Units were assigned to Duke Energy when ownership of us was transferred from Duke Energy to DEFS in 2000. On February 24, 2005, DFI entered into an LP Unit Purchase and Sale Agreement with Duke Energy and purchased these 2,500,000 Units for $104.0 million. As of December 31, 2006, none of these Units had been sold by DFI.

          At December 31, 2006, 2005 and 2004, TEPPCO had outstanding 89,804,829, 69,963,554 and 62,998,554 Units, respectively.

Natural Gas Imbalances

          Gas imbalances occur when gas producers (customers) deliver more or less actual natural gas gathering volumes to our gathering systems than they originally nominated. Actual deliveries are different from nominated volumes due to fluctuations in gas production at the wellhead. To the extent that these shipper imbalances are not cashed out, Val Verde records a payable to shippers who supply more natural gas gathering volumes than nominated, and receivable from the shippers who nominate more natural gas gathering volumes than supplied. To the extent pipeline imbalances are not cashed out, Val Verde records a receivable from connecting pipeline transporters when total volumes delivered exceed the total of shipper’s nominations and records a payable to connecting pipeline transporters when the total shippers’ nominations exceed volumes delivered. We record natural gas imbalances using a mark-to-market approach.

Property, Plant and Equipment

          We record property, plant and equipment at its acquisition cost. Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost. We charge replacements and renewals of minor items of property that do not materially increase values or extend useful lives to maintenance expense. Depreciation expense is computed on the straight-line method using rates based upon expected useful lives of various classes of assets (ranging from 2% to 20% per annum).

          We evaluate impairment of long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of the carrying amount of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or estimated fair value less costs to sell.

Revenue Recognition

          Our Downstream Segment revenues are earned from transportation, marketing and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. Transportation revenues are recognized as products are delivered to customers. Storage revenues are recognized upon receipt of products into storage and upon performance of storage services. Terminaling revenues are recognized as products are out-loaded. Revenues from the sale of product inventory are recognized when the products are sold. Our refined products marketing activities generate revenues by purchasing refined products from our throughput partners and establishing a margin by selling refined products for physical delivery through spot sales at the Aberdeen truck rack to independent wholesalers and retailers of refined products. These purchases and sales are generally contracted to occur on the same day.

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          Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Revenues are also generated from trade documentation and pumpover services, primarily at Cushing, Oklahoma, and Midland, Texas. Revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to our crude oil marketing company, TEPPCO Crude Oil, L.P. (“TCO”), which typically occurs upon our receipt of the product. Revenues related to trade documentation and pumpover fees are recognized as services are completed.

          Except for crude oil purchased from time to time as inventory, our policy is to purchase only crude oil for which we have a market to sell and to structure sales contracts so that crude oil price fluctuations do not materially affect the margin received. As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users or by entering into a future delivery obligation. Through these transactions, we seek to maintain a position that is balanced between crude oil purchases and sales and future delivery obligations. However, commodity price risks cannot be completely economically hedged.

          Our Midstream Segment revenues are earned from the gathering of natural gas, transportation of NGLs and fractionation of NGLs. Gathering revenues are recognized as natural gas is received from the customer. Transportation revenues are recognized as NGLs are delivered for customers. Fractionation revenues are recognized ratably over the contract year as products are delivered. We generally do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, with the exception of inventory imbalances discussed in “Natural Gas Imbalances.” Therefore, the results of our Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs.

Unit Option Plan and Unit Purchase Plan

          At a special meeting of its unitholders on December 8, 2006, TEPPCO’s unitholders approved the EPCO, Inc. 2006 TPP Long-Term Incentive Plan, which provides for awards of TEPPCO’s Units and other rights to TEPPCO’s non-employee directors and to employees of EPCO and its affiliates providing services to us. Awards under this plan may be granted in the form of restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. Additionally, TEPPCO’s unitholders approved the EPCO, Inc. TPP Employee Unit Purchase Plan, which provides for discounted purchases of TEPPCO’s Units by employees of EPCO and its affiliates. Generally, any employee who (1) has been employed by EPCO or any of its designated affiliates for three consecutive months, (2) is a regular, active and full time employee and (3) is scheduled to work at least 30 hours per week is eligible to participate in this plan, provided that employees covered by collective bargaining agreements (unless otherwise specified therein) and 5% owners of TEPPCO, EPCO or any affiliate are not eligible to participate (see Note 4).

Use of Derivatives

          We account for derivative financial instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133. These statements establish accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative.

          Our derivative instruments consist primarily of interest rate swaps and contracts for the purchase and sale of petroleum products in connection with our crude oil marketing activities. Substantially all derivative instruments related to our crude oil marketing activities meet the normal purchases and sales criteria of SFAS 133, as amended,

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and as such, changes in the fair value of petroleum product purchase and sales agreements are reported on the accrual basis of accounting. SFAS 133 describes normal purchases and sales as contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business.

          For all hedging relationships, we formally document at inception the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed and a description of the method of measuring ineffectiveness. This process includes linking all derivatives that are designated as fair value or cash flow to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. We also formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.

          For derivative instruments designated as fair value hedges, changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a fair value hedge, along with the loss or gain on the hedged asset or liability or unrecognized firm commitment of the hedged item that is attributable to the hedged risk, are recorded in earnings with the change in fair value of the derivative and hedged asset or liability reflected on the balance sheet. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective as a hedge, until earnings are affected by the variability in cash flows of the designated hedged item. Hedge effectiveness is measured at least quarterly based on the relative cumulative changes in fair value between the derivative contract and the hedged item over time. The ineffective portion of the change in fair value of a derivative instrument that qualifies as either a fair value hedge or a cash flow hedge is reported immediately in earnings.

          According to SFAS 133, as amended, we are required to discontinue hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the fair value or cash flows of the hedged item, or the derivative expires or is sold, terminated, or exercised, or the derivative is de-designated as a hedging instrument, because it is unlikely that a forecasted transaction will occur, a hedged firm commitment no longer meets the definition of a firm commitment, or management determines that designation of the derivative as a hedging instrument is no longer appropriate.

          When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective fair value hedge, we continue to carry the derivative on the balance sheet at its fair value and no longer adjust the hedged asset or liability for changes in fair value. The adjustment of the carrying amount of the hedged asset or liability is accounted for in the same manner as other components of the carrying amount of that asset or liability. When hedge accounting is discontinued because the hedged item no longer meets the definition of a firm commitment, we continue to carry the derivative on the balance sheet at its fair value, remove any asset or liability that was recorded pursuant to recognition of the firm commitment from the balance sheet, and recognize any gain or loss in earnings. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, we continue to carry the derivative on the balance sheet at its fair value with subsequent changes in fair value included in earnings, and gains and losses that were accumulated in other comprehensive income are recognized immediately in earnings. In all other situations in which hedge accounting is discontinued, we continue to carry the derivative at its fair value on the balance sheet and recognize any subsequent changes in its fair value in earnings.

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NOTE 3. RECENT ACCOUNTING DEVELOPMENTS

          In December 2004, the FASB issued SFAS No. 123(R) (revised 2004), Share-Based Payment. SFAS 123(R) is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees. SFAS 123(R) requires that the cost resulting from all share-based payment transactions be recognized in the financial statements at fair value. SFAS 123(R) became effective for public companies for annual periods beginning after June 15, 2005. Accordingly, we adopted SFAS 123(R) in the first quarter of 2006. We adopted SFAS 123(R) under the modified prospective transition method. We have determined that our 1999 Phantom Unit Retention Plan and our 2005 Phantom Unit Plan are liability awards under the provisions of SFAS 123(R). No additional compensation expense has been recorded in connection with the adoption of SFAS 123(R) as we have historically recorded the associated liabilities at fair value. The adoption of SFAS 123(R) did not have a material effect on our financial position, results of operations or cash flows.

          In June 2005, the Emerging Issues Task Force (“EITF”) reached consensus in EITF 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights, to provide guidance on how general partners in a limited partnership should determine whether they control a limited partnership and therefore should consolidate it. The EITF agreed that the presumption of general partner control would be overcome only when the limited partners have either of two types of rights. The first type, referred to as “kick-out rights,” is the right to dissolve or liquidate the partnership or otherwise remove the general partner without cause. The second type, referred to as “participating rights,” is the right to effectively participate in significant decisions made in the ordinary course of the partnership’s business. The kick-out rights and the participating rights must be substantive in order to overcome the presumption of general partner control. The consensus is effective for general partners of all new limited partnerships formed and for existing limited partnerships for which the partnership agreements are modified subsequent to the date of FASB ratification (June 29, 2005). For existing limited partnerships that have not been modified, the guidance in EITF 04-5 is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. For existing limited partnerships that have not been modified, the guidance in EITF 04-5 is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. For consistency purposes, we have consolidated our interest in TEPPCO into our financial statements beginning January 1, 2004. Prior to the adoption of EITF 04-5, we accounted for our investment in TEPPCO under the equity method of accounting.

          In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS 154 establishes new standards on accounting for changes in accounting principles. All such changes must be accounted for by retrospective application to the financial statements of prior periods unless it is impracticable to do so. SFAS 154 completely replaces APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Periods. However, it carries forward the guidance in those pronouncements with respect to accounting for changes in estimates, changes in the reporting entity and the correction of errors. SFAS 154 is effective for accounting changes and error corrections made in fiscal years beginning after December 15, 2005, with early adoption permitted for changes and corrections made in years beginning after June 1, 2005. The application of SFAS 154 does not affect the transition provisions of any existing pronouncements, including those that are in the transition phase as of the effective date of SFAS 154. The adoption of SFAS 154 did not have a material effect on our financial position, results of operations or cash flows.

          In September 2005, the EITF reached consensus in EITF 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, to define when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction subject to APB Opinion No. 29, Accounting for Nonmonetary Transactions. Two or more inventory transactions with the same party should be combined if they are entered into in contemplation of one another. The EITF also requires entities to account for

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

exchanges of inventory in the same line of business at fair value or recorded amounts based on inventory classification. The guidance in EITF 04-13 is effective for new inventory arrangements entered into in reporting periods beginning after March 15, 2006. We adopted EITF 04-13 on April 1, 2006, which resulted in crude oil inventory purchases and sales under buy/sell transactions, which were previously recorded as gross purchases and sales, to be treated as inventory exchanges in our statements of consolidated income. EITF 04-13 reduced gross revenues and purchases, but did not have a material effect on our financial position, results of operations or cash flows. The treatment of buy/sell transactions under EITF 04-13 reduced the relative amount of revenues and purchases of petroleum products on our statements of consolidated income by approximately $1,127.6 million for the period from April 1, 2006 through December 31, 2006. The revenues and purchases of petroleum products associated with buy/sell transactions that are reported on a gross basis in our statements of consolidated income for the period from January 1, 2006 through March 31, 2006, and for the years ended December 31, 2005 and 2004, are approximately $275.4 million, $1,405.7 million and $496.1 million, respectively.

          In June 2006, the EITF reached consensus in EITF 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation). The accounting guidance permits companies to elect to present on either a gross or net basis sales and other taxes that are imposed on and concurrent with individual revenue-producing transactions between a seller and a customer. The gross basis includes the taxes in revenues and costs; the net basis excludes the taxes from revenues. The accounting guidance does not apply to tax systems that are based on gross receipts or total revenues. EITF 06-3 requires companies to disclose their policy for presenting the taxes and disclose any amounts presented on a gross basis if those amounts are significant. The guidance in EITF 06-3 is effective January 1, 2007. As a matter of policy, we report such taxes on a net basis. We believe that adoption of EITF 06-3 will not have a material effect on our financial position, results of operations or cash flows.

          In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an Interpretation of SFAS 109, Accounting for Income Taxes (“FIN 48”). FIN 48 provides that the tax effects of an uncertain tax position should be recognized in a company’s financial statements if the position taken by the entity is more likely than not sustainable if it were to be examined by an appropriate taxing authority, based on technical merit. After determining if a tax position meets such criteria, the amount of benefit to be recognized should be the largest amount of benefit that has more than a 50% chance of being realized upon settlement. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, and we were required to adopt FIN 48 as of January 1, 2007. The adoption of FIN 48 did not have a material effect on our financial position, results of operations or cash flows.

          In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS 157 applies only to fair-value measurements that are already required or permitted by other accounting standards and is expected to increase the consistency of those measurements. SFAS 157 emphasizes that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. Companies will be required to disclose the extent to which fair value is used to measure assets and liabilities, the inputs used to develop the measurements, and the effect of certain of the measurements on earnings (or changes in net assets) for the period. SFAS 157 is effective for fiscal years beginning after December 15, 2007, and we are required to adopt SFAS 157 as of January 1, 2008. We believe that the adoption of SFAS 157 will not have a material effect on our financial position, results of operations or cash flows.

          In September 2006, the SEC issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). SAB 108 addresses how the effects of prior-year uncorrected misstatements should be considered when quantifying misstatements in current-year financial statements. The SAB requires registrants to quantify misstatements using both balance-sheet and income-statement approaches and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. When the effect of initial adoption is

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

determined to be material, SAB 108 allows registrants to record that effect as a cumulative-effect adjustment to beginning-of-year retained earnings. The requirements are effective for annual financial statements covering the first fiscal year ending after November 15, 2006. Additionally, the nature and amount of each individual error being corrected through the cumulative-effect adjustment, when and how each error arose, and the fact that the errors had previously been considered immaterial is required to be disclosed. We are required to adopt SAB 108 for our current fiscal year ending December 31, 2006. The adoption of SAB 108 did not have a material effect on our financial position, results of operations or cash flows.

          In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R). SFAS 158 requires an employer to recognize the over-funded or under-funded status of its defined benefit pension and other postretirement plans as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. In addition, SFAS 158 eliminates the use of a measurement date that is different than the date of the employer’s year-end financial statements. SFAS 158 requires an employer to disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition asset or obligation. The requirement to recognize the funded status and to provide the required disclosures is effective for fiscal years ending after December 15, 2006. Accordingly, we adopted SFAS 158 in the fourth quarter 2006. The adoption of SFAS 158 did not have a material effect on our financial position, results of operations or cash flows.

          In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115. SFAS 159 permits entities to choose to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected would be reported in net income. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between the different measurement attributes the company elects for similar types of assets and liabilities. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact of the adoption of SFAS 159 on our financial statements. We do not believe the adoption of SFAS 159 will have a material effect on our financial position, results of operations or cash flows.

NOTE 4. ACCOUNTING FOR EQUITY AWARDS

1994 Long Term Incentive Plan

          During 1994, we adopted the Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan (“1994 LTIP”). The 1994 LTIP provided certain key employees with an incentive award whereby the participant was granted an option to purchase Units. These same employees were also granted a stipulated number of Performance Units, the cash value of which could have been used to pay for the exercise of the respective Unit options awarded. Under the provisions of the 1994 LTIP, no more than one million options and two million Performance Units could have been granted.

          According to the plan provisions, when TEPPCO’s calendar year earnings per Unit (exclusive of certain special items) exceeded a stated threshold, each participant received a credit to their respective Performance Unit account equal to the earnings per Unit excess multiplied by the number of Performance Units awarded. The balance in the Performance Unit account could have been used to offset the cost of exercising Unit options granted in connection with the Performance Units or could have been withdrawn two years after the underlying options expire, usually 10 years from the date of grant. Any unused balance previously credited was forfeited upon termination. We accrued compensation expense for the Performance Units awarded annually based upon the terms of the plan

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discussed above. Under the agreement for such Unit options, the options became exercisable in equal installments over periods of one, two, and three years from the date of the grant.

          At December 31, 2006, all options have been fully exercised. We have not granted options for any periods presented, and we have no accrued liability balances remaining for Performance Unit accounts. The 1994 LTIP was terminated effective as of June 19, 2006.

1999 and 2002 Phantom Unit Retention Plans

          Effective January 1, 1999 and June 1, 2002, we adopted the Texas Eastern Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan (“1999 Plan”) and the Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan (“2002 PURP”), respectively. The 1999 Plan and the 2002 PURP provide key employees with incentive awards whereby a participant is granted phantom units. These phantom units are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at stated redemption dates. The fair market value of each phantom unit is equal to the closing price of TEPPCO’s Units as reported on the NYSE on the redemption date.

          Under the agreement for the phantom units, each participant vests the number of phantom units initially granted under his or her award according to the terms agreed upon at the grant date. Each participant is required to redeem their phantom units as they vest. Each participant is also entitled to quarterly cash distributions equal to the product of the number of phantom units outstanding for the participant and the amount of the cash distribution that TEPPCO paid per Unit to its unitholders.

          We accrue compensation expense annually based upon the terms of the 1999 Plan and 2002 PURP discussed above. Due to the change in our ownership on February 24, 2005 (see Note 1), all phantom units outstanding at February 24, 2005 under both the 1999 Plan and the 2002 PURP fully vested and were redeemed by participants in 2005. As such, there were no outstanding phantom units under either the 1999 Plan or the 2002 PURP at December 31, 2005. During 2006, a total of 44,600 phantom units were granted under the 1999 Plan and remain outstanding at December 31, 2006. At December 31, 2006, we had an accrued liability balance of $0.8 million for compensation related to the 1999 Plan. No amounts were outstanding and no liabilities remained at December 31, 2006 for the 2002 PURP.

2000 Long Term Incentive Plan

          Effective January 1, 2000, we established the Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) to provide key employees incentives to achieve improvements in TEPPCO’s financial performance. Generally, upon the close of a three-year performance period, if the participant is then still an employee of EPCO, the participant will receive a cash payment in an amount equal to (1) the applicable performance percentage specified in the award multiplied by (2) the number of phantom units granted under the award multiplied by (3) the average of the closing prices of a TEPPCO Unit over the ten consecutive trading days immediately preceding the last day of the performance period. Generally, a participant’s performance percentage is based upon the improvement of TEPPCO’s Economic Value Added (as defined below) during a three-year performance period over the Economic Value Added during the three-year period immediately preceding the performance period. If a participant incurs a separation from service during the performance period due to death, disability or retirement (as such terms are defined in the 2000 LTIP), the participant will be entitled to receive a cash payment in an amount equal to the amount computed as described above multiplied by a fraction, the numerator of which is the number of days that have elapsed during the performance period prior to the participant’s separation from service and the denominator of which is the number of days in the performance period.

          At December 31, 2006, phantom units outstanding under the 2000 LTIP were 11,300 and 8,400 for awards granted for the years ended December 31, 2006 and 2005, respectively. At December 31, 2005, there were 23,400

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

phantom units outstanding for awards granted for the plan year ended December 31, 2005. All phantom units for awards granted under the 2003 and 2004 plan years became fully vested and were paid out to participants in 2005, in accordance with plan provisions as a result of the change in our ownership on February 24, 2005.

          Economic Value Added means TEPPCO’s average annual EBITDA for the performance period minus the product of its average asset base and its cost of capital for the performance period. EBITDA means TEPPCO’s earnings before net interest expense, other income – net, depreciation and amortization and its proportional interest in EBITDA of its joint ventures as presented in its consolidated financial statements prepared in accordance with generally accepted accounting principles, except that at his discretion our Chief Executive Officer (“CEO”) may exclude gains or losses from extraordinary, unusual or non-recurring items. Average asset base means the quarterly average, during the performance period, of TEPPCO’s gross value of property, plant and equipment, plus products and crude oil operating oil supply and the gross value of intangibles and equity investments. TEPPCO’s cost of capital is approved by our CEO at the date of award grant.

          In addition to the payment described above, during the performance period, we will pay to the participant the amount of cash distributions that TEPPCO would have paid to its unitholders had the participant been the owner of the number of Units equal to the number of phantom units granted to the participant under this award. We accrue compensation expense annually based upon the terms of the 2000 LTIP discussed above. At December 31, 2006 and 2005, we had an accrued liability balance of $0.6 million and $0.7 million, respectively, for compensation related to the 2000 LTIP.

2005 Phantom Unit Plan

          Effective January 1, 2005, we adopted the Texas Eastern Products Pipeline Company, LLC 2005 Phantom Unit Plan (“2005 Phantom Unit Plan”) to provide key employees incentives to achieve improvements in TEPPCO’s financial performance. Generally, upon the close of a three-year performance period, if the participant is then still an employee of EPCO, the participant will receive a cash payment in an amount equal to (1) the grantee’s vested percentage multiplied by (2) the number of phantom units granted under the award multiplied by (3) the average of the closing prices of a TEPPCO Unit over the ten consecutive trading days immediately preceding the last day of the performance period. Generally, a participant’s vested percentage is based upon the improvement of TEPPCO’s EBITDA (as defined below) during a three-year performance period over the target EBITDA as defined at the beginning of each year during the three-year performance period. EBITDA means TEPPCO’s earnings before minority interest, net interest expense, other income – net, income taxes, depreciation and amortization and its proportional interest in EBITDA of its joint ventures as presented in its consolidated financial statements prepared in accordance with generally accepted accounting principles, except that at his discretion, our CEO may exclude gains or losses from extraordinary, unusual or non-recurring items. At December 31, 2006, phantom units outstanding for awards granted for the years ended December 31, 2006 and 2005, were 44,200 and 44,000, respectively. At December 31, 2005, phantom units outstanding for awards granted for the plan year ended December 31, 2005, were 53,600.

          In addition to the payment described above, during the performance period, we will pay to the participant the amount of cash distributions that TEPPCO would have paid to its unitholders had the participant been the owner of the number of Units equal to the number of phantom units granted to the participant under this award. We accrue compensation expense annually based upon the terms of the 2005 Phantom Unit Plan discussed above. At December 31, 2006 and 2005, we had an accrued liability balance of $1.6 million and $0.7 million, respectively, for compensation related to the 2005 Phantom Unit Plan.

EPCO, Inc. 2006 TPP Long-Term Incentive Plan

          At a special meeting of its unitholders on December 8, 2006, TEPPCO’s unitholders approved the EPCO, Inc. 2006 TPP Long-Term Incentive Plan (“2006 LTIP”), which provides for awards of TEPPCO’s Units and other

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

rights to our non-employee directors and to employees of EPCO and its affiliates providing services to us. Awards under the 2006 LTIP may be granted in the form of restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The exercise price of unit options or unit appreciation rights awarded to participants will be determined by the Audit and Conflicts Committee of our board of directors (“AC Committee”) (at its discretion) at the date of grant and may be no less than the fair market value of the option award as of the date of grant. The 2006 LTIP will be administered by the AC Committee. Subject to adjustment as provided in the 2006 LTIP, awards with respect to up to an aggregate of 5,000,000 units may be granted under the 2006 LTIP. As of December 31, 2006, no awards had been granted under the 2006 LTIP. We will reimburse EPCO for the costs allocable to any future Incentive Plan awards made to employees who work in our business.

          The 2006 LTIP may be amended or terminated at any time by the board of directors of EPCO or the AC Committee; however, any material amendment, such as a material increase in the number of Units available under the plan or a change in the types of awards available under the plan, would require the approval of at least 50% of TEPPCO’s unitholders. The AC Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in awards under the 2006 LTIP in specified circumstances. The 2006 LTIP is effective until December 8, 2016 or, if earlier, the time which all available Units under the 2006 LTIP have been delivered to participants or the time of termination of the 2006 LTIP by EPCO or the AC Committee.

EPCO, Inc. TPP Employee Unit Purchase Plan

          At a special meeting of its unitholders on December 8, 2006, TEPPCO’s unitholders approved the EPCO, Inc. TPP Employee Unit Purchase Plan (the “Unit Purchase Plan”), which provides for discounted purchases of TEPPCO’s Units by employees of EPCO and its affiliates. Generally, any employee who (1) has been employed by EPCO or any of its designated affiliates for three consecutive months, (2) is a regular, active and full time employee and (3) is scheduled to work at least 30 hours per week is eligible to participate in the Unit Purchase Plan, provided that employees covered by collective bargaining agreements (unless otherwise specified therein) and 5% owners of us, EPCO or any affiliate are not eligible to participate.

          A maximum of 1,000,000 Units may be delivered under the Unit Purchase Plan (subject to adjustment as provided in the plan). Units to be delivered under the plan may be acquired by the custodian of the plan in the open market or directly from TEPPCO, EPCO, any of EPCO’s affiliates or any other person; however, it is generally intended that Units are to be acquired from TEPPCO. Eligible employees may elect to have a designated whole percentage (ranging from 1% to 10%) of their eligible compensation for each pay period withheld for the purchase of Units under the plan. EPCO and its affiliated employers will periodically remit to the custodian the withheld amounts, together with an additional amount by which EPCO will bear approximately 10% of the cost of the Units for the benefit of the participants. Unit purchases will be made following three month purchase periods over which the withheld amounts are to be accumulated. We will reimburse EPCO for all such costs allocated to employees who work in our business.

          The plan will be administered by a committee appointed by the Chairman or Vice Chairman of EPCO. The Unit Purchase Plan may be amended or terminated at any time by the board of directors of EPCO, or the Chairman of the Board or Vice Chairman of the Board of EPCO; however, any material amendment, such as a material increase in the number of Units available under the plan or an increase in the employee discount amount, would also require the approval of at least 50% of TEPPCO’s unitholders. The Unit Purchase Plan is effective until December 8, 2016, or, if earlier, at the time that all available Units under the plan have been purchased on behalf of the participants or the time of termination of the plan by EPCO or the Chairman or Vice Chairman of EPCO. As of December 31, 2006, no purchase period has begun and no Units had been purchased under this plan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 5. EMPLOYEE BENEFIT PLANS

Retirement Plans

          The TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) was a non-contributory, trustee-administered pension plan. In addition, the TEPPCO Supplemental Benefit Plan (“TEPPCO SBP”) was a non-contributory, nonqualified, defined benefit retirement plan, in which certain executive officers participated. The TEPPCO SBP was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans. The benefit formula for all eligible employees was a cash balance formula. Under a cash balance formula, a plan participant accumulated a retirement benefit based upon pay credits and current interest credits. The pay credits were based on a participant’s salary, age and service. We used a December 31 measurement date for these plans.

          On May 27, 2005, the TEPPCO RCBP and the TEPPCO SBP were amended. Effective May 31, 2005, participation in the TEPPCO RCBP was frozen, and no new participants were eligible to be covered by the plan after that date. Effective June 1, 2005, EPCO adopted the TEPPCO RCBP and the TEPPCO SBP for the benefit of its employees providing services to us. Effective December 31, 2005, all plan benefits accrued were frozen, participants received no additional pay credits after that date, and all plan participants were 100% vested regardless of their years of service. The TEPPCO RCBP plan was terminated effective December 31, 2005, and plan participants had the option to receive their benefits either through a lump sum payment in 2006 or through an annuity. In April 2006, we received a determination letter from the Internal Revenue Service (“IRS”) providing IRS approval of the plan termination. For those plan participants who elected to receive an annuity, we will purchase an annuity contract from an insurance company in which the plan participant owns the annuity, absolving us of any future obligation to the participant. Participants in the TEPPCO SBP received pay credits through November 30, 2005, and received lump sum benefit payments in December 2005. Both the TEPPCO RCBP and TEPPCO SBP benefit payments are discussed below.

          In June 2005, we recorded a curtailment charge of $0.1 million in accordance with SFAS No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, as a result of the TEPPCO RCBP and TEPPCO SBP amendments. As of May 31, 2005, the following assumptions were changed for purposes of determining the net periodic benefit costs for the remainder of 2005: the discount rate, the long-term rate of return on plan assets, and the assumed mortality table. The discount rate was decreased from 5.75% to 5.00% to reflect rates of returns on bonds currently available to settle the liability. The expected long-term rate of return on plan assets was changed from 8% to 2% due to the movement of plan funds from equity investments into short-term money market funds. The mortality table was changed to reflect overall improvements in mortality experienced by the general population. The curtailment charge arose due to the accelerated recognition of the unrecognized prior service costs. We recorded additional settlement charges of approximately $0.2 million in the fourth quarter of 2005 relating to the TEPPCO SBP. We recorded additional settlement charges of approximately $3.5 million during the fourth quarter of 2006 relating to the TEPPCO RCBP for any existing unrecognized losses upon the plan termination and final distribution of the assets to the plan participants. At December 31, 2006, $1.3 million of the TEPPCO RCBP plan assets had not been distributed to plan participants.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

          The components of net pension benefits costs for the TEPPCO RCBP and the TEPPCO SBP for the years ended December 31, 2006, 2005 and 2004, were as follows:

		For Year Ended December 31,
		2006				2005				2004
Service cost benefit earned during the year		$	—			$	4,393			$	3,653
Interest cost on projected benefit obligation			891				934				719
Expected return on plan assets			(412	)			(671	)			(878	)
Amortization of prior service cost			—				5				7
Recognized net actuarial loss			135				129				57
SFAS 88 curtailment charge			—				50				—
SFAS 88 settlement charge			3,545				194				—
Net pension benefits costs		$	4,159			$	5,034			$	3,558

Other Postretirement Benefits

          We provided certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis (“TEPPCO OPB”). Employees became eligible for these benefits if they met certain age and service requirements at retirement, as defined in the plans. We provided a fixed dollar contribution, which did not increase from year to year, towards retired employee medical costs. The retiree paid all health care cost increases due to medical inflation. We used a December 31 measurement date for this plan.

          In May 2005, benefits provided to employees under the TEPPCO OPB were changed. Employees eligible for these benefits received them through December 31, 2005, however, effective December 31, 2005, these benefits were terminated. As a result of this change in benefits and in accordance with SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, we recorded a curtailment credit of approximately $1.7 million in our accumulated postretirement obligation which reduced our accumulated postretirement obligation to the total of the expected remaining 2005 payments under the TEPPCO OPB. The employees participating in this plan at that time were transferred to DEFS, who is expected to provide postretirement benefits to these retirees. We recorded a one-time settlement to DEFS in the third quarter of 2005 of $0.4 million for the remaining postretirement benefits.

          The components of net postretirement benefits cost for the TEPPCO OPB for the years ended December 31, 2006, 2005 and 2004, were as follows:

		For Year Ended December 31,
		2006				2005				2004
Service cost benefit earned during the year		$	—			$	81			$	165
Interest cost on accumulated postretirement benefit obligation			—				69				153
Amortization of prior service cost			—				53				126
Recognized net actuarial loss			—				4				1
Curtailment credit			—				(1,676	)			—
Settlement credit			—				(4	)			—
Net postretirement benefits costs		$	—			$	(1,473	)		$	445

          Effective June 1, 2005, the payroll functions performed by DEFS for us were transferred from DEFS to EPCO. For those employees who were receiving certain other postretirement benefits at the time of our acquisition by DFI, DEFS is expected to continue to provide these benefits to those employees. Effective June 1, 2005, EPCO began providing certain other postretirement benefits to those employees who became eligible for the benefits after June 1, 2005, and will charge those benefit related costs to us. As a result of these changes, we recorded a $1.2 million reduction in our other postretirement obligation in June 2005.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

          We employed a building block approach in determining the long-term rate of return for plan assets. Historical markets were studied and long-term historical relationships between equities and fixed-income were preserved consistent with a widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates were evaluated before long-term capital market assumptions were determined. The long-term portfolio return was established via a building block approach with proper consideration of diversification and rebalancing. Peer data and historical returns were reviewed to check for reasonability and appropriateness.

          The weighted average assumptions used to determine benefit obligations for the retirement plans and other postretirement benefit plans at December 31, 2006 and 2005, were as follows:

										Other Postretirement
		Pension Benefits								Benefits
		2006				2005				2006				2005
Discount rate			4.73	%			4.59	%			—				5.75	%
Increase in compensation levels			—				—				—				—

          The weighted average assumptions used to determine net periodic benefit cost for the retirement plans and other postretirement benefit plans for the years ended December 31, 2006 and 2005, were as follows:

										Other Postretirement
		Pension Benefits								Benefits
		2006				2005				2006				2005
Discount rate (1)			4.59	%			5.75%/5.00	%			—				5.75%/5.00	%
Increase in compensation levels			—				5.00	%			—				—
Expected long-term rate of return on plan assets (2)			2.00	%			8.00%/2.00	%			—				—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

          The following table sets forth our pension and other postretirement benefits changes in benefit obligation, fair value of plan assets and funded status as of December 31, 2006 and 2005:

										Other Postretirement
		Pension Benefits								Benefits
		2006				2005				2006				2005
Change in benefit obligation
Benefit obligation at beginning of year		$	22,111			$	15,940			$	—			$	2,964
Service cost			—				4,393				—				81
Interest cost			891				934				—				70
Actuarial loss			152				2,740				—				76
Retiree contributions			—				—				—				64
Benefits paid			(22,677	)			(910	)			—				(80	)
Impact of curtailment			—				(986	)			—				(3,575	)
Settlement			—				—				—				400
Benefit obligation at end of year		$	477			$	22,111			$	—			$	—
Change in plan assets
Fair value of plan assets at beginning of year		$	23,104			$	14,969			$	—			$	—
Actual return on plan assets			884				20				—				—
Retiree contributions			—				—				—				64
Employer contributions			—				9,025				—				16
Benefits paid			(22,677	)			(910	)			—				(80	)
Fair value of plan assets at end of year		$	1,311			$	23,104			$	—			$	—
Funded status		$	834			$	993			$	—			$	—
Amount Recognized in the Balance Sheet:
Noncurrent assets		$	834			$	—			$	—			$	—
Net pension asset at end of year		$	834			$	—			$	—			$	—
Amount Recognized in Accumulated Other Comprehensive Income:
Unrecognized actuarial loss (1)		$	67			$	—			$	—			$	—

          The following table illustrates the incremental effect of applying SFAS No. 158 on individual line items in the consolidated balance sheet as of December 31, 2006:

		December 31, 2006
		Before								After
		Application of								Application of
		SFAS No. 158				Adjustments				SFAS No. 158
Prepaid pension cost (included in other current assets)		$	901			$	(901	)		$	—
Other assets			71,827				834				72,661
Total assets			3,922,208				(67	)			3,922,141
Accumulated other comprehensive income			493				(67	)			426
Total member’s equity (deficit)			(85,537	)			(67	)			(85,604	)
Total liabilities and member’s equity (deficit)			3,922,208				(67	)			3,922,141

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

          We estimate the following benefit payments, which reflect expected future service, as appropriate, will be paid:

						Other
		Pension				Postretirement
		Benefits				Benefits
2007		$	477			$	—

Plan Assets

          At December 31, 2006 and 2005, all plan assets for the retirement plans and other postretirement benefit plans were invested in money market securities. We do not expect to make further contributions to our retirement plans and other postretirement benefit plans in 2007.

Other Plans

          DEFS also sponsored an employee savings plan, which covered substantially all employees. Effective February 24, 2005, in conjunction with the change in our ownership, our participation in this plan ended. Plan contributions on our behalf of $0.9 million and $3.5 million were recognized for the period January 1, 2005 through February 23, 2005, and during the year ended December 31, 2004, respectively.

          EPCO maintains a 401(k) plan for the benefit of employees providing services to us, and we will continue to reimburse EPCO for the cost of maintaining this plan in accordance with the ASA.

NOTE 6. FINANCIAL INSTRUMENTS — INTEREST RATE SWAPS

          In July 2000, TEPPCO entered into an interest rate swap agreement to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving credit facility. This interest rate swap matured in April 2004. We designated this swap agreement, which hedged exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement was based on a notional amount of $250.0 million. Under the swap agreement, TEPPCO paid a fixed rate of interest of 6.955% and received a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this swap was designated as a cash flow hedge, the changes in fair value, to the extent the swap was effective, were recognized in other comprehensive income until the hedged interest costs were recognized in earnings. During the year ended December 31, 2004, we recognized an increase in interest expense of $2.9 million related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.

          In October 2001, TE Products entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating rate of interest based on a three-month U.S. Dollar LIBOR rate, plus a spread of 147 basis points, and receives a fixed rate of interest of 7.51%. During the years ended December 31, 2006, 2005 and 2004, we recognized reductions in interest expense of $1.9 million, $5.6 million and $9.6 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the years ended December 31, 2006, 2005 and 2004, we reviewed the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair values of this interest rate swap were liabilities of approximately $2.6 million and $0.9 million at December 31, 2006 and 2005, respectively.

          During 2002, TEPPCO entered into interest rate swap agreements, designated as fair value hedges, to hedge its exposure to changes in the fair value of TEPPCO’s fixed rate 7.625% Senior Notes due 2012. The swap

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, TEPPCO paid a floating rate of interest based on a U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. These swap agreements were later terminated in 2002 resulting in gains of $44.9 million. The gains realized from the swap terminations have been deferred as adjustments to the carrying value of the Senior Notes and are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the Senior Notes. At December 31, 2006 and 2005, the unamortized balance of the deferred gains was $28.0 million and $32.4 million, respectively. In the event of early extinguishment of the Senior Notes, any remaining unamortized gains would be recognized in the statement of consolidated income at the time of extinguishment.

          During May 2005, TEPPCO executed a treasury rate lock agreement for a notional amount of $200.0 million to hedge its exposure to increases in the treasury rate that was to be used to establish the fixed interest rate for a debt offering that was proposed to occur in the second quarter of 2005. During June 2005, the proposed debt offering was cancelled, and the treasury lock was terminated with a realized loss of $2.0 million. The realized loss was recorded as a component of interest expense in the statements of consolidated income in June 2005.

          On January 20, 2006, TEPPCO entered into interest rate swap agreements with a total notional amount of $200.0 million to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving credit facility. These interest rate swaps mature in January 2008. Under the swap agreements, TEPPCO pays a fixed rate of interest ranging from 4.67% to 4.695% and receive a floating rate based on a three-month U.S. Dollar LIBOR rate. In the third quarter of 2006, these swaps were designated as cash flow hedges. For the period from January 20, 2006 through the date these swaps were designated as cash flow hedges, changes in the fair value of the swaps were recognized in earnings, which resulted in a $2.2 million reduction to interest expense. While these interest rate swaps remain in effect, future changes in the fair value of the cash flow hedges, to the extent the swaps are effective, will be recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At December 31, 2006, the fair value of these interest rate swaps was $1.1 million.

          During October 2006, TEPPCO executed a series of treasury rate lock agreements that extend through June 2007 for a notional amount totaling $200.0 million. These agreements, which are derivative instruments, have been designated as cash flow hedges to offset TEPPCO’s exposure to increases in the underlying U.S. Treasury benchmark rate that is expected to be used to establish the fixed interest rate for debt that it expects to incur in 2007. The weighted average rate under the treasury lock agreements was approximately 4.7%. The actual coupon rate of the expected debt issuance will be comprised of the underlying U.S. Treasury benchmark rate, plus a credit spread premium for its debt security. At December 31, 2006, the fair value of these treasury locks was less than $0.1 million. To the extent effective, gains and losses on the value of the treasury locks will be deferred until the forecasted debt is issued and will be amortized to earnings over the life of the debt. No ineffectiveness was required to be recorded as of December 31, 2006.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 7. INVENTORIES

          Inventories are valued at the lower of cost (based on weighted average cost method) or market. The costs of inventories did not exceed market values at December 31, 2006 and 2005. The major components of inventories were as follows:

		December 31,
		2006				2005
Crude oil (1)		$	49,312			$	3,021
Refined products and LPGs (2) (3)			7,636				11,864
Lubrication oils and specialty chemicals			7,500				5,740
Materials and supplies			7,029				8,203
Other			716				241
Total		$	72,193			$	29,069

NOTE 8. PROPERTY, PLANT AND EQUIPMENT

          Major categories of property, plant and equipment at December 31, 2006 and 2005, were as follows:

		December 31,
		2006				2005
Land and right of way		$	128,791			$	147,064
Line pipe and fittings			1,218,226				1,434,392
Storage tanks			196,306				189,054
Buildings and improvements			58,973				51,596
Machinery and equipment			346,868				370,439
Construction work in progress			202,820				241,855
Total property, plant and equipment		$	2,151,984			$	2,434,400
Less accumulated depreciation and amortization			509,889				474,332
Net property, plant and equipment		$	1,642,095			$	1,960,068

          Depreciation expense, including impairment charges, on property, plant and equipment was $78.9 million, $80.8 million and $80.7 million for the years ended December 31, 2006, 2005 and 2004, respectively. During the fourth quarter of 2004, we wrote off approximately $2.1 million in assets taken out of service to depreciation expense.

          In September 2005, our Todhunter facility, near Middletown, Ohio, experienced a propane release and fire at a dehydration unit within the storage facility. The facility is included in our Downstream Segment. The dehydration unit was destroyed due to the propane release and fire, and as a result, we wrote off the remaining book value of the asset of $0.8 million to depreciation and amortization expense during the third quarter of 2005.

          We evaluate impairment of long-lived assets in accordance with SFAS No. 144. During the third quarter of 2005, our Upstream Segment was notified by a connecting carrier that the flow of its pipeline system would be

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

reversed, which would directly impact the viability of one of our pipeline systems. This system, located in East Texas, consists of approximately 45 miles of pipeline, six tanks of various sizes and other equipment and asset costs. As a result of changes to the connecting carrier, we performed an impairment test of the system and recorded a $1.8 million non-cash impairment charge, included in depreciation and amortization expense in our statements of consolidated income, for the excess carrying value over the estimated discounted cash flows of the system.

          During the third quarter of 2005, we completed an evaluation of a crude oil system included in our Upstream Segment. The system, located in Oklahoma, consists of approximately six miles of pipelines, tanks and other equipment and asset costs. The usage of the system has declined in recent months as a result of shifting crude oil production into areas not supported by the system, and as such, it has become more economical to transport barrels by truck to our other pipeline systems. As a result, we performed an impairment test on the system and recorded a $0.8 million non-cash impairment charge, included in depreciation and amortization expense in our statements of consolidated income, for the excess carrying value over the estimated discounted cash flows of the system.

          During the third quarter of 2004, we completed an evaluation of our marine terminal facility in the Beaumont, Texas, area. The facility consists primarily of a barge dock, a ship dock, four storage tanks and various segments of connecting pipelines and is included in our Downstream Segment. The evaluation indicated that the docks and other assets at the facility needed extensive work to continue to be commercially operational. As a result, we performed an impairment test on the entire marine facility and recorded a $4.4 million non-cash impairment charge, included in depreciation and amortization expense in our statements of consolidated income, for the excess carrying value over the estimated discounted cash flows of the facility.

Asset Retirement Obligations

          During 2006, we recorded $0.6 million of expense, included in depreciation and amortization expense, related to conditional AROs related to the retirement of the Val Verde natural gas gathering system and to structural restoration work to be completed on leased office space that is required upon our anticipated office lease termination. Additionally, we have recorded a $1.2 million liability, which represents the present values of these conditional AROs. During 2006, we assigned probabilities for settlement dates and settlement methods for use in an expected present value measurement and recorded conditional AROs.

          The following table presents information regarding our asset retirement obligations:

Asset retirement obligation liability balance, December 31, 2005		$	—
Liabilities recorded			1,189
Liabilities settled			—
Accretion			39
Revision in estimates			—
Asset retirement obligation liability balance, December 31, 2006		$	1,228

          Property, plant and equipment at December 31, 2006, includes $0.5 million of asset retirement costs capitalized as an increase in the associated long-lived asset. Additionally, based on information currently available, we estimate that accretion expense will approximate $0.1 million for 2007, $0.1 million for 2008, $0.1 million for 2009, $0.2 million for 2010 and $0.2 million for 2011.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 9. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

Seaway

          Through one of our indirect wholly owned subsidiaries, we own a 50% ownership interest in Seaway. The remaining 50% interest is owned by ConocoPhillips. We operate the Seaway assets. Seaway owns a pipeline that carries mostly imported crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal at Texas City, Texas, to refineries in the Texas City and Houston, Texas, areas. The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of Seaway. From June 2002 through December 31, 2005, we received 60% of revenue and expense of Seaway. The sharing ratio changed from 60% to 40% on May 12, 2006, and as such, or share of revenue and expense of Seaway was 47% for 2006. Thereafter, we receive 40% of revenue and expense of Seaway. During the years ended December 31, 2006, 2005 and 2004, we received distributions from Seaway of $20.5 million, $24.7 million and $36.9 million, respectively. During the years ended December 31, 2006, 2005 and 2004, we did not invest any funds in Seaway.

Centennial

          In August 2000, TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”), a former subsidiary of CMS Energy Corporation, and Marathon Petroleum Company LLC (“Marathon”) to form Centennial. Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois. Through February 9, 2003, each participant owned a one-third interest in Centennial. On February 10, 2003, TE Products and Marathon each acquired an additional 16.7% interest in Centennial from PEPL for $20.0 million each, increasing their ownership percentages in Centennial to 50% each. During the years ended December 31, 2006, 2005 and 2004, TE Products contributed $2.5 million, $0 and $1.5 million, respectively, to Centennial. TE Products has received no cash distributions from Centennial since its formation.

MB Storage

          On January 1, 2003, TE Products and Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”) formed Mont Belvieu Storage Partners, L.P. (“MB Storage”). TE Products and Louis Dreyfus each owned a 50% ownership interest in MB Storage. MB Storage owns storage capacity at the Mont Belvieu fractionation and storage complex and a short haul transportation shuttle system that ties Mont Belvieu, Texas, to the upper Texas Gulf Coast energy marketplace. MB Storage is a service-oriented, fee-based venture serving the fractionation, refining and petrochemical industries with substantial capacity and flexibility for the transportation, terminaling and storage of NGLs, LPGs and refined products. TE Products operated the facilities for MB Storage. Pursuant to a Federal Trade Commission (“FTC”) order and consent agreement, we sold our interest in MB Storage and certain related pipelines on March 1, 2007 (see Note 21). Effective January 1, 2003, TE Products contributed property and equipment with a net book value of $67.1 million to MB Storage. Additionally, as of the contribution date, Louis Dreyfus had invested $6.1 million for expansion projects for MB Storage that TE Products was required to reimburse if the original joint development and marketing agreement was terminated by either party. This deferred liability was also contributed and credited to the capital account of Louis Dreyfus in MB Storage.

          For the years ended December 31, 2006 and 2005, TE Products received the first $1.7 million per quarter (or $6.78 million on an annual basis) of MB Storage’s income before depreciation expense, as defined in the Agreement of Limited Partnership of MB Storage. For the year ended December 31, 2004, TE Products received the first $1.8 million per quarter (or $7.15 million on an annual basis) of MB Storage’s income before depreciation expense. TE Products’ share of MB Storage’s earnings is adjusted annually by the partners of MB Storage. Any amount of MB Storage’s annual income before depreciation expense in excess of $6.78 million for 2006 and 2005 and $7.15 million for 2004 was allocated evenly between TE Products and Louis Dreyfus. Depreciation expense on assets each party originally contributed to MB Storage is allocated between TE Products and Louis Dreyfus based

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

on the net book value of the assets contributed. Depreciation expense on assets constructed or acquired by MB Storage subsequent to formation is allocated evenly between TE Products and Louis Dreyfus. For the years ended December 31, 2006, 2005 and 2004, TE Products’ sharing ratios in the earnings of MB Storage was 59.4%, 64.2% and 69.4%, respectively. During the years ended December 31, 2006, 2005 and 2004, TE Products received distributions of $12.9 million, $12.4 million and $10.3 million, respectively, from MB Storage. During the years ended December 31, 2006, 2005 and 2004, TE Products contributed $4.8 million, $5.6 million and $21.4 million, respectively, to MB Storage. The 2005 contribution includes a combination of non-cash asset transfers of $1.4 million and cash contributions of $4.2 million. The 2004 contribution includes $16.5 million for the acquisition of storage and pipeline assets in April 2004. The remaining contributions have been for capital expenditures.

Summarized Financial Information for Seaway, Centennial and MB Storage

          We use the equity method of accounting to account for our investments in Seaway, Centennial and MB Storage. Summarized combined financial information for Seaway, Centennial and MB Storage for the years ended December 31, 2006 and 2005, is presented below:

		For Year Ended
		December 31,
		2006				2005
Revenues		$	160,408			$	164,494
Net income			34,070				52,623

          Summarized combined balance sheet information for Seaway, Centennial and MB Storage as of December 31, 2006 and 2005, is presented below:

		December 31,
		2006				2005
Current assets		$	58,241			$	60,082
Noncurrent assets			615,790				630,212
Current liabilities			37,663				32,242
Long-term debt			150,000				150,000
Noncurrent liabilities			6,055				13,626
Partners’ capital			480,313				494,426

Jonah

          On August 1, 2006, Enterprise, through its affiliate, Enterprise Gas Processing, LLC, became our joint venture partner by acquiring an interest in Jonah, the partnership through which we own an interest in the Jonah system. Prior to entering into the Jonah joint venture, Enterprise had managed the construction of the Phase V expansion and funded the initial costs under a letter of intent we entered into in February 2006. In connection with the joint venture arrangement, we and Enterprise plan to continue the Phase V expansion, which is expected to increase the system capacity of the Jonah system from 1.5 billion cubic feet (“Bcf”) per day to approximately 2.3 Bcf per day and to significantly reduce system operating pressures, which is anticipated to lead to increased production rates and ultimate reserve recoveries. The first portion of the expansion, which is expected to increase the system gathering capacity to approximately 2.0 Bcf per day, is scheduled to be completed in the second quarter of 2007. The second portion of the expansion is expected to be completed by the end of 2007. The anticipated cost of the Phase V expansion is expected to be approximately $444.0 million. We expect to reimburse Enterprise for approximately 50% of these costs. To the extent the costs exceed an agreed upon base cost estimate of $415.2 million, we and Enterprise will each pay our respective ownership share (approximately 80% and 20%, respectively) of the expansion costs to that exceed the agreed upon base cost estimate.

          Enterprise will continue to manage the Phase V construction project. We are entitled to all distributions from the joint venture until specified milestones are achieved, at which point Enterprise will be entitled to receive

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

approximately 50% of the incremental cash flow from portions of the system placed in service as part of the expansion. From August 1, 2006, we and Enterprise equally share the costs of the Phase V expansion. We have reimbursed Enterprise $109.4 million for 50% of the Phase V cost incurred by it (including its cost of capital of $1.3 million). At December 31, 2006, we had a payable to Enterprise for costs incurred through December 31, 2006, of $8.7 million. After subsequent milestones are achieved, we and Enterprise will share distributions based on a formula that takes into account the capital contributions of the parties, including expenditures by us prior to the expansion. Based on this formula in the partnership agreement, we expect to own an interest in Jonah of approximately 80%, with Enterprise owning the remaining 20% and serving as operator, with further costs being allocated based on such ownership interests. For the year ended December 31, 2006, our sharing ratio in the earnings of Jonah was 99.7%. During the year ended December 31, 2006, Jonah declared a distribution to us of $41.6 million, of which $30.0 was paid in cash and the remainder is reflected as a receivable from Jonah. During the year ended December 31, 2006, we contributed $121.0 million to Jonah. The joint venture is governed by a management committee comprised of two representatives approved by Enterprise and two representatives approved by us, each with equal voting power. This transaction was reviewed and recommended for approval by our AC Committee.

          Effective August 1, 2006, with the formation of the joint venture, Jonah was deconsolidated, and we began using the equity method of accounting to account for our investment in Jonah. Under the equity method, we record the costs of our investment within the “Equity Investments” line on our consolidated balance sheet, and as changes in the net assets of Jonah occur (for example, earnings, contributions and distributions), we will recognize our proportional share of that change in the ”Equity Investments” account.

          Summarized financial information for Jonah for the period August 1, 2006 through December 31, 2006, is presented below:

Revenues		$	79,618
Net income			34,743

          Summarized balance sheet information for Jonah as of December 31, 2006, is presented below:

Current assets		$	33,963
Noncurrent assets			800,591
Current liabilities			25,113
Noncurrent liabilities			191
Partners’ capital			809,250

NOTE 10. ACQUISITIONS

Mexia Pipeline

          On March 31, 2005, we purchased crude oil pipeline assets for $7.1 million from BP Pipelines (North America) Inc. (“BP”). The assets include approximately 158 miles of pipeline, which extend from Mexia, Texas, to the Houston, Texas, area and two stations in south Houston with connections to a BP pipeline that originates in south Houston. We funded the purchase through borrowings under TEPPCO’s revolving credit facility, and we allocated the purchase price to property, plant and equipment. We have integrated these assets into our South Texas pipeline system, which is included in our Upstream Segment.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Storage and Terminaling Assets

          On April 1, 2005, we purchased crude oil storage and terminaling assets in Cushing, Oklahoma, from Koch Supply & Trading, L.P. for $35.4 million. The assets consist of eight storage tanks with 945,000 barrels of storage capacity, receipt and delivery manifolds, interconnections to several pipelines, crude oil inventory and approximately 70 acres of land. We funded the purchase through borrowings under TEPPCO’s revolving credit facility, and we allocated the purchase price to property, plant and equipment and inventory.

Refined Products Terminal and Truck Rack

          On July 12, 2005, we purchased a refined products terminal and truck loading rack in North Little Rock, Arkansas, for $6.9 million from ExxonMobil Corporation. The assets include three storage tanks and a two-bay truck loading rack. We funded the purchase through borrowings under TEPPCO’s revolving credit facility, and we allocated the purchase price to property, plant and equipment and inventory. The terminal serves the central Arkansas refined products market and complements our existing Downstream Segment infrastructure in North Little Rock, Arkansas.

Genco Assets

          On July 15, 2005, we acquired from Texas Genco LLC (“Genco”) all of its interests in certain companies that own a 90-mile pipeline system and 5.5 million barrels of storage capacity for $62.1 million. We funded the purchase through borrowings under TEPPCO’s revolving credit facility, and we allocated the purchase price to property, plant and equipment. This acquisition was made as part of an expansion of our refined products origin capabilities in the Houston, Texas, and Texas City, Texas, areas. The assets of the purchased companies are being integrated into our Downstream Segment origin infrastructure in Texas City and Baytown, Texas. The integration and other system enhancements should be in service by the first quarter of 2007, at an estimated cost of $45.0 million. On October 6, 2006, we sold certain of these assets to an affiliate of Enterprise (see Note 11).

Terminal Assets

          On July 14, 2006, we purchased assets from New York LP Gas Storage, Inc. for $10.0 million. The assets consist of two active caverns, one active brine pond, a four bay truck rack, seven above ground storage tanks, and a twelve-spot railcar rack located east of our Watkins Glen, New York facility. We funded the purchase through borrowings under TEPPCO’s revolving credit facility, and we allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and inventory.

Refined Products Terminal

          Effective November 1, 2006, we purchased a refined petroleum product terminal in Aberdeen, Mississippi, for approximately $5.8 million from Mississippi Terminal and Marketing Inc. (“MTMI”). We funded the purchase through borrowings under TEPPCO’s revolving credit facility, and we allocated the purchase price primarily to property, plant and equipment, goodwill and intangible assets. We recorded $1.3 million of goodwill in this acquisition. The facility, located along the Tennessee-Tombigbee Waterway system, has storage capacity of 130,000 barrels for gasoline and diesel, which are supplied by barge for delivery to local markets, including Tupelo and Columbus, Mississippi. In connection with this acquisition, which we plan to integrate into our Downstream Segment, we plan to construct a new 500,000-barrel terminal in Boligee, Alabama, at a cost of approximately $20.0 million, on an 80-acre site which we are leasing from the Greene County Industrial Development Board under a 60-year agreement. The Boligee terminal site is located approximately two miles from Colonial Pipeline. The new terminal is expected to begin service during the fourth quarter of 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cavern Assets

          On December 26, 2006, we purchased assets from Vectren Utility Holdings, Inc. for $4.8 million. The assets consist of one active 170,000 barrel LPG storage cavern, the associated piping and related equipment. These assets are located adjacent to our Todhunter facility near Middleton, Ohio and tie into our existing LPG pipeline. We funded the purchase through borrowings under TEPPCO’s revolving credit facility, and we allocated the purchase price primarily to property, plant and equipment.

NOTE 11. DISPOSITIONS AND DISCONTINUED OPERATIONS

Pioneer Plant

          On March 31, 2006, we sold our ownership interest in the Pioneer silica gel natural gas processing plant located near Opal, Wyoming, together with Jonah’s rights to process natural gas originating from the Jonah and Pinedale fields, located in southwest Wyoming, to an affiliate of Enterprise for $38.0 million in cash. The Pioneer plant was not an integral part of our Midstream Segment operations, and natural gas processing is not a core business for us. We have no continuing involvement in the operations or results of this plant. This transaction was reviewed and recommended for approval by our AC Committee and a fairness opinion was rendered by an investment banking firm. The sales proceeds were used to fund organic growth projects, retire debt and for other general partnership purposes. The carrying value of the Pioneer plant at March 31, 2006, prior to the sale, was $19.7 million. Costs associated with the completion of the transaction were approximately $0.4 million.

          Condensed statements of income for the Pioneer plant, which is classified as discontinued operations, for the years ended December 31, 2006, 2005 and 2004, are presented below:

		For Year Ended
		December 31,
		2006				2005				2004
Operating revenues:
Sales of petroleum products		$	3,828			$	10,479			$	7,295
Other			932				2,975				2,807
Total operating revenues			4,760				13,454				10,102
Costs and expenses:
Purchases of petroleum products			3,000				8,870				5,944
Operating expense			182				692				738
Depreciation and amortization			51				612				610
Taxes — other than income taxes			30				130				121
Total costs and expenses			3,263				10,304				7,413
Income from discontinued operations		$	1,497			$	3,150			$	2,689

          Assets of the discontinued operations consisted of the following at December 31, 2005:

		December 31,
		2005
Inventories		$	7
Property, plant and equipment, net			19,812
Assets of discontinued operations		$	19,819

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

          Net cash flows from discontinued operations for the years ended December 31, 2006, 2005 and 2004, are presented below:

		For Year Ended
		December 31,
		2006				2005				2004
Cash flows from discontinued operating activities:
Net income		$	19,369			$	3,150			$	2,689
Depreciation and amortization			51				612				610
Gain on sale of Pioneer plant			(17,872	)			—				—
(Increase) decrease in inventories			(27	)			20				(28	)
Net cash flows provided by discontinued operating activities			1,521				3,782				3,271
Cash flows from discontinued investing activities:
Capital expenditures			—				—				(7,398	)
Net cash flows used in discontinued investing activities			—				—				(7,398	)
Net cash flows from discontinued operations		$	1,521			$	3,782			$	(4,127	)

Crude oil and Refined Products Assets

          On October 6, 2006, we sold certain crude oil pipeline assets and refined products pipeline assets in the Houston, Texas area, to an affiliate of Enterprise for approximately $11.7 million. These assets, which have been idle since acquisition, were part of the assets acquired by us in 2005 from Genco and BP (see Note 10). The sales proceeds were used to fund organic growth projects, retire debt and for other general partnership purposes. The carrying value of these pipeline assets was approximately $6.0 million. We recognized a gain of $5.7 million on this transaction.

NOTE 12. GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

          Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization. We account for goodwill under SFAS No. 142, Goodwill and Other Intangible Assets, which was issued by the FASB in July 2001. SFAS 142 prohibits amortization of goodwill, but instead requires testing for impairment at least annually. We test goodwill for impairment annually at December 31.

          To perform an impairment test of goodwill, we have identified our reporting units and have determined the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill, to those reporting units. We then determine the fair value of each reporting unit and compare it to the carrying value of the reporting unit. We will continue to compare the fair value of each reporting unit to its carrying value on an annual basis to determine if an impairment loss has occurred. There have been no goodwill impairment losses recorded since the adoption of SFAS 142.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

          The following table presents the carrying amount of goodwill at December 31, 2006 and 2005, by business segment:

		Downstream				Midstream				Upstream				Segments
		Segment				Segment				Segment				Total
Goodwill:
December 31, 2006 (1)		$	1,339			$	—			$	14,167			$	15,506
December 31, 2005			—				2,777				14,167				16,944

Other Intangible Assets

          The following table reflects the components of intangible assets, including excess investments, being amortized at December 31, 2006 and 2005:

		December 31, 2006								December 31, 2005
		Gross Carrying				Accumulated				Gross Carrying				Accumulated
		Amount				Amortization				Amount				Amortization
Intangible assets:
Gathering and transportation agreements (1)		$	241,537			$	(87,121	)		$	464,337			$	(118,921	)
Fractionation agreement			38,000				(16,625	)			38,000				(14,725	)
Other			12,310				(2,691	)			10,226				(2,009	)
Subtotal		$	291,847			$	(106,437	)		$	512,563			$	(135,655	)
Excess investments:
Centennial Pipeline LLC		$	33,390			$	(16,579	)		$	33,390			$	(12,947	)
Seaway Crude Pipeline Company			26,908				(4,450	)			27,100				(3,764	)
Jonah Gas Gathering Company			2,924				—				—				—
Subtotal		$	63,222			$	(21,029	)		$	60,490			$	(16,711	)
Total intangible assets		$	355,069			$	(127,466	)		$	573,053			$	(152,366	)