exhibit99

EX-99.1 3 exhibit99_1.htm EXHIBIT 99.1 exhibit99_1.htm

Exhibit 99.1

Texas Eastern Products Pipeline Company, LLC and Subsidiaries

Consolidated Balance Sheet as of December 31, 2008

and Report of Independent Registered Public Accounting Firm

CONSOLIDATED BALANCE SHEET OF

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

TABLE OF CONTENTS

	Page No.
Report of Independent Registered Public Accounting Firm	1

Consolidated Balance Sheet as of December 31, 2008	2

Notes to Consolidated Balance Sheet	3
Note 1. Organization	3
Note 2. Summary of Significant Accounting Policies	3
Note 3. Recent Accounting Developments	12
Note 4. Accounting for Equity Awards	14
Note 5. Employee Benefit Plans	20
Note 6. Financial Instruments	21
Note 7. Inventories	25
Note 8. Property, Plant and Equipment	25
Note 9. Investments in Unconsolidated Affiliates	26
Note 10. Acquisitions	29
Note 11. Intangible Assets and Goodwill	32
Note 12. Debt Obligations	34
Note 13. Noncontrolling Interest	37
Note 14. Equity (Deficit)	38
Note 15. Business Segments	39
Note 16. Related Party Transactions	40
Note 17. Commitments and Contingencies	43
Note 18. Concentrations of Credit Risk	50

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 sheet of Texas Eastern Products Pipeline Company, LLC and subsidiaries (the “Company”) as of December 31, 2008. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statement based on our audit.

We conducted our audit 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 audit 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such consolidated balance sheet presents fairly, in all material respects, the financial position of Texas Eastern Products Pipeline Company, LLC and subsidiaries as of December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 1, 2, 3, 13 and 14 to the consolidated balance sheet, the accompanying consolidated balance sheet has been retrospectively adjusted for the adoption of FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51 (“SFAS 160”).

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 2, 2009

(July 6, 2009 as to the effects of the adoption of SFAS 160 and the related disclosures in Notes 1, 2, 3, 13 and 14)

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (Dollars in thousands)
	December 31,
	2008
ASSETS
Current assets:
Cash and cash equivalents	$	37
Accounts receivable, trade (net of allowance for doubtful accounts of $2,559)		790,374
Accounts receivable, related parties		15,758
Inventories		52,906
Other		48,495
Total current assets		907,570
Property, plant and equipment, at cost (net of accumulated depreciation of $678,784)		2,439,910
Equity investments		1,255,923
Intangible assets (net of accumulated amortization of $158,391)		207,653
Goodwill		106,611
Other assets		132,161
Total assets	$	5,049,828

LIABILITIES AND EQUITY

Current liabilities:
Accounts payable and accrued liabilities	$	792,469
Accounts payable, related parties		17,219
Accrued interest		36,401
Other accrued taxes		23,038
Other		30,869
Total current liabilities		899,996
Long-term debt:
Senior notes		1,713,291
Junior subordinated notes		299,574
Other long-term debt		516,654
Total long-term debt		2,529,519
Other liabilities and deferred credits		28,826
Commitments and contingencies
Equity (deficit):
Texas Eastern Products Pipeline Company, LLC member’s equity (deficit):
Member’s equity (deficit)		(110,301	)
Accumulated other comprehensive loss		(6,302	)
Total Texas Eastern Products Pipeline Company, LLC member’s equity (deficit)		(116,603	)
Noncontrolling interest		1,708,090
Total equity (deficit)		1,591,487
Total liabilities and equity (deficit)	$	5,049,828

See Notes to Consolidated Balance Sheet.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET

Except 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.

NOTE 1. ORGANIZATION

Texas Eastern Products Pipeline Company, LLC (the “Company”), is a Delaware limited liability company that owns a 2% general partner interest in TEPPCO Partners, L.P. (“TEPPCO”) and acts as the managing general partner of TEPPCO. We have no independent operations and no material assets outside those of TEPPCO. TEPPCO is a publicly traded, diversified energy logistics company with operations that span much of the continental United States. Its limited partner units (“Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “TPP.” TEPPCO was formed in March 1990 as a Delaware limited partnership. TEPPCO operates principally through TE Products Pipeline Company, LLC (“TE Products”), TCTM, L.P. (“TCTM”), TEPPCO Midstream Companies, LLC (“TEPPCO Midstream”) and TEPPCO Marine Services, LLC (“TEPPCO Marine Services”).

Our membership interests are owned by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded partnership controlled by Dan L. Duncan. Enterprise GP Holdings is an affiliate of EPCO, Inc. (“EPCO”), a privately held company also controlled by Dan L. Duncan. Mr. Duncan and certain of his affiliates, including DFI GP Holdings L.P. (“DFIGP”), Enterprise GP Holdings and Dan Duncan LLC, a privately held company controlled by him, control us, TEPPCO and Enterprise Products Partners L.P. (“Enterprise Products Partners”) and its affiliates, including Duncan Energy Partners L.P. (“Duncan Energy Partners”). EPCO and its affiliates and Enterprise GP Holdings are not liable for our obligations nor do we assume or guarantee the obligations of such affiliates. We do not receive financial assistance from or own interests in any other EPCO affiliates other than our general partner interests in TEPPCO. Enterprise GP Holdings, DFIGP and other entities controlled by Mr. Duncan own 17,073,315 of TEPPCO’s Units. Our executive officers are employees of EPCO, and most of the other personnel working on behalf of TEPPCO also are employees of EPCO. Under an amended and restated administrative services agreement (“ASA”), EPCO performs 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.

References to “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 as part of a common control group with EPCO, Enterprise GP Holdings or TEPPCO and its subsidiaries.

Effective January 1, 2009, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 160, Noncontrolling Interests in Consolidated Financial Statements – an Amendment to ARB No. 51. SFAS 160 established accounting and reporting standards for noncontrolling interests, which were previously identified as minority interest in our consolidated balance sheet. The presentation and disclosure requirements of SFAS 160 have been applied retrospectively to the consolidated balance sheet and notes included in this Current Report on Form 8-K.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

We adhere to the following significant accounting policies in the preparation of our consolidated balance sheet.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

Business Segments

We operate and report in four business segments:

§	pipeline transportation, marketing and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals (“Downstream Segment”);

§	gathering, pipeline transportation, marketing and storage of crude oil, distribution of lubrication oils and specialty chemicals and fuel transportation services (“Upstream Segment”);

§	gathering of natural gas, fractionation of natural gas liquids (“NGLs”) and pipeline transportation of NGLs (“Midstream Segment”); and

§	marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges (“Marine Services Segment”).

Our reportable segments offer different products and services and are managed separately because each requires different business strategies (see Note 15).

Certain of our interstate pipeline 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, natural gas, asphalt, heavy fuel oil and other heated oil products, collectively, as “petroleum products” or “products.”

Allowance for Doubtful Accounts

Our allowance for doubtful accounts balance is generally determined based on specific identification and estimates of future uncollectible accounts, as appropriate. 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 estimates associated with the allowance for doubtful accounts to assess the sufficiency of the reserves to cover potential losses. The following table presents the activity of our allowance for doubtful accounts for the year ended December 31, 2008:

	For Year Ended December 31,
	2008

Balance at January 1	$	125
Charges to expense (1)		2,434
Balance at December 31	$	2,559

_________________

(1)	Charges to expense include the write-off of receivables primarily attributable to two customer bankruptcies.

Asset Retirement Obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their 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. See Note 8 for further information regarding our AROs.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

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 principal 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 fractionation facilities in Colorado. The Marine Services Segment’s principal assets consist of tow boats and tank barges used in the marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products.

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 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.

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, 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 sufficient information becomes available for us to reasonably estimate the settlement dates of the retirement obligations.

Basis of Presentation and Principles of Consolidation

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 balance sheet and that of TEPPCO are few. The most significant difference is that relating to noncontrolling 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 13 for additional information regarding noncontrolling interest ownership in our consolidated subsidiaries).

The balance sheet includes our accounts on a consolidated basis. We have eliminated all intercompany items in consolidation.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and liquid investments 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.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

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 rates used to capitalize interest on borrowed funds was 6.43% for the year ended December 31, 2008.

Consolidation Policy

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

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

Our investments in Seaway Crude Pipeline Company (“Seaway”) and Centennial Pipeline LLC (“Centennial”) are accounted for under the equity method of accounting, as we own 50% ownership interests in these entities and have 50% equal management with the other joint venture participants. Our investment in Texas Offshore Port System (a development stage enterprise) is accounted for under the equity method of accounting, as we own a 33% ownership interest in this entity and have equal voting rights with the other joint venture participants. Our investment in Jonah Gas Gathering Company (“Jonah”) is accounted for under the equity method of accounting, as we have 50% equal management with the other participant, even though we own an approximate 80% economic interest in the partnership.

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

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 with input from legal counsel assesses 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 result in proceedings, our management with input from 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.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

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

Current Assets and Current Liabilities

We present, as individual captions in our consolidated balance sheet, all components of current assets and current liabilities that exceed five percent of total current assets and liabilities, respectively.

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. None of our estimated environmental remediation liabilities are discounted to present value since the ultimate amount and timing of cash payments for such liabilities are not readily determinable. Expenditures to mitigate or prevent future environmental contamination are capitalized.

At December 31, 2008, our accrued liabilities for environmental remediation projects totaled $6.9 million. These amounts were derived from a range of reasonable estimates based upon studies and site surveys. Unanticipated changes in circumstances and/or legal requirements could result in expenses being incurred in future periods in addition to an increase in actual cash required to remediate contamination for which we are responsible.

The following table presents the activity of our environmental reserve for the year ended December 31, 2008:

	For Year Ended December 31,
	2008

Balance at January 1	$	4,002
Charges to expense		4,981
Deductions and other		(2,047	)
Balance at December 31	$	6,936

Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principals (“GAAP”) 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.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

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 financial instruments approximates their fair value due to their short-term nature. The fair values of these financial instruments are represented in our consolidated balance sheet.

Financial Instruments

We account for 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 financial instruments (including certain financial 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 financial instrument depends on the intended use of the financial instrument and the resulting designation, which is established at the inception of a financial instrument.

Our financial instruments consist primarily of contracts for the purchase and sale of petroleum products in connection with our crude oil marketing activities. Substantially all financial instruments related to our crude oil marketing activities meet the normal purchases and sales criteria of SFAS 133, as amended, 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 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 financial instruments 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 financial instruments 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 financial instrument is not highly effective as a hedge or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.

For financial instruments designated as fair value hedges, changes in the fair value of a financial instrument 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 financial instrument and hedged asset or liability reflected on the balance sheet. Changes in the fair value of a financial instrument 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 financial instrument 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 financial instrument contract and the hedged item over time. The ineffective portion of the change in fair value of a financial 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 financial instrument is no longer effective in offsetting changes in the fair value or cash flows of the hedged item, or the financial instrument expires or is sold, terminated, or exercised, or the financial

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

instrument 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 financial instrument as a hedging instrument is no longer appropriate.

When hedge accounting is discontinued because it is determined that the financial instrument no longer qualifies as an effective fair value hedge, we continue to carry the financial instrument 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 financial instrument 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 financial instrument 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 financial instrument at its fair value on the balance sheet and recognize any subsequent changes in its fair value in earnings.

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired. 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 11 for a further discussion of our goodwill).

Income Taxes

Our limited liability company is not directly 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 taxes on its share of our taxable income.

Revised Texas Franchise Tax

In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, our tax status in the State of Texas has changed from non-taxable to taxable. TE Products (formerly TE Products Pipeline Company, Limited Partnership) and TEPPCO Midstream (formerly TEPPCO Midstream Companies, L.P.) each converted into a Texas limited partnership and immediately thereafter each merged into a separate newly-formed Texas limited liability company on June 30, 2007. The pre-June 30, 2007 revenue of each of these former partnerships was not subject to the Revised Texas Franchise Tax because the former partnerships did not conduct business in Texas after June 30, 2007.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

For the year ended December 31, 2008, our current and deferred tax liabilities are applicable to our state tax obligations under the Revised Texas Franchise Tax. At December 31, 2008, we had a current tax liability of $3.9 million and a deferred tax liability of less than $0.1 million. During the year ended December 31, 2008, we recorded an increase in current income tax liability of $4.5 million and a less than $0.1 million increase to deferred tax liability.

Accounting for Uncertainty in Income Taxes

In accordance with Financial Accounting Standards Board (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes, we must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized upon ultimate settlement with a taxing authority with full knowledge of all relevant information.

Intangible Assets and Excess Investments

Intangible assets on the consolidated balance sheet consist primarily of gathering contracts assumed in the acquisition of Val Verde on June 30, 2002, a fractionation agreement, customer contracts related to the acquisition of crude oil supply and transportation assets, customer relationships and non-compete agreements related to the acquisition of the marine assets and other intangible assets (see Note 11). Included in equity investments on the consolidated balance sheet are excess investments in Centennial, 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 11).

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, which is amortized on a straight-line basis over the life of the assets constructed (see Note 11).

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 purchase, sale and exchange agreements. Receivables and payables arising from exchange 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. Our Upstream Segment also acquires and disposes of crude oil under purchase, sale, buy/sale and exchange agreements. Additionally, our Upstream Segment acquires crude oil inventory through a pipeline loss allowance (“PLA”) in certain of our pipeline tariffs, whereby the shipper conveys physical crude oil to us, in addition to a cash tariff payment for transportation services, in exchange for our bearing the risk of pipeline volumetric losses. These PLA barrels are recorded to inventory based on the current market value at the time the barrels are transported and later sold. Inventories of materials and supplies, used for ongoing replacements and expansions, are carried at cost.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

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 a 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 average market prices, which is representative of the estimated value of the imbalances upon final settlement.

Noncontrolling Interest

As presented in our Consolidated Balance Sheet, noncontrolling 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. For financial reporting purposes, the assets and liabilities of TEPPCO are consolidated with those of the Parent Company, with any third-party ownership in such amounts presented as noncontrolling interest. See Note 13 for information regarding noncontrolling interest.

Property, Plant and Equipment

Property, plant and equipment is recorded 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.

Equity Awards

We account for equity awards in accordance with SFAS No. 123(R), Share-Based Payment. SFAS 123(R) requires us to recognize compensation expense related to equity awards based on the fair value of the award at grant date. The fair value of restricted unit awards is based on the market price of the underlying Units on the date of grant. The fair value of other equity awards is estimated using the Black-Scholes option pricing model. Under SFAS 123(R), the fair value of an equity award is amortized to earnings on a straight-line basis over the requisite service or vesting period of the equity awards. As used in the context of the compensation plans, the term “restricted unit” represents a time-vested unit under SFAS 123(R). Such awards are non-vested until the required service period expires. Compensation for liability awards is recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. Liability awards will be settled in cash upon vesting. We accrue compensation expense based upon the terms of each plan (see Note 4).

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NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

NOTE 3. RECENT ACCOUNTING DEVELOPMENTS

The accounting standard setting bodies have recently issued the following accounting guidance that may affect our future financial statements: SFAS 141(R), Business Combinations; FASB Staff Position (“FSP”) SFAS 142-3, Determination of the Useful Life of Intangible Assets; SFAS No. 157, Fair Value Measurements; SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133; EITF 08-6, Equity Method Investment Accounting Considerations; and SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51.

SFAS No. 141(R), Business Combinations. SFAS 141(R) replaces SFAS No. 141, Business Combinations and was effective January 1, 2009. SFAS 141(R) retains the fundamental requirements of SFAS 141 in that the acquisition method of accounting (previously termed the “purchase method”) is used for all business combinations and for the “acquirer” to be identified for each business combination. SFAS 141(R) defines the acquirer as the entity that obtains control of one or more businesses in a business combination and establishes the acquisition date as the date that the acquirer achieves control. This new guidance also retains guidance in SFAS 141 for identifying and recognizing intangible assets separately from goodwill. SFAS 141(R) will have an impact on the way in which we evaluate acquisitions.

The objective of SFAS 141(R) is to improve the relevance, representational faithfulness, and comparability of the information a reporting entity provides in its financial reports about business combinations and their effects. To accomplish this, SFAS 141(R) establishes principles and requirements for how the acquirer:

§	recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interests in the acquiree.

recognizes and measures the goodwill acquired in the business combination or a gain resulting from a bargain purchase. SFAS 141(R) defines a bargain purchase as a business combination in which the total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of the consideration transferred plus any noncontrolling interest in the acquiree, and requires the acquirer to recognize that excess in net income as a gain attributable to the acquirer.

§	determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.

SFAS 141(R) also requires that direct costs of an acquisition (e.g. finder’s fees, outside consultants, etc.) be expensed as incurred and not capitalized as part of the purchase price.

FSP No. FAS 142-3, Determination of the Useful Life of Intangible Assets. In April 2008, the FASB issued FSP No. 142-3, which revised the factors that should be considered in developing renewal or extension assumptions used in determining the useful lives of recognized intangible assets under SFAS No. 142, Goodwill and Other Intangible Assets. These revisions are intended to improve consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of such assets under SFAS 141(R) and other accounting guidance. The measurement and disclosure requirements of this new guidance will be applied to intangible assets acquired after January 1, 2009. Our adoption of this guidance is not expected to have a material impact on our consolidated financial statement.

SFAS No. 157, Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Although certain provisions of SFAS 157 were effective January 1, 2008, the remaining guidance of this new standard applicable to nonfinancial assets and liabilities was effective January 1, 2009. See Note 6 for information regarding fair value-related disclosures required for 2008 in connection with SFAS 157.

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SFAS 157 applies 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 are required to disclose the extent to which fair value is used to measure assets and liabilities, the inputs used to develop such measurements, and the effect of certain of the measurements on earnings (or changes in net assets) during a period. Our adoption of this guidance is not expected to have a material impact on our consolidated financial statement. SFAS 157 will impact the valuation of assets and liabilities (and related disclosures) in connection with future business combinations and impairment testing.

SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities - An Amendment of FASB Statement No. 133. SFAS 161 revised the disclosure requirements for financial instruments and related hedging activities to provide users of financial statements with an enhanced understanding of (i) why and how an entity uses financial instruments, (ii) how an entity accounts for financial instruments and related hedged items under SFAS 133, Accounting for Derivative Instruments and Hedging Activities, and its related interpretations and (iii) how financial instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.

SFAS 161 requires qualitative disclosures about objectives and strategies for using financial instruments, quantitative disclosures about fair value amounts of and gains and losses on financial instruments and disclosures about credit risk-related contingent features in financial instrument agreements. SFAS 161 was effective January 1, 2009, and we will apply its requirements beginning with the first quarter of 2009.

EITF 08-6, Equity Method Investment Accounting Considerations. EITF 08-6 clarifies the accounting for certain transactions and impairment considerations involving equity method investments under SFAS 141(R) and SFAS 160. EITF 08-6 generally requires that (i) transaction costs should be included in the initial carrying value of an equity method investment; (ii) an equity method investor shall not test separately an investee’s underlying assets for impairment, rather such testing should be performed in accordance with Accounting Principles Board Opinion No. 18 (i.e., on the equity method investment itself); (iii) an equity method investor shall account for a share issuance by an investee as if the investor had sold a proportionate share of its investment (any gain or loss to the investor resulting from the investee’s share issuance shall be recognized in earnings); and (iv) a gain or loss should not be recognized when changing the method of accounting for an investment from the equity method to the cost method. EITF 08-6 was effective January 1, 2009.

SFAS 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51. SFAS 160 established accounting and reporting standards for noncontrolling interests, which have been referred to as minority interests in prior accounting literature. SFAS 160 was effective January 1, 2009. A noncontrolling interest is that portion of equity in a consolidated subsidiary not attributable, directly or indirectly, to a reporting entity. This new standard requires, among other things, that (i) ownership interests of noncontrolling interests be presented as a component of equity, including accumulated other comprehensive income, on the balance sheet (i.e., elimination of the “mezzanine” presentation); (ii) elimination of minority interest expense as a line item on the statement of income and, as a result, that net income and other comprehensive income be allocated between the reporting entity and noncontrolling interests on the face of the statement of income; and (iii) enhanced disclosures regarding noncontrolling interests.

Effective January 1, 2009, we adopted the provisions of SFAS 160. The presentation and disclosure requirements of SFAS 160 have been applied retrospectively to the consolidated balance sheet and notes included in this Current Report on Form 8-K.

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NOTE 4. ACCOUNTING FOR EQUITY AWARDS

1999 Plan

The Texas Eastern Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan (“1999 Plan”) provides for the issuance of phantom unit awards as incentives to key employees. These liability awards are settled for cash based on the fair market value of the vested portion of the phantom units at redemption dates in each award. The fair market value of each phantom unit award is equal to the closing price of a TEPPCO Unit on the NYSE on the redemption date. Each participant is required to redeem their phantom units as they vest. Each participant is also entitled to cash distributions equal to the product of the number of phantom units granted to the participant and the per Unit cash distribution that TEPPCO paid to its unitholders. Grants under the 1999 Plan are subject to forfeiture if the participant’s employment with EPCO is terminated.

A total of 18,600 phantom units were outstanding under the 1999 Plan at December 31, 2008. In April 2008, 13,000 phantom units vested and $0.4 million was paid out to one participant in the second quarter of 2008. The remaining awards outstanding at December 31, 2008 cliff vest as follows: 13,000 in April 2009 and 5,600 in January 2010. At December 31, 2008, we had an accrued liability balance of $0.4 million for compensation related to the 1999 Plan. For the year ended December 31, 2008, participants received $62 thousand in cash distributions.

2000 LTIP

The Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) provides key employees incentives to achieve improvements in TEPPCO’s financial performance. Generally, upon the close of a three-year performance period, the participant will receive a cash payment equal to (i) the applicable “performance percentage” as specified in the award multiplied by (ii) the number of phantom units granted under the award multiplied by (iii) 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. In addition, during the performance period, each participant is entitled to cash distributions equal to the product of the number of phantom units granted to the participant and the per Unit cash distribution that TEPPCO paid to its unitholders. Grants under the 2000 LTIP are accounted for as liability awards and subject to forfeiture if the participant’s employment with EPCO is terminated, with customary exceptions for death, disability or retirement.

A participant’s “performance percentage” is based upon an improvement in Economic Value Added during a given three-year performance period over the Economic Value Added for the three-year period immediately preceding the performance period. The term “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. In this context, EBITDA means earnings before net interest expense, other income, depreciation and amortization and TEPPCO’s proportional interest in the EBITDA of its joint ventures, except that our chief executive officer 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 carrying value of property, plant and equipment, plus long-term inventory, and the gross carrying value of intangible assets and equity investments. The cost of capital is determined at the date each award is granted.

At December 31, 2008, a total of 11,300 phantom units vested and will be paid out to participants in the first quarter of 2009. At December 31, 2008, we had an accrued liability balance of $0.2 million for compensation related to the 2000 LTIP. After payout in the first quarter of 2009 on awards which vested on December 31, 2008, there will be no remaining phantom units outstanding under the 2000 LTIP. For the year ended December 31, 2008, participants received $38 thousand in cash distributions.

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2005 Phantom Unit Plan

The Texas Eastern Products Pipeline Company, LLC 2005 Phantom Unit Plan (“2005 Phantom Unit Plan”) provides key employees incentives to achieve improvements in TEPPCO’s financial performance. Generally, upon the close of a three-year performance period, the participant will receive a cash payment equal to (i) the applicable “performance percentage” as specified in the award multiplied by (ii) the number of phantom units granted under the award multiplied by (iii) 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. In addition, during the performance period, each participant is entitled to cash distributions equal to the product of the number of phantom units granted to the participant and the per Unit cash distribution that TEPPCO paid to its unitholders. Grants under the 2005 Phantom Unit Plan are accounted for as liability awards and subject to forfeiture if the participant’s employment with EPCO is terminated, with customary exceptions for death, disability or retirement.

Generally, a participant’s performance percentage is based upon the achievement of a cumulative EBITDA for the performance period of an amount equal to the sum of the EBITDA targets established for each of the three years of the performance period. In this context, EBITDA means earnings before net interest expense, other income, depreciation and amortization and TEPPCO’s proportional interest in the EBITDA of its joint ventures, except that our chief executive officer may exclude gains or losses from extraordinary, unusual or non-recurring items.

At December 31, 2008, a total of 36,600 phantom units vested and will be paid out to participants in the first quarter of 2009. At December 31, 2008, we had an accrued liability balance of $0.6 million for compensation related to the 2005 Phantom Unit Plan. After the payout in the first quarter of 2009 on awards which vested on December 31, 2008, there will be no remaining phantom units outstanding under the 2005 Phantom Unit Plan. For the year ended December 31, 2008, participants received $0.1 million in cash distributions.

2006 LTIP

The EPCO, Inc. 2006 TPP Long-Term Incentive Plan (“2006 LTIP”) provides for awards of TEPPCO Units and other rights to our non-employee directors and to certain employees of EPCO and its affiliates providing services to us. Awards granted under the 2006 LTIP may be in the form of restricted units, phantom units, unit options, UARs and distribution equivalent rights. The exercise price of unit options or UARs awarded to participants is determined by the Audit, Conflicts and Governance Committee of our Board of Directors (“ACG 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 is administered by the ACG Committee. Subject to adjustment as provided in the 2006 LTIP, awards with respect to up to an aggregate of 5,000,000 of TEPPCO’s Units may be granted under the 2006 LTIP. We reimburse EPCO for the costs allocable to 2006 LTIP awards made to employees who work in our business. The 2006 LTIP is effective until the earlier of (i) December 8, 2016, (ii) the time by which all available TEPPCO Units under the 2006 LTIP have been delivered to participants, or (iii) the time of termination of the 2006 LTIP by EPCO or the ACG Committee. The 2006 LTIP may be amended or terminated at any time by the board of directors of EPCO, which is an affiliate of the Company, or the ACG Committee; however, any material amendment, such as a material increase in the number of TEPPCO 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 our unitholders. The ACG Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in awards under the 2006 LTIP in specified circumstances. After giving effect to outstanding unit options and restricted units at December 31, 2008, and the forfeiture of restricted units through December 31, 2008, a total of 4,487,084 additional TEPPCO Units could be issued under the 2006 LTIP in the future.

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Unit Options

The information in the following table presents unit option activity under the 2006 LTIP for the periods indicated:

					Weighted-
			Weighted-		Average
			Average		Remaining
	Number		Strike Price		Contractual
	of Units		(dollars/Unit)		Term (in years)
Unit Options:
Outstanding at December 31, 2007 (1)		155,000	$	45.35
Granted (2)		200,000		35.86
Outstanding at December 31, 2008		355,000		40.00		4.57

Options exercisable at:
December 31, 2008		--	$	--		--

(1)	During 2008, these unit option grants were amended. The expiration dates of these awards granted on May 22, 2007 were modified from May 22, 2017 to December 31, 2012.

(2)

The total grant date fair value of these awards granted on May 19, 2008 was $0.3 million based upon the following assumptions: (i) expected life of the option of 4.7 years; (ii) risk-free interest rate of 3.3%; (iii) expected distribution yield on TEPPCO Units of 7.9%; (iv) estimated forfeiture rate of 17%; and (v) expected Unit price volatility on TEPPCO Units of 18.7%.

At December 31, 2008, total unrecognized compensation cost related to nonvested unit options granted under the 2006 LTIP was an estimated $0.6 million. We expect to recognize this cost over a weighted-average period of 2.95 years.

Restricted Units

The following table presents restricted unit activity for the periods indicated:

				Weighted-
				Average Grant
	Number			Date Fair Value
	of Units			per Unit (1)
Restricted Units at December 31, 2007		62,400
Granted (2)		96,900		$	29.54
Vested		(1,000	)	$	40.61
Forfeited		(1,000	)	$	35.86
Restricted Units at December 31, 2008		157,300

___________________________

(1)	Determined by dividing the aggregate grant date fair value of awards (including an allowance for forfeitures) by the number of awards issued.

(2)	Aggregate grant date fair value of restricted unit awards issued during 2008 was $2.8 million based on grant date market prices ranging from $34.63 to $35.86 per TEPPCO Unit and an estimated forfeiture rate of 17%.

The total fair value of our restricted unit awards that vested during the year ended December 31, 2008 was $24 thousand. At December 31, 2008, total unrecognized compensation cost related to restricted units was $3.7 million, and these costs are expected to be recognized over a weighted-average period of 2.8 years.

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Phantom Units

At December 31, 2008, a total of 1,647 phantom units were outstanding, which have been awarded under the 2006 LTIP to three of the non-executive members of our board of directors. Each phantom unit will pay out in cash on April 30, 2011 or, if earlier, the date the director is no longer serving on the board of directors, whether by voluntarily resignation or otherwise. Each participant is also entitled to cash distributions equal to the product of the number of phantom units granted to the participant and the per TEPPCO Unit cash distribution that TEPPCO paid to its unitholders. Phantom unit awards to non-executive directors are accounted for in a manner similar to SFAS 123(R) liability awards.

UARs

At December 31, 2008, a total of 431,377 UARs were outstanding, which have been awarded under the 2006 LTIP to non-executive members of our board of directors and to certain employees providing services directly to us.

Non-Executive Members of our Board of Directors. At December 31, 2008, a total of 95,654 UARs, awarded to non-executive members of our board of directors under the 2006 LTIP, were outstanding at a weighted average exercise price of $41.82 per TEPPCO Unit (66,225 UARs issued in 2007 at an exercise price of $45.30 per TEPPCO Unit to the then three non-executive members of our board of directors and 29,429 UARs issued in 2008 at an exercise price of $33.98 per TEPPCO Unit to a non-executive member of our board of directors in connection with his election to the board). The UARs are subject to five year cliff vesting and will vest earlier if the director dies or is removed from, or not re-elected or appointed to, the board of directors for reasons other than his voluntary resignation or unwillingness to serve. When the UARs become payable, the director will receive a payment in cash equal to the fair market value of the TEPPCO Units subject to the UARs on the payment date over the fair market value of the TEPPCO Units subject to the UARs on the date of grant. UARs awarded to non-executive directors are accounted for similar to SFAS 123(R) liability awards.

Employees. At December 31, 2008, a total of 335,723 UARs, awarded under the 2006 LTIP to certain employees providing services directly to us, were outstanding at an exercise price of $45.35 per TEPPCO Unit. The UARs are subject to five year cliff vesting and are subject to forfeiture. When the UARs become payable, the awards will be redeemed in cash (or, in the sole discretion of the ACG Committee, TEPPCO Units or a combination of cash and TEPPCO Units) equal to the fair market value of the TEPPCO Units subject to the UARs on the payment date over the fair market value of the TEPPCO Units subject to the UARs on the date of grant. In addition, for each calendar quarter from the grant date until the UARs become payable, each holder will receive a cash payment equal to the product of (i) the per TEPPCO Unit cash distribution paid to our unitholders during such calendar quarter less the quarterly distribution amount in effect at the time of grant multiplied by (ii) the number of TEPPCO Units subject to the UAR. UARs awarded to employees are accounted for as liability awards under SFAS 123(R) since the current intent is to settle the awards in cash.

Employee Partnerships

EPCO formed TEPPCO Unit L.P. (“TEPPCO Unit I”) and TEPPCO Unit II L.P. (“TEPPCO Unit II”) (collectively, “Employee Partnerships”) to serve as an incentive arrangement for key employees of EPCO by providing them with a “profits interest” in the Employee Partnerships. Certain EPCO employees who perform services for us, including our chief executive officer and other executive officers, were issued Class B limited partner interests and admitted as Class B limited partners without any capital contribution. The profits interest awards (i.e., the Class B limited partner interests) in the Employee Partnerships entitles each holder to participate in the appreciation in value of TEPPCO Units. The Class B limited partner interests are subject to forfeiture if the participating employee’s employment with EPCO is terminated prior to vesting of the profit interest, with customary

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exceptions for death, disability and certain retirements. The risk of forfeiture associated with the Class B limited partner interests in the Employee Partnerships will also lapse upon certain change in control events.

The following is a discussion of the significant terms of the Employee Partnerships.

TEPPCO Unit I. On September 4, 2008, EPCO formed a Delaware limited partnership, TEPPCO Unit I, for which it serves as the general partner, to serve as an incentive arrangement for certain employees of EPCO, including our executive officers. EPCO Holdings, Inc. (“EPCO Holdings”), an affiliate of EPCO, contributed approximately $7.0 million to TEPPCO Unit I as a capital contribution with respect to its interest and was admitted as the Class A limited partner of TEPPCO Unit I. TEPPCO Unit I purchased 241,380 Units directly from TEPPCO in an unregistered transaction at the public offering price concurrently with the closing of TEPPCO’s September 2008 equity offering. Certain EPCO employees who perform services for us, including executive officers, were issued Class B limited partner interests and admitted as Class B limited partners of TEPPCO Unit I without any capital contribution. The Class B limited partner interests, which entitle the holder to participate in the appreciation in value of TEPPCO’s Units, are equity-based compensatory awards designed to incentivize officers and employees of EPCO who perform services for us to enhance the long-term value of TEPPCO’s Units.

Compensation expense attributable to these awards is based on the estimated grant date fair value of each award. A portion of the fair value of these equity-based awards is allocated to us under the ASA as a non-cash expense. We are not responsible for reimbursing EPCO for any expenses of TEPPCO Unit I, including the value of any contributions of cash or TEPPCO’s Units made by private company affiliates of EPCO at the formation of TEPPCO Unit I.

Unless otherwise agreed to by EPCO, EPCO Holdings and a majority in interest of the Class B limited partners or unless other specified dissolution events occur, TEPPCO Unit I will terminate at the earlier of (i) thirty days following September 4, 2013 (five years from the date of TEPPCO Unit I’s agreement of limited partnership) or (ii) a change in control of EPCO, Enterprise GP Holdings, TEPPCO or us. Summarized below are certain material terms regarding distributions by TEPPCO Unit I to its partners:

Distributions of Cash Flow – Each quarter, 100% of the cash distributions received by the TEPPCO Unit I from TEPPCO in that quarter will be distributed to the Class A limited partner until the Class A limited partner has received an amount equal to the Class A preferred return (as defined below), and any excess distributions received by TEPPCO Unit I in that quarter will be distributed to the Class B limited partners. The Class A preferred return equals the Class A capital base (as defined below) multiplied by a floating rate determined by EPCO, in its sole discretion, that will be no less than 4.5% and no greater than 5.725% per annum. The Class A limited partner’s capital base equals the amount of any contributions of cash or cash equivalents made by the Class A limited partner to TEPPCO Unit I, plus any unpaid Class A preferred return from prior periods, less any distributions of cash or Units previously made to the Class A limited partner by TEPPCO Unit I.

Liquidating Distributions – Upon liquidation of TEPPCO Unit I (after satisfaction of any debt or other obligations of TEPPCO Unit I), Units having a fair market value equal to the Class A capital base will be distributed to EPCO Holdings, plus any accrued Class A preferred return for the quarter in which liquidation occurs. Any remaining Units will be distributed to the Class B limited partners.

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

The grant date fair value of the Class B limited partner interests in TEPPCO Unit I was $2.1 million. This fair value was estimated using the Black-Scholes option pricing model, which incorporates various assumptions

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including (i) an expected life of the awards of five years, (ii) risk-free interest rate of 2.87%, (iii) an expected distribution yield on TEPPCO’s Units of 7.28%, and (iv) an expected Unit price volatility for TEPPCO’s Units of 16.42%. At December 31, 2008, there was an estimated $1.7 million of unrecognized compensation cost related to TEPPCO Unit I. We will recognize our share of these costs in accordance with the ASA over a weighted average period of 4.68 years.

TEPPCO Unit II. On November 13, 2008, EPCO formed a Delaware limited partnership, TEPPCO Unit II, for which it serves as the general partner, to serve as an incentive arrangement for Mr. Thompson, our chief executive officer and an employee of EPCO. On the same date, Duncan Family Interests, Inc. (“DFI”), an affiliate of EPCO, contributed to TEPPCO Unit II 123,185 Units (with a value of approximately $3.1 million, based on the closing price of TEPPCO’s Units on the NYSE on November 12, 2008) and was admitted as the Class A limited partner of TEPPCO Unit II. Mr. Thompson was issued 100% of the Class B limited partner interests and admitted as Class B limited partner of TEPPCO Unit II without any capital contribution. The Class B limited partner interest, which entitles Mr. Thompson to participate in the appreciation in value of TEPPCO’s Units, is an equity-based compensatory award designed to incentivize him to enhance the long-term value of TEPPCO’s Units.

Compensation expense attributable to this award is based on the estimated grant date fair value of the award and the fair value is allocated to us under the ASA. We are responsible for reimbursing EPCO for the amount of distributions of cash or securities, if any, made by TEPPCO Unit II to Mr. Thompson.

Unless otherwise agreed to by EPCO, DFI and the Class B limited partner or unless other specified dissolution events occur, TEPPCO Unit II will terminate at the earlier of (i) thirty days following November 13, 2013 (five years from the date of TEPPCO Unit II’s agreement of limited partnership) or (ii) a change in control of us, TEPPCO or EPCO. Summarized below are certain material terms regarding distributions by TEPPCO Unit II to its partners:

Distributions of Cash Flow – Each quarter, 100% of the cash distributions received by TEPPCO Unit II from TEPPCO in that quarter will be distributed to the Class A limited partner until the Class A limited partner has received an amount equal to the Class A preferred return (as defined below), and any remaining excess distributions received by TEPPCO Unit II in that quarter will be distributed to the Class B limited partner. The Class A preferred return equals the Class A capital base (as defined below) multiplied by a rate of 6.31% per annum. The Class A limited partner’s capital base equals the amount of any contributions of cash or cash equivalents made by the Class A limited partner to TEPPCO Unit II, plus any unpaid Class A preferred return from prior periods, less any distributions of cash or Units previously made to the Class A limited partner by TEPPCO Unit II (as described below).

Liquidating Distributions – Upon liquidation of TEPPCO Unit II (after satisfaction of any debt or other obligations of TEPPCO Unit II), Units having a fair market value equal to the Class A capital base will be distributed to DFI, plus any accrued Class A preferred return for the quarter in which liquidation occurs. Any remaining Units will be distributed to the Class B limited partner.

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

The grant date fair value of the Class B limited partner interest in TEPPCO Unit II was $1.4 million. This fair value was estimated using the Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the awards of five years, (ii) a risk-free interest rate of 2.37%, (iii) an expected distribution yield on TEPPCO’s Units of 13.87%, and (iv) an expected Unit price volatility for TEPPCO’s Units of 66.38%. At December 31, 2008, there was an estimated $1.3 million of unrecognized compensation cost related to

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TEPPCO Unit II. We will recognize our share of these costs in accordance with the ASA over a weighted average period of 4.87 years.

NOTE 5. EMPLOYEE BENEFIT PLANS

Retirement Plan

The TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) was a non-contributory, trustee-administered pension plan. 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 this plan.

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 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 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 purchased an annuity contract from an insurance company in which the plan participants own the annuity, absolving us of any future obligation to the participants.

As of December 31, 2008, all benefit obligations to TEPPCO RCBP plan participants have been settled. During the first quarter of 2008, the remaining balance of the TEPPCO RCBP was transferred to an EPCO benefit plan.

Other Plans

EPCO maintains defined contribution plans for the benefit of employees providing services to us, and we reimburse EPCO for the cost of maintaining these plans in accordance with the ASA (see Note 16 for additional information related to the costs and expenses allocated to us for employee benefits).

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

NOTE 6. FINANCIAL INSTRUMENTS

The following table presents the estimated fair values of our financial instruments at December 31, 2008:

	Carrying		Fair
Financial Instruments	Value		Value

Financial assets:
Cash and cash equivalents (1)	$	37	$	37
Accounts receivable (1)		790,374		790,374
Commodity financial instruments (2) (3)		15,711		15,711

Financial liabilities:
Accounts payable and accrued liabilities (1)		792,469		792,469
Fixed-rate debt (principal amount) (4)		2,000,000		1,553,218
Variable-rate debt (5)		516,654		516,654
Commodity financial instruments (2) (3)		15,708		15,708

______________

(1)	Cash and cash equivalents, accounts receivable and accounts payable and accrued liabilities are carried at amounts which reasonably approximate their fair values due to their short-term nature.

(2)	Represents commodity financial instrument transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.

(3)	The fair values associated with our interest rate and commodity hedging portfolios were developed using available market information and appropriate valuation techniques.

(4)	The estimated fair values of TEPPCO’s fixed rate debt are based on quoted market prices for such debt or debt of similar terms and maturities (see Note 12).

(5)	The carrying amount of TEPPCO’s variable-rate debt obligation reasonably approximates its fair value due to its variable interest rate.

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

We are exposed to financial market risks, including changes in commodity prices and interest rates. We do not have foreign exchange risks. We may use financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the type of risks we attempt to hedge are those related to fair values of certain debt instruments and cash flows resulting from changes in applicable interest rates or commodity prices.

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

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

Interest Rate Risk Hedging Program

Our interest rate exposure results from variable and fixed interest rate borrowings under various debt agreements. From time to time we utilize interest rate swaps and similar arrangements to manage a portion of our interest rate exposure, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. At December 31, 2008, there were no interest related financial instruments outstanding.

Fair Value Hedges – Interest Rate Swaps

In January 2006, TEPPCO entered into interest rate swap agreements with a total notional value of $200.0 million to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving credit facility. Under the swap agreements, TEPPCO paid a fixed rate of interest ranging from 4.67% to 4.695% and received a floating rate based on the three-month U.S. Dollar LIBOR rate. At December 31, 2007, the fair value of these interest rate swaps was an asset of $0.3 million. These interest rate swaps expired in January 2008.

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. This swap agreement, designated as a fair value hedge, had a notional value of $210.0 million and was set to mature in January 2028 to match the principal and maturity of the TE Products Senior Notes. In September 2007, TEPPCO terminated this swap agreement, resulting in a loss of $1.2 million. This loss was deferred as an adjustment to the carrying value of the 7.51% Senior Notes, and approximately $0.2 million of the loss was amortized to interest expense in 2007, with the remaining $1.0 million recognized in interest expense in January 2008 at the time the 7.51% Senior Notes were redeemed (see Note 12).

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 its fixed rate 7.625% Senior Notes due 2012. The swap agreements had a combined notional value of $500.0 million and were set to mature in 2012 to match the principal and maturity of the underlying debt. These swap agreements were terminated in 2002 resulting in deferred gains of $44.9 million, which are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the 7.625% Senior Notes. At December 31, 2008, the unamortized balance of the deferred gains was $18.1 million. In the event of early extinguishment of the 7.625% Senior Notes, any remaining unamortized gains would be recognized in the statement of consolidated income at the time of extinguishment.

Cash Flow Hedges – Treasury Locks

At times, we may use treasury lock financial instruments to hedge the underlying U.S. treasury rates related to anticipated debt incurrence. Gains or losses on the termination of such instruments are amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt. Each of TEPPCO’s treasury lock transactions was designated as a cash flow hedge under SFAS 133.

In October 2006 and February 2007, TEPPCO entered into treasury lock agreements, accounted for as cash flow hedges, which extended through June 2007 for a notional value totaling $300.0 million. In May 2007, these treasury locks were terminated concurrent with the issuance of junior subordinated notes (see Note 12). The termination of the treasury locks resulted in gains of $1.4 million, and these gains were recorded in accumulated other comprehensive income. These gains are being amortized using the effective interest method as reductions to future interest expense over the term of the forecasted fixed rate interest payments, which is ten years. Over the next twelve months, TEPPCO expects to reclassify $0.1 million of accumulated other comprehensive income that was generated by these treasury locks as a reduction to interest expense. In the event of early extinguishment of the junior subordinated notes, any remaining unamortized gains would be recognized in the statement of consolidated income at the time of extinguishment.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

In 2007, TEPPCO entered into treasury locks, accounted for as cash flow hedges, which extended through January 31, 2008 for a notional value totaling $600.0 million. At December 31, 2007, the fair value of the treasury locks was a liability of $25.3 million. In January 2008, these treasury locks were extended through April 30, 2008. In March 2008, these treasury locks were settled concurrently with the issuance of senior notes (see Note 12). The settlement of the treasury locks resulted in losses of $52.1 million, and these losses were recorded in accumulated other comprehensive income. TEPPCO recognized approximately $3.6 million of this loss in interest expense as a result of interest payments hedged under the treasury locks not occurring as forecasted. The remaining losses are being amortized using the effective interest method as increases to future interest expense over the terms of the forecasted interest payments, which range from five to ten years. Over the next twelve months, TEPPCO expects to reclassify $5.8 million of accumulated other comprehensive loss that was generated by these treasury locks as an increase to interest expense. In the event of early extinguishment of these senior notes, any remaining unamortized losses would be recognized in the statement of consolidated income at the time of extinguishment.

Commodity Risk Hedging Program

We seek to maintain a position that is substantially balanced between crude oil purchases and related sales and future delivery obligations. As part of our crude oil marketing business, we enter into financial instruments such as swaps and other hedging instruments. The purpose of such hedging activity is to either balance our inventory position or to lock in a profit margin.

At December 31, 2008, TEPPCO had no commodity financial instruments that were accounted for as cash flow hedges. Gains and losses on financial instruments used in cash flow hedges are offset against corresponding gains or losses of the hedged item and are deferred through other comprehensive income, thus minimizing exposure to cash flow risk. No ineffectiveness was recognized as of December 31, 2008. In addition, TEPPCO had some commodity financial instruments that did not qualify for hedge accounting. These financial instruments had a minimal impact on our earnings. The fair value of the open positions at December 31, 2008 was an asset of $3 thousand.

Adoption of SFAS 157 – Fair Value Measurements

On January 1, 2008, we adopted the provisions of SFAS No. 157 that apply to financial assets and liabilities. We adopted the provisions of SFAS 157 that apply to nonfinancial assets and liabilities on January 1, 2009. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

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

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

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

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

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

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

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities measured on a recurring basis at December 31, 2008. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels. At December 31, 2008, we had no Level 1 financial assets and liabilities.

	Level 2		Level 3			Total

Financial assets:
Commodity financial instruments	$	15,488	$	223		$	15,711

Total	$	15,488	$	223		$	15,711

Financial liabilities:
Commodity financial instruments	$	15,338	$	370		$	15,708

Total	$	15,338	$	370		$	15,708

Net financial liabilities, Level 3			$	(147	)

The determination of fair values above associated with our commodity financial instrument portfolios are developed using available market information and appropriate valuation techniques in accordance with SFAS 157.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

The following table sets forth a reconciliation of changes in the fair value of our net financial assets and liabilities classified as Level 3 in the fair value hierarchy:

	Net
	Commodity
	Financial
	Instruments

Balance, January 1, 2008	$	(394	)
Total gains included in net income		247

Balance, December 31, 2008	$	(147	)

NOTE 7. INVENTORIES

Inventories are valued at the lower of cost (based on weighted average cost method) or market. The major components of inventories were as follows:

	December 31,
	2008

Crude oil (1)	$	32,792
Refined products and LPGs (2)		406
Lubrication oils and specialty chemicals		11,127
Materials and supplies		8,581
Total	$	52,906

_____________________

(1)	$30.7 million of our crude oil inventory was subject to forward sales contracts.

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

NOTE 8. PROPERTY, PLANT AND EQUIPMENT

Major categories of property, plant and equipment at December 31, 2008, were as follows:

	Estimated
	Useful Life		December 31,
	In Years		2008
Plants and pipelines (1)		5-40 (4)	$	1,919,646
Underground and other storage facilities (2)		5-40 (5)		296,806
Transportation equipment (3)		5-10		11,303
Marine vessels		20-30		453,041
Land and right of way				143,823
Construction work in progress				294,075
Total property, plant and equipment				3,118,694
Less accumulated depreciation				678,784
Property, plant and equipment, net			$	2,439,910

_____________________

(1)	Plants and pipelines include refined products, LPGs, NGL, petrochemical, crude oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings, laboratory and shop equipment; and related assets.

(2)	Underground and other storage facilities include underground product storage caverns, storage tanks and other related assets.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

(3)	Transportation equipment includes vehicles and similar assets used in our operations.

(4)	The estimated useful lives of major components of this category are as follows: pipelines, 20-40 years (with some equipment at 5 years); terminal facilities, 10-40 years; office furniture and equipment, 5-10 years; buildings 20-40 years; and laboratory and shop equipment, 5-40 years.

(5)	The estimated useful lives of major components of this category are as follows: underground storage facilities, 20-40 years (with some components at 5 years) and storage tanks, 20-30 years.

Asset Retirement Obligations

We have 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.

The following table presents information regarding our AROs:

ARO liability balance, December 31, 2007	$	1,346
Accretion expense		128
ARO liability balance, December 31, 2008	$	1,474

Property, plant and equipment at December 31, 2008, includes $0.5 million of asset retirement costs capitalized as an increase in the associated long-lived asset.

NOTE 9. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

We own interests in related businesses that are accounted for using the equity method of accounting. These investments are identified below by reporting business segment (see Note 15 for a general discussion of our business segments). The following table presents our investments in unconsolidated affiliates as of December 31, 2008:

	Ownership Percentage at
	December 31,		December 31,
	2008		2008

Downstream Segment:
Centennial		50.0%	$	71,841
Other		25.0%		332
Upstream Segment:
Seaway		50.0%		190,129
Texas Offshore Port System		33.3%		35,915
Midstream Segment:
Jonah		80.64%		957,706
Total			$	1,255,923

On a quarterly basis, we monitor the underlying business fundamentals of our investments in unconsolidated affiliates and test such investments for impairment when impairment indicators are present. As a result of our reviews for the year ended December 31, 2008, no impairment charges were required. We have the intent and ability to hold these investments, which are integral to our operations.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

Centennial

TE Products owns a 50% ownership interest in Centennial, and Marathon Petroleum Company LLC (“Marathon”) owns the remaining 50% interest. Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois. Marathon operates the mainline Centennial pipeline, and TE Products operates the Beaumont origination point and the Creal Springs terminal. During the year ended December 31, 2008, we did not invest any funds in Centennial. TE Products has received no cash distributions from Centennial since its formation.

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 and commercially manage the Seaway assets. Seaway owns pipelines and terminals that carry imported, offshore and domestic onshore 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. Seaway also has a connection to our South Texas system that allows it to receive both onshore and offshore domestic crude oil in the Texas Gulf Coast area for delivery to Cushing. The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of Seaway. The sharing ratio (including the amount of distributions we receive) for 2008 was 40% of Seaway. During the year ended December 31, 2008, we received distributions from Seaway of $13.8 million. During the year ended December 31, 2008, we did not invest any funds in Seaway. Our share of undistributed earnings of Seaway totaled approximately $1.4 million at December 31, 2008.

Texas Offshore Port System

In August 2008, we, together with Enterprise Products Partners and Oiltanking Holding Americas, Inc. (“Oiltanking”) formed Texas Offshore Port System, a joint venture to design, construct, operate and own a new Texas offshore crude oil port and pipeline system to facilitate delivery of waterborne crude oil to refining centers located along the upper Texas Gulf Coast. The joint venture’s primary project, referred to as “TOPS”, includes (i) an offshore port (which will be located approximately 36 miles from Freeport, Texas), (ii) an onshore storage facility with approximately 3.9 million barrels of total crude oil storage capacity, and (iii) an 85-mile pipeline system that will have the capacity to deliver up to 1.8 million barrels per day of crude oil, that will extend from the offshore port to a storage facility near Texas City, Texas. The joint venture’s complementary project, referred to as the Port Arthur Crude Oil Express (“PACE”) will transport crude oil from Texas City, including crude oil from TOPS, and will consist of a 75-mile pipeline and 1.2 million barrels of crude oil storage capacity in the Port Arthur, Texas area. Development of the TOPS and PACE projects is supported by long-term contracts with affiliates of Motiva Enterprises, LLC and Exxon Mobil Corporation, which have committed a combined 725,000 barrels per day of crude oil to the projects. The timing of the construction and related capital costs of the TOPS and PACE projects will be affected by the acquisition of requisite permits.

We, Enterprise Products Partners and Oiltanking each own, through our respective subsidiaries, a one-third interest in the joint venture. A subsidiary of Enterprise Products Partners acts as construction manager and will act as operator. The aggregate cost of the TOPS and PACE projects is expected to be approximately $1.8 billion (excluding capitalized interest), with the majority of such capital expenditures occurring in 2009 and 2010. TEPPCO and an affiliate of Enterprise Products Partners have each guaranteed up to approximately $700.0 million, which includes a contingency amount for potential cost overruns, of the capital contribution obligations of our respective subsidiary partners in the joint venture. At December 31, 2008, we have invested $36.0 million in the joint venture.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

Jonah

Enterprise Products Partners, through its affiliate, Enterprise Gas Processing, LLC, is our joint venture partner in Jonah, the partnership through which we have owned our interest in the system serving the Jonah and Pinedale fields in the greater Green River Basin in southwestern Wyoming. The joint venture is governed by a management committee comprised of two representatives approved by Enterprise Products Partners and two representatives approved by us, each with equal voting power. Enterprise Products Partners serves as operator. In June 2008, Jonah completed the Phase V expansion, which increased the combined system capacity of the Jonah and Pinedale fields from 1.5 billion cubic feet (“Bcf”) per day to 2.35 Bcf per day. The increased capacity from the expansion has reduced system operating pressures and increased production rates and ultimate reserve recoveries. Enterprise Products Partners managed the Phase V construction project.

From August 1, 2006 through July 2007, we and Enterprise Products Partners equally shared the costs of the Phase V expansion, and Enterprise Products Partners shared in the incremental cash flow resulting from the operation of those new facilities. During August 2007, with the completion of the first portion of the expansion, we and Enterprise Products Partners began sharing joint venture cash distributions and earnings 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, beginning in August 2007, our ownership interest in Jonah was approximately 80.64%, and Enterprise Products Partners’ ownership interest in Jonah was approximately 19.36%. Amounts exceeding an agreed upon base cost estimate of $415.2 million were shared 19.36% by Enterprise Products Partners and 80.64% by us. Our ownership interest in Jonah is currently anticipated to remain at 80.64%. Through December 31, 2008, we have reimbursed Enterprise Products Partners $306.5 million ($44.9 million in 2008, $152.2 million in 2007 and $109.4 million in 2006) for our share of the Phase V cost incurred by it (including its cost of capital incurred prior to the formation of the joint venture of $1.3 million). At December 31, 2008, we had a payable to Enterprise Products Partners for costs incurred of $1.0 million.

In early 2008, Jonah began an expansion of the portion of its system serving the Pinedale field, which is expected to further increase the combined system capacity of the Jonah and Pinedale fields from 2.35 Bcf per day to approximately 2.55 Bcf per day. This project will include an additional 17,000 horsepower of compression at the Paradise and Bird Canyon stations in Sublette County, Wyoming and involve construction of approximately 52 miles of 30-inch and 24-inch diameter pipelines. This expansion is expected to be completed in phases, with final completion expected in early 2009. The total anticipated cost of this system expansion is expected to be approximately $125.0 million. Our share of the costs of the construction is expected to be 80.64%, and Enterprise Products Partners’ share is expected to be 19.36%. Enterprise Products Partners is managing this construction project.

During the year ended December 31, 2008, we received distributions from Jonah of $132.2 million. During the year ended December 31, 2008, we invested cash of $129.8 million in Jonah.

Summarized combined balance sheet information by reporting segment as of December 31, 2008, is presented below:

	December 31, 2008
	Current Assets		Noncurrent Assets		Current Liabilities		Long-term Debt		Noncurrent Liabilities		Equity

Downstream Segment	$	12,870	$	239,414	$	20,673	$	120,000	$	358	$	111,253
Upstream Segment (1)		52,423		338,616		11,155		--		22		379,862
Midstream Segment		53,810		1,163,257		28,224		--		378		1,188,465

__________________

(1)	Includes our ownership interest in Texas Offshore Port System.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

NOTE 10. ACQUISITIONS

Cenac

On February 1, 2008, we, through our subsidiary, TEPPCO Marine Services, entered the marine transportation business for refined products, crude oil and condensate. We acquired transportation assets and certain intangible assets that comprised the marine transportation business of Cenac Towing Co., Inc. (“Cenac Towing”), Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr., the sole owner of Cenac Towing Co., Inc. and Cenac Offshore, L.L.C. (collectively, “Cenac”). The aggregate value of total consideration we paid or issued to complete the Cenac acquisition was $444.7 million, which consisted of $258.2 million in cash and 4,854,899 newly issued TEPPCO Units. Additionally, we assumed $63.2 million of Cenac’s long-term debt in this transaction. On February 1, 2008, we repaid the $63.2 million of assumed debt in full with borrowings under TEPPCO’s term credit agreement (see Note 12).

The following table summarizes the components of total consideration paid or issued in this transaction.

Cash payment for Cenac acquisition	$	256,593
Fair value of TEPPCO’s 4,854,899 Units		186,558
Other cash acquisition costs paid to third-parties		1,589
Total consideration	$	444,740

We financed the cash portion of the consideration with borrowings under TEPPCO’s term credit agreement (see Note 12). In accordance with purchase accounting, the value of TEPPCO’s Units issued in connection with the Cenac acquisition was based on the average closing price of such Units immediately prior to and on the day of February 1, 2008. For the purpose of this calculation, the average closing price was $38.43 per TEPPCO Unit.

We acquired 42 tow boats, 89 tank barges and the economic benefit of certain related commercial agreements. This business serves refineries and storage terminals along the Mississippi, Illinois and Ohio rivers, and the Intracoastal Waterway between Texas and Florida. These assets also gather crude oil from production facilities and platforms along the U.S. Gulf Coast and in the Gulf of Mexico. This acquisition is a natural extension of our existing assets and complements two of our core franchise businesses: the transportation and storage of refined products and the gathering, transportation and storage of crude oil.

The results of operations for the Cenac acquisition are included in our consolidated financial statements beginning at the date of acquisition, in a newly created business segment, Marine Services Segment. Our fleet of acquired tow boats and tank barges will continue to be operated by employees of Cenac under a transitional operating agreement with TEPPCO Marine Services for a period of up to two years following the acquisition. These operations will remain headquartered in Houma, Louisiana during such time.

The purchase agreement gives us the right to repurchase the approximately 4.9 million TEPPCO Units issued in the transaction in connection with proposed sales thereof by Cenac and specified related persons for 10 years. If we or any of our affiliates sell any of the assets acquired from Cenac Towing prior to June 30, 2018 and recognize certain “built-in gains” for federal income tax purposes that are allocable to Cenac Towing, we have indemnification obligations under the purchase agreement to pay Cenac Towing an amount generally intended to compensate for the incremental level of double taxation imposed on Cenac Towing as a result of the sale. The purchase agreement prohibits Cenac from competing with our marine services business for two years or from soliciting employees and service providers of TEPPCO Marine Services and its affiliates for four years. The purchase agreement contains other customary representations, warranties, covenants and indemnification provisions.

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

This acquisition was accounted for using the purchase method of accounting and, accordingly, the cost has been allocated to assets acquired and liabilities assumed based on estimated fair values. Such fair values have been developed using recognized business valuation techniques.

The following table summarizes estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

Property, plant and equipment	$	360,146
Intangible assets		63,500
Other assets		2,726
Total assets acquired		426,372

Long-term debt		(63,157	)
Total liabilities assumed		(63,157	)
Total assets acquired less liabilities assumed		363,215
Total consideration given		444,740
Goodwill	$	81,525

The $63.5 million fair value of acquired intangible assets represents customer relationships and non-compete agreements. Customer relationship intangible assets represent the estimated economic value attributable to certain relationships acquired in connection with the Cenac acquisition whereby (i) we acquired information about or access to customers and now have regular contact with them and (ii) the customers now have the ability to make direct contact with us. In this context, customer relationships arise from contractual arrangements (such as transportation contracts) and through means other than contracts, such as regular contact by sales or service representative. The values assigned to these intangible assets are amortized to earnings on a straight-line basis over the expected period of economic benefit, which ranges from 2 to 20 years.

Of the $444.7 million in consideration we paid or issued to complete the Cenac acquisition, $81.5 million has been assigned to goodwill. Management attributes the value of this goodwill to potential future benefits we expect to realize as a result of acquiring these assets.

Horizon

On February 29, 2008, we expanded our Marine Services Segment with the acquisition of marine assets from Horizon Maritime, L.L.C. (“Horizon”), a privately-held Houston-based company and an affiliate of Mr. Cenac for $80.8 million in cash. We acquired 7 tow boats, 17 tank barges, rights to two tow boats under construction and certain related commercial and other agreements (or the associated economic benefits). In April 2008, we paid $3.0 million to Horizon pursuant to the purchase agreement upon delivery of one of the tow boats under construction, and in June 2008, we paid $3.8 million upon delivery of the second tow boat. The acquired vessels transport asphalt, heavy fuel oil and other heated oil products to storage facilities and refineries along the Mississippi, Illinois and Ohio Rivers, and the Intracoastal Waterway. We financed the acquisition with borrowings under TEPPCO’s term credit agreement.

The results of operations for the Horizon acquisition are included in our consolidated financial statements beginning at the date of acquisition, in our Marine Services Segment. This acquisition was accounted for using the purchase method of accounting and, accordingly, the cost has been allocated to assets acquired and liabilities assumed based on estimated fair values. Such fair values have been developed using recognized business valuation techniques. The following table summarizes estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

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NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

Property, plant and equipment	$	71,216
Intangible assets		6,500
Other assets		981
Total assets acquired		78,697

Total consideration given		87,584
Goodwill	$	8,887

The $6.5 million fair value of acquired intangible assets represents customer relationships and non-compete agreements. Customer relationship intangible assets represent the estimated economic value attributable to certain relationships acquired in connection with the Horizon acquisition whereby (i) we acquired information about or access to customers and now have regular contact with them and (ii) the customers now have the ability to make direct contact with us. In this context, customer relationships arise from contractual arrangements (such as transportation contracts) and through means other than contracts, such as regular contact by sales or service representative. The values assigned to these intangible assets are amortized to earnings on a straight-line basis over the expected period of economic benefit, which ranges from 2 to 9 years.

Of the $87.6 million in consideration we paid to complete the acquisition of the Horizon business, $8.9 million has been assigned to goodwill. Management attributes the value of this goodwill to potential future benefits we expect to realize as a result of acquiring these assets and further expanding our Marine Services Segment.

Lubrication and Other Fuel Oil Assets

On August 1, 2008, we purchased lubrication and other fuel oil assets, located in Wyoming, from Quality Petroleum, Inc. for approximately $6.8 million, which includes $1.3 million related to a non-compete agreement. The assets, included in our Upstream Segment, consist of operating inventory, buildings, land and various equipment and the assignment of certain distributor agreements. 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, inventory and intangible assets. We recorded $0.7 million of goodwill related to this acquisition.

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NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

NOTE 11. INTANGIBLE ASSETS AND GOODWILL

Intangible Assets

The following table summarizes our intangible assets, including excess investments, being amortized at December 31, 2008:

	December 31, 2008
	Gross Carrying Amount		Accumulated Amortization
Intangible assets:
Downstream Segment:
Transportation agreements	$	1,000	$	(408	)
Other		5,621		(764	)
Subtotal		6,621		(1,172	)

Upstream Segment:
Transportation agreements		888		(395	)
Other		10,580		(3,009	)
Subtotal		11,468		(3,404	)

Midstream Segment:
Gathering agreements		239,649		(125,811	)
Fractionation agreements		38,000		(20,425	)
Other		306		(164	)
Subtotal		277,955		(146,400	)

Marine Services Segment:
Customer relationship intangibles		51,320		(3,121	)
Other		18,680		(4,294	)
Subtotal		70,000		(7,415	)
Total intangible assets		366,044		(158,391	)

Excess investments: (1)
Downstream Segment (2)		33,390		(26,128	)
Upstream Segment (3)		26,908		(5,820	)
Midstream Segment (4)		12,580		(241	)
Subtotal		72,878		(32,189	)

Total intangible assets, including excess investments	$	438,922	$	(190,580	)

_____________________

(1)	Excess investments are included in “Equity Investments” in our consolidated balance sheet.

(2)	Relates to our investment in Centennial.

(3)	Relates to our investment in Seaway.

(4)	Relates to our investment in Jonah.

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.

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

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NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

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. 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 $8.7 million assigned to our crude supply and transportation intangible customer contracts is being amortized on a unit-of-production basis. The values assigned to our customer relationships and non-compete agreements related to the acquisition of the marine assets are generally amortized on a straight-line basis from 2 to 20 years (see Note 10).

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 are amortizing the excess investment in Jonah on a straight-line basis over the life of the assets constructed.

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired. 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.

The following table presents the carrying amount of goodwill at December 31, 2008, by business segment:

	December 31,
	2008
Downstream Segment	$	1,339
Upstream Segment		14,860
Marine Services Segment		90,412
Total goodwill	$	106,611

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NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

NOTE 12. DEBT OBLIGATIONS

The following table summarizes the principal amounts outstanding under all of TEPPCO’s debt instruments at December 31, 2008:

	December 31,
	2008

Long-term:
Senior debt obligations: (1)
Revolving Credit Facility, due December 2012	$	516,654
7.625% Senior Notes, due February 2012		500,000
6.125% Senior Notes, due February 2013		200,000
5.90% Senior Notes, due April 2013		250,000
6.65% Senior Notes, due April 2018		350,000
7.55% Senior Notes, due April 2038		400,000
Total principal amount of long-term senior debt obligations		2,216,654

7.000% Junior Subordinated Notes, due June 2067 (1)		300,000
Total principal amount of long-term debt obligations		2,516,654
Adjustment to carrying value associated with hedges of fair value and unamortized discounts (2)		12,865
Total Debt Instruments (2)	$	2,529,519

_________________

(1)	TE Products, TCTM, TEPPCO Midstream and Val Verde (collectively, the “Subsidiary Guarantors”) have issued full, unconditional, joint and several guarantees of TEPPCO’s senior notes, junior subordinated notes and revolving credit facility.

(2)	From time to time TEPPCO enters into interest rate swap agreements to hedge its exposure to changes in the fair value on a portion of the debt obligations presented above (see Note 6). Amount includes $5.2 million of unamortized discounts and $18.1 million related to fair value hedges.

Revolving Credit Facility

TEPPCO has in place an unsecured revolving credit facility (“Revolving Credit Facility”), which matures on December 12, 2012. The Revolving Credit Facility allows TEPPCO to request unlimited one-year extensions of the maturity date, subject to lender approval and satisfaction of certain other conditions. In July 2008, commitments under TEPPCO’s facility were increased from $700.0 million to $950.0 million. The aggregate outstanding principal amount of swing line loans or same day borrowings permitted under the Revolving Credit Facility is $40.0 million. The interest rate is based, at TEPPCO’s option, on either the lender’s base rate, or LIBOR rate, plus a margin, in effect at the time of the borrowings. The applicable margin with respect to LIBOR rate borrowings is based on TEPPCO’s senior unsecured non-credit enhanced long-term debt rating issued by Standard & Poor’s Rating Services (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”). The Revolving Credit Facility contains a term-out option in which TEPPCO may, on the maturity date, convert the principal balance of all revolving loans then outstanding into a non-revolving one-year term loan. Upon the conversion of the revolving loans to term loans pursuant to the term-out option, the applicable LIBOR spread will increase by 0.125% per year, and if immediately prior to such borrowing the total outstanding revolver borrowings then outstanding exceeds 50% of the total lender commitments, the applicable LIBOR spread with respect to borrowings will increase by an additional 10 basis points.

During September 2008, Lehman Brothers Bank, FSB (“Lehman”), which had a 4.05% participation in TEPPCO’s Revolving Credit Facility, stopped funding its commitment following the bankruptcy filing of its parent. Assuming that future fundings are not received for the Lehman percentage commitment, aggregate available capacity would be reduced by approximately $28.9 million.

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The Revolving Credit Facility contains financial covenants that require TEPPCO to maintain a ratio of Consolidated Funded Debt to Pro Forma EBITDA (as defined and calculated in the facility) of less than 5.00 to 1.00 (and, if after giving effect to a permitted acquisition the ratio exceeds 5.00 to 1.00, the threshold ratio will be increased to 5.50 to 1.00 for the fiscal quarter in which such acquisition occurs and the first full fiscal quarter following such acquisition). Other restrictive covenants in the Revolving Credit Facility limit TEPPCO’s ability, and the ability of certain of its subsidiaries, to, among other things, incur certain additional indebtedness, make distributions in excess of “Available Cash,” as that term is defined in TEPPCO’s partnership agreement, incur certain liens, engage in specified transactions with affiliates and complete mergers, acquisitions and sales of assets. The credit agreement 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 aggregate principal amount of $50.0 million and allows for the issuance of certain hybrid securities of up to 15% of TEPPCO’s Consolidated Total Capitalization (as defined therein). At December 31, 2008, $516.7 million was outstanding under TEPPCO’s Revolving Credit Facility at a weighted average interest rate of 1.4%, and available borrowing capacity under the facility was approximately $404.4 million. At December 31, 2008, TEPPCO was in compliance with the covenants of the Revolving Credit Facility.

Senior Notes

On January 27, 1998, TE Products issued $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”). Interest on the TE Products Senior Notes was payable semiannually in arrears on January 15 and July 15 of each year. The 6.45% TE Products Senior Notes were issued at a discount of $0.3 million and were being accreted to their face value over the term of the notes. The 6.45% TE Products Senior Notes due 2008 were redeemed at maturity on January 15, 2008. The 7.51% TE Products Senior Notes due 2028, issued at par, became redeemable at any time after January 15, 2008, at the option of TE Products, in whole or in part, at varying fixed annual redemption prices. In October 2007, TE Products repurchased $35.0 million principal amount of the 7.51% TE Products Senior Notes for $36.1 million and accrued interest. On January 28, 2008, TE Products redeemed the remaining $175.0 million of 7.51% TE Products Senior Notes at a redemption price of 103.755% of the principal amount plus accrued and unpaid interest at the date of redemption. TEPPCO funded the retirement of both series of senior notes with borrowings under its term credit agreement.

On February 20, 2002 and January 30, 2003, TEPPCO issued $500.0 million principal amount of 7.625% Senior Notes due 2012 (“7.625% Senior Notes”) and $200.0 million principal amount of 6.125% Senior Notes due 2013 (“6.125% Senior Notes), respectively. These senior notes were issued at discounts of $2.2 million and $1.4 million, respectively, and are being accreted to their face value over the applicable term of the senior notes. The 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.

On March 27, 2008, TEPPCO issued (i) $250.0 million principal amount of 5.90% Senior Notes due 2013, (ii) $350.0 million principal amount of 6.65% Senior Notes due 2018, and (iii) $400.0 million principal amount of 7.55% Senior Notes due 2038. The senior notes were issued at discounts of $0.2 million, $1.3 million and $2.2 million, respectively, and are being accreted to their face value over the applicable terms of the senior notes. The 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 50 basis points.

The indentures governing TEPPCO’s senior notes contain covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indentures do not limit TEPPCO’s ability to incur additional indebtedness. At December 31, 2008, TEPPCO was in compliance with the covenants of its senior notes.

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NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

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’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). The Subsidiary Guarantors have issued full, unconditional, and joint and several guarantees, on a junior subordinated basis, of payment of the principal of, premium, if any, and interest on the Junior Subordinated Notes.

The indenture governing the Junior Subordinated Notes does not limit TEPPCO’s ability to incur additional debt, including debt that ranks senior to or equally with the Junior Subordinated Notes. The indenture allows TEPPCO to defer interest payments on one or more occasions for up to ten consecutive years, subject to certain conditions. The indenture 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 its respective majority-owned subsidiaries not to make, any payment of interest, principal or premium, if any, on or repay, purchase or redeem any of TEPPCO’s or the Subsidiary Guarantors’ 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 its 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 bear interest at a fixed annual rate of 7.000% from May 2007 to June 1, 2017, payable semi-annually in arrears. 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. Interest payments may be deferred on a cumulative basis for up to ten consecutive years, subject to certain provisions. Deferred interest will accumulate additional 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 1, 2017 for a “make-whole” redemption price 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 50 basis points; and thereafter at a redemption price equal to 100% of their principal amount plus accrued and unpaid interest. The Junior Subordinated Notes are also redeemable prior to June 1, 2017 in whole (but not in part) upon the occurrence of certain tax or rating agency events at specified redemption prices. At December 31, 2008, TEPPCO was in compliance with the covenants of the Junior Subordinated Notes.

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 provided in the underlying documents) pursuant to which TEPPCO and its Subsidiary Guarantors agreed for the benefit of such debt holders that TEPPCO 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. The replacement capital covenant is not a term of the indenture or the Junior Subordinated Notes.

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NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

Fair Values

The following table summarizes the estimated fair values of the TEPPCO Senior Notes and Junior Subordinated Notes at December 31, 2008:

	Face Value		Fair Value

7.625% Senior Notes, due February 2012	$	500,000	$	468,083
6.125% Senior Notes, due February 2013		200,000		174,201
5.90% Senior Notes, due April 2013		250,000		214,506
6.65% Senior Notes, due April 2018		350,000		280,698
7.55% Senior Notes, due April 2038		400,000		295,190
7.000% Junior Subordinated Notes, due June 2067		300,000		120,540

Term Credit Agreement

TEPPCO had in place a senior unsecured term credit agreement (“Term Credit Agreement”), with a borrowing capacity of $1.0 billion and a maturity date of December 19, 2008. During the first quarter of 2008, TEPPCO borrowed $1.0 billion under the Term Credit Agreement to finance the retirement of TE Products’ senior notes, the Cenac and Horizon acquisitions and for other partnership purposes. In March 2008, TEPPCO repaid the outstanding balance of the Term Credit Agreement with proceeds from the issuance of senior notes and other cash on hand and terminated the agreement.

Debt Obligations of Unconsolidated Affiliates

We have one unconsolidated affiliate, Centennial, with long-term debt obligations. The following table shows the total debt of Centennial at December 31, 2008 (on a 100% basis) and the corresponding scheduled maturities of such debt.

	Scheduled Maturities of Debt
2009	$	9,900
2010		9,100
2011		9,000
2012		8,900
2013		8,600
After 2013		84,400
Total scheduled maturities of debt	$	129,900

At December 31, 2008, Centennial’s debt obligations consisted of $129.9 million borrowed under a master shelf loan agreement. Borrowings under the master shelf agreement mature in May 2024 and are collateralized by substantially all of Centennial’s assets and severally guaranteed by Centennial’s owners.

In January 2008, TEPPCO entered into an amended and restated guaranty agreement (“Amended Guaranty”) in which TEPPCO, TCTM, TEPPCO Midstream and TE Products (collectively, “TEPPCO Guarantors”) are required, on a joint and several basis, to pay 50% of any past-due amount under Centennial’s master shelf loan agreement not paid by Centennial (see Note 17).

NOTE 13. NONCONTROLLING INTEREST

Noncontrolling 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 and the associated incentive distribution rights of TEPPCO. For financial

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NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

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 sheet amounts shown as noncontrolling interest. Distributions to and contributions from noncontrolling interests represent cash payments and cash contributions, respectively. At December 31, 2008, TEPPCO had outstanding 104,704,861 Units.

Equity Offerings and Registration Statements

In September 2008, TEPPCO filed a universal shelf registration statement with the U.S. Securities and Exchange Commission (“SEC”) that allows it to issue an unlimited amount of debt and equity securities and removed from registration securities remaining under its previous universal shelf registration statement.

On September 9, 2008, TEPPCO issued and sold in an underwritten public offering 9.2 million Units at a price to the public of $29.00 per Unit, including 1.2 million Units sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering. The proceeds from the offering, net of underwriting discount and offering expenses, totaled approximately $257.0 million. Concurrently with this offering, TEPPCO sold 241,380 unregistered Units at the public offering price of $29.00 to TEPPCO Unit I, an affiliate of EPCO in which certain EPCO employees who perform services for us, including the executive officers, were issued Class B limited partner interests to incentivize them to enhance the long-term value of TEPPCO’s Units. The net proceeds from the offering and the unregistered issuance to TEPPCO Unit I were used to reduce indebtedness under TEPPCO’s Revolving Credit Facility. For additional information regarding TEPPCO Unit I and the equity-based compensatory awards issued therein, please see Note 4.

EPCO, Inc. TPP Employee Unit Purchase Plan

The EPCO, Inc. TPP Employee Unit Purchase Plan (the “Unit Purchase Plan”) provides for discounted purchases of TEPPCO Units by employees of EPCO and its affiliates. A maximum of 1,000,000 of TEPPCO’s Units may be delivered under the Unit Purchase Plan (subject to adjustment as provided in the plan). The Unit Purchase Plan is effective until the earlier of (i) December 8, 2016 (ii) the time that all available TEPPCO Units under the plan have been purchased on behalf of the participants or (iii) the time of termination of the plan by EPCO or the Chairman or Vice Chairman of EPCO. As of December 31, 2008, 27,604 TEPPCO Units have been issued to employees under this plan.

Distribution Reinvestment Plan

Our distribution reinvestment plan (“DRIP”) provides for the issuance of up to 10,000,000 TEPPCO’s Units. TEPPCO Units purchased through the DRIP may be acquired at a discount rating from 0% to 5% (currently set at 5%), which will be set from time to time by TEPPCO. As of December 31, 2008, 418,233 TEPPCO Units have been issued in connection with the DRIP.

NOTE 14. EQUITY (DEFICIT)

At December 31, 2008, the Parent Company’s member’s equity (deficit) consisted of our capital account and accumulated other comprehensive loss.

At December 31, 2008, we had a deficit balance of $110.3 million in our member’s equity account. This negative balance does not represent an asset 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 TEPPCO’s 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

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NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

quarterly cash distributions of all of its Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by us, as general partner, in our reasonable discretion (these cash distributions paid to us 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 during previous years resulted in a deficit in the member’s equity account at December 31, 2008. Future cash distributions that exceed net income will result in an increase in the deficit balance in the member’s equity account.

According to TEPPCO’s partnership agreement, in the event of TEPPCO’s dissolution, after satisfying its liabilities, TEPPCO’s remaining assets would be divided among the limited partners of TEPPCO and us, as general partner, generally in the same proportion as Available Cash but calculated on a cumulative basis over the life of TEPPCO. If a deficit balance still remains in our equity account after all allocations are made between TEPPCO’s partners, we would not be required to make whole any such deficit.

Accumulated Other Comprehensive Income (Loss)

SFAS No. 130, Reporting Comprehensive Income requires 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. Our accumulated other comprehensive loss balance consisted of a $45.8 million loss related to interest rate and treasury lock financial instruments at December 31, 2008, of which $39.5 million was attributable to noncontrolling interests.

NOTE 15. BUSINESS SEGMENTS

We have four reporting segments:

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

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

§	Our Midstream Segment, which is engaged in the gathering of natural gas, fractionation of NGLs and pipeline transportation of NGLs; and

§	Our Marine Services Segment, which is engaged in the marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges.

Amounts indicated below as “Other” include the elimination of intersegment related party receivables and investment balances among our reporting segments and assets that we hold that have not been allocated to any of our reporting segments (including such items as corporate furniture and fixtures, vehicles, computer hardware and software, prepaid insurance and unamortized debt issuance costs on debt issued at the TEPPCO level).

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NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

The table below includes information by segment, together with reconciliations to our consolidated totals for the period ended December 31, 2008:

	Downstream Segment		Upstream Segment		Midstream Segment		Marine Services Segment		Other			Consolidated

Segment assets	$	1,320,870	$	1,586,345	$	1,529,125	$	653,262	$	(39,782	)	$	5,049,820

Investments in unconsolidated affiliates		63,222		226,044		957,706		--		8,951			1,255,923

Intangible assets		5,449		8,064		131,555		62,585		--			207,653

Goodwill		1,339		14,860		--		90,412		--			106,611

NOTE 16. RELATED PARTY TRANSACTIONS

The following table summarizes related party balances at December 31, 2008:

	December 31,
	2008
Accounts receivable, related parties (1)	$	15,758
Accounts payable, related parties (2)		17,219

_____________________

(1)	Relates to sales and transportation services provided to Enterprise Products Partners and certain of its subsidiaries and EPCO and certain of its affiliates and direct payroll, payroll related costs and other operational expenses charged to unconsolidated affiliates.

(2)

Relates to direct payroll, payroll related costs and other operational related charges from Enterprise Products Partners and certain of its subsidiaries and EPCO and certain of its affiliates, transportation and other services provided by unconsolidated affiliates and advances from Seaway for operating expenses and $3.4 million related to operational related charges from Cenac.

As an affiliate of EPCO and other companies controlled by Mr. Duncan, our transactions and agreements with them are not necessarily on an arm’s length basis. As a result, we cannot provide assurance that the terms and provisions of such transactions or agreements are at least as favorable to us as we could have obtained from unaffiliated third parties.

Relationship with EPCO and 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;

§	Enterprise GP Holdings, which owns all of our membership interests;

§	Enterprise Products Partners, which is controlled by affiliates of EPCO, including Enterprise GP Holdings;

§	Duncan Energy Partners, which is controlled by affiliates of EPCO;

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

§	Enterprise Offshore Port System, LLC, which is controlled by affiliates of EPCO and is one of our joint venture partners in Texas Offshore Port System; and

§	the Employee Partnerships, which are controlled by EPCO (see Note 4).

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Dan L. Duncan directly owns and controls EPCO and, through Dan Duncan LLC, owns and controls EPE Holdings, the general partner of Enterprise GP Holdings. Enterprise GP Holdings owns all of our membership interests. Our principal business activity is to act as managing partner of TEPPCO. Our executive officers are employees of EPCO (see Note 1).

We 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 and its consolidated private company subsidiaries and affiliates depend on the cash distributions they receive from the Parent Company and other investments to fund their operations and to meet their debt obligations. We paid cash distributions of $54.9 million during the year ended December 31, 2008 to our member.

The ownership interests in us and the limited partner interests in TEPPCO that are owned or controlled by EPCO and certain of 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. All of the membership interests in us and the limited partner interests in TEPPCO that are owned or controlled by Enterprise GP Holdings are pledged as security under its credit facility. If Enterprise GP Holdings were to default under its credit facility, its lender banks could own the Parent Company.

EPCO Administrative Services Agreement

We do not have any employees, and all of our management, administrative and operating functions are performed by employees of EPCO, pursuant to the ASA or by other service providers. We, TEPPCO, Enterprise Products Partners, Duncan Energy Partners, Enterprise GP Holdings and the respective general partners are parties to the ASA. The ACG Committees of each general partner have approved the ASA.

Under the ASA, we reimburse EPCO for all costs and expenses it incurs in providing management, administrative and operating services for us, including compensation of employees (i.e., salaries, medical benefits and retirement benefits) (see Note 1). Since the vast majority of such expenses are charged to us on an actual basis (i.e., no mark-up or subsidy is charged or received by EPCO), we believe that such expenses are representative of what the amounts would have been on a standalone basis. With respect to allocated costs, we believe that the proportional direct allocation method employed by EPCO is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis.

The significant terms of the ASA are as follows:

EPCO provides administrative, management 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 (direct and indirect) 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.

§	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 year ended December 31, 2008 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.

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Likewise, our general and administrative costs for the year ended December 31, 2008 include amounts we reimburse to EPCO for administrative services, including compensation of employees. We are responsible to reimburse EPCO for the amount of distributions of cash or securities, if any, made by TEPPCO Unit II to Mr. Thompson. 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 companies, and we and our operating companies 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 be offered first to certain Enterprise Products Partners’ affiliates before they may be pursued by EPCO and its other affiliates or offered to us.

On January 30, 2009, we entered into the Fifth Amended and Restated ASA, which amended the previous ASA to provide for the cash reimbursement to EPCO by us of distributions of cash or securities, if any, made by TEPPCO Unit II to its Class B limited partner, Mr. Thompson, our chief executive officer and an employee of EPCO (see Note 4). The Fifth Amended and Restated ASA also extends the term of EPCO’s service obligations from December 2010 to December 2013.

Jonah Joint Venture

Enterprise Products Partners (through an affiliate) is our joint venture partner in Jonah, the partnership through which we have owned our interest in the system serving the Jonah and Pinedale fields. Through December 31, 2008, we have reimbursed Enterprise Products Partners $306.5 million ($44.9 million in 2008, $152.2 million in 2007 and $109.4 million in 2006) for our share of the Phase V cost incurred by it (including its cost of capital incurred prior to the formation of the joint venture of $1.3 million). At December 31, 2008, we had a payable to Enterprise Products Partners for costs incurred of $1.0 million (see Note 9). At December 31, 2008, we had a receivable from Jonah of $4.7 million for operating expenses. During the year ended December 31, 2008, we received distributions from Jonah of $132.2 million. During the year ended December 31, 2008, Jonah paid distributions of $31.7 million to the affiliate of Enterprise Products Partners that is our joint venture partner.

TEPPCO has agreed to indemnify Enterprise Products Partners 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-Pinedale 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-Pinedale 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 Products Partners 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 Products Partners may receive from third-party insurers. TEPPCO carries insurance coverage that may offset any payments required under the indemnity. TEPPCO does not expect that these indemnities will have a material adverse effect on our financial position, results of operations or cash flows.

Texas Offshore Port System Joint Venture

Enterprise Products Partners (through an affiliate) is one of our joint venture partners in Texas Offshore Port System, which was formed in August 2008 to design, construct, operate and own a new Texas offshore crude

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oil port and pipeline system to facilitate delivery of waterborne crude oil to refining centers located along the upper Texas Gulf Coast. We, Enterprise Products Partners and Oiltanking each own, through our respective subsidiaries, a one-third interest in the joint venture. A subsidiary of Enterprise Products Partners acts as construction manager and will act as operator. TEPPCO and an affiliate of Enterprise Products Partners have each guaranteed up to approximately $700.0 million, which includes a contingency amount for potential cost overruns, of the capital contribution obligations of our respective subsidiary partners in the joint venture. Through December 31, 2008, we have invested $36.0 million in Texas Offshore Port System (see Note 9).

Sale of Parent Company to Enterprise GP Holdings; Relationship with Energy Transfer Equity

On May 7, 2007, all of our membership interests, together with 4,400,000 of TEPPCO’s Units, were sold by DFIGP to Enterprise GP Holdings, a publicly traded partnership also controlled indirectly by Dan L. Duncan. As of May 7, 2007, Enterprise GP Holdings owns and controls our 2% general partner interest in TEPPCO and has the right (through its 100% ownership in us) to receive the incentive distribution rights associated with our general partner interest in TEPPCO. Enterprise GP Holdings, DFIGP and other entities controlled by Mr. Duncan own 17,073,315 of TEPPCO’s Units.

Concurrently with the acquisition of the Parent Company, Enterprise GP Holdings acquired non-controlling ownership interests, accounted for as equity method investments, in Energy Transfer Equity, L.P. (“Energy Transfer Equity”) and LE GP, LLC, the general partner of Energy Transfer Equity.

Other Transactions

In December 2008, we entered into a lease agreement with Seminole Pipeline Company (“Seminole”) and Mid-America Pipeline Company, LLC, (MAPL) for the use of excess capacity on the Seminole pipeline system, a pipeline extending from Hobbs, New Mexico to Mont Belvieu, Texas. For Chaparral to use the excess capacity on Seminole, it must also access a segment of the MAPL pipeline as well. The primary term of this lease expired on January 31, 2009, and will continue on a month-to-month basis. Seminole and MAPL are subsidiaries of Enterprise Products Partners.

Relationship with Unconsolidated Affiliates

Our significant related party revenues and expense transactions with unconsolidated affiliates consist of management, rental and other revenues, transportation expense related to movements on Centennial and Seaway and rental expense related to the lease of pipeline capacity on Centennial. For additional information regarding our unconsolidated affiliates, see Note 9.

See “Jonah Joint Venture” and “Texas Offshore Port System Joint Venture” within this Note 16 for descriptions of ongoing transactions involving our Jonah and Texas Offshore Port System joint ventures with Enterprise Products Partners.

NOTE 17. COMMITMENTS AND CONTINGENCIES

As TEPPCO’s general partner, the Parent Company generally has liability for the liabilities and obligations of TEPPCO.

Litigation

In 1991, we were named as a defendant in a matter styled Jimmy R. Green, et al. v. Cities Service Refinery, et al. as filed in the 26th Judicial District Court of Bossier Parish, Louisiana. The plaintiffs in this matter reside or

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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 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 TEPPCO and Enterprise Products Partners or its affiliates. Mr. Brinckerhoff filed an amended complaint on July 12, 2007. The amended complaint names as defendants the Parent Company; our Board of Directors; the Parent Company’s parent companies, including EPCO; Enterprise Products Partners and certain of its affiliates and Dan L. Duncan. TEPPCO is named as a nominal defendant.

The amended complaint alleges, among other things, that certain of the transactions adopted at a special meeting of TEPPCO’s unitholders on December 8, 2006, including a reduction of the Parent Company’s maximum percentage interest in TEPPCO’s distributions in exchange for TEPPCO’s Units (the “Issuance Proposal”), were unfair to TEPPCO’s unitholders and constituted a breach by the defendants of fiduciary duties owed to TEPPCO’s unitholders and that the Proxy Statement failed to provide TEPPCO’s unitholders with all material facts necessary for them to make an informed decision whether to vote in favor of or against the proposals. The amended 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 Products Partners or its affiliates that were unfair to TEPPCO or otherwise unfairly favored Enterprise Products Partners or its affiliates over TEPPCO. The amended complaint alleges that such transactions include the Jonah joint venture entered into by TEPPCO and an Enterprise Products Partners affiliate in August 2006 (citing the fact that our ACG 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 Products Partners’ affiliate of the Pioneer plant in March 2006. As more fully described in the Proxy Statement, our ACG Committee recommended the Issuance Proposal for approval by our Board of Directors. The amended complaint also alleges that Richard S. Snell, Michael B. Bracy and Murray H. Hutchison, constituting the three members of our ACG Committee at the time, cannot be considered independent because of their alleged ownership of securities in Enterprise Products Partners and its affiliates and/or their relationships with Mr. Duncan.

The amended complaint seeks relief (i) awarding damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the complaint; (ii) rescinding all actions taken pursuant to the Proxy vote and (iii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts. Pre-trial discovery in this proceeding is underway. 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 October 2005, Williams Gas Processing, n/k/a Williams Field Services Company, LLC (“Williams”) notified Jonah that the gas delivered to Williams’ Opal Gas Processing Plant (“Opal Plant”) allegedly failed to conform to quality specifications of the Interconnect and Operator Balancing Agreement (“Interconnect Agreement”) which has allegedly caused damages to the Opal Plant in excess of $28.0 million. On July 24, 2007, Jonah filed suit against Williams in Harris County, Texas seeking a declaratory order that Jonah was not liable to Williams. In addition, on August 24, 2007, Williams filed a complaint in the 3rd Judicial District Court of Lincoln County, Wyoming alleging that Jonah was delivering non-conforming gas from its gathering customers in the Jonah

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system to the Opal Plant, in violation of the Interconnect Agreement. Jonah denies any liability to Williams. Discovery is ongoing.

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 other proceedings will not individually or in the aggregate have a future material adverse effect on our consolidated financial position.

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 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 financial position.

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 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 or financial position. At December 31, 2008, we had an accrued liability of $6.9 million related to sites requiring environmental remediation activities.

In 1999, our Arcadia, Louisiana, facility and adjacent terminals were directed by the Remediation Services Division of the Louisiana Department of Environmental Quality (“LDEQ”) to pursue remediation of environmental 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, 2008, we have an accrued liability of $0.5 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.

We received a notice of probable violation from the U.S. Department of Transportation 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.

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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 with interest 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 and gas gathering 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. 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 or if the states in which we operate adopt policies imposing more onerous regulation on gathering. Additional rules and legislation pertaining to these matters are considered and adopted from time to time at both state and federal levels. We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations or revenues.

Contractual Obligations

The following table summarizes TEPPCO’s various contractual obligations at December 31, 2008. A description of each type of contractual obligation follows:

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	Payment or Settlement due by Period
	Total		2009		2010		2011		2012		2013		Thereafter

Maturities of long-term debt (1)	$	2,516,654	$	--	$	--	$	--	$	1,016,654	$	450,000	$	1,050,000
Interest payments (2)	$	2,624,102	$	146,838	$	146,838	$	146,839	$	127,474	$	87,975	$	1,968,138
Operating leases (3)	$	55,696	$	12,467	$	10,640	$	9,712	$	9,045	$	6,156	$	7,676

Purchase obligations (4):
Product purchase commitments:
Estimated payment obligation:
Crude oil	$	212,435	$	212,435	$	--	$	--	$	--	$	--	$	--
Refined Products	$	10,594	$	10,594	$	--	$	--	$	--	$	--	$	--
Other	$	3,057	$	1,772	$	884	$	401	$	--	$	--	$	--
Underlying major volume commitments:
Crude oil (in barrels)		4,409		4,409		--		--		--		--		--
Refined Products (in barrels)		353		353		--		--		--		--		--
Service payment commitments (5)	$	5,024	$	4,675	$	349	$	--	$	--	$	--	$	--

Contributions to Jonah (6)	$	27,000	$	27,000	$	--	$	--	$	--	$	--	$	--
Contributions to Texas Offshore Port System (7)	$	70,000	$	70,000	$	--	$	--	$	--	$	--	$	--
Capital expenditure obligations (8)	$	116,733	$	116,733	$	--	$	--	$	--	$	--	$	--
Other liabilities and deferred credits (9)	$	28,826	$	--	$	5,616	$	5,607	$	5,607	$	2,096	$	9,900

__________________

(1)

TEPPCO has long-term payment obligations under its Revolving Credit Facility, its Senior Notes and its Junior Subordinated Notes. Amounts shown in the table represent TEPPCO’s scheduled future maturities of long-term debt principal for the periods indicated (see Note 12 for additional information regarding TEPPCO’s consolidated debt obligations).

(2)

Includes interest payments due on TEPPCO’s Senior Notes and Junior Subordinated Notes and interest payments and commitment fees due on its Revolving Credit Facility. The interest amount calculated on the Revolving Credit Facility and the Junior Subordinated Notes is based on the assumption that the amount outstanding and the interest rate charged both remain at their current levels.

(3)

We lease certain 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.

(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, 2008. The majority of contractual commitments we make for the purchase of crude oil range in term from a thirty-day evergreen to one year. A substantial portion of the contracts for the purchase of crude oil that extend beyond thirty days include cancellation provisions that allow us to cancel the contract with thirty days written notice.

(5)

Includes approximately $4.5 million related to a shipment commitment on Centennial, approximately $0.4 million related to a commitment to pay for compression services on Val Verde and approximately $0.1 million related to the monthly service fee we pay Cenac to operate the marine assets in accordance with the transitional operating agreement.

(6)	Expected contributions to Jonah in 2009 for our share of capital expenditures.

(7)

Expected contributions to Texas Offshore Port System for our share of costs related to the TOPS and PACE projects. TEPPCO is obligated under the joint venture agreement to contribute one-third of the funds to complete the projects, which TEPPCO currently estimate will total $600.0 million for its share.

(8)	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.

(9)	Includes approximately $9.6 million of long-term deferred revenue payments, primarily in the Downstream and Upstream segments, which are being recognized into income as the services are performed and approximately $12.0

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million related to our estimated long-term portions of our liabilities under our guarantees to Centennial for its credit agreement and for a catastrophic event. The amount of commitment by year is our best estimate of projected payments of these long-term liabilities.

Other

Guarantees

At December 31, 2008, Centennial’s debt obligations consisted of $129.9 million borrowed under a master shelf loan agreement. In January 2008, TEPPCO entered into an Amended Guaranty agreement with Centennial’s lenders, under which the TEPPCO Guarantors are required, on a joint and several basis, to pay 50% of any past-due amount under Centennial’s master shelf loan agreement not paid by Centennial. The Amended Guaranty also has a credit maintenance requirement whereby TEPPCO may be required to provide additional credit support in the form of a letter of credit or pay certain fees if either of its credit ratings from S&P and Moody’s falls below investment grade levels as specified in the Amended Guaranty. If Centennial defaults on its debt obligations, the estimated maximum potential amount of future payments for the TEPPCO Guarantors and Marathon is $65.0 million each at December 31, 2008. At December 31, 2008, we have a liability of $9.0 million, which is based upon the expected present value of amounts we would have to pay under the guarantee.

TE Products, Marathon and Centennial have also 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, at December 31, 2008, TE Products has a liability of $3.9 million, which is based upon the expected present value of amounts we would have to pay under the guarantee. If a catastrophic event were to occur and we were required to contribute cash to Centennial, such contributions might be covered by our insurance (net of deductible), 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 pieces of equipment. We currently estimate that our minimum lease payment related to this equipment will be $3.9 million for 2009. 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.

Motiva Project

In December 2006, we signed an agreement with Motiva Enterprises, LLC (“Motiva”) for us to construct and operate a new refined products storage facility to support the expansion of Motiva’s refinery in Port Arthur, Texas. Under the terms of the agreement, we are constructing 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 or July 1, 2010, whichever comes first. The project includes the construction of 20 storage tanks, five 5.4-mile product pipelines connecting the storage facility to Motiva’s refinery, 21,000 horsepower of pumping capacity, and distribution pipeline connections to the Colonial, Explorer and Magtex pipelines. As a part of a separate but complementary initiative, we are constructing an 11-mile, 20-inch pipeline to connect the new storage facility in Port Arthur to our refined products terminal in Beaumont, Texas, which is one of the primary origination facilities for our mainline system. These projects 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

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$355.0 million, which includes $25.0 million for the 11-mile, 20-inch pipeline, $24.0 million of capitalized interest and $17.0 million of mutually agreed upon scope changes requested by Motiva. Through December 31, 2008, we have spent approximately $170.1 million on this construction project. 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, plus a ten percent cancellation fee.

Texas Offshore Port System

We, through a subsidiary, own a one-third interest in the Texas Offshore Port System joint venture. The aggregate cost of the TOPS and PACE projects is expected to be approximately $1.8 billion (excluding capitalized interest), with the majority of such expenditures currently expected to occur in 2010 and 2011. TEPPCO has guaranteed up to approximately $700.0 million, which includes a contingency amount for potential cost overruns, of the capital expenditure obligations of our subsidiary in the joint venture. See Note 9 for further information.

Other

Substantially all of the petroleum products that we transport and store are owned by our customers. At December 31, 2008, TCTM and TE Products had approximately 5.2 million barrels and 11.3 million barrels, respectively, of products in their custody that were owned by customers. We are obligated for the transportation, storage and delivery of such products on behalf of our customers. We maintain insurance to cover product losses through circumstances beyond our control at levels we believe are consistent with the associated exposures.

Insurance

We carry insurance coverage we believe to be consistent with the exposures associated with the nature and scope of our operations. As of December 31, 2008, 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, (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 and (5) hulls and certain liabilities which may arise from marine vessel operations. 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 coverage 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 16).

Commitments under our EPCO equity compensation plans

In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for us (see Note 1). This includes costs associated with unit option awards granted to these employees to purchase TEPPCO’s Units. At December 31, 2008, there were 355,000 unit options outstanding for which we were responsible for reimbursing EPCO for the costs of such awards (see Note 4).

TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

The weighted-average strike price of unit option awards outstanding at December 31, 2008 was $40.00 per TEPPCO Unit. At December 31, 2008, none of these unit options were exercisable. As these options are exercised, we will reimburse EPCO for the gross unit option value of the options exercised to make EPCO whole for related employee tax withholding requirements. See Note 4 for additional information regarding our accounting for equity awards.

NOTE 18. 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 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 year ended December 31, 2008, Valero Energy Corp., BP Oil Supply Company and Shell Trading Company accounted for 21%, 16% and 12%, respectively, of our total consolidated revenues. No other single customer accounted for 10% or more of our total consolidated revenues for the year ended December 31, 2008.