Enterprise GP 8K/A Completion of Acquisition or Disposition of Assets | SEC 18 Jul 07

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


(1)		Represents the Parent Company’s equity method investment in TEPPCO. This Parent Company investment is eliminated in the process of consolidating the financial statements of the Parent Company with those of TEPPCO. This balance does not represent an asset to TEPPCO nor does it represent an obligation on the Parent Company’s part to contribute cash or other property to TEPPCO. Our general partner equity account at TEPPCO generally consists of our cumulative share of TEPPCO’s earnings less any cash distributions that it has paid to us plus any amounts we have contributed to TEPPCO. During 2006, we were allocated $57.7 million (representing 28.6%) of TEPPCO’s net income and received $81.9 million in cash distributions from TEPPCO. During 2005, we were allocated $47.6 million (representing 29.3%) of TEPPCO’s net income and received $73.2 million in cash distributions from TEPPCO.

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


(1)		Represents the Parent Company’s earnings from its equity method investment in TEPPCO.

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,

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 Obligationsand 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 Disclosureand 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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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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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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

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.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

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	%		—		—


(1)		Expense was remeasured on May 31, 2005, as a result of TEPPCO RCBP and TEPPCO SBP amendments. The discount rate was decreased from 5.75% to 5% effective June 1, 2005, to reflect rates of returns on bonds currently available to settle the liability.

(2)		As a result of TEPPCO RCBP and TEPPCO SBP amendments, the expected return on assets was changed from 8% to 2% due to the movement of plan funds from equity investments into short-term money market funds, effective June 1, 2005.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

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		$	—		$	—	$	—


(1)		This amount will be amortized out of accumulated other comprehensive income into net periodic benefit cost in 2007.

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

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

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.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

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


(1)		At December 31, 2006, the substantial majority of our crude oil inventory was subject to forward sales contracts.

(2)		Refined products and LPGs inventory is managed on a combined basis.

(3)		At December 31, 2006, we recorded a $1.5 million lower of cost or market adjustment related to our Downstream Segment’s inventory.

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.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

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

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

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

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

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.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

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

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

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


(1)		Effective August 1, 2006, with the formation of a joint venture with Enterprise, Jonah was deconsolidated and has been subsequently accounted for as an equity investment (see Note 9). On November 1, 2006, we acquired a refined products terminal, and recorded $1.3 million of goodwill (see Note 10).

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	)


(1)		Effective August 1, 2006, with the formation of a joint venture with Enterprise, Jonah was deconsolidated and has been subsequently accounted for as an equity investment (see Note 9).

SFAS 142 requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. Amortization expense on intangible assets was $28.8 million, $30.5 million and $32.2 million for the years ended December 31, 2006, 2005 and 2004, respectively. Amortization expense on excess investments included in equity earnings was $4.3 million, $4.8 million and $3.8 million for the years ended December 31, 2006, 2005 and 2004, respectively.

The values assigned to our intangible assets for natural gas gathering contracts on the Val Verde system are amortized on a unit-of-production basis, based upon the actual throughput of the systems compared to the expected total throughput for the lives of the contracts. From time to time, we may obtain limited production forecasts and updated throughput estimates from some of the producers on the system, and as a result, we evaluate the remaining expected useful lives of the contract assets based on the best available information. During the quarter ended September 30, 2006, we received updated limited production estimates from some of the producers on the Val Verde

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

system, which reduced the future production forecast. We revised the units-of-production calculation for Val Verde, which increased amortization expense by approximately $0.2 million per month. Further revisions to these estimates may occur as additional production information is made available to us.

The values assigned to our fractionation agreement and other intangible assets are generally amortized on a straight-line basis. Our fractionation agreement is being amortized over its contract period of 20 years. The amortization periods for our other intangible assets, which include non-compete and other agreements, range from 3 years to 15 years. The value of $8.5 million assigned to our crude supply and transportation intangible customer contracts is being amortized on a unit-of-production basis.

The value assigned to our excess investment in Centennial was created upon its formation. Approximately $30.0 million is related to a contract and is being amortized on a unit-of-production basis based upon the volumes transported under the contract compared to the guaranteed total throughput of the contract over a 10-year life. The remaining $3.4 million is related to a pipeline and is being amortized on a straight-line basis over the life of the pipeline, which is 35 years. The value assigned to our excess investment in Seaway was created upon acquisition of our 50% ownership interest in 2000. We are amortizing the excess investment in Seaway on a straight-line basis over a 39-year life related primarily to the life of the pipeline. The value assigned to our excess investment in Jonah was created as a result of interest capitalized on the construction of Jonah’s expansion. We will continue to capitalize interest on the construction of the expansion of the Jonah system until the construction is completed and placed into service. When the expansion is placed into service, we will amortize the excess investment in Jonah on a straight-line basis over life of the assets constructed.

The following table sets forth the estimated amortization expense of intangible assets and the estimated amortization expense allocated to equity earnings for the years ending December 31:


	Intangible Assets (1)		Excess Investments
2007	$	23,194	$	4,440
2008		20,664		4,588
2009		18,053		4,793
2010		18,034		3,587
2011		18,026		885


(1)		Excludes estimated amortization expense of Jonah’s intangible assets as a result of its deconsolidation effective August 1, 2006.

NOTE 13. DEBT OBLIGATIONS

The following table summarizes the principal amounts outstanding under all of TEPPCO’s debt instruments as of December 31, 2006 and 2005:


	December 31,
	2006		2005
Revolving Credit Facility, due December 2011	$	490,000	$	405,900
6.45% TE Products Senior Notes, due January 2008		179,968		179,937
7.625% TEPPCO Senior Notes, due February 2012		498,866		498,659
6.125% TEPPCO Senior Notes, due February 2013		199,130		198,988
7.51% TE Products Senior Notes, due January 2028		210,000		210,000

Total borrowings		1,577,964		1,493,484
Adjustment to carrying value associated with hedges of fair value		25,323		31,537

Total debt instruments	$	1,603,287	$	1,525,021

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Revolving Credit Facility

TEPPCO has in place a $700.0 million unsecured revolving credit facility, including the issuance of letters of credit (“Revolving Credit Facility”), which matures on December 13, 2011. Commitments under the credit facility may be increased up to a maximum of $850.0 million upon TEPPCO’s request, subject to lender approval and the satisfaction of certain other conditions. The interest rate is based, at TEPPCO’s option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. Financial covenants in the Revolving Credit Facility requires that TEPPCO maintain a ratio of Consolidated Funded Debt to Pro Forma EBITDA (as defined and calculated in the facility) of less than 4.75 to 1.00 (subject to adjustment for specified acquisitions) and a ratio of EBITDA to Interest Expense (as defined and calculated in the facility) of at least 3.00 to 1.00, in each case with respect to specified twelve month periods. Other restrictive covenants in the Revolving Credit Facility limit TEPPCO’s ability to, among other things, incur additional indebtedness, make certain distributions, incur liens, engage in specified transactions with affiliates and complete mergers, acquisitions and sales of assets.

On July 31, 2006, TEPPCO amended its Revolving Credit Facility. The primary revisions were as follows:

	•		The maturity date of the credit facility was extended from December 13, 2010 to December 13, 2011. Also under the terms of the amendment, TEPPCO may request up to two one-year extensions of the maturity date. These extensions, if requested, will become effective subject to lender approval and satisfaction of certain other conditions.

	•		The amendment releases Jonah as a guarantor of the Revolving Credit Facility and restricts the amount of outstanding debt of the Jonah joint venture to debt owing to the owners of its partnership interests and other third-party debt in the principal aggregate amount of $50.0 million.

	•		The amendment modifies the financial covenants to, among other things, allows TEPPCO to include in the calculation of its Consolidated EBITDA (as defined in the Revolving Credit Facility) pro forma adjustments for material capital projects.

	•		The amendment allows for the issuance of Hybrid Securities (as defined in the Revolving Credit Facility) of up to 15% of TEPPCO’s Consolidated Total Capitalization (as defined in the Revolving Credit Facility).

At December 31, 2006, TEPPCO had $490.0 million outstanding under the Revolving Credit Facility at a weighted average interest rate of 5.96%. At December 31, 2006, TEPPCO was in compliance with the covenants of this credit facility.

Senior Notes

On January 27, 1998, TE Products issued of $180.0 million principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the “TE Products Senior Notes”). The 6.45% TE Products Senior Notes were issued at a discount of $0.3 million and are being accreted to their face value over the term of the notes. The 6.45% TE Products Senior Notes due 2008 may not be redeemed prior to their maturity on January 15, 2008. The 7.51% TE Products Senior Notes due 2028, issued at par, may be redeemed at any time after January 15, 2008, at the option of TE Products, in whole or in part, at the following redemption prices (expressed in percentages of the principal amount) during the twelve months beginning January 15 of the years indicated:

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Redemption				Redemption
Year	Price			Year	Price
2008		103.755	%	2013		101.878	%
2009		103.380	%	2014		101.502	%
2010		103.004	%	2015		101.127	%
2011		102.629	%	2016		100.751	%
2012		102.253	%	2017		100.376	%

and thereafter at 100% of the principal amount, together in each case with accrued interest at the redemption date.

The TE Products Senior Notes do not have sinking fund requirements. Interest on the TE Products Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The TE Products Senior Notes are unsecured obligations of TE Products and rank pari passu with all other unsecured and unsubordinated indebtedness of TE Products. The indenture governing the TE Products Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit TE Products’ ability to incur additional indebtedness. At December 31, 2006, TE Products was in compliance with the covenants of the TE Products Senior Notes.

On February 20, 2002, TEPPCO issued $500.0 million principal amount of 7.625% Senior Notes due 2012 (“7.625% TEPPCO Senior Notes”). The 7.625% TEPPCO Senior Notes were issued at a discount of $2.2 million and are being accreted to their face value over the term of the notes. The 7.625% TEPPCO Senior Notes may be redeemed at any time at TEPPCO’s option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing the 7.625% TEPPCO Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit TEPPCO’s ability to incur additional indebtedness. At December 31, 2006, TEPPCO was in compliance with the covenants of these 7.625% TEPPCO Senior Notes.

On January 30, 2003, TEPPCO issued $200.0 million principal amount of 6.125% Senior Notes due 2013 (“6.125% TEPPCO Senior Notes”). The 6.125% TEPPCO Senior Notes were issued at a discount of $1.4 million and are being accreted to their face value over the term of the notes. The 6.125% TEPPCO Senior Notes may be redeemed at any time at TEPPCO’s option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing the 6.125% TEPPCO Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit TEPPCO’s ability to incur additional indebtedness. At December 31, 2006, TEPPCO was in compliance with the covenants of these 6.125% TEPPCO Senior Notes.

The following table summarizes the estimated fair values of the Senior Notes as of December 31, 2006 and 2005 (in millions):


			Fair Value
	Face		December 31,
	Value		2006		2005
6.45% TE Products Senior Notes, due January 2008	$	180.0	$	181.6	$	183.7
7.625% TEPPCO Senior Notes, due February 2012		500.0		537.1		552.0
6.125% TEPPCO Senior Notes, due February 2013		200.0		201.6		205.6
7.51% TE Products Senior Notes, due January 2028		210.0		221.5		224.1

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

TEPPCO has entered into interest rate swap agreements to hedge its exposure to changes in the fair value on a portion of the Senior Notes discussed above (see Note 6). In May 2007, TEPPCO issued junior subordinated notes (see Note 21 for further information).

Letter of Credit

At December 31, 2006, TEPPCO had outstanding an $8.7 million standby letter of credit in connection with crude oil purchased during the fourth quarter of 2006. The payable related to these purchases of crude oil is expected to be paid during the first quarter of 2007.

NOTE 14. MINORITY INTEREST

Minority interest represents third-party ownership interests, including those of TEPPCO’s public unitholders, in the net assets of TEPPCO through TEPPCO’s publicly traded Units. The Parent Company owns 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.

The following table shows the activity for minority interest for the years ended December 31, 2006, 2005 and 2004:


Minority interest at December 31, 2003	$	1,114,661
Adjustments to issuance of Limited Partner Units, net		(99	)
Net income allocation — year ended December 31, 2004		98,580
Cash distributions		(166,158	)

Minority interest at December 31, 2004		1,046,984
Issuance of Limited Partner Units, net		278,806
Net income allocation — year ended December 31, 2005		114,972
Cash distributions		(177,916	)

Minority interest at December 31, 2005		1,262,846
Issuance of Limited Partner Units, net		195,059
Net income allocation — year ended December 31, 2006		144,319
Cash distributions		(196,665	)

Minority interest at December 31, 2006	$	1,405,559

TEPPCO’s Equity Offerings — Issuance of Units

On May 5, 2005, TEPPCO issued and sold in an underwritten public offering 6.1 million Units at a price to the public of $41.75 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $244.5 million. On June 8, 2005, 865,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on May 5, 2005. Proceeds from the over-allotment sale, net of underwriting discount, totaled $34.7 million. The proceeds were used to reduce indebtedness under TEPPCO’s Revolving Credit Facility, to fund revenue generating and system upgrade capital expenditures and for general partnership purposes.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In July 2006, TEPPCO issued and sold in an underwritten public offering 5.0 million Units at a price to the public of $35.50 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $170.4 million. On July 12, 2006, 750,000 additional Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering. Proceeds from the over-allotment sale, net of underwriting discount, totaled $25.6 million. The net proceeds from the offering and the over-allotment were used to reduce indebtedness under TEPPCO’s Revolving Credit Facility.

Incentive Distribution Rights

On December 8, 2006, at a special meeting of its unitholders, TEPPCO’s Fourth Amended and Restated Agreement of Limited Partnership (the “New Partnership Agreement”), which amends and restates the Third Amended and Restated Agreement of Limited Partnership in effect prior to the special meeting (the “Previous Partnership Agreement”) was approved and became effective. The New Partnership Agreement contains the following amendments to the Previous Partnership Agreement, among others:

	•		changes to certain provisions that relate to distributions and capital contributions, including the reduction in the Parent Company’s incentive distribution rights from 50% to 25% (“IDR Reduction Amendment”), elimination of the Parent Company’s requirement to make capital contributions to TEPPCO to maintain a 2% capital account, and adjustment of TEPPCO’s minimum quarterly distribution and target distribution levels for entity-level taxes;

	•		changes to various voting percentage requirements, in most cases from 66²/³% of outstanding Units to a majority of outstanding Units;

	•		the percentage of holders of outstanding Units necessary to constitute a quorum was reduced from 66²/³% to a majority of the outstanding Units;

	•		removal of provisions requiring unitholder approval for specified actions with respect to the Operating Partnerships;

	•		changes to supplement and revise certain provisions that relate to conflicts of interest and fiduciary duties; and

	•		changes to provide for certain registration rights of the Parent Company and its affiliates (including with respect to the Units issued in respect of the IDR Reduction Amendment, as described below), for the maintenance of the separateness of TEPPCO from any other person or entity and other miscellaneous matters.

By approval of the various proposals at the special meeting, and upon effectiveness of the New Partnership Agreement, an agreement was effectuated whereby TEPPCO issued 14,091,275 Limited Partners Units on December 8, 2006 to the Parent Company as consideration for the IDR Reduction Amendment. The number of Units issued to the Parent Company was based upon a predetermined formula that, based on the distribution rate and the number of Units outstanding at the time of the issuance, resulted in the Parent Company receiving cash distributions from the newly-issued Units and from its reduced maximum percentage interest in TEPPCO’s quarterly distributions approximately equal to the cash distributions it would have received from its maximum percentage interest in TEPPCO’s quarterly distributions without the IDR Reduction Amendment. Effective as of December 8, 2006, the Parent Company distributed the newly issued Units to its member, which in turn caused them to be distributed to other affiliates of EPCO.

At the 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 our 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 its 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

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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).

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

NOTE 15. MEMBER’S EQUITY (DEFICIT)

At December 31, 2006 and 2005, member’s equity (deficit) consisted of our capital account and accumulated other comprehensive income.

Member’s Equity (Deficit)

At December 31, 2006 and 2005, we had deficit balances of $86.0 million and $61.5 million, respectively, in our member’s equity account. These negative balances do not represent assets to us and do not represent obligations of our member to contribute cash or other property to us. The member’s equity account generally consists of our member’s cumulative share of our net income less cash distributions made to it plus capital contributions that it has made to us. Cash distributions that we receive during a period from TEPPCO may exceed our share of its net income for the period. In turn, cash distributions we make to our member during a period may exceed our net income for the period. TEPPCO makes quarterly cash distributions of all of its Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the Parent Company in its reasonable discretion (these cash distributions paid to the Parent Company are eliminated upon consolidation of the Parent Company’s financial statements with TEPPCO’s financial statements). Cash distributions by us to our member in excess of our net income and capital contributions during the years ended December 31, 2006 and 2005, resulted in deficits in the member’s equity account at December 31, 2006 and 2005. Future cash distributions that exceed net income will result in an increase in the deficit balance in the member’s equity account.

Accumulated Other Comprehensive Income

SFAS No. 130,Reporting Comprehensive Incomerequires certain items such as foreign currency translation adjustments, gains or losses associated with pension or other postretirement benefits, prior service costs or credits associated with pension or other postretirement benefits, transition assets or obligations associated with pension or other postretirement benefits and unrealized gains and losses on certain investments in debt and equity securities to be reported in a financial statement. As of and for the years ended December 31, 2006 and 2005, the components of accumulated other comprehensive income reflected on our consolidated balance sheets were composed of crude oil hedges, interest rate swaps, and unrecognized losses associated with the TEPPCO RCBP. The crude oil hedges mature in 2007. While the crude oil hedges are in effect, changes in their fair values, to the extent the hedges are effective, are recognized in accumulated other comprehensive income until they are recognized in net income in future periods. The interest rate swaps mature in January 2008, are related to TEPPCO’s variable rate revolving credit facility and are designated as cash flow hedges beginning in the third quarter of 2006.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The accumulated balance of other comprehensive income related to our cash flow hedges and unrecognized losses associated with our pension benefits is as follows:


Balance at December 31, 2003	$	(2,902	)
Transferred to earnings		2,939
Change in fair value of cash flow hedge		(37	)

Balance at December 31, 2004		—
Change in fair value of cash flow hedge		11

Balance at December 31, 2005		11
Transferred to earnings		2,255
Changes in fair values of interest rate cash flow hedges		(2,503	)
Changes in fair values of crude oil cash flow hedges		730
Adjustment to initially apply SFAS No. 158		(67	)

Balance at December 31, 2006	$	426

NOTE 16. BUSINESS SEGMENTS

We have three reporting segments:

	•		Our Downstream Segment, which is engaged in the transportation, marketing and storage of refined products, LPGs and petrochemicals;

	•		Our Upstream Segment, which is engaged in the gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals; and

	•		Our Midstream Segment, which is engaged in the gathering of natural gas, fractionation of NGLs and transportation of NGLs.

The amounts indicated below as “Other” relate primarily to Parent Company financial statements, intersegment eliminations and assets that we hold that have not been allocated to any of our reporting segments.

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. We generally realize higher revenues in the Downstream Segment during the first and fourth quarters of each year since these operations are somewhat seasonal. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand for propane, a major fuel for residential heating. The two largest operating expense items of the Downstream Segment are labor and electric power. Our Downstream Segment also includes the results of operations of the northern portion of the Dean Pipeline, which transports refinery grade propylene from Mont Belvieu to Point Comfort, Texas. Our Downstream Segment also includes our equity investments in MB Storage, which we sold on March 1, 2007 (see Note 21), and in Centennial (see Note 9).

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. Marketing operations consist primarily of aggregating purchased crude oil along our pipeline systems, or from third party pipeline systems, and arranging the necessary transportation logistics for the ultimate sale or delivery of the crude oil to local refineries, marketers or other end users. Revenues are also generated from trade documentation and pumpover services, primarily at Cushing, Oklahoma, and Midland, Texas. Our Upstream Segment also includes our equity investment in Seaway (see Note 9). Seaway consists of large diameter pipelines that transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coast to Cushing,

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Oklahoma, a crude oil distribution point for the central United States, and to refineries in the Texas City and Houston areas.

Our Midstream Segment revenues are earned from the gathering of coal bed methane and conventional natural gas in the San Juan Basin in New Mexico and Colorado, through Val Verde; transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from West Texas and New Mexico to Mont Belvieu; and the fractionation of NGLs in Colorado. Our Midstream Segment also includes our equity investment in Jonah (see Note 9). Jonah, which is a joint venture between us and an affiliate of Enterprise, owns a natural gas gathering system in the Green River Basin in southwestern Wyoming. Prior to August 1, 2006, when Jonah was wholly-owned by us, operating results for Jonah were included in the consolidated Midstream Segment operating results. Effective August 1, 2006, we entered into the joint venture with Enterprise’s affiliate, upon which Jonah was deconsolidated, and its operating results since August 1, 2006, have been accounted for under the equity method of accounting. Operating results of the Pioneer plant, which we sold to an Enterprise affiliate in March 2006, are shown as discontinued operations for the years ended December 31, 2006 and 2005.

The tables below include financial information by reporting segment for the years ended December 31, 2006, 2005 and 2004:


	For Year Ended December 31, 2006
	Downstream			Upstream			Midstream			Segments
	Segment			Segment			Segment			Total			Other			Consolidated
Sales of petroleum products (1)	$	5,800		$	9,060,782		$	18,766		$	9,085,348		$	(4,832	)	$	9,080,516
Operating revenues		298,501			48,847			182,503			529,851			(2,882	)		526,969
Purchases of petroleum products(1)		5,526			8,953,407			17,272			8,976,205			(9,143	)		8,967,062
Operating expenses, including power and taxes — other than income taxes		153,246			66,801			59,150			279,197			(749	)		278,448
General and administrative expenses		17,085			5,986			8,277			31,348			335			31,683
Depreciation and amortization expense		41,405			14,400			52,447			108,252			—			108,252
Gains on sales of assets		(4,223	)		(1,805	)		(1,376	)		(7,404	)		—			(7,404	)

Operating income		91,262			70,840			65,499			227,601			1,843			229,444
Equity earnings (losses)		(8,018	)		11,905			35,052			38,939			(2,178	)		36,761
Interest income		1,008			407			662			2,077			9			2,086
Other income, net		494			388			6			888			—			888

Earnings before interest expense, income taxes, discontinued operations and minority interest	$	84,746		$	83,540		$	101,219		$	269,505		$	(326	)	$	269,179


(1)		Amounts for the period from April 1, 2006 through December 31, 2006 have been fully adjusted for the impact of adopting EITF 04-13. The period from January 1, 2006 through March 31, 2006 and for the years ended December 31, 2005 and 2004 have not been adjusted for the adoption of EITF 04-13, as retroactive restatement was not permitted, which impacts comparability (see Note 3 for further information).

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	For Year Ended December 31, 2005
	Downstream			Upstream			Midstream			Segments
	Segment			Segment			Segment			Total			Other			Consolidated
Sales of petroleum products	$	—		$	8,062,131		$	—		$	8,062,131		$	(323	)	$	8,061,808
Operating revenues		287,191			48,108			211,171			546,470			(3,244	)		543,226
Purchases of petroleum products		—			7,989,682			—			7,989,682			(3,244	)		7,986,438
Operating expenses, including power		142,131			63,263			50,288			255,682			(323	)		255,359
General and administrative expenses		17,653			7,077			8,413			33,143			310			33,453
Depreciation and amortization expense		39,403			17,161			54,165			110,729			—			110,729
Gains on sales of assets		(139	)		(118	)		(411	)		(668	)		—			(668	)

Operating income		88,143			33,174			98,716			220,033			(310	)		219,723
Equity earnings (losses)		(2,984	)		23,078			—			20,094			—			20,094
Interest income		477			—			210			687			—			687
Other income, net		278			156			14			448			(10,000	)		(9,552	)

Earnings before interest expense, income taxes, discontinued operations and minority interest	$	85,914		$	56,408		$	98,940		$	241,262		$	(10,310	)	$	230,952


	For Year Ended December 31, 2004
	Downstream			Upstream			Midstream		Segments
	Segment			Segment			Segment		Total			Other			Consolidated
Sales of petroleum products	$	—		$	5,426,832		$	—	$	5,426,832		$	—		$	5,426,832
Operating revenues		279,400			49,163			195,902		524,465			(3,207	)		521,258
Purchases of petroleum products		—			5,370,234			—		5,370,234			(3,207	)		5,367,027
Operating expenses, including power		148,644			55,459			53,269		257,372			85			257,457
General and administrative expenses		16,884			5,434			5,698		28,016			1			28,017
Depreciation and amortization expense		43,135			13,130			56,019		112,284			—			112,284
Gains on sales of assets		(526	)		(527	)		—		(1,053	)		—			(1,053	)

Operating income		71,263			32,265			80,916		184,444			(86	)		184,358
Equity earnings (losses)		(6,544	)		28,692			—		22,148			—			22,148
Interest income		309			43			115		467			—			467
Interest income, related party		—			—			—		—			187			187
Other income, net		478			363			12		853			—			853

Earnings before interest expense, income taxes, discontinued operations and minority interest	$	65,506		$	61,363		$	81,043	$	207,912		$	101		$	208,013

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table provides the total assets, capital expenditures and significant non-cash investing activities for each segment as of and for the years ended December 31, 2006, 2005 and 2004:


	Downstream		Upstream		Midstream		Segments
	Segment		Segment		Segment		Total		Other			Consolidated
December 31, 2006:
Total assets	$	1,160,929	$	1,504,699	$	1,335,502	$	4,001,130	$	(78,989	)	$	3,922,141
Capital expenditures		75,344		48,351		42,929		166,624		3,422			170,046
Non-cash investing activities		—		—		581,341		581,341		—			581,341

December 31, 2005:
Total assets	$	1,056,217	$	1,353,492	$	1,280,548	$	3,690,257	$	(9,458	)	$	3,680,799
Capital expenditures		58,609		40,954		119,837		219,400		1,153			220,553
Non-cash investing activities		1,429		—		—		1,429		—			1,429

December 31, 2004:
Total assets	$	959,042	$	1,069,007	$	1,184,184	$	3,212,233	$	150,505		$	3,362,738
Capital expenditures		80,930		37,448		37,677		156,055		694			156,749
Capital expenditures for discontinued operations		—		—		7,398		7,398		—			7,398

The following table reconciles the segment data from the tables above to consolidated net income for the years ended December 31, 2006, 2005 and 2004:


	For Year Ended December 31,
	2006			2005			2004
Earnings before interest expense, provision for income taxes, discontinued operations and minority interest	$	269,179		$	230,952		$	208,013
Interest expense — net		(86,171	)		(81,861	)		(72,053	)

Income before provision for income taxes, discontinued operations and minority interest		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
Discontinued operations		5,534			922			776

Net income	$	57,406		$	37,266		$	40,070

NOTE 17. RELATED PARTY TRANSACTIONS

EPCO and Affiliates and Duke Energy, DEFS and Affiliates

Prior to February 24, 2005, we were an indirect wholly owned subsidiary of DEFS. On February 24, 2005, DEFS sold its interest in us to DFI (see Note 1). DEFS and Duke Energy continued to provide some administrative services for us for a period of up to one year after the sale, at which time, we assumed these services. In connection with our acquisition by DFI, our employees became employees of EPCO effective June 1, 2005. Currently, all of our management, administrative and operating functions are performed by employees of EPCO, pursuant to the ASA. We reimburse EPCO for the allocated costs of its employees who perform operating, management and other administrative functions for us (see Note 1).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following information summarizes our business relationships and related transactions with EPCO and its affiliates, including entities controlled by Dan L. Duncan, and DEFS and its affiliates during the years ended December 31, 2006, 2005 and 2004. We have also provided information regarding our business relationships and transactions with our unconsolidated affiliates.

We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities:

	•		EPCO and its consolidated private company subsidiaries;

	•		DFI, which owns and controls us;

	•		Enterprise Products Partners L.P., which is controlled by affiliates of EPCO;

	•		Duncan Energy Partners L.P. (“DEP”), which is controlled by affiliates of EPCO; and

	•		Enterprise Gas Processing LLC, which is controlled by affiliates of EPCO and is our joint venture partner in Jonah.

EPCO, a private company controlled by Dan L. Duncan, also owns DFI, which owns and controls us. DFI owns all of the membership interests in us. Our principal business activity is to act as TEPPCO’s managing partner. Our executive officers are employees of EPCO (see Note 1).

The Parent Company and TEPPCO are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are separate from those of EPCO and its other affiliates. EPCO depends on the cash distributions it receives from us and other investments to fund its other operations and to meet its debt obligations. We paid cash distributions of $81.9 million and $73.2 million during the years ended December 31, 2006 and 2005, to our member.

The ownership interests in us that are owned or controlled by EPCO and its affiliates, other than those interests owned by Dan Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as security under the credit facility of an affiliate of EPCO. This credit facility contains customary and other events of default relating to EPCO and certain affiliates, including Enterprise GP Holdings, Enterprise and us. The ownership interests in us that are owned or controlled by Enterprise GP Holdings are pledged as security under its credit facility.

Unless noted otherwise, our agreements with EPCO are not the result of arm’s length transactions. As a result, we cannot provide assurance that the terms and provisions of such agreements are at least as favorable to us as we could have obtained from unaffiliated third parties.

Administrative Services Agreement

We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the ASA. The Parent Company and TEPPCO, Enterprise and its general partner, Enterprise GP Holdings L.P. and its general partner, DEP and its general partner and certain affiliated entities are parties to the ASA. The significant terms of the ASA are as follows:

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

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

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•

EPCO allows us to participate as named insureds in its overall insurance program with the associated costs being allocated to us.

Our operating costs and expenses for the years ended December 31, 2006 and 2005 include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including compensation of employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets.

Likewise, our general and administrative costs for the years ended December 31, 2006 and 2005 include amounts we reimburse to EPCO for administrative services, including compensation of employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA based on the estimated use of such services by each party (e.g., the allocation of general legal or accounting salaries based on estimates of time spent on each entity’s business and affairs).

EPCO and its affiliates have no obligation to present business opportunities to us or our Operating Partnerships, and we and our Operating Partnerships have no obligation to present business opportunities to EPCO and its affiliates. However, the ASA requires that business opportunities offered to or discovered by EPCO, which controls both us and our affiliates and Enterprise and it affiliates, be offered first to certain Enterprise affiliates before they may be pursued by EPCO and its other affiliates or offered to us.

The following table summarizes the related party transactions with EPCO and affiliates and DEFS and affiliates for the years ended December 31, 2006, 2005 and 2004 (in millions):


	For Year Ended December 31,
	2006		2005		2004
Revenues from EPCO and affiliates: (1)
Sales of petroleum products (2)	$	3.2	$	—	$	—
Transportation — NGLs (3)		10.2		7.4		—
Transportation — LPGs(4)		3.6		4.3		—
Other operating revenues (5)		1.5		0.3		—
Costs and Expenses from EPCO and affiliates: (1)
Payroll, administrative and other (6)(7)		136.9		78.0		—
Purchases of petroleum products (8)		41.8		3.4		—
Revenues from DEFS and affiliates: (9)
Sales of petroleum products		—		4.3		23.2
Transportation — NGLs		—		2.8		16.7
Gathering — Natural gas — Jonah		—		0.5		3.3
Transportation — LPGs		—		0.7		2.6
Other operating revenues		—		2.4		14.0
Costs and Expenses from DEFS and affiliates: (9)
Payroll, administrative and other (10)(11)(12)		—		17.4		102.4
Purchases of petroleum products (13)		—		38.5		146.4


(1)		Operating revenues earned and expenses incurred from activities with EPCO and its affiliates are considered related party transactions beginning February 24, 2005, as a result of the change in our ownership.

(2)		Includes Jonah NGL sales through July 31, 2006 of $2.9 million to Enterprise Gas Processing, LLC and $0.3 million in sales from Lubrication Services, L.P. (“LSI”) to various EPCO affiliates.

(3)		Includes revenues from NGL transportation on the Chaparral and Panola NGL pipelines.

(4)		Includes revenues from LPG transportation on the TE Products pipeline.

(5)		Includes other operating revenues on the TE Products pipeline.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(6)		Includes payroll, payroll related expenses, administrative expenses, including reimbursements related to employee benefits and employee benefit plans, incurred in managing us and our subsidiaries in accordance with the ASA, and other operating expenses.

(7)		Includes insurance expense for the years ended December 31, 2006 and 2005, related to premiums paid by EPCO of $15.8 million and $9.8 million, respectively. Beginning February 24, 2005, the majority of our insurance coverage, including property, liability, business interruption, auto and directors and officers’ liability insurance, was obtained through EPCO.

(8)		Includes TCO purchases of condensate of $41.6 million, Jonah processing fees through July 31, 2006 of $0.1 million and $0.1 million of expenses related to LSI’s use of an affiliate of EPCO as a transporter.

(9)		Operating revenues earned and expenses incurred from activities with DEFS and its affiliates are considered related party transactions prior to February 23, 2005, at which time a change in our ownership occurred.

(10)		Includes operating costs and expenses related to DEFS managing and operating the Jonah and Val Verde systems and the Chaparral NGL pipeline on our behalf under contractual agreements established at the time of acquisition of each asset. In connection with the change in our ownership, we or EPCO have assumed these activities.

(11)		Includes costs related to payroll, payroll related expenses and administrative expenses incurred in managing us and our subsidiaries.

(12)		Includes insurance expense for the years ended December 31, 2005 and 2004, related to premiums paid to Bison Insurance Company Limited (“Bison”), a wholly owned subsidiary of Duke Energy, of $1.2 million and $6.5 million, respectively. Through February 23, 2005, we contracted with Bison for a majority of our insurance coverage, including property, liability, auto and directors and officers’ liability insurance.

(13)		Includes TCO purchases of condensate and $0.8 million of purchases by Jonah’s Pioneer processing plant which is classified as income from discontinued operations in the consolidated financial statements.

The following table summarizes the related party balances with EPCO and affiliates at December 31, 2006 and 2005 (in millions):


	December 31,
	2006		2005
Accounts receivable, related party (1)	$	0.3	$	4.3
Gas imbalance receivable		1.3		—
Insurance reimbursement receivable		1.4		1.3
Accounts payable, related party (2)		26.4		9.8
Deferred revenue, related party		0.3		—
Long-term payable (3)		1.8		—


(1)		Relates to sales and transportation services provided to EPCO and affiliates.

(2)		Relates to direct payroll, payroll related costs and other operational related charges from EPCO and affiliates.

(3)		Relates to our share of EPCO’s Oil Insurance Limited insurance program retrospective premiums obligation.

Sale of Pioneer plant

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

Jonah Joint Venture

On August 1, 2006, Enterprise (through an affiliate) became our joint venture partner by acquiring an interest in Jonah, the partnership through which we owned the Jonah system. 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 (see Note 9 for further discussion on the Jonah joint venture).

In conjunction with the formation of the joint venture, we have agreed to indemnify Enterprise from any and all losses, claims, demands, suits, liability, costs and expenses arising out of or related to breaches of our representations, warranties, or covenants related to the formation of the Jonah joint venture, Jonah’s ownership or operation of the Jonah system prior to the effective date of the joint venture, and any environmental activity, or violation of or liability under environmental laws arising from or related to the condition of the Jonah system prior to the effective date of the joint venture. In general, a claim for indemnification cannot be filed until the losses suffered by Enterprise exceed $1.0 million, and the maximum potential amount of future payments under the indemnity is limited to $100.0 million. However, if certain representations or warranties are breached, the maximum potential amount of future payments under the indemnity is capped at $207.6 million. All indemnity payments are net of insurance recoveries that Enterprise may receive from third-party insurers. We carry insurance coverage that may offset any payments required under the indemnity. We do not expect that these indemnities will have a material adverse effect on our financial position, results of operations or cash flows.

Other Transactions

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 had been idle since acquisition, were part of the assets acquired by us in 2005 from Genco and BP. 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 at September 30, 2006, was approximately $6.0 million. We recognized a gain of $5.7 million on this transaction.

On November 1, 2006, we announced plans to construct a new 20-inch diameter lateral pipeline to connect our mainline system to the Enterprise and MB Storage facilities at Mont Belvieu, Texas, at a cost of approximately $8.6 million. The new connection, which provides delivery from Enterprise of propane into our system at full line flow rates, complements our current ability to source product from MB Storage. The new connection also offers the ability to deliver other liquid products such as butanes and natural gasoline from Enterprise’s storage facilities into our system at reduced flow rates until enhancements can be made. The capability to deliver butanes and natural gasoline from MB Storage at full flow rates is not expected to be impacted. Construction of the new connection was completed and placed in service in December 2006. This new pipeline replaces a 10-mile, 18-inch segment of pipeline that we sold to an Enterprise affiliate in January 2007 (see Note 21).

We have entered into a lease with DEP, for a 12-mile, 10-inch interconnecting pipeline extending from Pasadena, Texas to Baytown, Texas. The primary term of this lease will expire on September 15, 2007, and will continue on a month-to-month basis subject to termination by either party upon 60 days’ notice.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Relationships with Unconsolidated Subsidiaries

Centennial

TE Products has a 50% ownership interest in Centennial (see Note 9). TE Products has entered into a management agreement with Centennial to operate Centennial’s terminal at Creal Springs, Illinois, and pipeline connection in Beaumont, Texas. For each of the years ended December 31, 2006, 2005 and 2004, we recognized management fees of $0.2 million from Centennial, and actual operating expenses billed to Centennial were $7.4 million, $3.7 million and $6.9 million, respectively.

TE Products also has a joint tariff with Centennial to deliver products at TE Products’ locations using Centennial’s pipeline as part of the delivery route to connecting carriers. TE Products, as the delivering pipeline, invoices the shippers for the entire delivery rate, records only the net rate attributable to it as transportation revenues and records a liability for the amounts due to Centennial for its share of the tariff. In addition, TE Products performs ongoing construction services for Centennial and bills Centennial for labor and other costs to perform the construction. At December 31, 2006 and 2005, we had net payable balances of $4.4 million and $1.4 million, respectively, to Centennial for its share of the joint tariff deliveries and other operational related charges, partially offset by the reimbursement due to us for construction services provided to Centennial.

In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years that contains a minimum throughput requirement. For the years ended December 31, 2006, 2005 and 2004, TE Products incurred $5.6 million, $5.9 million and $5.3 million, respectively, of rental charges related to the lease of pipeline capacity on Centennial.

Jonah

An affiliate of Enterprise operates the Jonah assets. TCO purchases NGLs from Jonah as part of its crude oil marketing activities. During the period August 1, 2006 through December 31, 2006, TCO incurred $2.2 million in purchases from Jonah related to the crude oil marketing activities. At December 31, 2006, we had a distribution receivable of $11.5 million from Jonah, which is included in accounts receivable, related parties.

Seaway

We own a 50% ownership interest in Seaway, and the remaining 50% interest is owned by ConocoPhillips (see Note 9). We operate the Seaway assets. During the years ended December 31, 2006, 2005 and 2004, we billed Seaway $7.6 million, $8.5 million and $7.6 million, respectively, for direct payroll and payroll related expenses for operating Seaway. Additionally, for each of the years ended December 31, 2006, 2005 and 2004, we billed Seaway $2.1 million for indirect management fees for operating Seaway. At December 31, 2006 and 2005, we had payable balances to Seaway of $1.4 million and $0.6 million, respectively, for advances Seaway paid to us as operator for operating costs, including payroll and related expenses and management fees.

MB Storage

Effective January 1, 2003, TE Products entered into agreements with Louis Dreyfus to form MB Storage (see Note 9). TE Products operates the facilities for MB Storage. TE Products and MB Storage have entered into a pipeline capacity lease agreement, and for each of the years ended December 31, 2006, 2005 and 2004, TE Products recognized $0.1 million in rental revenue related to this lease agreement. During the years ended December 31, 2006, 2005 and 2004, TE Products also billed MB Storage $3.1 million, $3.6 million and $3.2 million, respectively, for direct payroll and payroll related expenses for operating MB Storage. At December 31, 2006, TE Products had a net payable balance to MB Storage of $2.3 million for operating costs, including payroll and related expenses for

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

operating MB Storage. At December 31, 2005, TE Products had a net receivable balance from MB Storage of $0.9 million for operating costs, including payroll and related expenses for operating MB Storage.

NOTE 18. COMMITMENTS AND CONTINGENCIES

Litigation

In the fall of 1999, the Parent Company and TE Products were named as defendants in a lawsuit in Jackson County Circuit Court, Jackson County, Indiana, styledRyan E. McCleery and Marcia S. McCleery, et al. and Michael and Linda Robson, et al. v. Texas Eastern Corporation, et al.In the lawsuit, the plaintiffs contend, among other things, that we and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In their complaint, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. On March 18, 2005, we entered into Release and Settlement Agreements with the McCleery plaintiffs dismissing all of these plaintiffs’ claims on terms that did not have a material adverse effect on our financial position, results of operations or cash flows. Although we did not settle with all plaintiffs and we therefore remain named parties in theMichael and Linda Robson, et al. v. Texas Eastern Corporation, et al. action, a co-defendant has agreed, by Cooperative Defense Agreement, to fund the defense and satisfy all final judgments which might be rendered with the remaining claims asserted against us. Consequently, we do not believe that the outcome of these remaining claims will have a material adverse effect on our financial position, results of operations or cash flows.

On December 21, 2001, TE Products was named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana, styledRebecca L. Grisham et al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that our pipeline, which crosses the plaintiffs’ property, leaked toxic products onto their property and, consequently caused damages to them. We have filed an answer to the plaintiffs’ petition denying the allegations, and we are defending ourselves vigorously against the lawsuit. The plaintiffs assert damages attributable to the remediation of the property of approximately $1.4 million. This case has been stayed pending the completion of remediation pursuant to the Louisiana Department of Environmental Quality (“LDEQ”) requirements. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

In 1991, we were named as a defendant in a matter styledJimmy R. Green, et al. v. Cities Service Refinery, et al.as filed in the 26^th Judicial District Court of Bossier Parish, Louisiana. The plaintiffs in this matter reside or formerly resided on land that was once the site of a refinery owned by one of our co-defendants. The former refinery is located near our Bossier City facility. Plaintiffs have claimed personal injuries and property damage arising from alleged contamination of the refinery property. The plaintiffs have recently pursued certification as a class and have significantly increased their demand to approximately $175.0 million. We have never owned any interest in the refinery property made the basis of this action, and we do not believe that we contributed to any alleged contamination of this property. While we cannot predict the ultimate outcome, we do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of New Castle County in the State of Delaware, in his individual capacity, as a putative class action on behalf of TEPPCO’s other unitholders, and derivatively on TEPPCO’s behalf, concerning proposals made to its unitholders in its definitive proxy statement filed with the SEC on September 11, 2006 (“Proxy Statement”) and other transactions involving us and Enterprise or its affiliates. The complaint names as defendants the Parent

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Company; our Board of Directors; the Parent Company’s parent companies, including EPCO; Enterprise and certain of its affiliates; and Dan L. Duncan. TEPPCO is named as a nominal defendant.

The complaint alleges, among other things, that certain of the transactions proposed in the Proxy Statement, including a proposal to reduce the Parent Company’s maximum percentage interest in TEPPCO’s distributions in exchange for Units (the “Issuance Proposal”), are unfair to its unitholders and constitute a breach by the defendants of fiduciary duties owed to its unitholders and that the Proxy Statement failed to provide its unitholders with all material facts necessary for them to make an informed decision whether to vote in favor of or against the proposals. The complaint further alleges that, since Mr. Duncan acquired control of us in 2005, the defendants, in breach of their fiduciary duties to TEPPCO and its unitholders, have caused TEPPCO to enter into certain transactions with Enterprise or its affiliates that are unfair to TEPPCO or otherwise unfairly favored Enterprise or its affiliates over TEPPCO. The complaint alleges that such transactions include the Jonah joint venture entered into by TEPPCO and an Enterprise affiliate in August 2006 (citing the fact that our AC Committee did not obtain a fairness opinion from an independent investment banking firm in approving the transaction) and the sale by TEPPCO to an Enterprise affiliate of the Pioneer plant in March 2006 and the impending divestiture of TEPPCO’S interest in MB Storage in connection with an investigation by the FTC. As more fully described in the Proxy Statement, the AC Committee recommended the Issuance Proposal for approval by our Board of Directors. The complaint also alleges that Richard S. Snell, Michael B. Bracy and Murray H. Hutchison, constituting the three members of the AC Committee, cannot be considered independent because of their alleged ownership of securities in Enterprise and its affiliates and their relationships with Mr. Duncan.

The complaint seeks relief (i) rescinding transactions in the complaint that have been consummated or awarding rescissory damages in respect thereof including the divestiture of our interest in MB Storage; (ii) awarding damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the complaint; and (iii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts.

On September 22, 2006, the plaintiff in the action filed a motion to expedite the proceedings, requesting the Court to schedule a hearing on plaintiff’s motion for a preliminary injunction to enjoin the defendants from proceeding with the special meeting of unitholders. On September 26, 2006, the defendants advised the Court that TEPPCO would provide to its unitholders specified supplemental disclosures, which were included in the Form 8-K and supplemental proxy materials TEPPCO filed with the SEC on October 5, 2006. The special meeting was convened on December 8, 2006, at which TEPPCO unitholders approved all of the proposals. In light of the foregoing, we believe that the plaintiff’s grounds for seeking relief by requiring TEPPCO to issue a proxy statement that corrects the alleged misstatements and omissions in the Proxy Statement and enjoining the special meeting are moot. On November 17, 2006, the defendants (other than TEPPCO, the nominal defendant) moved to dismiss the complaint. While we cannot predict the ultimate outcome, we do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

In addition to the proceedings discussed above, we have been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. We believe that the outcome of these lawsuits and other proceedings will not individually or in the aggregate have a future material adverse effect on our consolidated financial position, results of operations or cash flows.

Regulatory Matters

Our pipelines and other facilities are subject to multiple environmental obligations and potential liabilities under a variety of federal, state and local laws and regulations. These include, without limitation: the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Clean Air Act; the Federal Water Pollution Control Act or the Clean Water Act; the Oil Pollution

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Act; and analogous state and local laws and regulations. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals, with respect to air emissions, water quality, wastewater discharges, and solid and hazardous waste management. Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could influence our results of operations. If an accidental leak, spill or release of hazardous substances occurs at any facilities that we own, operate or otherwise use, or where we send materials for treatment or disposal, we could be held jointly and severally liable for all resulting liabilities, including investigation, remedial and clean-up costs. Likewise, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination. Any or all of this could materially affect our results of operations and cash flows.

We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations, and that the cost of compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial position. We cannot ensure, however, that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows. At December 31, 2006 and 2005, we have an accrued liability of $1.8 million and $2.4 million, respectively, related to sites requiring environmental remediation activities.

In 1994, the LDEQ issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this contamination. Effective March 2004, we executed an access agreement with an adjacent industrial landowner who is located upgradient of the Arcadia facility. This agreement enables the landowner to proceed with remediation activities at our Arcadia facility for which it has accepted shared responsibility. At December 31, 2006, we have an accrued liability of $0.1 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program proposed to the LDEQ will have a future material adverse effect on our financial position, results of operations or cash flows.

On July 27, 2004, we received notice from the United States Department of Justice (“DOJ”) of its intent to seek a civil penalty against us related to our November 21, 2001, release of approximately 2,575 barrels of jet fuel from our 14-inch diameter pipeline located in Orange County, Texas. The DOJ, at the request of the Environmental Protection Agency, is seeking a civil penalty against us for alleged violations of the Clean Water Act (“CWA”) arising out of this release, as well as three smaller spills at other locations in 2004 and 2005. We have agreed with the DOJ on a proposed penalty of $2.9 million, along with our commitment to implement additional spill prevention measures, and expect to finalize the settlement by the end of 2007. We do not expect this settlement to have a material adverse effect on our financial position, results of operations or cash flows.

One of the spills encompassed in our current settlement discussion with the DOJ involved a 37,450-gallon release from Seaway on May 13, 2005 at Colbert, Oklahoma. This release was remediated under the supervision of the Oklahoma Corporation Commission, but resulted in claims by neighboring landowners that have been settled for approximately $0.7 million. In addition, the release resulted in a Corrective Action Order by the U.S. Department of Transportation. Among other requirements of this Order, we were required to reduce the operating pressure of Seaway by 20% until completion of required corrective actions. The corrective actions were completed and on June 1, 2006, we increased the operating pressure of Seaway back to 100%. We have a 50% ownership interest in Seaway, and any settlement should be covered by our insurance. We do not expect the completion of our

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

obligations relating to the Colbert release to have a material adverse effect on our financial position, results of operations or cash flows.

On September 18, 2005, a propane release and fire occurred at our Todhunter facility, near Middletown, Ohio. The incident resulted in the death of one of our employees; there were no other injuries. Repairs to the impacted facilities have been completed. On March 17, 2006, we received a citation from the Occupational Safety and Health Administration (“OSHA”) arising out of this incident, with a penalty of $0.1 million. The settlement of this citation did not have a material adverse effect on our financial position, results of operations or cash flows.

We are also in negotiations with the U.S. Department of Transportation with respect to a notice of probable violation that we received on April 25, 2005, for alleged violations of pipeline safety regulations at our Todhunter facility, with a proposed $0.4 million civil penalty. We responded on June 30, 2005, by admitting certain of the alleged violations, contesting others and requesting a reduction in the proposed civil penalty. We do not expect any settlement, fine or penalty to have a material adverse effect on our financial position, results of operations or cash flows.

The FERC, pursuant to the Interstate Commerce Act of 1887, as amended, the Energy Policy Act of 1992 and rules and orders promulgated thereunder, regulates the tariff rates for our interstate common carrier pipeline operations. To be lawful under that Act, interstate tariff rates, terms and conditions of service must be just and reasonable and not unduly discriminatory, and must be on file with FERC. In addition, pipelines may not confer any undue preference upon any shipper. Shippers may protest, and the FERC may investigate, the lawfulness of new or changed tariff rates. The FERC can suspend those tariff rates for up to seven months. It can also require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful. The FERC and interested parties can also challenge tariff rates that have become final and effective. Because of the complexity of rate making, the lawfulness of any rate is never assured. A successful challenge of our rates could adversely affect our revenues.

The FERC uses prescribed rate methodologies for approving regulated tariff rates for transporting crude oil and refined products. Our interstate tariff rates are either market-based or derived in accordance with the FERC’s indexing methodology, which currently allows a pipeline to increase its rates by a percentage linked to the producer price index for finished goods. These methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting increased costs. Changes in the FERC’s approved methodology for approving rates could adversely affect us. Adverse decisions by the FERC in approving our regulated rates could adversely affect our cash flow.

The intrastate liquids pipeline transportation services we provide are subject to various state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer. Although state regulation typically is less onerous than FERC regulation, the rates we charge and the provision of our services may be subject to challenge.

Although our natural gas gathering systems are generally exempt from FERC regulation under the Natural Gas Act of 1938, FERC regulation still significantly affects our natural gas gathering business. In recent years, the FERC has pursued pro-competition policies in its regulation of interstate natural gas pipelines. If the FERC does not continue this approach, it could have an adverse effect on the rates we are able to charge in the future. In addition, our natural gas gathering operations could be adversely affected in the future should they become subject to the application of federal regulation of rates and services. Additional rules and legislation pertaining to these matters are considered and adopted from time to time. We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations, but we could be required to incur additional capital expenditures.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Contractual Obligations

The following table summarizes our various contractual obligations at December 31, 2006. A description of each type of contractual obligation follows (in millions):


	Payment or Settlement due by Period
	Total		2007		2008		2009		2010		2011		Thereafter
Maturities of long-term debt (1)	$	1,580.0	$	—	$	180.0	$	—	$	—	$	490.0	$	910.0
Interest payments (2)		790.6		106.9		101.2		95.4		95.4		94.1		297.6
Operating leases (3)		69.7		18.7		11.7		8.8		7.3		6.3		16.9
Purchase obligations (4)		15.0		12.9		1.4		0.5		0.1		—		0.1
Capital expenditure obligations (5)		9.5		9.5		—		—		—		—		—
Standby letter of credit (6)		8.7		8.7		—		—		—		—		—
Other liabilities and deferred Credits (7)		5.2		—		1.8		1.7		0.2		0.1		1.4


(1)		TEPPCO has long-term payment obligations under its Revolving Credit Facility and its Senior Notes. Amounts shown in the table represent the scheduled future maturities of long-term debt principal for the periods indicated (see Note 13 for additional information regarding TEPPCO’s consolidated debt obligations).

(2)		Includes interest payments due on our Senior Notes and interest payments and commitment fees due on our Revolving Credit Facility. The interest amount calculated on the Revolving Credit Facility is based on the assumption that the amount outstanding and the interest rate charged both remain at their current levels.

(3)		We lease property, plant and equipment under noncancelable and cancelable operating leases. Amounts shown in the table represent minimum cash lease payment obligations under our operating leases with terms in excess of one year for the periods indicated. Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. Total rental expense for the years ended December 31, 2006, 2005 and 2004, was $25.3 million, $24.0 million and $22.1 million, respectively.

(4)		We have long and short-term purchase obligations for products and services with third-party suppliers. The prices that we are obligated to pay under these contracts approximate current market prices. The preceding table shows our commitments and estimated payment obligations under these contracts for the periods indicated. Our estimated future payment obligations are based on the contractual price under each contract for products and services at December 31, 2006.

(5)		We have short-term payment obligations relating to capital projects we have initiated. These commitments represent unconditional payment obligations that we have agreed to pay vendors for services rendered or products purchased.

(6)		At December 31, 2006, we had outstanding an $8.7 million standby letter of credit in connection with crude oil purchased during the fourth quarter of 2006. The payable related to these purchases of crude oil is expected to be paid during the first quarter of 2007.

(7)		Excludes approximately $10.1 million of long-term deferred revenue payments, which are being transferred to income over the term of the respective revenue contracts and $4.2 million related to our estimated long-term portion of our obligation under a catastrophic event guarantee for Centennial. The amount of commitment by year is our best estimate of projected payments of these long-term liabilities.

Other

Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2006, $150.0 million was outstanding under those credit facilities, of which $10.0 million matures in April 2007, and $140.0 million matures in April 2024. TE Products and Marathon Petroleum Company LLC (“Marathon”) have

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

each guaranteed one-half of the repayment of Centennial’s outstanding debt balance (plus interest) under these credit facilities. The guarantees arose in order for Centennial to obtain adequate financing to fund construction and conversion costs of its pipeline system. Prior to the expiration of the long-term credit facility, TE Products could be relinquished from responsibility under the guarantee should Centennial meet certain financial tests. If Centennial defaults on its outstanding balance, the estimated maximum potential amount of future payments for TE Products and Marathon is $75.0 million each at December 31, 2006. As a result of the guarantee, TE Products recorded an obligation of $0.1 million, which represents the present value of the estimated amount we would have to pay under the guarantee.

TE Products, Marathon and Centennial have entered into a limited cash call agreement, which allows each member to contribute cash in lieu of Centennial procuring separate insurance in the event of a third-party liability arising from a catastrophic event. There is an indefinite term for the agreement and each member is to contribute cash in proportion to its ownership interest, up to a maximum of $50.0 million each. As a result of the catastrophic event guarantee, TE Products recorded a $4.4 million obligation, which represents the present value of the estimated amount that we would have to pay under the guarantee. If a catastrophic event were to occur and we were required to contribute cash to Centennial, contributions exceeding our deductible might be covered by our insurance, depending upon the nature of the catastrophic event.

One of our subsidiaries, TCO, has entered into master equipment lease agreements with finance companies for the use of various equipment. We have guaranteed the full and timely payment and performance of TCO’s obligations under the agreements. Generally, events of default would trigger our performance under the guarantee. The maximum potential amount of future payments under the guarantee is not estimable, but would include base rental payments for both current and future equipment, stipulated loss payments in the event any equipment is stolen, damaged, or destroyed and any future indemnity payments. We carry insurance coverage that may offset any payments required under the guarantees. We do not believe that any performance under the guarantee would have a material effect on our financial condition, results of operations or cash flows.

On February 24, 2005, the Parent Company was acquired from DEFS by DFI. On March 11, 2005, the Bureau of Competition of the FTC delivered written notice to DFI’s legal advisor that it was conducting a non-public investigation to determine whether DFI’s acquisition of us may substantially lessen competition or violate other provisions of federal antitrust laws. We have cooperated fully with this investigation.

On October 31, 2006, an FTC order and consent agreement ending its investigation became final. The order required the divestiture of TEPPCO’s 50% interest in MB Storage and certain related assets to one or more FTC-approved buyers in a manner approved by the FTC and subject to its final approval. The order contained no minimum price for the divestiture and required that TEPPCO provide the acquirer or acquirers the opportunity to hire employees who spend more than 10% of their time working on the divested assets. The order also imposes specified operational, reporting and consent requirements on us including, among other things, in the event that we acquire interests in or operate salt dome storage facilities for NGLs in specified areas. The FTC approved a buyer and sale terms for our interest in MB Storage and certain related pipelines, and we closed on such sale on March 1, 2007 (see Note 21).

On December 19, 2006, we announced that we had signed an agreement with Motiva Enterprises, LLC (“Motiva”) for us to construct and operate a new refined products storage facility to support the proposed expansion of Motiva’s refinery in Port Arthur, Texas. Under the terms of the agreement, we will construct a 5.4 million barrel refined products storage facility for gasoline and distillates. The agreement also provides for a 15-year throughput and dedication of volume, which will commence upon completion of the refinery expansion. The project includes the construction of 20 storage tanks, five 3.5-mile product pipelines connecting the storage facility to Motiva’s refinery, 15,000 horsepower of pumping capacity, and distribution pipeline connections to the Colonial, Explorer and Magtex pipelines. The storage and pipeline project is expected to be completed in mid-2009. As a part of a separate but complementary initiative, we will construct an 11-mile, 20-inch pipeline to connect the new storage

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

facility in Port Arthur to our refined products terminal in Beaumont, Texas, which is the primary origination facility for our mainline system. This associated project will facilitate connections to additional markets through the Colonial, Explorer and Magtex pipeline systems and provide the Motiva refinery with access to our pipeline system. The total cost of the project is expected to be approximately $240.0 million, including $20.0 million for the 11-mile, 20-inch pipeline. By providing access to several major outbound refined product pipeline systems, shippers should have enhanced flexibility and new transportation options. Under the terms of the agreement, if Motiva cancels the agreement prior to the commencement date of the project, Motiva will reimburse us the actual reasonable expenses we have incurred after the effective date of the agreement, including both internal and external costs that would be capitalized as a part of the project. If the cancellation were to occur in 2007, Motiva would also pay costs incurred to date plus a five percent cancellation fee, with the fee increasing to ten percent after 2007.

Substantially all of the petroleum products that we transport and store are owned by our customers. At December 31, 2006, TCTM and TE Products had approximately 3.8 million barrels and 23.7 million barrels, respectively, of products in their custody that was owned by customers. We are obligated for the transportation, storage and delivery of such products on behalf of our customers. We maintain insurance adequate to cover product losses through circumstances beyond our control.

We carry insurance coverage consistent with the exposures associated with the nature and scope of our operations. Our current insurance coverage includes (1) commercial general liability insurance for liabilities to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from earthquake, flood damage and business interruption/extra expense. For select assets, we also carry pollution liability insurance that provides coverage for historical and gradual pollution events. All coverages are subject to certain deductibles, limits or sub-limits and policy terms and conditions.

We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are commensurate with the nature and scope of our operations. The cost of our general insurance coverages has increased over the past year reflecting the changing conditions of the insurance markets. These insurance policies, except for the pollution liability policies, are through EPCO (see Note 17).

NOTE 19. CONCENTRATIONS OF CREDIT RISK

Our primary market areas are located in the Northeast, Midwest and Southwest regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. We thoroughly analyze our customers’ historical and future credit positions prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments and guarantees.

For the years ended December��31, 2006, 2005 and 2004, Valero Energy Corp. accounted for 14%, 14% and 16%, respectively, of our total consolidated revenues, and for the year ended December 31, 2006, BP Oil Supply Company accounted for 11% of our total consolidated revenues. No other single customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2006, 2005 and 2004.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 20. SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides information regarding (i) the net effect of changes in our operating assets and liabilities, (ii) non-cash investing activities and (iii) cash payments for interest for the years ended December 31, 2006, 2005 and 2004:


	For Year Ended December 31,
	2006			2005			2004
Decrease (increase) in:
Accounts receivable, trade	$	(67,317	)	$	(249,745	)	$	(181,690	)
Accounts receivable, related parties		1,736			6,638			(14,693	)
Advance to related parties		—			—			(67,006	)
Inventories		(45,002	)		(970	)		(3,433	)
Other current assets		25,812			(19,088	)		(9,920	)
Other		(9,906	)		(4,371	)		(9,163	)
Increase (decrease) in:
Accounts payable and accrued expenses		44,348			254,251			186,942
Accounts payable, related parties		15,810			(12,508	)		4,360
Other		(6,133	)		(11,253	)		19,735

Net effect of changes in operating accounts	$	(40,652	)	$	(37,046	)	$	(74,868	)


Non-cash investing activities:
Net assets transferred to Mont Belvieu Storage Partners, L.P.	$	—		$	1,429		$	—

Net assets transferred to Jonah Gas Gathering Company	$	572,609		$	—		$	—

Payable to Enterprise Gas Processing, LLC for spending for Phase V expansion of Jonah Gas Gathering Company	$	8,732		$	—		$	—


Supplemental disclosure of cash flows:
Cash paid for interest (net of amounts capitalized)	$	88,107		$	82,315		$	77,510

NOTE 21. SUBSEQUENT EVENTS

On January 23, 2007, we sold a 10-mile, 18-inch segment of pipeline to an affiliate of Enterprise for approximately $8.0 million in cash. These assets were part of our Downstream Segment and had a net book value of approximately $2.5 million. The sales proceeds were used to fund construction of a replacement pipeline in the area, in which the new pipeline provides greater operational capability and flexibility. We recognized a gain of approximately $5.5 million on this transaction.

On February 28, 2007, due to the substantial completion of inquires by the FTC into EPCO’s acquisition of us, the parties to the ASA amended it to remove Exhibit B thereto, which had been adopted to address matters the parties anticipated the FTC may consider in its inquiry. Exhibit B had set forth certain separateness and screening policies and procedures among the parties that became inapposite upon the issuance of the FTC’s order in connection with the inquiry or were already otherwise reflected in applicable FTC, SEC, NYSE or other laws, standards or governmental regulations. For further discussion of the FTC investigation, please see Note 18.

MB Storage

On March 1, 2007, TE Products sold its 49.5% ownership interest in MB Storage, its 50% ownership interest in Mont Belvieu Venture, LLC (the general partner of MB Storage) and other related assets to Louis Dreyfus

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

for a total of approximately $157.2 million in cash, which includes approximately $18.5 million for other TE Products assets. This sale was in compliance with the October 2006 order and consent agreement with the FTC and was completed in accordance with the terms and conditions approved by the FTC in February 2007. We expect to use the proceeds from the transaction to partially fund our 2007 portion of the Jonah Phase V expansion and other recently announced organic growth projects. We recognized gains of approximately $59.8 million and $13.2 million related to the sale of our equity interests and other related assets of TE Products, respectively.

In accordance with a transition services agreement between TE Products and Louis Dreyfus effective as of March 1, 2007, TE Products will provide certain administrative services to MB Storage for a period of up to two years after the sale, for a fee equal to 110% of the direct costs and expenses TE Products and its affiliates incur to provide the transition services to MB Storage. Payments for these services will be made according to the terms specified in the transition services agreement.

Junior Subordinated Notes

In May 2007, TEPPCO issued and sold $300.0 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due June 1, 2067 (“Junior Subordinated Notes”). TEPPCO used the proceeds from this subordinated debt to temporarily reduce borrowings outstanding under its Revolving Credit Facility and for general partnership purposes. TEPPCO’s payment obligations under the Junior Subordinated Notes are subordinated to all of its current and future senior indebtedness (as defined in the related indenture). TE Products, TEPPCO Midstream, TCTM and Val Verde (collectively, the “Subsidiary Guarantors”) have jointly and severally guaranteed, on a junior subordinated basis, payment of the principal or, premium, if any, and interest on the Junior Subordinated Notes.

The indenture governing the Junior Subordinated Notes allows TEPPCO to defer interest payments on one or more occasions for up to ten consecutive years, subject to certain conditions. The indenture agreement also provides that during any period in which TEPPCO defers interest payments on the Junior Subordinated Notes, subject to certain exceptions, (i) TEPPCO cannot declare or make any distributions with respect to, or redeem, purchase or make a liquidation payment with respect to, any of its equity securities; (ii) neither TEPPCO nor the Subsidiary Guarantors will make, and TEPPCO and the Subsidiary Guarantors will cause their respective majority-owned subsidiaries not to make, any payment of interest, principal or premium, if any, on or repay, purchase or redeem any of its or the Subsidiary Guarantor’s debt securities (including securities similar to the Junior Subordinated Notes) that contractually rank equally with or junior to the Junior Subordinated Notes or the guarantees, as applicable; and (iii) neither TEPPCO nor the Subsidiary Guarantors will make, and TEPPCO and the Subsidiary Guarantors will cause their respective majority-owned subsidiaries not to make, any payments under a guarantee of debt securities (including under a guarantee of debt securities that are similar to the Junior Subordinated Notes) that contractually ranks equally with or junior to the Junior Subordinated Notes or the guarantees, as applicable.

The Junior Subordinated Notes will bear interest at a fixed annual rate of 7.0% from May 2007 to June 1, 2017, payable semi-annually in arrears on June 1 and December 1 of each year, commencing December 1, 2007. After June 1, 2017, the Junior Subordinated Notes will bear interest at a variable annual rate equal to the 3-month LIBOR rate for the related interest period plus 2.7775%, payable quarterly in arrears on March 1, June 1, September 1 and December 1 of each year commencing September 1, 2017. Interest payments may be deferred on a cumulative basis for up to ten consecutive years, subject to the certain provisions. Deferred interest will bear interest at the then-prevailing interest rate on the Junior Subordinated Notes. The Junior Subordinated Notes mature in June 2067. The Junior Subordinated Notes are redeemable in whole or in part prior to June 2017 for a “make-whole” redemption price and thereafter at a redemption price equal to 100% of their principal amount plus accrued interest. The Junior Subordinated Notes are also redeemable prior to June 2017 in whole (but not in part) upon the occurrence of certain tax or rating agency events at specified redemption prices.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In connection with the issuance of the Junior Subordinated Notes, TEPPCO and its Subsidiary Guarantors entered into a Replacement Capital Covenant in favor of holders of a designated series of senior long-term indebtedness (as defined in the underlying documents) pursuant to which TEPPCO and its Subsidiary Guarantors agreed for the benefit of such debt holders that they would not redeem or repurchase or otherwise satisfy, discharge or defease any of the Junior Subordinated Notes on or before June 1, 2037, unless, subject to certain limitations, during the 180 days prior to the date of that redemption, repurchase, defeasance or purchase, TEPPCO has or one of its subsidiaries has received a specified amount of proceeds from the sale of qualifying securities that have characteristics that are the same as, or more equity-like than, the applicable characteristics of the Junior Subordinated Notes.

Treasury Locks

In February 2007, TEPPCO executed a series of treasury rate lock agreements that extended through June 2007 for a notional amount totaling $100.0 million. These agreements, which were derivative instruments, were designated as cash flow hedges to offset TEPPCO’s exposure to increases in the underlying U.S. Treasury benchmark rate that was used to establish the fixed interest rate for Junior Subordinated Notes that TEPPCO issued in May 2007. In May 2007, these treasury locks, including the treasury locks for a notional amount of $200.0 million TEPPCO entered into in October 2006 (see Note 6), were terminated concurrent with the issuance of the Junior Subordinated Notes. The termination of the treasury locks resulted in gains of $1.4 million. These gains will be deferred as adjustments to the carrying value of the Junior Subordinated Notes and will be amortized using the effective interest method as reductions to future interest expense over the fixed rate term of the Junior Subordinated Notes, which is ten years. In the event of early extinguishment of the Junior Subordinate Notes, any remaining unamortized gains would be recognized in the consolidated statement of income at the time of extinguishment.

Centennial Debt Guarantee

In May 2007, provisions of Centennial’s credit facility were amended. Provisions included in the $140.0 million Centennial credit facility required that certain financial metrics be achieved and for the guarantees to be removed by May 2007. These metrics were not achieved, and the provisions of the Centennial credit facility were amended in May 2007 to require the guarantees to remain throughout the life of the debt. As a result of the guarantee, TE Products recorded an obligation of $9.2 million, which represents the present value of the estimated amount TEPPCO would have to pay under the guarantee.

Enterprise GP Inactive 8-K/ACompletion of Acquisition or Disposition of Assets