tppform10q_063009.htm

10-Q 1 tppform10q_063009.htm QUARTERLY REPORT tppform10q_063009.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2009

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___ to ___.

Commission file number: 1-10403

TEPPCO Partners, L.P.

(Exact name of Registrant as Specified in Its Charter)

Delaware		76-0291058
(State or Other Jurisdiction of		(I.R.S. Employer Identification No.)
Incorporation or Organization)

	1100 Louisiana Street, Suite 1600
	Houston, Texas 77002
	(Address of Principal Executive Offices, Including Zip Code)

	(713) 381-3636
	(Registrant’s Telephone Number, Including Area Code)

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

Yes þ No o

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

Yes ¨ No ¨

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

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

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

Yes o No þ

There were 104,943,004 limited partner units, including 260,400 restricted units, of TEPPCO Partners, L.P. outstanding at August 1, 2009. These limited partner units trade on the New York Stock Exchange under the ticker symbol “TPP.”

TEPPCO PARTNERS, L.P.

TABLE OF CONTENTS

		Page No.
PART I. FINANCIAL INFORMATION.
Item 1.	Financial Statements.
	Unaudited Condensed Consolidated Balance Sheets		2
	Unaudited Condensed Statements of Consolidated Income		3
	Unaudited Condensed Statements of Consolidated Comprehensive Income		4
	Unaudited Condensed Statements of Consolidated Cash Flows		5
	Unaudited Condensed Statements of Consolidated Partners’ Capital		6
	Notes to Unaudited Condensed Consolidated Financial Statements:
	1. Partnership Organization and Basis of Presentation		7
	2. General Accounting Matters		8
	3. Accounting for Equity Awards		10
	4. Derivative Instruments and Hedging Activities		12
	5. Inventories		18
	6. Property, Plant and Equipment		18
	7. Investments in Unconsolidated Affiliates		19
	8. Business Combination		21
	9. Intangible Assets and Goodwill		21
	10. Debt Obligations		22
	11. Partners’ Capital and Distributions		23
	12. Business Segments		26
	13. Related Party Transactions		28
	14. Earnings Per Unit		32
	15. Commitments and Contingencies		33
	16. Supplemental Cash Flow Information		40
	17. Supplemental Condensed Consolidating Financial Information		40
	18. Subsequent Events		44
Item 2.	Management’s Discussion and Analysis of Financial Condition
	and Results of Operations.		46
	Cautionary Note Regarding Forward-Looking Statements.		46
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.		71
Item 4.	Controls and Procedures.		72

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.		73
Item 1A.	Risk Factors.		73
Item 5.	Other Information.		75
Item 6.	Exhibits.		77

Signatures			79

PART I. FINANCIAL INFORMATION.

Item 1. Financial Statements.

TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	June 30,			December 31,
ASSETS	2009			2008
Current assets:
Cash and cash equivalents	$	--		$	--
Accounts receivable, trade (net of allowance for doubtful accounts of
$2.6 at June 30, 2009 and $2.6 at December 31, 2008)		984.8			790.4
Accounts receivable, related parties		10.7			15.8
Inventories		95.6			52.9
Other		38.7			48.5
Total current assets		1,129.8			907.6
Property, plant and equipment, at cost (net of accumulated depreciation of
$729.9 at June 30, 2009 and $678.8 at December 31, 2008)		2,591.6			2,439.9
Investments in unconsolidated affiliates		1,198.9			1,255.9
Intangible assets (net of accumulated amortization of $172.3 at June 30, 2009 and $158.3 at December 31, 2008)		195.1			207.7
Goodwill		106.6			106.6
Other assets		132.9			132.1
Total assets	$	5,354.9		$	5,049.8

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	967.9		$	792.5
Accounts payable, related parties		40.9			17.2
Accrued interest		36.0			36.4
Other accrued taxes		21.0			23.0
Other		21.1			30.9
Total current liabilities		1,086.9			900.0
Long-term debt:
Senior notes		1,710.9			1,713.3
Junior subordinated notes		299.6			299.6
Other long-term debt		723.3			516.7
Total long-term debt		2,733.8			2,529.6
Other liabilities and deferred credits		27.8			28.7
Commitments and contingencies
Partners’ capital:
Limited partners’ interests:
Limited partner units (104,682,604 units outstanding at June 30, 2009 and 104,547,561 units outstanding at December 31, 2008)		1,673.8			1,746.2
Restricted limited partner units (260,400 units outstanding at June 30, 2009 and 157,300 units outstanding at December 31, 2008)		1.9			1.4
General partner’s interest		(126.3	)		(110.3	)
Accumulated other comprehensive loss		(43.0	)		(45.8	)
Total partners’ capital		1,506.4			1,591.5
Total liabilities and partners’ capital	$	5,354.9		$	5,049.8

See Notes to Unaudited Condensed Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Dollars in millions, except per unit amounts)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Operating revenues:
Sales of petroleum products	$	1,745.4		$	4,006.5		$	3,023.3		$	6,651.1
Transportation – Refined products		41.1			44.1			77.0			81.4
Transportation – LPGs		17.5			16.1			55.8			52.3
Transportation – Crude oil		15.2			17.4			37.1			32.7
Transportation – NGLs		13.6			12.7			26.1			25.7
Transportation – Marine		43.7			48.1			80.6			73.6
Gathering – Natural gas		14.4			14.8			28.0			28.2
Other		22.3			20.8			42.9			44.0
Total operating revenues		1,913.2			4,180.5			3,370.8			6,989.0
Costs and expenses:
Purchases of petroleum products		1,703.3			3,975.7			2,938.8			6,582.3
Operating expense		76.4			66.5			143.2			120.3
Operating fuel and power		17.9			29.1			37.6			50.5
General and administrative		15.8			11.0			25.8			19.8
Depreciation and amortization		36.8			31.9			69.8			60.2
Taxes – other than income taxes		7.1			7.0			14.0			13.1
Total costs and expenses		1,857.3			4,121.2			3,229.2			6,846.2
Operating income		55.9			59.3			141.6			142.8
Other income (expense):
Interest expense		(32.3	)		(33.0	)		(64.4	)		(71.6	)
Equity in income (loss) of unconsolidated affiliates		(12.2	)		21.3			12.9			41.0
Other, net		0.7			1.1			1.0			1.4
Income before provision for income taxes		12.1			48.7			91.1			113.6
Provision for income taxes		(0.9	)		(1.0	)		(1.7	)		(1.8	)
Net income	$	11.2		$	47.7		$	89.4		$	111.8

Net income allocated to:
Limited partners	$	9.3		$	39.7		$	74.3		$	93.1
General partner	$	1.9		$	8.0		$	15.1		$	18.7

Basic and diluted earnings per unit	$	0.09		$	0.42		$	0.71		$	0.99

See Notes to Unaudited Condensed Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME

(Dollars in millions)

	For the Three Months					For the Six Months
	Ended June 30,					Ended June 30,
	2009		2008			2009		2008

Net income	$	11.2	$	47.7		$	89.4	$	111.8
Other comprehensive income (loss):
Cash flow hedges: (see Note 4)
Change in fair values of interest rate derivative instruments		--		--			--		(23.2	)
Reclassification adjustment for loss included in net income
related to interest rate derivative instruments		1.4		--			2.8		(0.1	)
Changes in fair values of commodity derivative instruments		--		(20.6	)		--		(27.1	)
Reclassification adjustment for loss included in net income
related to commodity derivative instruments		--		9.6			--		19.2
Total cash flow hedges		1.4		(11.0	)		2.8		(31.2	)
Total other comprehensive income (loss)		1.4		(11.0	)		2.8		(31.2	)
Comprehensive income	$	12.6	$	36.7		$	92.2	$	80.6

See Notes to Unaudited Condensed Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in millions)

	For the Six Months
	Ended June 30,
	2009			2008
Operating activities:
Net income	$	89.4		$	111.8
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		69.8			60.2
Non-cash impairment charge		2.3			--
Amortization of deferred compensation		0.1			0.7
Amortization in interest expense		1.4			2.2
Changes in fair market value of derivative instruments		(0.4	)		(0.3	)
Equity in income of unconsolidated affiliates		(12.9	)		(41.0	)
Distributions received from unconsolidated affiliates		89.2			79.3
Loss on early extinguishment of debt		--			8.7
Net effect of changes in operating accounts (see Note 16)		(31.4	)		(57.5	)
Net cash provided by operating activities		207.5			164.1
Investing activities:
Cash used for business combinations		(50.0	)		(345.6	)
Investment in Jonah Gas Gathering Company		(19.1	)		(64.5	)
Investment in Texas Offshore Port System (see Note 7)		1.7			--
Acquisition of intangible assets		(1.4	)		(0.3	)
Cash paid for linefill classified as other assets		(1.5	)		(14.5	)
Capital expenditures		(164.3	)		(139.2	)
Net cash used in investing activities		(234.6	)		(564.1	)
Financing activities:
Borrowings under debt agreements		759.3			3,344.4
Repayments of debt		(552.6	)		(2,732.9	)
Net proceeds from issuance of limited partner units		3.3			5.6
Debt issuance costs		--			(9.3	)
Settlement of interest rate derivative instruments - treasury locks		--			(52.1	)
Acquisition of treasury units		(0.1	)		--
Distributions paid to partners		(182.8	)		(155.7	)
Net cash provided by financing activities		27.1			400.0
Net change in cash and cash equivalents		--			--
Cash and cash equivalents, January 1		--			--
Cash and cash equivalents, June 30	$	--		$	--

See Notes to Unaudited Condensed Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF

CONSOLIDATED PARTNERS’ CAPITAL

(Dollars in millions)

							Accumulated
							Other
	Limited			General			Comprehensive
	Partners			Partner			Income (Loss)			Total
Balance, December 31, 2008	$	1,747.6		$	(110.3	)	$	(45.8	)	$	1,591.5
Net proceeds from issuance of limited partner units		3.3			--			--			3.3
Acquisition of treasury units		(0.1	)		--			--			(0.1	)
Net income		74.3			15.1			--			89.4
Cash distributions paid to partners		(151.8	)		(31.0	)		--			(182.8	)
Non-cash contributions		0.3			--			--			0.3
Amortization of equity awards		2.1			(0.1	)		--			2.0
Reclassification adjustment for loss included in net
income related to interest rate derivative instruments		--			--			2.8			2.8
Balance, June 30, 2009	$	1,675.7		$	(126.3	)	$	(43.0	)	$	1,506.4

							Accumulated
							Other
	Limited			General			Comprehensive
	Partners			Partner			Income (Loss)			Total
Balance, December 31, 2007	$	1,395.2		$	(88.0	)	$	(42.6	)	$	1,264.6
Net proceeds from issuance of limited partner units		5.6			--			--			5.6
Issuance of limited partner units in connection with Cenac acquisition on February 1, 2008		186.6			--			--			186.6
Net income		93.1			18.7			--			111.8
Cash distributions paid to partners		(129.8	)		(25.9	)		--			(155.7	)
Non-cash contributions		0.3			--			--			0.3
Amortization of equity awards		0.5			--			--			0.5
Changes in fair values of commodity derivative instruments		--			--			(27.1	)		(27.1	)
Reclassification adjustment for loss included in net income related to commodity derivative instruments		--			--			19.2			19.2
Changes in fair values of interest rate derivative instruments		--			--			(23.2	)		(23.2	)
Balance, June 30, 2008	$	1,551.5		$	(95.2	)	$	(73.7	)	$	1,382.6

See Notes to Unaudited Condensed Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions.

Note 1. Partnership Organization and Basis of Presentation

Partnership Organization

TEPPCO Partners, L.P. is a publicly traded, diversified energy logistics partnership with operations that span much of the continental United States. Our limited partner units (“Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “TPP”. We were formed in March 1990 as a Delaware limited partnership. As used in this Report, “we,” “us,” “our,” the “Partnership” and “TEPPCO” mean TEPPCO Partners, L.P. and, where the context requires, include our subsidiaries.

We operate through TE Products Pipeline Company, LLC (“TE Products”), TCTM, L.P. (“TCTM”), TEPPCO Midstream Companies, LLC (“TEPPCO Midstream”), and beginning February 1, 2008, through TEPPCO Marine Services, LLC (“TEPPCO Marine Services”). Texas Eastern Products Pipeline Company, LLC (the “General Partner”), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us. We hold a 99.999% limited partner interest in TCTM, 99.999% membership interests in each of TE Products and TEPPCO Midstream and a 100% membership interest in TEPPCO Marine Services. TEPPCO GP, Inc., our subsidiary, holds a 0.001% general partner interest in TCTM and a 0.001% managing member interest in each of TE Products and TEPPCO Midstream.

Dan L. Duncan and certain of his affiliates, including Enterprise GP Holdings L.P. (“Enterprise GP Holdings”) and Dan Duncan LLC, a privately held company controlled by him, control us, our General Partner and Enterprise Products Partners L.P. (“Enterprise Products Partners”) and its affiliates, including Duncan Energy Partners L.P. (“Duncan Energy Partners”). Enterprise GP Holdings owns and controls the 2% general partner interest in us and has the right (through its 100% ownership of our General Partner) to receive the incentive distribution rights associated with the general partner interest. Enterprise GP Holdings, DFI GP Holdings L.P. (“DFIGP”) and other entities controlled by Mr. Duncan own 17,073,315 of our Units, which include 2,500,000 of our Units owned by DFIGP. Under an amended and restated administrative services agreement (“ASA”), EPCO, Inc. (“EPCO”), a privately held company also controlled by Mr. Duncan, performs management, administrative and operating functions required for us, and we reimburse EPCO for all direct and indirect expenses that have been incurred in managing us.

On June 28, 2009, we and our General Partner entered into definitive merger agreements with Enterprise Products Partners, its general partner, Enterprise Products GP, LLC (“EPGP”), and two of its subsidiaries. See Note 13 for information regarding the proposed merger with Enterprise Products Partners.

We refer to refined products, liquefied petroleum gases (“LPGs”), petrochemicals, crude oil, lubrication oils and specialty chemicals, natural gas liquids (“NGLs”), natural gas, asphalt, heavy fuel oil, other heated oil products and marine bunker fuel, collectively as “petroleum products” or “products.”

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements reflect all adjustments that are, in the opinion of our management, of a normal and recurring nature and necessary for a fair statement of our financial position as of June 30, 2009, and the results of our operations and cash flows for the periods presented. The results of operations for the three months and six months ended June 30, 2009 are not necessarily indicative of results of our operations for the full year 2009. The unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). Certain information and note disclosures normally

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to those rules and regulations. You should read these interim financial statements in conjunction with our consolidated financial statements and notes thereto presented in the TEPPCO Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2008.

Note 2. General Accounting Matters

Estimates

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

Fair Value Information

Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses and other current liabilities are carried at amounts which reasonably approximate their fair values due to their short-term nature. The estimated fair values of our fixed rate debt are based on quoted market prices for such debt or debt of similar terms and maturities. The carrying amount of our variable rate debt obligation reasonably approximates its fair value due to its variable interest rate. See Note 4 for fair value information associated with our derivative instruments.

The following table presents the estimated fair values of our financial instruments at the dates indicated:

	June 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
Financial Instruments	Value		Value		Value		Value
Financial assets:
Cash and cash equivalents	$	--	$	--	$	--	$	--
Accounts receivable, trade		984.8		984.8		790.4		790.4
Financial liabilities:
Accounts payable and accrued liabilities		967.9		967.9		792.5		792.5
Other current liabilities		21.1		21.1		30.9		30.9
Fixed-rate debt (principal amount)		2,000.0		1,967.0		2,000.0		1,553.2
Variable-rate debt		723.3		723.3		516.7		516.7

Recent Accounting Developments

The following information summarizes recently issued accounting guidance since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008 that will or may affect our future financial statements.

In April 2009, the Financial Accounting Standards Board (“FASB”) issued new guidance in the form of FASB Staff Positions (“FSPs”) in an effort to clarify certain fair value accounting rules. FSP Financial Accounting Standard (“FAS”) 157-4 (Accounting Standards Codification (“ASC”) 820), Determining Fair Value When the Volumes and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, establishes a process to determine whether a market is not active and a transaction is not distressed. FSP FAS 157-4 states that companies should look at several factors and use judgment to ascertain if a formerly active market has become inactive. When estimating fair value, FSP FAS 157-4 requires companies to place more weight on observable transactions determined to be orderly and less weight on transactions for which there is

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

insufficient information to determine whether the transaction is orderly (entities do not have to incur undue cost and effort in making this determination). The FASB also issued FSP FAS 107-1 and APB 28-1 (ASC 825), Interim Disclosures About Fair Value of Financial Instruments. This FSP requires that companies provide qualitative and quantitative information about fair value estimates for all financial instruments not measured on the balance sheet at fair value in each interim report. Previously, this was only an annual requirement. We adopted these FSPs effective June 30, 2009. Our adoption of this new guidance did not have a material impact on our financial statements or related disclosures.

In May 2009, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 165 (ASC 855), Subsequent Events, which establishes general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. We adopted SFAS 165 on June 30, 2009. Our adoption of this guidance did not have any impact on our financial position, results of operations or cash flows.

In June 2009, the FASB issued SFAS No. 167 (ASC 810), Amendments to FASB Interpretation No. 46(R), which amended consolidation guidance for variable interest entities (“VIEs”) under FASB Interpretation (“FIN”) No. 46(R) (“FIN 46(R)”) (ASC 810-10) Consolidation of Variable Interest Entities. VIEs are entities whose equity investors do not have sufficient equity capital at risk such that the entity cannot finance its own activities. When a business has a controlling financial interest in a VIE, the assets, liabilities and profit or loss of that entity must be included in consolidation. A business enterprise must consolidate a VIE when that enterprise has a variable interest that will cover most of the entity’s expected losses and/or receive most of the entity’s anticipated residual return. SFAS 167, among other things, eliminates the scope exception for qualifying special-purpose entities, amends certain guidance for determining whether an entity is a VIE, expands the list of events that trigger reconsideration of whether an entity is a VIE, requires a qualitative rather than a quantitative analysis to determine the primary beneficiary of a VIE, requires continuous assessments of whether a company is the primary beneficiary of a VIE and requires enhanced disclosures about a company’s involvement with a VIE. SFAS 167 is effective for us on January 1, 2010. At June 30, 2009, we did not have any VIEs; therefore, our adoption of this new guidance is not expected to have a material impact on our consolidated financial statements.

In June 2009, the FASB issued SFAS No. 168 (ASC 105), The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162, which establishes the ASC as the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. The ASC is a reorganization of current GAAP into a topical format that eliminates the current GAAP hierarchy and establishes instead two levels of guidance — authoritative and nonauthoritative. All guidance contained in the ASC carries an equal level of authority. Rules and interpretive releases of the SEC under federal securities laws are also sources of authoritative GAAP for SEC registrants. SFAS 168 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. SFAS 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We will adopt SFAS 168 on September 30, 2009. Our adoption of this new guidance is not expected to have any impact on our financial position, results of operations or cash flows. References to specific GAAP in our consolidated financial statements after our adoption of SFAS 168 will refer exclusively to the ASC. We have elected to provide references to the ASC parenthetically in this Quarterly Report.

Subsequent Events

We have evaluated subsequent events through August 6, 2009, which is the date our Unaudited Condensed Consolidated Financial Statements and Notes are being issued.

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 3. Accounting for Equity Awards

We account for equity awards in accordance with SFAS No. 123(R) (ASC 718 and 505), Share-Based Payment (“SFAS 123(R)”). Such awards were not material to our consolidated financial position, results of operations or cash flows for all periods presented. The amount of equity-based compensation allocable to us was $1.2 million and $0.8 million for the three months ended June 30, 2009 and 2008, respectively. For the six months ended June 30, 2009 and 2008, the amount of equity-based compensation allocable to us was $2.2 million and $1.2 million, respectively.

Certain key employees of EPCO participate in long-term incentive compensation plans managed by EPCO. The compensation expense we record related to equity awards is based on an allocation of the total cost of such incentive plans to EPCO. We record our pro rata share of such costs based on the percentage of time each employee spends on our business activities.

1999 Phantom Unit Retention 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. A total of 2,800 phantom units were outstanding under the 1999 Plan at June 30, 2009, which cliff vest in January 2010. During the first quarter of 2009, 2,800 additional phantom units which were outstanding at December 31, 2008 under the 1999 Plan were forfeited. Additionally, in April 2009, 13,000 phantom units vested and $0.3 million was paid out to a participant in April 2009. At June 30, 2009 and December 31, 2008, we had accrued liability balances of $0.1 million and $0.4 million, respectively, for compensation related to the 1999 Plan.

2000 Long Term Incentive Plan

The Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) provides key employees incentives to achieve improvements in our financial performance. At December 31, 2008, we had an accrued liability balance of $0.2 million for compensation related to the 2000 LTIP. On December 31, 2008, 11,300 phantom units vested and $0.2 million was paid out to participants in the first quarter of 2009. There were no remaining phantom units outstanding under the 2000 LTIP at June 30, 2009.

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 our financial performance. At December 31, 2008, we had an accrued liability balance of $0.6 million for compensation related to the 2005 Phantom Unit Plan. On December 31, 2008, a total of 36,600 phantom units vested and $0.6 million was paid out to participants in the first quarter of 2009. There were no remaining phantom units outstanding under the 2005 Phantom Unit Plan at June 30, 2009.

EPCO 2006 Long-Term Incentive Plan

The EPCO, Inc. 2006 TPP Long-Term Incentive Plan (“2006 LTIP”) provides for awards of our 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, unit appreciation rights (“UARs”) and distribution equivalent rights. Subject to adjustment as provided in the 2006 LTIP, awards with respect to up to an aggregate of 5,000,000 Units may be granted under the 2006 LTIP. After giving effect to the issuance or forfeiture of restricted unit awards and option awards through June 30, 2009, a total of 4,161,046 additional Units could be issued under the 2006 LTIP in the future. The merger agreement governing our proposed merger with a

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

subsidiary of Enterprise Products Partners contains restrictions on the issuance of additional Units under the 2006 LTIP. See Note 13 for information regarding the proposed merger with Enterprise Products Partners.

Unit option awards. 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)

Outstanding at December 31, 2008		355,000		$	40.00
Granted (1)		329,000		$	24.84
Forfeited		(109,500	)	$	34.38
Outstanding at June 30, 2009 (2)		574,500		$	32.39		4.78

(1) The total grant date fair value of these unit option awards granted in 2009 was $1.3 million based upon the following assumptions: (i) weighted-average expected life of options of 4.8 years; (ii) weighted-average risk-free interest rate of 2.14%; (iii) weighted-average expected distribution yield on our Units of 11.31%; (iv) estimated forfeiture rate of 17.0%; and (v) weighted-average expected unit price volatility on our Units of 59.32%. (2) No unit options were exercisable as of June 30, 2009.

At June 30, 2009, the estimated total unrecognized compensation cost related to nonvested unit option awards granted under the 2006 LTIP was $1.5 million. We expect to recognize our share of this cost over a weighted-average period of 3.46 years in accordance with the ASA (see Note 13).

Restricted unit awards. The following table presents restricted unit activity under the 2006 LTIP for the periods indicated:


				Weighted-
				Average Grant
	Number			Date Fair Value
	of Units			per Unit (1)
Restricted units at December 31, 2008		157,300
Granted (2)		140,450		$	23.93
Vested		(5,000	)	$	34.63
Forfeited		(32,350	)	$	32.29
Restricted units at June 30, 2009		260,400

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per Unit for forfeited and vested awards is determined before an allowance for forfeitures. (2) Aggregate grant date fair value of restricted unit awards issued during 2009 was $3.4 million based on grant date market prices ranging from $28.81 to $29.83 per Unit and an estimated forfeiture rate of 17.0%.

The total fair value of our restricted unit awards that vested during the three months and six months ended June 30, 2009 was $0.1 million. At June 30, 2009, the estimated total unrecognized compensation cost related to restricted unit awards under the 2006 LTIP was $6.2 million. We expect to recognize our share of this cost over a weighted-average period of 3.17 years in accordance with the ASA.

Phantom unit awards. At June 30, 2009, a total of 1,647 phantom units were outstanding, which were awarded in 2007 under the 2006 LTIP to three of the then non-executive members of the board of directors. 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 we paid to our unitholders. Phantom unit awards to non-executive directors are accounted for in a manner similar to SFAS 123(R) liability awards.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UAR awards. At June 30, 2009, a total of 392,788 UARs were outstanding, which were awarded in 2007 under the 2006 LTIP to non-executive members of the board of directors and to certain employees providing services directly to us.

Non-Executive Members of the Board of Directors. At June 30, 2009, a total of 95,654 UARs, awarded to non-executive members of the board of directors under the 2006 LTIP, were outstanding at a weighted-average exercise price of $41.82 per Unit (66,225 UARs issued in 2007 at an exercise price of $45.30 per Unit to the then three non-executive members of the board of directors and 29,429 UARs issued in 2008 at an exercise price of $33.98 per Unit to a non-executive member of the board of directors in connection with his election to the board). UARs awarded to non-executive directors are accounted for in a manner similar to SFAS 123(R) liability awards. Mr. Hutchison, who was a non-executive member of the board of directors at the time of issuance of these UARs (and the phantom unit awards discussed above), became interim executive chairman in March 2009.

Employees. At June 30, 2009, a total of 297,134 UARs, awarded under the 2006 LTIP to certain employees providing services directly to us, were outstanding at an exercise price of $45.35 per Unit. 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

In 2008, EPCO formed TEPPCO Unit, L.P. (“TEPPCO Unit”) and TEPPCO Unit II, L.P. (“TEPPCO Unit II”) (collectively, “Employee Partnerships”) to serve as long-term incentive arrangements for key employees of EPCO by providing them with a “profits interest” in the Employee Partnerships. At June 30, 2009, the estimated unrecognized compensation cost related to TEPPCO Unit and TEPPCO Unit II was $1.4 million and $1.2 million, respectively. We expect to recognize our share of these costs over a weighted-average period of 4.27 years in accordance with the ASA.

Note 4. Derivative Instruments and Hedging Activities

In the course of our normal business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with certain identifiable and anticipated transactions, we use derivative instruments. Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates or commodity prices. Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities.

SFAS No. 133 (ASC 815), Accounting for Derivative Instruments and Hedging Activities, requires companies to recognize derivative instruments at fair value as either assets or liabilities on the balance sheet. While the standard requires that all derivatives be reported at fair value on the balance sheet, changes in fair value of the derivative instruments will be reported in different ways depending on the nature and effectiveness of the hedging activities to which they are related. After meeting specified conditions, a qualified derivative may be specifically designated as a total or partial hedge of:

§	Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment – In a fair value hedge, all gains and losses (of both the derivative instrument and the hedged item) are recognized in income during the period of change.

§	Variable cash flows of a forecasted transaction – In a cash flow hedge, the effective portion of the hedge is reported in other comprehensive income and is reclassified into earnings when the forecasted transaction affects earnings.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

An effective hedge is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of changes in the fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period. Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item. Any ineffectiveness associated with a hedge is recognized in earnings immediately. Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item.

On January 1, 2009, we adopted the disclosure requirements of SFAS No. 161 (ASC 815), Disclosures About Derivative Financial Instruments and Hedging Activities. SFAS 161 requires enhanced qualitative and quantitative disclosure requirements regarding derivative instruments. This footnote reflects the new disclosure standard.

Interest Rate Derivative Instruments

We utilize interest rate swaps, treasury locks and similar derivative instruments to manage our exposure to changes in the interest rates of certain debt agreements. This strategy is a component in controlling our cost of capital associated with such borrowings. At June 30, 2009, we had no interest rate derivative instruments outstanding.

At times, we may use treasury lock derivative instruments to hedge the underlying U.S. treasury rates related to forecasted issuances of debt. As cash flow hedges, gains or losses on these instruments are recorded in other comprehensive income and amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt. During March 2008, we terminated treasury locks having a combined notional value of $600.0 million and recognized an aggregate loss of $23.2 million in other comprehensive income during the first quarter of 2008. We recognized approximately $3.6 million of this loss in interest expense during the six months ended June 30, 2008 as a result of interest payments hedged under the treasury locks not occurring as forecasted.

For information regarding fair value amounts and gains and losses on interest rate derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note 4.

Commodity Derivative Instruments

We seek to maintain a position that is substantially balanced between crude oil purchases and related sales and future delivery obligations. The price of crude oil is subject to fluctuations in response to changes in supply, demand, general market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risk associated with crude oil, we enter into commodity derivative instruments such as forwards, basis swaps and futures contracts. The purpose of such hedging strategy is to either balance our inventory position or to lock in a profit margin.

At June 30, 2009, we had no outstanding commodity derivatives designated as hedging instruments under SFAS 133. Currently, our commodity derivative instruments do not meet the hedge accounting requirements of SFAS 133 and are accounted for as economic hedges using mark-to-market accounting. These financial instruments had a minimal impact on our earnings. The following table summarizes our outstanding commodity derivative instruments not designated as hedging instruments under SFAS 133 at June 30, 2009:

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

		Accounting
Derivative Purpose	Volume (1)	Treatment
Derivatives not designated as hedging instruments under SFAS 133:

Crude oil risk management activities (2)	4.5 MMBbls	Mark-to-market

(1) Reflects the absolute value of the derivative notional volumes. (2) Reflects the use of derivative instruments to manage risks associated with our portfolio of crude oil storage assets. These commodity derivative instruments have forward positions through March 2010.

For information regarding fair value amounts and gains and losses on commodity derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items” within this Note 4.

Credit-Risk Related Contingent Features in Derivative Instruments

We have no credit-risk related contingent features in any of our derivative instruments.

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

Derivative Instruments and Related Hedged Items

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

Asset Derivatives

Liability Derivatives

June 30, 2009

December 31, 2008

June 30, 2009

December 31, 2008

Balance Sheet

Fair

Balance Sheet

Fair

Balance Sheet

Fair

Balance Sheet

Fair

Location

Value

Location

Value

Location

Value

Location

Value

Derivatives not designated as hedging instruments under SFAS 133

Commodity derivatives

Other current

assets

2.7

Other current

assets

15.7

Other current

liabilities

2.3

Other current

liabilities

15.7

Total derivatives not

designated as hedging

instruments

2.7

15.7

2.3

15.7

The following table presents the effect of our derivative instruments designated as fair value hedges under SFAS 133 on our condensed consolidated statements of income for the periods indicated:

Derivatives in SFAS 133
Fair Value		Gain/(Loss) Recognized in
Hedging Relationships	Location	Income on Derivative
		For the Three Months				For the Six Months
		Ended June 30,				Ended June 30,
		2009		2008		2009		2008
Interest rate derivatives	Interest expense	$	--	$	--	$	--	$	--
Total		$	--	$	--	$	--	$	--

Derivatives in SFAS 133
Fair Value		Gain/(Loss) Recognized in
Hedging Relationships	Location	Income on Hedged Item
		For the Three Months				For the Six Months
		Ended June 30,				Ended June 30,
		2009		2008		2009		2008
Interest rate derivatives	Interest expense	$	--	$	--	$	--	$	--
Total		$	--	$	--	$	--	$	--

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables present the effect of our derivative instruments designated as cash flow hedges under SFAS 133 on our condensed consolidated statements of income for the periods indicated:

Derivatives
in SFAS 133 Cash Flow	Change in Value Recognized in OCI on
Hedging Relationships	Derivative (Effective Portion)
	For the Three Months					For the Six Months
	Ended June 30,					Ended June 30,
	2009		2008			2009		2008
Interest rate derivatives	$	--	$	--		$	--	$	(23.2	)
Commodity derivatives		--		(20.6	)		--		(27.1	)
Total	$	--	$	(20.6	)	$	--	$	(50.3	)

Derivatives	Location of Gain/(Loss)
in SFAS 133 Cash Flow	Reclassified from AOCI	Amount of Gain/(Loss) Reclassified from AOCI
Hedging Relationships	into Income (Effective Portion)	to Income (Effective Portion)
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2009			2008			2009			2008
Interest rate derivatives	Interest expense	$	(1.4	)	$	--		$	(2.8	)	$	0.1
Commodity derivatives	Revenue		--			(9.6	)		--			(19.2	)
Total		$	(1.4	)	$	(9.6	)	$	(2.8	)	$	(19.1	)

	Location of Gain/(Loss)
Derivatives	Recognized in Income
in SFAS 133 Cash Flow	on Ineffective Portion	Amount of Gain/(Loss) Reclassified in Income
Hedging Relationships	of Derivative	on Ineffective Portion of Derivative
		For the Three Months				For the Six Months
		Ended June 30,				Ended June 30,
		2009		2008		2009		2008
Interest rate derivatives	Interest expense	$	--	$	--	$	--	$	(3.6	)
Commodity derivatives	Revenue		--		--		--		--
Total		$	--	$	--	$	--	$	(3.6	)

Over the next twelve months, we expect to reclassify $6.0 million of accumulated other comprehensive loss attributable to settled treasury locks to earnings as an increase to interest expense.

The following table presents the effect of our derivative instruments not designated as hedging instruments under SFAS 133 on our condensed consolidated statements of income for the periods indicated:

Derivatives Not
Designated as SFAS 133		Gain/(Loss) Recognized in
Hedging Instruments	Location	Income on Derivative
		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2009			2008			2009		2008
Commodity derivatives	Revenue	$	(0.2	)	$	(0.1	)	$	0.6	$	0.3
Total		$	(0.2	)	$	(0.1	)	$	0.6	$	0.3

SFAS 157 – Fair Value Measurements

SFAS 157 (ASC 820) defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. Recognized valuation

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

techniques employ inputs such as product prices, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.

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

Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur with 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. At June 30, 2009, we had no Level 1 financial assets and liabilities.

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, the time value of money, volatility factors for stocks, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions are (i) observable in the marketplace throughout the full term of the instrument, (ii) can be derived from observable data or (iii) are validated by inputs other than quoted prices (e.g., interest rates and yield curves at commonly quoted intervals). Our Level 2 fair values primarily consist of commodity forward agreements transacted over-the-counter. The fair values of these derivatives are based on observable price quotes for similar products and locations.

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. Our Level 3 fair values largely consist of commodity contracts generally less than one year in term. We rely on broker quotes for these prices due to the limited observability of locational and quality-based pricing differentials. At June 30, 2009, our Level 3 financial assets were less than $0.1 million.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured on a recurring basis at June 30, 2009. These financial assets and liabilities are

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, in addition to their placement within the fair value hierarchy levels.

	Level 2		Level 3		Total
Financial assets:
Commodity derivative instruments	$	2.7	$	--	$	2.7
Total	$	2.7	$	--	$	2.7

Financial liabilities:
Commodity derivative instruments	$	2.3	$	--	$	2.3
Total	$	2.3	$	--	$	2.3

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

	For the Six Months Ended June 30,
	2009			2008
Balance, January 1	$	(0.1	)	$	(0.4	)
Total gains included in net income		0.4			0.4
Purchases, issuances, settlements		0.1			--
Balance, March 31		0.4			--
Total losses included in net income		--			(0.1	)
Purchases, issuances, settlements		(0.4	)		--
Balance, June 30	$	--		$	(0.1	)

We adopted the provisions of SFAS 157 that apply to nonfinancial assets and liabilities on January 1, 2009. Our adoption of this guidance had no impact on our financial position, results of operations or cash flows.

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances (for example, when there is evidence of impairment). The following table presents the fair value of an asset carried on the balance sheet by caption and by level within the SFAS 157 valuation hierarchy (as described above) at the date indicated for which a nonrecurring change in fair value has been recorded during the period:

		June 30, 2009				Level 1				Level 2				Level 3				Total Losses
Property, plant and equipment		$	3.0			$	--			$	--			$	3.0			$	2.3

As a result of idling a river terminal at Helena, Arkansas, in our Downstream Segment, during the six months ended June 30, 2009, we recorded a non-cash impairment charge of $2.3 million, which is included in operating expense for the three months and six months ended June 30, 2009 (see Note 6). We estimated the fair value of the asset using appropriate valuation techniques.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 5. 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 at the dates indicated:

	June 30,		December 31,
	2009		2008
Crude oil (1)	$	58.1	$	32.8
Refined products and LPGs (2)		17.2		0.4
Lubrication oils and specialty chemicals		10.2		11.1
Materials and supplies		10.0		8.6
NGLs		0.1		--
Total	$	95.6	$	52.9

(1) At June 30, 2009 and December 31, 2008, $57.8 million and $30.7 million, respectively, of our crude oil inventory was subject to forward sales contracts. (2) Refined products and LPGs inventory is managed on a combined basis.

Due to fluctuating commodity prices, we recognize lower of average cost or market (“LCM”) adjustments when the carrying value of our inventories exceeds their net realizable value. These non-cash charges are a component of costs and expenses in the period they are recognized. For the three months ended June 30, 2009 and 2008, we recognized LCM adjustments of approximately $1.1 million and $0.1 million, respectively. We recognized LCM adjustments of $2.1 million and $0.1 million for the six months ended June 30, 2009 and 2008, respectively.

Note 6. Property, Plant and Equipment

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

	Estimated
	Useful Life		June 30,		December 31,
	in Years		2009		2008
Plants and pipelines (1)		5-40(5)	$	1,943.9	$	1,919.7
Underground and other storage facilities (2)		5-40(6)		315.8		296.8
Transportation equipment (3)		5-10		13.0		11.3
Marine vessels (4)		20-30		508.6		453.0
Land and right of way				144.1		143.8
Construction work in progress				396.1		294.1
Total property, plant and equipment			$	3,321.5	$	3,118.7
Less: accumulated depreciation				729.9		678.8
Property, plant and equipment, net			$	2,591.6	$	2,439.9

(1) Plants and pipelines include refined products, LPGs, NGLs, 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. (3) Transportation equipment includes vehicles and similar assets used in our operations. (4) $50.0 million of the increase relates to the vessels acquired from TransMontaigne Products Services Inc. (see Note 8). (5) 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. (6) 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.

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
Depreciation expense (1)	$	28.4	$	23.9	$	53.8	$	45.8
Capitalized interest (2)		5.2		5.5		10.5		9.9

(1) Depreciation expense is a component of depreciation and amortization expense as presented in our unaudited condensed statements of consolidated income. (2) Capitalized interest (included in interest expense on our unaudited condensed statements of consolidated income) increases the carrying value of the associated asset and reduces interest expense during the period it is recorded.

During the three months and six months ended June 30, 2009, we recorded a $2.3 million non-cash impairment charge, which is included in operating expense, related to the idling of a river terminal at Helena, Arkansas, in our Downstream Segment.

Asset Retirement Obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of certain tangible long-lived assets that result from acquisitions, construction, development and/or normal operations or a combination of these factors. Our ARO liability balance at June 30, 2009 and December 31, 2008 was $1.5 million. Accretion expense was less than $0.1 million for each of the three months ended June 30, 2009 and 2008. For each of the six months ended June 30, 2009 and 2008, accretion expense was $0.1 million. Property, plant and equipment at June 30, 2009 include $0.7 million of asset retirement costs capitalized as an increase in the associated long-lived asset.

Note 7. Investments In Unconsolidated Affiliates

We own interests in related businesses that are accounted for using the equity method of accounting. These investments are identified in the following table by reporting business segment (see Note 12 for a general discussion of our business segments). The following table presents our investments in unconsolidated affiliates at the dates indicated:

	Ownership
	Percentage at
	June 30,		June 30,		December 31,
	2009		2009		2008
Downstream Segment:
Centennial Pipeline LLC (“Centennial”)		50.0%	$	66.4	$	71.8
Other		25.0%		0.4		0.4
Upstream Segment:
Seaway Crude Pipeline Company (“Seaway”)		50.0%		182.9		190.1
Texas Offshore Port System (“TOPS”) (1)		--		--		35.9
Midstream Segment:
Jonah Gas Gathering Company (“Jonah”)		80.64%		949.2		957.7
Total			$	1,198.9	$	1,255.9

(1) In January 2009, we received a $3.1 million refund of our 2008 contributions to TOPS due to a delay in the timing of the expected project spending. In February and March 2009, we then invested an additional $1.4 million in TOPS. In April 2009, we elected to dissociate from TOPS and forfeited our investment. See below for further information.

Our investments in Centennial, Seaway and Jonah included excess cost amounts totaling $73.3 million and $72.9 million at June 30, 2009 and December 31, 2008, respectively. The value assigned to our excess investment in Centennial was created upon its formation, the value assigned to our excess investment in Seaway was created upon acquisition of our ownership interest in Seaway and 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 amortize such excess cost as a reduction in equity earnings in a manner similar

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

to depreciation over the life of applicable contracts or assets acquired or constructed. Amortization of excess cost amounts was $1.1 million and $1.3 million for the three months ended June 30, 2009 and 2008, respectively. For the six months ended June 30, 2009 and 2008, amortization of such excess cost amounts was $2.6 million and $2.4 million, respectively. For the remainder of 2009, amortization expense associated with our excess investments is currently estimated at $3.0 million.

In August 2008, a wholly owned subsidiary of ours, together with a subsidiary of Enterprise Products Partners and Oiltanking Holding Americas, Inc. (“Oiltanking”), formed the TOPS partnership. Effective April 16, 2009, our wholly owned subsidiary dissociated from TOPS. As a result, equity earnings and net income for the second quarter of 2009 include a non-cash charge of $34.2 million. This loss represents our cumulative investment in TOPS through the date of dissociation and reflects our capital contributions to TOPS for construction in progress amounts. We believe that the dissociation discharged our affiliate with respect to further obligations under the TOPS partnership agreement, and accordingly, us from the associated liability under the related parent guarantee; therefore, we have not recorded any amounts related to such guarantee. The wholly owned subsidiary of Enterprise Products Partners that was a partner in TOPS also dissociated from the partnership effective April 16, 2009. See Note 15 for litigation matters associated with our dissociation from TOPS.

The following table summarizes equity in income (loss) of unconsolidated affiliates by business segment for the periods indicated:

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Downstream Segment	$	(4.3	)	$	(3.7	)	$	(7.4	)	$	(7.8	)
Upstream Segment (1)		(31.3	)		4.2			(28.0	)		7.2
Midstream Segment		23.8			21.9			49.4			45.6
Intersegment eliminations		(0.4	)		(1.1	)		(1.1	)		(4.0	)
Total	$	(12.2	)	$	21.3		$	12.9		$	41.0

(1) 2009 periods include the non-cash charge of $34.2 million related to the dissociation from TOPS.

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 second quarter of 2009, no impairment charges were required. We have the intent and ability to hold these investments, which are integral to our operations.

Summarized Financial Information of Unconsolidated Affiliates

Summarized combined income statement data by reporting segment for the periods indicated is presented in the following table (on a 100% basis):

	Summarized Income Statement Information for the Three Months Ended
	June 30, 2009								June 30, 2008
			Operating			Net					Operating		Net
	Revenues		Income (Loss)			Income (Loss)			Revenues		Income		Income (Loss)
Downstream Segment	$	7.7	$	(2.8	)	$	(5.4	)	$	10.4	$	1.3	$	(1.5	)
Upstream Segment		21.8		10.1			10.0			27.4		15.3		15.3
Midstream Segment		61.2		29.6			29.6			60.2		26.9		27.2

	Summarized Income Statement Information for the Six Months Ended
	June 30, 2009								June 30, 2008
			Operating			Net					Operating		Net
	Revenues		Income (Loss)			Income (Loss)			Revenues		Income		Income (Loss)
Downstream Segment	$	17.4	$	(0.6	)	$	(5.8	)	$	20.0	$	2.2	$	(3.3	)
Upstream Segment		41.5		18.8			18.8			48.0		25.7		25.7
Midstream Segment		120.6		61.4			61.6			118.4		56.2		56.6

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 8. Business Combination

On June 5, 2009, we expanded our Marine Services Segment with the acquisition of 19 tow boats and 28 tank barges from TransMontaigne Product Services Inc. (“TransMontaigne”), for $50.0 million in cash. The acquired vessels provide marine vessel fueling services for cruise liners and cargo ships, referred to as bunkering, and other ship-assist services and transport fuel oil for electric generation plants. The acquisition complements our existing fleet of vessels that currently transport petroleum products along the nation’s inland waterway system and in the Gulf of Mexico. The newly acquired marine assets are generally supported by contracts that have a three to five year term and are based primarily in Miami, Florida, with additional assets located in Mobile, Alabama, and Houston, Texas. We financed the acquisition with borrowings under our revolving credit facility.

The results of operations for the TransMontaigne acquisition are included in our consolidated financial statements beginning at the date of acquisition. This acquisition was accounted for as a business combination using the acquisition method of accounting in accordance with SFAS 141(R) (ASC 805). Under SFAS 141(R), all of the assets acquired in the transaction are recognized at their acquisition-date fair values, while transaction costs associated with the transaction are expensed as incurred. Accordingly, the cost of the acquisition has been recorded as property, plant and equipment based on estimated fair values. Such fair values have been developed using recognized business valuation techniques.

On a pro forma basis, our revenues, costs and expenses, operating income, net income and earnings per Unit amounts would not have differed materially from those we actually reported for the three months and six months ended June 30, 2009 and 2008 due to the immaterial nature of our 2009 business combination transaction.

Note 9. Intangible Assets and Goodwill

Intangible Assets

The following table summarizes intangible assets by business segment being amortized at the dates indicated:

	June 30, 2009							December 31, 2008
	Gross		Accum.			Carrying		Gross		Accum.			Carrying
	Value		Amort.			Value		Value		Amort.			Value
Intangible assets:
Downstream Segment:
Transportation agreements	$	1.0	$	(0.4	)	$	0.6	$	1.0	$	(0.4	)	$	0.6
Other		7.0		(1.0	)		6.0		5.6		(0.8	)		4.8
Subtotal		8.0		(1.4	)		6.6		6.6		(1.2	)		5.4
Upstream Segment:
Transportation agreements		0.9		(0.4	)		0.5		0.9		(0.4	)		0.5
Other		10.5		(3.3	)		7.2		10.6		(3.0	)		7.6
Subtotal		11.4		(3.7	)		7.7		11.5		(3.4	)		8.1
Midstream Segment:
Gathering agreements		239.7		(134.1	)		105.6		239.6		(125.8	)		113.8
Fractionation agreements		38.0		(21.4	)		16.6		38.0		(20.4	)		17.6
Other		0.3		(0.2	)		0.1		0.3		(0.1	)		0.2
Subtotal		278.0		(155.7	)		122.3		277.9		(146.3	)		131.6
Marine Services Segment:
Customer relationship intangibles		51.3		(4.8	)		46.5		51.3		(3.1	)		48.2
Other		18.7		(6.7	)		12.0		18.7		(4.3	)		14.4
Subtotal		70.0		(11.5	)		58.5		70.0		(7.4	)		62.6
Total intangible assets	$	367.4	$	(172.3	)	$	195.1	$	366.0	$	(158.3	)	$	207.7

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents amortization expense of intangible assets by business segment for the periods indicated:

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
Downstream Segment	$	0.1	$	0.1	$	0.2	$	0.2
Upstream Segment		0.2		0.2		0.3		0.3
Midstream Segment		4.8		5.4		9.4		10.4
Marine Services Segment		2.0		2.2		4.1		3.4
Total	$	7.1	$	7.9	$	14.0	$	14.3

Based on information currently available, we estimate that amortization expense will approximate $13.1 million for the last six months of 2009, $24.6 million for 2010, $22.7 million for 2011, $17.2 million for 2012 and $15.6 million for 2013.

Goodwill

The following table presents the carrying amount of goodwill by business segment at the dates indicated:

	June 30,		December 31,
	2009		2008
Downstream Segment	$	1.3	$	1.3
Upstream Segment		14.9		14.9
Marine Services Segment		90.4		90.4
Total	$	106.6	$	106.6

Note 10. Debt Obligations

The following table summarizes the principal amounts outstanding under all of our debt instruments at the dates indicated:

	June 30,		December 31,
	2009		2008
Senior debt obligations: (1)
Revolving Credit Facility, due December 2012 (2)	$	723.3	$	516.7
7.625% Senior Notes, due February 2012		500.0		500.0
6.125% Senior Notes, due February 2013		200.0		200.0
5.90% Senior Notes, due April 2013		250.0		250.0
6.65% Senior Notes, due April 2018		350.0		350.0
7.55% Senior Notes, due April 2038		400.0		400.0
Total principal amount of long-term senior debt obligations		2,423.3		2,216.7
7.000% Junior Subordinated Notes, due June 2067 (1)		300.0		300.0
Total principal amount of long-term debt obligations		2,723.3		2,516.7
Adjustment to carrying value associated with hedges of fair value and
unamortized discounts (3)		10.5		12.9
Total long-term debt obligations		2,733.8		2,529.6
Total Debt Instruments (3)	$	2,733.8	$	2,529.6

(1) TE Products, TCTM, TEPPCO Midstream and Val Verde Gas Gathering Company, L.P. (“Val Verde”) (collectively, the “Guarantor Subsidiaries”) have issued full, unconditional, joint and several guarantees of our senior notes, junior subordinated notes and revolving credit facility (“Revolving Credit Facility”). (2) The weighted-average interest rate paid on our variable rate Revolving Credit Facility at June 30, 2009 was 0.92%. (3) From time to time we enter into interest rate swap agreements to hedge our exposure to changes in the fair value on a portion of the debt obligations presented above (see Note 4). At June 30, 2009 and December 31, 2008, amount includes $5.0 million and $5.2 million of unamortized discounts, respectively, and $15.5 million and $18.1 million, respectively, related to fair value hedges.

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Except for routine fluctuations in our unsecured Revolving Credit Facility, there have been no material changes in the terms of our debt obligations since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008.

During September 2008, Lehman Brothers Bank, FSB (“Lehman”), which had a 4.05% participation in our Revolving Credit Facility, stopped funding its commitment following the bankruptcy filing of its parent entity. Assuming that future fundings are not received for the Lehman percentage commitment, aggregate available capacity would be reduced by approximately $28.9 million. At June 30, 2009, our available borrowing capacity under the Revolving Credit Facility was approximately $197.8 million.

See Note 18 for a subsequent event regarding a loan agreement we entered into with Enterprise Products Partners.

Covenants

We were in compliance with the covenants of our long-term debt obligations at June 30, 2009.

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 June 30, 2009 (on a 100% basis) and the corresponding scheduled maturities of such debt.

	Our				Scheduled Maturities of Debt
	Ownership														After
	Interest		Total		2009		2010		2011		2012		2013		2013
Centennial		50%	$	124.8	$	4.8	$	9.1	$	9.0	$	8.9	$	8.6	$	84.4

At June 30, 2009 and December 31, 2008, Centennial’s debt obligations consisted of $124.8 million and $129.9 million, respectively, 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 (see Note 15).

There have been no material changes in the terms of the debt obligations of Centennial since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008.

Note 11. Partners’ Capital and Distributions

Our Units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our partnership agreement (“Partnership Agreement”). We are managed by our General Partner.

In accordance with the Partnership Agreement, capital accounts are maintained for our General Partner and limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in our consolidated financial statements. In connection with the amendment of our Partnership Agreement in December 2006, the General Partner’s obligation to make capital contributions to maintain its 2% capital account was eliminated.

Our Partnership Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that our limited partners and General Partner will receive. Net income reflected under GAAP in our financial statements is allocated between the General Partner and the limited

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

partners in the same proportion as aggregate cash distributions made to the General Partner and the limited partners during the period. Net income determined under our Partnership Agreement, however, incorporates principles established for U.S. federal income tax purposes and is not comparable to net income reflected under GAAP in our financial statements.

Registration Statements

In general, the Partnership Agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for such consideration and on such terms and conditions as may be established by our General Partner in its sole discretion (subject, under certain circumstances, to the approval of our unitholders).

We have a universal shelf registration statement on file with the SEC that allows us to issue an unlimited amount of debt and equity securities.

We also have a registration statement on file with the SEC authorizing the issuance of up to 10,000,000 Units in connection with our distribution reinvestment plan (“DRIP”). A total of 533,936 Units have been issued under this registration statement from inception of the DRIP through June 30, 2009. See Note 18 for information regarding the suspension of the DRIP.

In addition, we have a registration statement on file related to our employee unit purchase plan (“EUPP”), under which we can issue up to 1,000,000 Units. A total of 43,506 Units have been issued to employees under this plan from inception of the EUPP through June 30, 2009. See Note 18 for information regarding the suspension of the EUPP.

During the six months ended June 30, 2009, a total of 131,605 Units were issued in connection with the DRIP and the EUPP. Total net proceeds received during the six months ended June 30, 2009 from these Unit offerings was $3.3 million.

Summary of Changes in Outstanding Units

The following table summarizes changes in our outstanding units since December 31, 2008:

		Limited
		Partner	Restricted	Treasury
		Units	Units	Units	Total
Balance, December 31, 2008		104,547,561	157,300	--	104,704,861
	Units issued in connection with DRIP	115,703	--	--	115,703
	Units issued in connection with EUPP	15,902	--	--	15,902
	Issuance of restricted units under 2006 LTIP	--	140,450	--	140,450
	Conversion of restricted units to Units	5,000	(5,000)	--	--
	Acquisition of treasury units	(1,562)	--	1,562	--
	Cancellation of treasury units	--	--	(1,562)	(1,562)
	Forfeiture of restricted units	--	(32,350)	--	(32,350)
Balance, June 30, 2009		104,682,604	260,400	--	104,943,004

During the six months ended June 30, 2009, 5,000 restricted unit awards vested and were converted into Units. Of this amount, 1,562 were sold back to us by an employee to cover related withholding tax requirements. The total cost of these treasury units were approximately $0.1 million, which was allocated to our limited partners. Immediately upon acquisition, we cancelled such treasury units.

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Quarterly Distributions of Available Cash

We make quarterly cash distributions of all of our available cash, generally defined in our Partnership Agreement as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its reasonable discretion (“Available Cash”). Pursuant to the Partnership Agreement, the General Partner receives incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds.

The following table reflects the allocation of total distributions paid during the periods indicated:

	For the Six Months Ended June 30,
	2009		2008
Limited Partner Units	$	151.8	$	129.8
General Partner Ownership Interest		3.1		2.6
General Partner Incentive		27.9		23.3
Total Cash Distributions Paid	$	182.8	$	155.7
Total Cash Distributions Paid Per Unit	$	1.450	$	1.405

Our quarterly cash distributions for 2009 are presented in the following table:

	Distribution		Record	Payment
	per Unit		Date	Date
1st Quarter 2009	$	0.725	Apr. 30, 2009	May 7, 2009
2nd Quarter 2009 (1)	$	0.725	Jul. 31, 2009	Aug. 7, 2009

(1) The second quarter 2009 cash distribution will total approximately $91.6 million.

General Partner’s Interest

At June 30, 2009 and December 31, 2008, we had deficit balances of $126.3 million and $110.3 million, respectively, in our General Partner’s equity account. These negative balances do not represent assets to us and do not represent obligations of the General Partner to contribute cash or other property to us. According to the Partnership Agreement, in the event of our dissolution, after satisfying our liabilities, our remaining assets would be divided among our limited partners and the General Partner generally in the same proportion as Available Cash but calculated on a cumulative basis over the life of the Partnership. If a deficit balance still remains in the General Partner’s equity account after all allocations are made between the partners, the General Partner would not be required to make whole any such deficit.

Accumulated Other Comprehensive Loss

Our accumulated other comprehensive loss balance consisted of losses of $43.0 million and $45.8 million related to interest rate and treasury lock derivative instruments at June 30, 2009 and December 31, 2008, respectively.

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 12. 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 petroleum products and provision of marine vessel fueling and other ship-assist services.

The following table presents our measurement of earnings before interest expense for the periods indicated:

	For the Three Months					For the Six Months
	Ended June 30,					Ended June 30,
	2009			2008		2009		2008
Total operating revenues	$	1,913.2		$	4,180.5	$	3,370.8	$	6,989.0
Less: Total costs and expenses		1,857.3			4,121.2		3,229.2		6,846.2
Operating income		55.9			59.3		141.6		142.8
Add: Equity in income (loss) of unconsolidated affiliates		(12.2	)		21.3		12.9		41.0
Other, net		0.7			1.1		1.0		1.4
Earnings before interest expense and provision for income taxes	$	44.4		$	81.7	$	155.5	$	185.2

A reconciliation of our earnings before interest expense and provision for income taxes to net income for the periods indicated is as follows:

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Earnings before interest expense and provision for income taxes	$	44.4		$	81.7		$	155.5		$	185.2
Interest expense		(32.3	)		(33.0	)		(64.4	)		(71.6	)
Income before provision for income taxes		12.1			48.7			91.1			113.6
Provision for income taxes		(0.9	)		(1.0	)		(1.7	)		(1.8	)
Net income	$	11.2		$	47.7		$	89.4		$	111.8

Amounts indicated in the following table as “Partnership and Other” for income and expense items (including operating income) relate primarily to intersegment eliminations from activities among our reporting segments. Amounts indicated in the following table as “Partnership and Other” for assets and capital expenditures 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 Partnership level).

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table includes information by segment, together with reconciliations to our consolidated totals, for the periods indicated:

	Reportable Segments
									Marine
	Downstream			Upstream			Midstream		Services		Partnership
	Segment			Segment			Segment		Segment		and Other			Consolidated
Revenues from third parties:
Three months ended June 30, 2009	$	79.0		$	1,751.4		$	27.6	$	43.7	$	--		$	1,901.7
Three months ended June 30, 2008		75.1			4,025.2			27.2		48.1		--			4,175.6
Six months ended June 30, 2009		155.6			3,047.5			52.8		80.6		--			3,336.5
Six months ended June 30, 2008		169.7			6,680.3			53.8		73.6		--			6,977.4

Revenues from related parties:
Three months ended June 30, 2009		7.9			0.2			3.5		--		(0.1	)		11.5
Three months ended June 30, 2008		1.3			0.2			3.4		--		--			4.9
Six months ended June 30, 2009		26.8			0.3			7.3		--		(0.1	)		34.3
Six months ended June 30, 2008		4.4			0.4			6.9		--		(0.1	)		11.6

Total revenues:
Three months ended June 30, 2009		86.9			1,751.6			31.1		43.7		(0.1	)		1,913.2
Three months ended June 30, 2008		76.4			4,025.4			30.6		48.1		--			4,180.5
Six months ended June 30, 2009		182.4			3,047.8			60.1		80.6		(0.1	)		3,370.8
Six months ended June 30, 2008		174.1			6,680.7			60.7		73.6		(0.1	)		6,989.0

Depreciation and amortization:
Three months ended June 30, 2009		13.3			6.7			10.3		6.5		--			36.8
Three months ended June 30, 2008		10.5			5.0			10.0		6.4		--			31.9
Six months ended June 30, 2009		24.8			12.3			19.8		12.9		--			69.8
Six months ended June 30, 2008		20.7			9.8			19.6		10.1		--			60.2

Operating income:
Three months ended June 30, 2009		13.5			29.9			3.8		8.3		0.4			55.9
Three months ended June 30, 2008		15.7			25.6			8.3		8.6		1.1			59.3
Six months ended June 30, 2009		47.9			70.8			8.3		13.5		1.1			141.6
Six months ended June 30, 2008		52.0			54.9			16.7		15.2		4.0			142.8

Equity in income (loss) of unconsolidated affiliates:
Three months ended June 30, 2009		(4.3	)		(31.3	)		23.8		--		(0.4	)		(12.2	)
Three months ended June 30, 2008		(3.7	)		4.2			21.9		--		(1.1	)		21.3
Six months ended June 30, 2009		(7.4	)		(28.0	)		49.4		--		(1.1	)		12.9
Six months ended June 30, 2008		(7.8	)		7.2			45.6		--		(4.0	)		41.0

Earnings before interest expense and provision for income taxes:
Three months ended June 30, 2009		9.4			(0.9	)		27.6		8.3		--			44.4
Three months ended June 30, 2008		12.4			30.4			30.3		8.6		--			81.7
Six months ended June 30, 2009		41.0			43.3			57.7		13.5		--			155.5
Six months ended June 30, 2008		44.8			62.7			62.5		15.2		--			185.2

Capital expenditures:
Six months ended June 30, 2009		120.7			16.5			7.3		18.3		1.5			164.3
Year ended December 31, 2008		209.8			33.4			5.2		43.6		8.5			300.5

Segment assets:
At June 30, 2009		1,417.9			1,697.8			1,517.8		703.1		18.3			5,354.9
At December 31, 2008		1,320.9			1,586.3			1,529.1		653.3		(39.8	)		5,049.8

Investments in unconsolidated affiliates:
At June 30, 2009		58.1			182.9			949.2		--		8.7			1,198.9
At December 31, 2008		63.2			226.0			957.7		--		9.0			1,255.9

Intangible assets, net:
At June 30, 2009		6.6			7.7			122.3		58.5		--			195.1
At December 31, 2008		5.4			8.1			131.6		62.6		--			207.7

Goodwill:
At June 30, 2009		1.3			14.9			--		90.4		--			106.6
At December 31, 2008		1.3			14.9			--		90.4		--			106.6

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 13. Related Party Transactions

The following table summarizes related party transactions for the periods indicated:

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
Revenues from EPCO and affiliates:
Sales of petroleum products (1)	$	0.2	$	0.3	$	0.3	$	0.9
Transportation – NGLs (2)		3.5		3.4		7.3		6.8
Transportation – LPGs (3)		1.5		1.0		6.4		3.3
Other operating revenues (4)		6.3		0.2		20.3		0.6
Related party revenues	$	11.5	$	4.9	$	34.3	$	11.6
Costs and Expenses from EPCO and affiliates:
Purchases of petroleum products (5)	$	45.2	$	30.5	$	71.9	$	50.2
Operating expense (6)		29.5		26.7		58.1		48.2
General and administrative (7)		7.4		8.0		15.5		16.8
Costs and Expenses from unconsolidated affiliates:
Purchases of petroleum products (8)		0.7		2.0		--		3.5
Operating expense (9)		0.6		1.6		2.2		3.9
Costs and Expenses from Cenac and affiliates:
Operating expense (10)		13.6		9.8		27.0		17.2
General and administrative (11)		0.5		0.8		1.6		1.3
Related party costs and expenses	$	97.5	$	79.4	$	176.3	$	141.1

(1) Includes sales from Lubrication Services, LLC (“LSI”) to Enterprise Products Partners and certain of its subsidiaries. (2) Includes revenues from NGL transportation on the Chaparral Pipeline Company, LLC and Quanah Pipeline Company, LLC (collectively referred to as “Chaparral” or “Chaparral NGL system”) and Panola Pipeline Company, LLC (“Panola Pipeline”) NGL pipelines from Enterprise Products Partners and certain of its subsidiaries. (3) Includes revenues from LPG transportation on the TE Products pipeline from Enterprise Products Partners and certain of its subsidiaries. (4) Includes sales of product inventory from TE Products to Enterprise Products Partners and other operating revenues on the TE Products pipeline from Enterprise Products Partners and certain of its subsidiaries. (5) Includes TEPPCO Crude Oil, LLC (“TCO”) purchases of petroleum products of $35.2 million and $25.9 million for the three months ended June 30, 2009 and 2008, respectively, from Enterprise Products Partners and certain of its subsidiaries and Energy Transfer Equity, L.P. and certain of its subsidiaries. For the six months ended June 30, 2009 and 2008, such amounts were $55.8 million and $41.5 million, respectively. (6) Includes operating payroll, payroll related expenses and other operating expenses, including reimbursements related to employee benefits and employee benefit plans, incurred by EPCO in managing us and our subsidiaries in accordance with the ASA and expenses related to Chaparral’s use of transportation services of a subsidiary of Enterprise Products Partners. Also includes insurance expense for the three months ended June 30, 2009 and 2008, of $1.9 million and $2.2 million, respectively, related to premiums paid by EPCO on our behalf. For the six months ended June 30, 2009 and 2008, such amounts were $5.1 million and $5.2 million, respectively. The majority of our insurance coverage, including property, liability, business interruption, auto and directors’ and officers’ liability insurance, is obtained through EPCO. (7) Includes administrative payroll, payroll related expenses and other administrative expenses, including reimbursements related to employee benefits and employee benefit plans, incurred by EPCO in managing and operating us and our subsidiaries in accordance with the ASA. (8) Includes TCO purchases of petroleum products from Jonah and Seaway and pipeline transportation expense from Seaway. (9) Includes rental expense and other operating expense. (10) Includes reimbursement for operating payroll, payroll related expenses, certain repairs and maintenance expenses and insurance premiums on our equipment under the transitional operating agreement with Cenac Towing Co., Inc., Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr. (collectively, "Cenac") pursuant to which, our fleet of acquired tow boats and tank barges (including those acquired from Horizon Maritime, L.L.C. (“Horizon”) and TransMontaigne) are operated by employees of Cenac for a period of up to two years following the Cenac acquisition. See Note 18 for information regarding the termination of the transitional operating agreement. (11) Includes reimbursement for administrative payroll and payroll related expenses, as well as payment of a $42 thousand monthly service fee and a 5% overhead fee charged on direct costs incurred by Cenac to operate the marine assets in accordance with the transitional operating agreement.

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The following table summarizes our related party receivable and payable amounts at the dates indicated:

	June 30,		December 31,
	2009		2008
Accounts receivable, related parties (1)	$	10.7	$	15.8
Accounts payable, related parties (2)		40.9		17.2

(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, advances from Seaway for operating expenses and $3.0 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 that are not a part of our consolidated group of companies:

§	EPCO and its privately-held affiliates;

§	Texas Eastern Products Pipeline Company, LLC, our General Partner;

§	Enterprise GP Holdings, which owns and controls our General Partner;

§	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; and

§	the Employee Partnerships, which are controlled by EPCO (see Note 3).

See Note 18 for a subsequent event regarding a loan agreement we entered into with Enterprise Products Partners.

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

We and our General Partner 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 privately-held affiliates depend on the cash distributions they receive from our General Partner and other investments to fund their operations and to meet their debt obligations. We paid cash distributions to our General Partner of $31.0 million and $25.9 million during the six months ended June 30, 2009 and 2008, respectively.

The limited partner interests in us 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 a privately-held affiliate of EPCO. All of the membership interests in our General Partner and the limited partner interests in us that are owned or

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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 our General Partner.

In August 2008, we, together with Enterprise Products Partners and Oiltanking, announced the formation of TOPS. On April 16, 2009, we, along with a subsidiary of Enterprise Products Partners, dissociated ourselves from TOPS (see Note 7).

EPCO ASA. We have no employees. We are managed by our General Partner, 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, Enterprise Products Partners, Duncan Energy Partners, Enterprise GP Holdings and our respective general partners are among the parties to the ASA. The Audit, Conflicts and Governance Committee (“ACG Committee”) of each general partner has 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.

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. Jerry Thompson, our chief executive officer and an employee of EPCO. The Fifth Amended and Restated ASA also extends the term of EPCO’s service obligations from December 2010 to December 2013.

Proposed Merger with Enterprise Products Partners. On June 28, 2009, we and our General Partner entered into definitive merger agreements with Enterprise Products Partners, EPGP, and two of its subsidiaries. Under the terms of the definitive agreements, we and our General Partner would become wholly owned subsidiaries of Enterprise Products Partners, and each of our outstanding Units, other than 3,645,509 of our Units owned by a privately-held affiliate of EPCO, would be cancelled and converted into the right to receive 1.24 Enterprise Products Partners common units. The 3,645,509 Units owned by a privately-held affiliate of EPCO would be converted, based on the 1.24 exchange ratio, into the right to receive 4,520,431 of Enterprise Products Partners Class B units (“Class B Units”). The Class B Units would not be entitled to regular quarterly cash distributions of Enterprise Products Partners for sixteen quarters following the closing of the merger and, except for the payment of distributions, would have the same rights and privileges as Enterprise Products Partners common units. The Class B Units would convert automatically into the same number of Enterprise Products Partners common units on the date immediately following the payment date for the sixteenth quarterly distribution following the closing of the merger. No fractional Enterprise Products Partners common units would be issued in the proposed merger, and our unitholders would, instead, receive cash in lieu of fractional Enterprise Products Partners common units, if any.

Under the terms of the definitive agreements, Enterprise GP Holdings would receive 1,331,681 common units of Enterprise Products Partners and an increase in the capital account of EPGP to maintain its 2% general partner interest in Enterprise Products Partners as consideration for 100% of the membership interests of our General Partner.

A Special Committee of the ACG Committee of our General Partner unanimously determined that the merger is fair and reasonable to us and our unaffiliated unitholders and recommended that the merger be approved by our unaffiliated unitholders, the ACG Committee of our General Partner and our General

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Partner’s board of directors. Based upon such determination and recommendation, the ACG Committee of our General Partner unanimously determined that the merger is fair and reasonable to us and our unaffiliated unitholders and approved the merger, such approval constituting “Special Approval” under our Partnership Agreement. The ACG Committee of our General Partner also recommended that our General Partner’s board of directors approve the merger. Based on the Special Committee’s determination and recommendation, as well as the ACG Committee’s determination, Special Approval and recommendation, our General Partner’s board of directors unanimously approved the merger and recommended that our unaffiliated unitholders vote in favor of the merger proposal. In addition, the ACG Committee of the general partner of each of Enterprise Products Partners and Enterprise GP Holdings also approved the transaction.

Completion of the proposed merger is subject to the approval of holders of at least a majority of our outstanding Units. In addition, pursuant to the merger agreement providing for the merger of our Partnership, the number of votes cast in favor of the merger agreement by our unitholders (excluding certain unitholders affiliated with EPCO and other specified officers and directors of our General Partner, Enterprise GP Holdings and Enterprise Products Partners) must exceed the votes cast against the merger agreement by such unitholders. Affiliates of EPCO, including Enterprise GP Holdings, have executed a support agreement with Enterprise Products Partners in which they have agreed to vote their Units in favor of the merger agreement. The closing is also subject to customary regulatory approvals, including that under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Subject to the receipt of regulatory and unitholder approvals, completion of the proposed merger is expected to occur during the fourth quarter of 2009. See Note 15 for information regarding litigation matters associated with the proposed merger.

The merger agreement providing for the merger of our Partnership contains provisions granting both us and Enterprise Products Partners the right to terminate the agreement for certain reasons, including, among others, (i) if our merger into its subsidiary has not occurred on or before December 31, 2009, and (ii) our failure to obtain unitholder approval as described above.

We incurred $6.8 million of merger-related expenses during the second quarter of 2009 that are reflected as a component of general and administrative costs.

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 June 30, 2009, we have reimbursed Enterprise Products Partners $308.3 million ($1.8 million in 2009, $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 June 30, 2009 and December 31, 2008, we had payables to Enterprise Products Partners for costs incurred of less than $0.1 million and $1.0 million, respectively. At June 30, 2009 and December 31, 2008, we had receivables from Jonah of $9.2 million and $4.7 million, respectively, for operating expenses. During the six months ended June 30, 2009 and 2008, we received distributions from Jonah of $76.0 million and $75.9 million, respectively. During each of the six months ended June 30, 2009 and 2008, Jonah paid distributions of $18.2 million to the affiliate of Enterprise Products Partners that is our joint venture partner.

Ownership of our General Partner by Enterprise GP Holdings; Relationship with Energy Transfer Equity. Enterprise GP Holdings owns and controls the 2% general partner interest in us and has the right (through its 100% ownership of our General Partner) to receive the incentive distribution rights associated with the general partner interest. Enterprise GP Holdings, DFIGP and other entities controlled by Mr. Duncan own 17,073,315 of our Units.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Enterprise GP Holdings acquired equity method investments in Energy Transfer Equity, L.P. (“Energy Transfer Equity”) and its general partner in May 2007. As a result, Energy Transfer Equity and its consolidated subsidiaries became related parties to us.

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 7.

See “Jonah Joint Venture” within this Note 13 for a description of ongoing transactions involving our Jonah joint venture with Enterprise Products Partners.

Note 14. Earnings Per Unit

The following table presents the net income available to our General Partner for the periods indicated for purposes of calculating earnings per Unit:

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Net income attributable to TEPPCO Partners, L.P.	$	11.2		$	47.7		$	89.4		$	111.8

Distributions Declared During Quarter:
Distributions to General Partner (including incentive distributions)	$	15.6		$	13.5		$	31.0		$	27.1
Distributions to limited partners		76.0			67.5			152.0			134.8
Total distributions declared during quarter	$	91.6		$	81.0		$	183.0		$	161.9

Excess of distributions over net income	$	(80.4	)	$	(33.3	)	$	(93.6	)	$	(50.1	)
General Partner’s interest in net income		16.93	%		16.74	%		16.93	%		16.74	%
Earnings allocation adjustment to General Partner under EITF 07-4 (1)	$	(13.7	)	$	(5.5	)	$	(15.9	)	$	(8.4	)

Distributions to General Partner (including incentive distributions)	$	15.6		$	13.5		$	31.0		$	27.1
Earnings allocation adjustment to General Partner under EITF 07-4		(13.7	)		(5.5	)		(15.9	)		(8.4	)
Net income available to our General Partner	$	1.9		$	8.0		$	15.1		$	18.7

(1) For purposes of computing basic and diluted earnings per Unit, we apply the provisions of EITF 07-4 (ASC 260), Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships. Our earnings are allocated on a basis consistent with distributions declared during the quarter (see Note 11).

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents our calculation of basic and diluted earnings per Unit for the periods indicated:

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
BASIC EARNINGS PER UNIT:
Numerator:
Limited partners’ interest in net income	$	9.3		$	39.7		$	74.3		$	93.1

Denominator:
Weighted-average Units		104.7			94.8			104.6			94.0
Weighted-average time-vested restricted units		0.2			0.1			0.2			--
Total		104.9			94.9			104.8			94.0

Basic earnings per Unit:
Net income attributable to TEPPCO Partners, L.P.	$	0.11		$	0.50		$	0.85		$	1.19
General Partner’s interest in net income		(0.02	)		(0.08	)		(0.14	)		(0.20	)
Limited partners’ interest in net income	$	0.09		$	0.42		$	0.71		$	0.99

DILUTED EARNINGS PER UNIT:
Numerator:
Limited partners’ interest in net income	$	9.3		$	39.7		$	74.3		$	93.1

Denominator:
Weighted-average Units		104.7			94.8			104.6			94.0
Weighted-average time-vested restricted units		0.2			0.1			0.2			--
Weighted-average incremental option units		*			--			*			*
Total		104.9			94.9			104.8			94.0

Diluted earnings per Unit:
Net income attributable to TEPPCO Partners, L.P.	$	0.11		$	0.50		$	0.85		$	1.19
General Partner’s interest in net income		(0.02	)		(0.08	)		(0.14	)		(0.20	)
Limited partners’ interest in net income	$	0.09		$	0.42		$	0.71		$	0.99

*Amount is negligible.

Our General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase, in accordance with our Partnership Agreement. At June 30, 2009 and 2008, we had outstanding 104,943,004 and 95,022,897 Units, respectively.

Note 15. Commitments and Contingencies

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 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 their last demand had been approximately $175.0 million. Following a hearing, the trial court ruled that the prerequisites for certifying a class do not exist. We expect that a final order dismissing the matter is forthcoming. Accordingly, 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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

the 3rd Judicial District Court of Lincoln County, Wyoming alleging that Jonah was delivering non-conforming gas from its gathering customers in the Jonah system to the Opal Plant, in violation of the Interconnect Agreement. Jonah denies any liability to Williams. Discovery is ongoing.

On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of the State of Delaware (the “Delaware Court”), in his individual capacity, as a putative class action on behalf of our other unitholders, and derivatively on our behalf, concerning proposals made to our unitholders in our definitive proxy statement filed with the SEC on September 11, 2006 (“Proxy Statement”) and other transactions involving us and Enterprise Products Partners or its affiliates. Mr. Brinckerhoff filed an amended complaint on July 12, 2007. The amended complaint names as defendants the General Partner; the board of directors of our General Partner; EPCO; Enterprise Products Partners and certain of its affiliates and Dan L. Duncan. We are named as a nominal defendant.

The amended complaint alleges, among other things, that certain of the transactions adopted at a special meeting of our unitholders on December 8, 2006, including a reduction of the General Partner’s maximum percentage interest in our distributions in exchange for Units (the “Issuance Proposal”), were unfair to our unitholders and constituted a breach by the defendants of fiduciary duties owed to our unitholders and that the Proxy Statement failed to provide our 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 the General Partner in 2005, the defendants, in breach of their fiduciary duties to us and our unitholders, have caused us to enter into certain transactions with Enterprise Products Partners or its affiliates that were unfair to us or otherwise unfairly favored Enterprise Products Partners or its affiliates over us. The amended complaint alleges that such transactions include the Jonah joint venture entered into by us 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 alleging we did not receive fair value for Enterprise Products Partners' participation in the joint venture), and the sale by us to an Enterprise Products Partners’ affiliate of the Pioneer plant in March 2006 (alleging that the purchase price did not provide fair value for the purchased assets to us). As more fully described in the Proxy Statement, the ACG Committee recommended the Issuance Proposal for approval by the board of directors of the General Partner. The amended complaint also alleges that Richard S. Snell, Michael B. Bracy and Murray H. Hutchison, constituting the three members of the 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. By its Opinion and Order dated November 25, 2008, the Delaware Court dismissed Mr. Brinckerhoff’s individual and putative class action claims with respect to the amendments to our Partnership Agreement. We refer to this action and the remaining claims in this action as the “Derivative Action.”

On April 29, 2009, Peter Brinckerhoff and Renee Horowitz, as Attorney in Fact for Rae Kenrow, purported unitholders of TEPPCO, filed separate complaints in the Delaware Court as putative class actions on behalf of our other unitholders, concerning the proposed merger of us and our General Partner with Enterprise Products Partners (see Note 13). On May 11, 2009, these actions were consolidated under the caption Texas Eastern Products Pipeline Company, LLC Merger Litigation, C.A. No. 4548-VCL (“Merger Action”). The complaints name as defendants our General Partner; Enterprise Products Partners and its general partner; EPCO; Dan L. Duncan; and each of the directors of our General Partner.

The Merger Action complaints allege, among other things, that the terms of the merger (as proposed as of the time the Merger Action complaints were filed) are grossly unfair to our unitholders, that Mr. Duncan and other defendants who control us have acted to drive down the price of our Units and that the proposed merger is an attempt to extinguish the Derivative Action without consideration and without

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adequate information having been provided to our unitholders to cast a vote with respect to the proposed merger. The complaints further allege that the process through which the Special Committee of our ACG Committee was appointed to consider the proposed merger is contrary to the spirit and intent of our Partnership Agreement and constitutes a breach of the implied covenant of fair dealing.

The complaints seek relief (i) enjoining the defendants and all persons acting in concert with them from pursuing the proposed merger; (ii) rescinding the proposed merger to the extent it is consummated, or awarding rescissory damages in respect thereof; (iii) directing the defendants to account for all damages suffered or to be suffered by the plaintiffs and the purposed class as a result of the defendants’ alleged wrongful conduct; and (iv) awarding plaintiffs’ costs of the actions, including fees and expenses of their attorneys and experts.

On June 28, 2009, the parties entered into a Memorandum of Understanding pursuant to which we, our General Partner, Enterprise Products Partners, EPCO, all other individual defendants and the plaintiffs have proposed to settle the Merger Action and the Derivative Action. On August 5, 2009, the parties entered into a Stipulation and Agreement of Compromise, Settlement and Release (the “Settlement Agreement”) contemplated by the Memorandum of Understanding. Pursuant to the Settlement Agreement, the board of directors of our General Partner will recommend to our unitholders that they approve the adoption of the merger agreement and take all necessary steps to seek unitholder approval for the merger as soon as practicable. Pursuant to the Settlement Agreement, approval of the merger will require, in addition to votes required under our Partnership Agreement, that the actual votes cast in favor of the proposal by holders of our outstanding Units, excluding those held by defendants to the Derivative Action, exceed the actual votes cast against the proposal by those holders. The Settlement Agreement further provides that the Derivative Action was considered by the Special Committee to be a significant benefit of ours for which fair value was obtained in the merger consideration.

The Settlement Agreement is subject to customary conditions, including Delaware Court approval. There can be no assurance that the Delaware Court will approve the settlement in the Settlement Agreement. In such event, the proposed settlement as contemplated by the Settlement Agreement may be terminated. Among other things, the plaintiffs’ agreement to settle the Derivative Action and Merger Action litigation, including their agreement to the fairness of the proposed terms and process of the merger negotiations is subject to (i) the drafting and execution of other such documentation as may be required to obtain final Delaware Court approval and dismissal of the actions, (ii) Delaware Court approval and the mailing of the notice of settlement which sets forth the terms of settlement to our unitholders, (iii) consummation of the proposed merger and (iv) final Delaware Court certification and approval of the settlement and dismissal of the actions. See Note 13 for additional information regarding our relationship with Enterprise Products Partners, including information related to the proposed merger.

Additionally, on June 29 and 30, 2009, respectively, M. Lee Arnold and Sharon Olesky, purported unitholders of TEPPCO, filed separate complaints in the District Courts of Harris County, Texas, as putative class actions on behalf of our other unitholders, concerning the proposed merger of us with Enterprise Products Partners. The complaints name as defendants us; our General Partner; Enterprise Products Partners and its general partner; EPCO; Dan L. Duncan; Jerry Thompson; and the board of directors of our General Partner. These allegations in the complaints are similar to the complaints filed in Delaware on April 29, 2009 and seek similar relief.

In connection with the dissociation of Enterprise Products Partners and us from TOPS (see Note 7), Oiltanking has filed an original petition against Enterprise Offshore Port System, LLC, Enterprise Products Operating, LLC, TEPPCO O/S Port System, LLC, us and our General Partner in the District Court of Harris County, Texas, 61st Judicial District (Cause No. 2009-31367), asserting, among other things, that the dissociation was wrongful and in breach of the TOPS partnership agreement, citing provisions of the agreement that, if applicable, would continue to obligate us and Enterprise Products Partners to make capital contributions to fund the project and impose liabilities on us and Enterprise Products Partners.

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Since we believe that our actions in dissociating from TOPS are expressly permitted by, and in accordance with, the terms of the TOPS partnership agreement, we intend to vigorously defend such actions. We have not recorded any reserves for potential liabilities relating to this litigation, although we may determine in future periods that an accrual of reserves for potential liabilities (including costs of litigation) should be made. If these payments are substantial, we could experience a material adverse impact on our results of operations and our liquidity.

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, results of operations or cash flows.

We evaluate our ongoing litigation based upon a combination of litigation and settlement alternatives. These reviews are updated as the facts and combinations of the cases develop or change. Assessing and predicting the outcome of these matters involves substantial uncertainties. In the event that the assumptions we used to evaluate these matters change in future periods or new information becomes available, we may be required to record a liability for an adverse outcome. In an effort to mitigate potential adverse consequences of litigation, we could also seek to settle legal proceedings brought against us. We have not recorded any significant reserves for any litigation in our financial statements.

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 results of operations and cash flows.

We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations, and that the cost of compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial position. We cannot ensure, however, that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment; and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows. At June 30, 2009 and December 31, 2008, our accrued liabilities for environmental remediation projects totaled $6.2 million and $6.9 million, respectively.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 June 30, 2009, 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, results of operations or cash flows.

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. In June 2009, we paid $0.4 million to the U.S. Department of Transportation in settlement of the matter. This settlement did not have a material adverse effect on our financial position, results of operations or cash flows.

The Federal Energy Regulatory Commission (“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.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” or “GHGs” and including carbon dioxide and methane, may be contributing to climate change. On April 17, 2009, the U.S. Environmental Protection Agency (“EPA”) issued a notice of its

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

proposed finding and determination that emission of carbon dioxide, methane, and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere. The EPA’s finding and determination would allow it to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. Although it may take the EPA several years to adopt and impose regulations limiting emissions of GHGs, any such regulation could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, on June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or “ACESA.” ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The U.S. Senate has also begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and may have an adverse effect on our business, financial position, demand for our products, results of operations and cash flows.

Contractual Obligations

Scheduled maturities of long-term debt. With the exception of routine fluctuations in the balance of our Revolving Credit Facility, there have been no material changes in our scheduled maturities of long-term debt since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008.

Operating lease obligations. Lease and rental expense was $4.6 million and $5.1 million during the three months ended June 30, 2009 and 2008, respectively. For the six months ended June 30, 2009 and 2008, lease and rental expense was $9.1 million and $10.3 million, respectively. There have been no material changes in our operating lease commitments since December 31, 2008.

Purchase obligations. Apart from that discussed below, there have been no material changes in our purchase obligations since December 31, 2008.

Due to our dissociation from TOPS, our capital expenditure commitments decreased by an estimated $68.0 million. See Note 7 for additional information regarding our dissociation from TOPS.

Other

Guarantees. At June 30, 2009 and December 31, 2008, Centennial’s debt obligations consisted of $124.8 million and $129.9 million, respectively, borrowed under a master shelf loan agreement. We, TE Products, TEPPCO Midstream and TCTM (collectively, 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. We may be required to provide additional credit support in the form of a letter of credit or pay certain fees if either of our credit ratings from Standard & Poor’s Ratings Group and Moody’s Investors Service, Inc. falls below investment grade levels. If Centennial defaults on its debt obligations, the estimated maximum potential amount of future payments for the TEPPCO Guarantors and Marathon Petroleum Company LLC (“Marathon”) is $62.4 million each at June 30, 2009. At June 30, 2009, we have a liability of $8.7 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 June 30, 2009, TE Products has a liability of $3.7 million, which is based upon the expected present value of amounts we would have to pay under the

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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. Through June 30, 2009, we have spent approximately $245.6 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.

TOPS. We, through a subsidiary, owned a one-third interest in TOPS until April 16, 2009. We had guaranteed up to approximately $700.0 million of the project costs to be incurred by this partnership. Upon our dissociation (see Note 7), our obligations under this commitment terminated.

Insurance Matters

EPCO completed its annual insurance renewal process during the second quarter of 2009. In light of recent hurricane and other weather-related events, the renewal of policies for weather-related risks resulted in significant increases in premiums and certain deductibles, as well as changes in the scope of coverage.

EPCO’s deductible for onshore physical damage from windstorms increased from $10.0 million per storm to $25.0 million per storm. EPCO’s onshore program currently provides $150.0 million per occurrence for named windstorm events compared to $175.0 million per occurrence in the prior year. For non-windstorm events, EPCO’s deductible for onshore physical damage remained at $5.0 million per occurrence. Business interruption coverage in connection with a windstorm event remained unchanged for onshore assets. Onshore assets covered by business interruption insurance must be out-of-service in excess of 60 days before any losses from business interruption will be covered. Furthermore, pursuant to the current policy, we will now absorb 50% of the first $50.0 million of any loss in excess of deductible amounts for our onshore assets. There were no changes to insurance coverage for our marine transportation assets.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 16. Supplemental Cash Flow Information

The following table provides information regarding (i) the net effect of changes in our operating assets and liabilities, (ii) non-cash investing and financing activities and (iii) cash payments for interest for the periods indicated:

	For the Six Months
	Ended June 30,
	2009			2008
Decrease (increase) in:
Accounts receivable, trade	$	(194.4	)	$	(586.7	)
Accounts receivable, related parties		6.1			(6.1	)
Inventories		(42.8	)		(43.7	)
Other current assets		(3.2	)		(9.9	)
Other		(3.3	)		(7.7	)
Increase (decrease) in:
Accounts payable and accrued liabilities		181.6			610.8
Accounts payable, related parties		23.8			(12.1	)
Other		0.8			(2.1	)
Net effect of changes in operating accounts	$	(31.4	)	$	(57.5	)

Non-cash investing activities:
Payable to Enterprise Gas Processing, LLC for spending for Phase V expansion of Jonah Gas Gathering Company	$	--		$	2.8
Liabilities for construction work in progress	$	10.7		$	22.5
Non-cash financing activities:
Issuance of Units in Cenac acquisition	$	--		$	186.6
Supplemental disclosure of cash flows:
Cash paid for interest (net of amounts capitalized)	$	63.4		$	56.9

Note 17. Supplemental Condensed Consolidating Financial Information

The Guarantor Subsidiaries have issued full, unconditional, and joint and several guarantees of our senior notes, our Junior Subordinated Notes (collectively “the Guaranteed Debt”) and our Revolving Credit Facility.

The following supplemental condensed consolidating financial information reflects our separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of our other non-guarantor subsidiaries, the combined consolidating adjustments and eliminations and our consolidated accounts for the dates and periods indicated. For purposes of the following consolidating information, our investments in our subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of accounting. Earnings of subsidiaries are therefore reflected in the Partnership’s and Guarantor Subsidiaries’ investment accounts and earnings. The elimination entries presented herein eliminate investments in subsidiaries and intercompany balances and transactions.

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	June 30, 2009
	TEPPCO Partners, L.P.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
Assets
Current assets	$	15.8	$	79.6	$	1,357.9	$	(323.5	)	$	1,129.8
Property, plant and equipment – net		14.0		1,378.2		1,199.4		--			2,591.6
Investments in unconsolidated affiliates		8.7		1,007.3		182.9		--			1,198.9
Investments in consolidated affiliates		1,592.5		430.6		--		(2,023.1	)		--
Goodwill		--		--		106.6		--			106.6
Intercompany notes receivable		2,843.9		--		--		(2,843.9	)		--
Intangible assets		--		110.8		84.3		--			195.1
Other assets		13.5		33.7		85.7		--			132.9
Total assets	$	4,488.4	$	3,040.2	$	3,016.8	$	(5,190.5	)	$	5,354.9
Liabilities and partners’ capital
Current liabilities	$	239.7	$	152.7	$	1,018.0	$	(323.5	)	$	1,086.9
Long-term debt		2,733.8		1,552.7		1,291.2		(2,843.9	)		2,733.8
Intercompany notes payable		--		--		--		--			--
Other long-term liabilities		8.5		16.7		2.6		--			27.8
Total partners’ capital		1,506.4		1,318.1		705.0		(2,023.1	)		1,506.4
Total liabilities and partners’ capital	$	4,488.4	$	3,040.2	$	3,016.8	$	(5,190.5	)	$	5,354.9

	December 31, 2008
	TEPPCO Partners, L.P.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
Assets
Current assets	$	23.1	$	145.2	$	1,148.0	$	(408.7	)	$	907.6
Property, plant and equipment – net		13.5		1,294.8		1,131.6		--			2,439.9
Investments in unconsolidated affiliates		9.0		1,020.9		226.0		--			1,255.9
Investments in consolidated affiliates		1,686.0		399.0		--		(2,085.0	)		--
Goodwill		--		--		106.6		--			106.6
Intercompany notes receivable		2,628.3		--		--		(2,628.3	)		--
Intangible assets		--		118.0		89.7		--			207.7
Other assets		14.4		33.3		84.4		--			132.1
Total assets	$	4,374.3	$	3,011.2	$	2,786.3	$	(5,122.0	)	$	5,049.8
Liabilities and partners’ capital
Current liabilities	$	244.5	$	215.4	$	848.8	$	(408.7	)	$	900.0
Long-term debt		2,529.6		--		--		--			2,529.6
Intercompany notes payable		--		1,424.3		1,204.0		(2,628.3	)		--
Other long-term liabilities		8.7		17.0		3.0		--			28.7
Total partners’ capital		1,591.5		1,354.5		730.5		(2,085.0	)		1,591.5
Total liabilities and partners’ capital	$	4,374.3	$	3,011.2	$	2,786.3	$	(5,122.0	)	$	5,049.8

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	For the Three Months Ended June 30, 2009
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
Operating revenues	$	--	$	86.7		$	1,826.6		$	(0.1	)	$	1,913.2
Costs and expenses		--		78.1			1,779.7			(0.5	)		1,857.3
Operating income		--		8.6			46.9			0.4			55.9
Interest expense		--		(20.1	)		(12.2	)		--			(32.3	)
Equity in income (loss) of unconsolidated affiliates		11.2		19.0			(31.3	)		(11.1	)		(12.2	)
Other, net		--		0.2			0.5			--			0.7
Income before provision for income taxes		11.2		7.7			3.9			(10.7	)		12.1
Provision for income taxes		--		(0.1	)		(0.8	)		--			(0.9	)
Net income	$	11.2	$	7.6		$	3.1		$	(10.7	)	$	11.2

	For the Three Months Ended June 30, 2008
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
Operating revenues	$	--	$	88.3		$	4,092.3		$	(0.1	)	$	4,180.5
Costs and expenses		--		70.4			4,052.0			(1.2	)		4,121.2
Operating income		--		17.9			40.3			1.1			59.3
Interest expense		--		(17.3	)		(15.7	)		--			(33.0	)
Equity in income of unconsolidated affiliates		47.7		44.9			4.2			(75.5	)		21.3
Other, net		--		0.3			0.8			--			1.1
Income before provision for income taxes		47.7		45.8			29.6			(74.4	)		48.7
Provision for income taxes		--		(0.3	)		(0.7	)		--			(1.0	)
Net income	$	47.7	$	45.5		$	28.9		$	(74.4	)	$	47.7

	For the Six Months Ended June 30, 2009
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
Operating revenues	$	--	$	187.4		$	3,183.5		$	(0.1	)	$	3,370.8
Costs and expenses		--		146.2			3,084.2			(1.2	)		3,229.2
Operating income		--		41.2			99.3			1.1			141.6
Interest expense		--		(40.3	)		(24.1	)		--			(64.4	)
Equity in income (loss) of unconsolidated affiliates		89.4		84.3			(28.0	)		(132.8	)		12.9
Other, net		--		0.5			0.5			--			1.0
Income before provision for income taxes		89.4		85.7			47.7			(131.7	)		91.1
Provision for income taxes		--		(0.4	)		(1.3	)		--			(1.7	)
Net income	$	89.4	$	85.3		$	46.4		$	(131.7	)	$	89.4

	For the Six Months Ended June 30, 2008
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
Operating revenues	$	--	$	191.2		$	6,797.9		$	(0.1	)	$	6,989.0
Costs and expenses		--		138.3			6,712.0			(4.1	)		6,846.2
Operating income		--		52.9			85.9			4.0			142.8
Interest expense		--		(44.1	)		(27.5	)		--			(71.6	)
Equity in income of unconsolidated affiliates		111.8		97.9			7.2			(175.9	)		41.0
Other, net		--		0.6			0.8			--			1.4
Income before provision for income taxes		111.8		107.3			66.4			(171.9	)		113.6
Provision for income taxes		--		(0.5	)		(1.3	)		--			(1.8	)
Net income	$	111.8	$	106.8		$	65.1		$	(171.9	)	$	111.8

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	For the Six Months Ended June 30, 2009
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
Operating activities:
Net income	$	89.4		$	85.3		$	46.4		$	(131.7	)	$	89.4
Adjustments to reconcile net income to net cash
from operating activities:
Depreciation and amortization		--			37.9			31.9			--			69.8
Non-cash impairment charge		--			2.3			--			--			2.3
Equity in income (loss) of unconsolidated affiliates		93.4			(49.5	)		28.0			(84.8	)		(12.9	)
Distributions received from unconsolidated affiliates		--			76.0			13.2			--			89.2
Other, net		(15.4	)		9.3			(42.8	)		18.6			(30.3	)
Net cash from operating activities		167.4			161.3			76.7			(197.9	)		207.5
Cash flows from investing activities:
Cash used for business combinations		--			--			(50.0	)		--			(50.0	)
Investment in Jonah		--			(19.1	)		--			--			(19.1	)
Investment in Texas Offshore Port System		--			--			1.7			--			1.7
Capital expenditures		--			(119.2	)		(45.1	)		--			(164.3	)
Other, net		--			(1.4	)		(1.5	)		--			(2.9	)
Net cash flows from investing activities		--			(139.7	)		(94.9	)		--			(234.6	)
Cash flows from financing activities:
Borrowings under debt agreements		759.3			--			--			--			759.3
Repayments of debt		(552.6	)		--			--			--			(552.6	)
Net proceeds from issuance of limited partner units		3.3			--			--			--			3.3
Intercompany debt activities		(206.7	)		123.7			90.5			(7.5	)		--
Repurchase of restricted units		(0.1	)					--			--			(0.1	)
Distributions paid to partners		(182.8	)		(145.3	)		(72.3	)		217.6			(182.8	)
Net cash flows from financing activities		(179.6	)		(21.6	)		18.2			210.1			27.1
Net change in cash and cash equivalents		(12.2	)		--			--			12.2			--
Cash and cash equivalents, January 1		16.1			--			--			(16.1	)		--
Cash and cash equivalents, June 30	$	3.9		$	--		$	--		$	(3.9	)	$	--

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	For the Six Months Ended June 30, 2008
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
Operating activities:
Net income	$	111.8		$	106.8		$	65.1		$	(171.9	)	$	111.8
Adjustments to reconcile net income to net cash
from operating activities:
Depreciation and amortization		--			34.6			25.6			--			60.2
Equity in income (loss) of unconsolidated affiliates		--			(37.8	)		(7.2	)		4.0			(41.0	)
Distributions received from unconsolidated affiliates		--			75.9			3.4			--			79.3
Other, net		109.2			20.8			(124.6	)		(51.6	)		(46.2	)
Net cash from operating activities		221.0			200.3			(37.7	)		(219.5	)		164.1
Cash flows from investing activities:
Cash used for business combinations		--			--			(345.6	)		--			(345.6	)
Investment in Jonah		--			(64.5	)		--			--			(64.5	)
Capital expenditures		--			(98.5	)		(40.7	)		--			(139.2	)
Other, net		--			(0.3	)		(14.5	)		--			(14.8	)
Net cash flows from investing activities		--			(163.3	)		(400.8	)		--			(564.1	)
Cash flows from financing activities:
Borrowings under debt agreements		3,344.4			--			--			--			3,344.4
Repayments of debt		(2,308.1	)		(361.6	)		(63.2	)		--			(2,732.9	)
Net proceeds from issuance of limited partner units		5.6			--			--			--			5.6
Debt issuance costs		(9.3	)		--			--			--			(9.3	)
Settlement of interest rate derivative instruments – treasury locks		(52.1	)		--			--			--			(52.1	)
Intercompany debt activities		(1,036.4	)		480.3			548.7			7.4			--
Distributions paid to partners		(155.7	)		(155.7	)		(47.0	)		202.7			(155.7	)
Net cash flows from financing activities		(211.6	)		(37.0	)		438.5			210.1			400.0
Net change in cash and cash equivalents		9.4			--			--			(9.4	)		--
Cash and cash equivalents, January 1		8.2			--			--			(8.2	)		--
Cash and cash equivalents, June 30	$	17.6		$	--		$	--		$	(17.6	)	$	--

Note 18. Subsequent Events

Suspension of DRIP and EUPP

In July 2009, we suspended the opportunity for investors to acquire additional Units under our DRIP, pursuant to the terms of the definitive merger agreements with Enterprise Products Partners (see Note 13). We expect this suspension to remain in place pursuant to such terms while the transaction is pending. Additionally, the EUPP will suspend operations in August 2009 pursuant to the terms of the definitive merger agreements.

Loan Agreement with Enterprise Products Operating LLC

On August 5, 2009, we entered into a Loan Agreement (the “Loan Agreement”) with Enterprise Products Operating LLC (“EPO”), a wholly owned subsidiary of Enterprise Products Partners, under which EPO agreed to make an unsecured revolving loan to us in an aggregate maximum outstanding principal amount not to exceed $100.0 million. Borrowings under the Loan Agreement mature on the earliest to occur of (i) the consummation of our proposed merger with Enterprise Products Partners, (ii) the termination of the related merger agreement in accordance with the provisions thereof, (iii) December 31, 2009, (iv) the date upon which the maturity of the loan is otherwise accelerated upon an event of default, and (v) the date upon which EPO’s commitment to make the loan is terminated by us pursuant to the Loan

TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Agreement. Borrowings under the Loan Agreement will bear interest at a floating rate equivalent to the one-month LIBOR Rate (as defined in the Loan Agreement) plus 2.00%. Interest is payable monthly.

The Loan Agreement provides that amounts borrowed are non-recourse to our General Partner and our limited partners. The Loan Agreement contains customary events of default, including (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to us; (iii) a change of control; or (iv) an event of default under our Revolving Credit Facility. Any amounts due by us under the Loan Agreement will be unconditionally and irrevocably guaranteed by our Guarantor Subsidiaries that guarantee our obligations under our Revolving Credit Facility. EPO’s obligation to fund any borrowings under the Loan Agreement is subject to specified conditions, including the condition that, on and as of the applicable date of funding, no additional amounts are available to us pursuant to our Revolving Credit Facility (either as borrowings or under any letters of credit). The ACG Committee reviewed and approved the Loan Agreement, such approval constituting “Special Approval” under the conflict of interest provisions of our Partnership Agreement. The execution of the Loan Agreement was also unanimously approved by the ACG Committee of EPGP.

Settlement Agreement

On August 5, 2009, the parties to the Merger Action and the Derivative Action described in Note 15 entered into a Settlement Agreement contemplated by the Memorandum of Understanding. Pursuant to the Settlement Agreement, the board of directors of our General Partner will recommend to our unitholders that they approve the adoption of the merger agreement governing our proposed merger with a subsidiary of Enterprise Products Partners and take all necessary steps to seek unitholder approval for the merger as soon as practicable. Pursuant to the Settlement Agreement, approval of the merger will require, in addition to votes required under our Partnership Agreement, that the actual votes cast in favor of the proposal by holders of our outstanding Units, excluding those held by defendants to the Derivative Action, exceed the actual votes cast against the proposal by those holders. The Settlement Agreement further provides that the Derivative Action was considered by the Special Committee to be a significant benefit of ours for which fair value was obtained in the merger consideration.

Borrowing under Revolving Credit Facility

On August 4, 2009, we submitted a request for borrowings under our Revolving Credit Facility expected to be received on August 7, 2009 in an aggregate amount of $95.9 million. Such borrowings will be used to pay the $91.6 million aggregate amount of our previously disclosed cash distribution on our outstanding Units with respect to the quarter ended June 30, 2009 and for general partnership purposes. Immediately following the payment of such distribution, we expect to have approximately $820 million principal amount outstanding under our Revolving Credit Facility.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

For the three months and six months ended June 30, 2009 and 2008

The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included in this Quarterly Report. The following information and such unaudited condensed consolidated financial statements should also be read in conjunction with the financial statements and related notes, together with our discussion and analysis of financial position and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2008.

Our financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).

Key References Used in this Quarterly Report

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” or “TEPPCO” are intended to mean the business and operations of TEPPCO Partners, L.P. and its consolidated subsidiaries.

References to “TE Products,” “TCTM,” “TEPPCO Midstream” and “TEPPCO Marine Services” mean TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and TEPPCO Marine Services, LLC, our subsidiaries.

References to “General Partner” mean Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO.

References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., a publicly traded partnership that owns our General Partner and Enterprise Products GP, LLC, the general partner of Enterprise Products Partners L.P.

References to “Enterprise Products Partners” mean Enterprise Products Partners L.P., a publicly traded Delaware limited partnership and its consolidated subsidiaries, which is an affiliate of ours.

References to “EPCO” mean EPCO, Inc., a privately-held company that is affiliated with our General Partner. Dan L. Duncan is the Group Co-Chairman and controlling shareholder of EPCO.

References to “petroleum products” or “products” mean refined products, liquefied petroleum gases (“LPGs”), petrochemicals, crude oil, lubrication oils and specialty chemicals, natural gas liquids (“NGLs”), natural gas, asphalt, heavy fuel oil, other heated oil products and marine bunker fuel.

As generally used in the energy industry and in this discussion, the identified terms have the following meanings:

	/d	= per day
	Mcf	= thousand cubic feet
	MMcf	= million cubic feet
	Bcf	= billion cubic feet
	MMbls	= million barrels
	MMBtus	= million British thermal units
	BBtus	= billion British thermal units

Cautionary Note Regarding Forward-Looking Statements

This discussion contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “forecast,” “intend,” “could,” “should,” “will,” “believe,” “may,” “potential” and

similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we and our General Partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our General Partner can give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions as described in more detail in Item 1A “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2008 and in Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2009 and this Quarterly Report. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this Quarterly Report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

Overview of Critical Accounting Policies and Estimates

A summary of the significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is included in our Annual Report on Form 10-K for the year ended December 31, 2008. Certain of these accounting policies require the use of estimates. As more fully described therein, the following estimates, in our opinion, are subjective in nature, require the exercise of judgment and involve complex analysis: revenue and expense accruals, including accruals for power costs, property taxes and crude oil margins; reserves for environmental matters; depreciation methods and estimated useful lives of property, plant and equipment; measuring recoverability of long-lived assets and equity method investments; measuring the fair value of goodwill; and amortization methods and estimated useful lives of intangible assets. These estimates are based on our knowledge and understanding of current conditions and actions we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial position, results of operations and cash flows.

Overview of Business

We are a publicly traded, diversified energy logistics partnership with operations that span much of the continental United States. Our limited partner units (“Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “TPP”. We were formed in March 1990 as a Delaware limited partnership.

We own and operate an extensive network of assets that facilitate the movement, marketing, gathering and storage of various commodities and energy-related products. Our pipeline network gathers and transports refined products, crude oil, natural gas, LPGs and NGLs, including one of the largest common carrier pipelines for refined products and LPGs in the United States. We also own a marine services business that transports petroleum products and provides marine vessel fueling services and other ship-assist services. In addition, we own interests in Seaway Crude Pipeline Company (“Seaway”), Centennial Pipeline LLC (“Centennial”), Jonah Gas Gathering Company (“Jonah”) and an undivided ownership interest in the Basin Pipeline (“Basin”). We operate and report in four business segments:

§	pipeline transportation, marketing and storage of refined products, 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 NGLs and pipeline transportation of NGLs (“Midstream Segment”); and

§	marine transportation of petroleum products and provision of marine vessel fueling and other ship-assist services (“Marine Services Segment”).

Our reportable segments offer different products and services and are managed separately because each requires different business strategies. We operate through TE Products, TCTM, TEPPCO Midstream and TEPPCO Marine Services. Texas Eastern Products Pipeline Company, LLC, a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us.

Please refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview of Business in our Annual Report on Form 10-K for the year ended December 31, 2008 for an overview of how revenues are earned in each segment and other factors affecting the results and financial position of our businesses.

Recent Developments

The following information highlights our significant developments since January 1, 2009 through the date of this filing.

Proposed Merger with Enterprise Products Partners

On June 28, 2009, we and our General Partner entered into definitive merger agreements with Enterprise Products Partners, its general partner (“EPGP”) and two of its subsidiaries. Under the terms of the definitive agreements, we and our General Partner would become wholly owned subsidiaries of Enterprise Products Partners, and each of our outstanding Units, other than 3,645,509 of our Units owned by a privately-held affiliate of EPCO, would be cancelled and converted into the right to receive 1.24 Enterprise Products Partners common units. The 3,645,509 Units owned by a privately-held affiliate of EPCO would be converted, based on the 1.24 exchange ratio, into the right to receive 4,520,431 of Enterprise Products Partners Class B units (“Class B Units”). The Class B Units would not be entitled to regular quarterly cash distributions of Enterprise Products Partners for sixteen quarters following the closing of the merger and, except for the payment of distributions, would have the same rights and privileges as Enterprise Products Partners common units. The Class B Units would convert automatically into the same number of Enterprise Products Partners common units on the date immediately following the payment date for the sixteenth quarterly distribution following the closing of the merger. No fractional Enterprise Products Partners common units would be issued in the proposed merger, and our unitholders would, instead, receive cash in lieu of fractional Enterprise Products Partners common units, if any.

A Special Committee of the Audit, Conflicts and Governance (“ACG”) Committee of our General Partner unanimously determined that the merger is fair and reasonable to us and our unaffiliated unitholders and recommended that the merger be approved by our unaffiliated unitholders, the ACG Committee of our General Partner and our General Partner’s board of directors. Based upon such determination and recommendation, the ACG Committee of our General Partner unanimously determined that the merger is fair and reasonable to us and our unaffiliated unitholders and approved the merger, such approval constituting “Special Approval” under our Partnership Agreement. The ACG Committee of our General Partner also recommended that our General Partner’s board of directors approve the merger. Based on the Special Committee’s determination and recommendation, as well as the ACG Committee’s determination, Special Approval and recommendation, our General Partner’s board of directors unanimously approved the merger and recommended that our unaffiliated unitholders vote in favor of the merger proposal. In addition, the ACG Committee of the general partner of each of Enterprise Products Partners and Enterprise GP Holdings also approved the transaction.

Completion of the proposed merger is subject to the approval of holders of at least a majority of our outstanding Units. In addition, pursuant to the merger agreement providing for the merger of our Partnership, the number of votes cast in favor of the merger agreement by our unitholders (excluding certain unitholders affiliated with EPCO and other specified officers and directors of our General Partner, Enterprise GP Holdings and Enterprise Products Partners) must exceed the votes cast against the merger agreement by such unitholders. Affiliates of EPCO, including Enterprise GP Holdings, have executed a support agreement with Enterprise Products Partners in which they have agreed to vote their Units in favor of the merger agreement. The closing is also subject to customary regulatory approvals, including that under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Subject to the receipt of regulatory and unitholder approvals, completion of the proposed merger is expected to occur during the fourth quarter of 2009. See Note 15 in the Notes to Unaudited Condensed Consolidated Financial Statements for information regarding litigation matters associated with the proposed merger.

In July 2009, we suspended the opportunity for investors to acquire additional Units under our distribution reinvestment plan (“DRIP”), pursuant to the terms of the definitive merger agreements with Enterprise Products Partners. Additionally, the employee unit purchase plan (“EUPP”) will suspend operations in August 2009 pursuant to the terms of the definitive merger agreements. We expect these suspensions to remain in place pursuant to such terms while the transaction is pending.

Loan Agreement with Enterprise Products Operating LLC

The Loan Agreement provides that amounts borrowed are non-recourse to our General Partner and our limited partners. The Loan Agreement contains customary events of default, including (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to us; (iii) a change of control; or (iv) an event of default under our revolving credit facility (“Revolving Credit Facility”). Any amounts due by us under the Loan Agreement will be unconditionally and irrevocably guaranteed by each of our subsidiaries that guarantee our obligations under our Revolving Credit Facility. EPO’s obligation to fund any borrowings under the Loan Agreement is subject to specified conditions, including the condition that, on and as of the applicable date of funding, no additional amounts are available to us pursuant to our Revolving Credit Facility (either as borrowings or under any letters of credit). The ACG Committee reviewed and approved the Loan Agreement, such approval constituting “Special Approval” under the conflict of interest provisions of our Partnership Agreement. The execution of the Loan Agreement was also unanimously approved by the ACG Committee of EPGP.

Settlement Agreement

On August 5, 2009, the parties to the Merger Action and the Derivative Action described in Note 15 in the Notes to Unaudited Condensed Consolidated Financial Statements entered into a Stipulation and

Agreement of Compromise, Settlement and Release (the “Settlement Agreement”) contemplated by the Memorandum of Understanding. Pursuant to the Settlement Agreement, the board of directors of our General Partner will recommend to our unitholders that they approve the adoption of the merger agreement governing our proposed merger with a subsidiary of Enterprise Products Partners and take all necessary steps to seek unitholder approval for the merger as soon as practicable. Pursuant to the Settlement Agreement, approval of the merger will require, in addition to votes required under our partnership agreement, that the actual votes cast in favor of the proposal by holders of our outstanding Units, excluding those held by defendants to the Derivative Action, exceed the actual votes cast against the proposal by those holders. The Settlement Agreement further provides that the Derivative Action was considered by the Special Committee to be a significant benefit of ours for which fair value was obtained in the merger consideration.

The Settlement Agreement is subject to customary conditions, including Court of Chancery of the State of Delaware (the “Delaware Court”) approval. There can be no assurance that the Delaware Court will approve the settlement in the Settlement Agreement. In such event, the proposed settlement as contemplated by the Settlement Agreement may be terminated. See Note 13 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional information regarding our relationship with Enterprise Products Partners, including information related to the proposed merger. See Note 15 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional information related to the Merger Action and the Derivative Action, including the Settlement Agreement.

Borrowing under Revolving Credit Facility

Acquisition of Marine Assets; Termination of Transitional Operating Agreement

On June 5, 2009, we expanded our Marine Services Segment with the acquisition of 19 tow boats and 28 tank barges from TransMontaigne Product Services Inc., (“TransMontaigne”), for $50.0 million in cash. The acquired vessels provide marine vessel fueling services for cruise liners and cargo ships, referred to as bunkering, and other ship-assist services and transport fuel oil for electric generation plants. The acquisition complements our existing fleet of vessels that currently transport petroleum products along the nation’s inland waterway system and in the Gulf of Mexico. The newly acquired marine assets are generally supported by contracts that have three to five year terms and are based primarily in Miami, Florida, with additional assets located in Mobile, Alabama, and Houston, Texas. We financed the acquisition with borrowings under our Revolving Credit Facility. See Note 8 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional information regarding this business combination.

Effective August 1, 2009, personnel providing services to us under the transitional operating agreement with Cenac Towing Co., L.L.C., Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr. (collectively, “Cenac”) became employees of EPCO, and the transitional operating agreement was terminated. Concurrently with the termination, TEPPCO Marine Services entered into a two-year consulting agreement with Mr. Cenac and Cenac Marine Services, L.L.C. under which Mr. Cenac has agreed to supervise TEPPCO Marine Services’ day-to-day operations on a part-time basis and, at TEPPCO Marine Services’ request, provide related management and transitional services. The agreement entitles Mr. Cenac to $500,000 per year in fees, plus a one-time retainer of $200,000. The consulting agreement contains noncompetition and nonsolitation provisions similar to those contained in the transitional operating agreement, which apply until the expiration of the two-year period following the date of last service provided under the consulting agreement.

Exit from Texas Offshore Port System Partnership

In August 2008, a wholly owned subsidiary of ours, together with a subsidiary of Enterprise Products Partners and Oiltanking Holding Americas, Inc. (“Oiltanking”), formed the Texas Offshore Port System partnership (“TOPS”). Effective April 16, 2009, our wholly owned subsidiary dissociated from TOPS. As a result, equity earnings and net income for the second quarter of 2009 include a non-cash charge of $34.2 million. This loss represents our cumulative investment in TOPS through the date of dissociation and reflects our capital contributions to TOPS for construction in progress amounts. We believe that the dissociation discharged our affiliate with respect to further obligations under the TOPS partnership agreement, and accordingly, us from the associated liability under the related parent guarantee; therefore, we have not recorded any amounts related to such guarantee. The wholly owned subsidiary of Enterprise Products Partners that was a partner in TOPS also dissociated from the partnership effective April 16, 2009. See Note 15 in the Notes to Unaudited Condensed Consolidated Financial Statements for litigation matters associated with our dissociation from TOPS.

Results of Operations

The following table summarizes financial information by business segment for the periods indicated (in millions):

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2009			2008			2009			2008
Operating revenues:
Downstream Segment	$	86.9		$	76.4		$	182.4		$	174.1
Upstream Segment		1,751.6			4,025.4			3,047.8			6,680.7
Midstream Segment		31.1			30.6			60.1			60.7
Marine Services Segment		43.7			48.1			80.6			73.6
Intersegment eliminations		(0.1	)		--			(0.1	)		(0.1	)
Total operating revenues		1,913.2			4,180.5			3,370.8			6,989.0
Operating income:
Downstream Segment		13.5			15.7			47.9			52.0
Upstream Segment		29.9			25.6			70.8			54.9
Midstream Segment		3.8			8.3			8.3			16.7
Marine Services Segment		8.3			8.6			13.5			15.2
Intersegment eliminations		0.4			1.1			1.1			4.0
Total operating income		55.9			59.3			141.6			142.8
Equity in income (loss) of unconsolidated affiliates:
Downstream Segment		(4.3	)		(3.7	)		(7.4	)		(7.8	)
Upstream Segment		(31.3	)		4.2			(28.0	)		7.2
Midstream Segment		23.8			21.9			49.4			45.6
Intersegment eliminations		(0.4	)		(1.1	)		(1.1	)		(4.0	)
Total equity in income (loss) of unconsolidated affiliates		(12.2	)		21.3			12.9			41.0
Earnings before interest: (1)
Downstream Segment		9.4			12.4			41.0			44.8
Upstream Segment		(0.9	)		30.4			43.3			62.7
Midstream Segment		27.6			30.3			57.7			62.5
Marine Services Segment		8.3			8.6			13.5			15.2

Interest expense		(32.3	)		(33.0	)		(64.4	)		(71.6	)
Income before provision for income taxes		12.1			48.7			91.1			113.6
Provision for income taxes		(0.9	)		(1.0	)		(1.7	)		(1.8	)
Net income	$	11.2		$	47.7		$	89.4		$	111.8

(1) See Note 12 in the Notes to Unaudited Condensed Consolidated Financial Statements for a reconciliation of earnings before interest to net income.

The following is an analysis of the results of operations, including reasons for material changes in results, by each of our business segments.

Downstream Segment

The following table provides financial information for the Downstream Segment for the periods indicated (in millions):

	For the Three Months									For the Six Months
	Ended June 30,						Increase			Ended June 30,						Increase
	2009			2008			(Decrease)			2009			2008			(Decrease)
Operating revenues:
Sales of petroleum products	$	12.8		$	1.2		$	11.6		$	19.5		$	8.2		$	11.3
Transportation – Refined products		41.1			44.1			(3.0	)		77.0			81.4			(4.4	)
Transportation – LPGs		17.5			16.1			1.4			55.8			52.3			3.5
Other		15.5			15.0			0.5			30.1			32.2			(2.1	)
Total operating revenues		86.9			76.4			10.5			182.4			174.1			8.3

Costs and expenses:
Purchases of petroleum products		12.6			1.3			11.3			19.2			8.2			11.0
Operating expense		30.7			30.4			0.3			55.6			57.3			(1.7	)
Operating fuel and power		7.0			10.5			(3.5	)		18.0			21.0			(3.0	)
General and administrative		6.3			4.5			1.8			10.0			8.2			1.8
Depreciation and amortization		13.3			10.5			2.8			24.8			20.7			4.1
Taxes – other than income taxes		3.5			3.5			--			6.9			6.7			0.2
Total costs and expenses		73.4			60.7			12.7			134.5			122.1			12.4

Operating income		13.5			15.7			(2.2	)		47.9			52.0			(4.1	)

Equity in income (loss) of unconsolidated affiliates		(4.3	)		(3.7	)		(0.6	)		(7.4	)		(7.8	)		0.4
Other, net		0.2			0.4			(0.2	)		0.5			0.6			(0.1	)

Earnings before interest	$	9.4		$	12.4		$	(3.0	)	$	41.0		$	44.8		$	(3.8	)

The following table presents volumes delivered in barrels and average tariff per barrel for the periods indicated (in millions, except tariff information):

	For the Three Months				Percentage		For the Six Months				Percentage
	Ended June 30,				Increase		Ended June 30,				Increase
	2009		2008		(Decrease)		2009		2008		(Decrease)
Volumes Delivered:
Refined products		40.0		41.9		(5%)		76.6		80.4		(5%)
LPGs		6.6		6.7		(1%)		19.2		19.6		(2%)
Total		46.6		48.6		(4%)		95.8		100.0		(4%)

Average Tariff per Barrel:
Refined products	$	1.03	$	1.05		(2%)	$	1.01	$	1.01		--
LPGs		2.65		2.41		10%		2.91		2.67		9%
Average system tariff per barrel		1.26		1.24		2%		1.39		1.34		4%

Three Months Ended June 30, 2009 Compared with Three Months Ended June 30, 2008

Sales and purchases related to petroleum products marketing activities at our Aberdeen and Boligee terminals increased $11.6 million and $11.3 million, respectively, for the three months ended June 30, 2009, compared with the three months ended June 30, 2008. The increases in purchases and sales were primarily due to increased volumes at the Boligee and Aberdeen terminals as a result of the start-up of the Boligee terminal in August 2008 and unplanned maintenance on storage tanks at the Aberdeen terminal in the 2008 period, partially offset by lower fuel prices in the 2009 period compared to the prior year period.

Revenues from refined products transportation decreased $3.0 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008, primarily due to the recognition of $2.1 million of deferred revenue in the 2008 period related to two customer transportation agreements, a 5% decrease in refined products volumes delivered in the 2009 period and a 2% decrease in the average tariff per barrel. Under some of our transportation agreements with customers, the contracts specify minimum periodic payments for transportation services. If the transportation services used during that time

period total less than the minimum payment, the unused payment is recorded as deferred revenue. The contracts generally specify a subsequent period of time in which the customer can ship additional products to recover the deferred revenue. During the second quarter of 2008, we recognized refined products transportation revenue related to time limit expirations under two transportation agreements without the customers recovering the deferred revenues. This additional revenue increased the refined products average tariff by $0.05 per barrel in the 2008 period, or 5%. Additionally, volume decreases were primarily due to lower diesel fuel, jet fuel and motor fuel movements resulting from a decline in product demand, partially offset by higher short-haul diesel fuel and higher long-haul blendstock movements resulting from increased diesel fuel deliveries to Gulf Coast diesel fuel storage facilities and restrictions on blendstock supplies that occurred in the second quarter of 2008. The refined products average tariff per barrel decreased primarily due to the recognition of deferred revenue in the 2008 period, partially offset by increases in system tariffs that went into effect in July 2008.

Revenues from LPG transportation increased $1.4 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008, primarily due to a 10% increase in the LPG average tariff per barrel, partially offset by a 1% decrease in the LPG volumes delivered. The LPG average rate per barrel increased from the prior year period, primarily due to increases in system tariffs that went into effect in July 2008 and increased long-haul propane deliveries and decreased shorter haul isobutane deliveries during the second quarter of 2009. Propane transportation volumes increased from the 2008 period due to lower production in certain market areas in the 2009 period and the impact of higher prices in the 2008 period.

Other operating revenues increased $0.5 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008, primarily due to a $0.8 million increase in refined products storage rental revenues, a $0.4 million increase in LPG rental and location exchange revenues and a $0.3 million increase in LPG inventory sales, partially offset by a $0.5 million decrease in refined products terminaling revenue and a $0.3 million decrease in refined products excess inventory revenue.

Costs and expenses increased $12.7 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008. Purchases of petroleum products, discussed above, increased $11.3 million compared with the prior year period. Operating expenses increased $0.3 million primarily due to a $2.3 million non-cash impairment charge to idle a river terminal at Helena, Arkansas (see Note 6 in the Notes to Unaudited Condensed Consolidated Financial Statements), a $1.8 million increase in product measurement losses, a $1.0 million increase in labor and benefits expense and a $0.9 million increase in pipeline operating and maintenance costs principally related to periodic tank maintenance requirements and other repairs and maintenance on various pipeline segments. These increases were partially offset by a $2.4 million decrease related to the write-off of project costs for a cancelled project in the 2008 period, a $1.8 million decrease in environmental remediation and assessment costs and a $1.4 million decrease in transportation expense related to movements on the Centennial pipeline and a third party pipeline. Operating fuel and power decreased $3.5 million primarily due to lower transportation volumes and lower power rates in the current period. General and administrative expenses increased $1.8 million primarily due to a $2.6 million increase in legal and other expenses related to the proposed merger with Enterprise Products Partners (see Note 13 in the Notes to Unaudited Condensed Consolidated Financial Statements), partially offset by a $0.5 million decrease in consulting and contract services and a $0.4 million decrease in labor and benefits expense. Depreciation and amortization expense increased $2.8 million primarily due to a $1.3 million increase due to asset retirements, a $1.0 million increase due to assets placed into service and a $0.5 million increase in amortization of equity awards. Taxes – other than income taxes remained unchanged between periods.

Equity losses from our equity investment in Centennial increased $0.6 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008, primarily due to lower transportation volumes and revenues and higher operating expenses, primarily related to increased expenses for pipeline maintenance and product transportation downgrades. Volumes on Centennial averaged 79,800 barrels per day during the three months ended June 30, 2009, compared with 115,900 barrels per day during the three months ended June 30, 2008, primarily due to lower demand in the Midwest market area in the 2009 period.

Six Months Ended June 30, 2009 Compared with Six Months Ended June 30, 2008

Sales and purchases related to petroleum products marketing activities at our Aberdeen and Boligee terminals increased $11.3 million and $11.0 million, respectively, for the six months ended June 30, 2009, compared with the six months ended June 30, 2008. The increases in purchases and sales were primarily due to increased volumes at the Boligee and Aberdeen terminals as a result of the start-up of the Boligee terminal in August 2008 and unplanned maintenance on storage tanks at the Aberdeen terminal in the 2008 period, partially offset by lower fuel prices in the 2009 period compared to the prior year period.

Revenues from refined products transportation decreased $4.4 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008, primarily due to the recognition of $2.1 million of deferred revenue in the 2008 period related to two customer transportation agreements as discussed above and a 5% decrease in refined products volumes delivered. Volume decreases were primarily due to lower long-haul jet fuel, motor fuel and diesel fuel movements resulting from a decline in product demand, partially offset by higher short-haul diesel fuel and higher long-haul blendstock movements due to higher demand in the Midwest markets. The refined products average tariff per barrel remained unchanged due to the recognition of deferred revenue in the 2008 period offset by increases in system tariffs that went into effect in July 2008 and April 2009.

Revenues from LPG transportation increased $3.5 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008, primarily due to a 9% increase in the LPG average tariff per barrel, partially offset by a 2% decrease in the LPG volumes delivered. The LPG average rate per barrel increased from the prior year period primarily due to increases in system tariffs that went into effect in July 2008, increased isobutane deliveries in the Midwest and lower propane deliveries to a Midwest petrochemical plant that has a lower tariff, resulting from downtime of the plant. Propane transportation volumes were slightly lower in the 2009 period compared to the prior year period primarily due to the downtime of the Midwest petrochemical plant during the 2009 period.

Other operating revenues decreased $2.1 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008, primarily due to a $2.4 million decrease in refined products excess inventory revenue, a $1.8 million decrease in product inventory sales and a $1.1 million decrease in refined products terminaling revenue, partially offset by a $1.7 million increase in refined products storage rental revenues, a $1.0 million increase in LPG rental and location exchange revenues and a $0.5 million increase in refinery grade propylene transportation revenue due to higher volumes.

Costs and expenses increased $12.4 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008. Purchases of petroleum products, discussed above, increased $11.0 million, compared with the prior year period. Operating expenses decreased $1.7 million primarily due to a $2.4 million decrease related to the write-off of project costs in the 2008 period, a $2.3 million increase in product measurement gains, a $2.2 million decrease in transportation expense related to movements on the Centennial pipeline and a third party pipeline and a $1.5 million decrease in environmental remediation and assessment expenses. These decreases in operating expenses were partially offset by a $2.3 million non-cash impairment charge to idle a river terminal at Helena, Arkansas, a $2.1 million increase in labor and benefits expense, a $1.9 million increase in pipeline operating and maintenance costs principally related to periodic tank maintenance requirements and other repairs and maintenance on various pipeline segments and a $0.4 million lower of cost or market (“LCM”) adjustment on inventory (see Note 5 in the Notes to Unaudited Condensed Consolidated Financial Statements). Operating fuel and power decreased $3.0 million, primarily due to lower transportation volumes and lower power rates in the current period. General and administrative expenses increased $1.8 million primarily due to a $2.6 million increase in legal and other expenses related to the proposed merger with Enterprise Products Partners and $0.5 million in severance expenses, partially offset by a $1.0 million decrease in labor and benefits expense. Depreciation and amortization expense increased $4.1 million, primarily due to a $1.8 million increase due to assets placed into service, a $1.3 million increase due to asset retirements and a $0.9 million increase in amortization of equity awards. Taxes – other than income taxes increased $0.2 million primarily due to a higher asset base in the current period.

Equity losses from our equity investment in Centennial decreased $0.4 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008, primarily due to improved tariff rates on lower transportation volumes, partially offset by increased expenses for pipeline maintenance and product transportation downgrades. Volumes on Centennial averaged 98,400 barrels per day during the six months ended June 30, 2009, compared with 118,800 barrels per day during the six months ended June 30, 2008, primarily due to lower demand in the Midwest market area in the 2009 period.

Upstream Segment

The following table provides financial information for the Upstream Segment for the periods indicated (in millions):

	For the Three Months								For the Six Months
	Ended June 30,					Increase			Ended June 30,					Increase
	2009			2008		(Decrease)			2009			2008		(Decrease)
Operating revenues: (1)
Sales of petroleum products (2)	$	1,732.7		$	4,005.3	$	(2,272.6	)	$	3,003.9		$	6,643.0	$	(3,639.1	)
Transportation – Crude oil		15.2			17.4		(2.2	)		37.1			32.7		4.4
Other		3.7			2.7		1.0			6.8			5.0		1.8
Total operating revenues		1,751.6			4,025.4		(2,273.8	)		3,047.8			6,680.7		(3,632.9	)

Costs and expenses: (1)
Purchases of petroleum products (2)		1,691.2			3,975.5		(2,284.3	)		2,920.8			6,578.2		(3,657.4	)
Operating expense		16.6			12.7		3.9			31.2			26.0		5.2
Operating fuel and power		2.1			1.9		0.2			3.9			3.6		0.3
General and administrative		3.2			2.7		0.5			5.1			4.5		0.6
Depreciation and amortization		6.7			5.0		1.7			12.3			9.8		2.5
Taxes – other than income taxes		1.9			2.0		(0.1	)		3.7			3.7		--
Total costs and expenses		1,721.7			3,999.8		(2,278.1	)		2,977.0			6,625.8		(3,648.8	)

Operating income		29.9			25.6		4.3			70.8			54.9		15.9

Equity in income (loss) of unconsolidated affiliates		(31.3	)		4.2		(35.5	)		(28.0	)		7.2		(35.2	)
Other, net		0.5			0.6		(0.1	)		0.5			0.6		(0.1	)

Earnings before interest	$	(0.9	)	$	30.4	$	(31.3	)	$	43.3		$	62.7	$	(19.4	)

(1) Amounts in this table are presented after elimination of intercompany transactions, including sales and purchases of petroleum products. (2) Petroleum products includes crude oil, lubrication oils and specialty chemicals.

Information presented in the following table includes the margin of the Upstream Segment, which is a non-GAAP financial measure under the rules of the Securities and Exchange Commission (“SEC”). We calculate the margin of the Upstream Segment as revenues generated from the sale of crude and lubrication oils, and transportation of crude oil, less the related cost of sales (or purchases) of crude and lubrication oils, in each case prior to the elimination of intercompany amounts. We believe margin is a more meaningful measure of financial performance than sales and cost of sales of crude and lubrication oils due to significant fluctuations in the period-to-period level of our marketing activities for these products and the underlying commodity prices. Additionally, our management uses the non-GAAP measure of margin to evaluate the financial performance of the Upstream Segment because it excludes expenses that are not directly related to the marketing activities being evaluated. Margin and volume information for the three months and six months ended June 30, 2009 and 2008 is presented in the following table (in millions, except per barrel and per gallon amounts):

	For the Three Months				Percentage		For the Six Months				Percentage
	Ended June 30,				Increase		Ended June 30,				Increase
	2009		2008		(Decrease)		2009		2008		(Decrease)
Margins: (1)
Crude oil marketing	$	25.6	$	15.6		64%	$	57.8	$	35.9		61%
Lubrication oil sales		2.6		3.0		(13%)		5.8		5.7		1%
Revenues: (1)
Crude oil transportation		22.5		24.1		(6%)		43.0		47.5		(9%)
Crude oil terminaling (2)		6.0		4.5		33%		13.6		8.4		62%
Total margin/revenues	$	56.7	$	47.2		20%	$	120.2	$	97.5		23%

Total barrels/gallons:
Crude oil marketing (barrels) (3)		41.8		44.3		(6%)		87.2		87.2		--
Lubrication oil volumes (gallons)		5.0		3.9		28%		10.4		7.8		33%

Crude oil transportation (barrels)		28.5		29.4		(3%)		57.7		57.2		1%
Crude oil terminaling (barrels)		50.8		39.7		28%		97.6		72.9		34%

Margin per barrel:
Lubrication oil margin (per gallon)	$	0.505	$	0.781		(35%)	$	0.556	$	0.738		(25%)

Average tariff per barrel:
Crude oil transportation	$	0.792	$	0.818		(3%)	$	0.746	$	0.830		(10%)
Crude oil terminaling		0.117		0.114		2%		0.139		0.115		21%

(1) Amounts in this table are presented prior to the eliminations of intercompany sales, revenues and purchases between TEPPCO Crude Oil, LLC (“TCO”) and TEPPCO Crude Pipeline, LLC (“TCPL”), both of which are our wholly owned subsidiaries. TCO is a significant shipper on TCPL. (2) Revenues associated with crude oil terminaling are classified as crude oil transportation in our unaudited condensed statements of consolidated income. (3) Reported quantities exclude inter-region transfers, which are transfers among TCO’s various geographically managed regions. For the three months and six months ended June 30, 2008, we previously reported 61.6 million and 119.2 million barrels, respectively, which included inter-region transfers.

The following table reconciles the Upstream Segment margin to operating income using the information presented in the unaudited condensed statements of consolidated income and the Upstream Segment financial information on the preceding page for the periods indicated (in millions):

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Sales of petroleum products	$	1,732.7		$	4,005.3		$	3,003.9		$	6,643.0
Transportation – Crude oil		15.2			17.4			37.1			32.7
Less: Purchases of petroleum products		(1,691.2	)		(3,975.5	)		(2,920.8	)		(6,578.2	)
Total margin/revenues		56.7			47.2			120.2			97.5
Other operating revenues		3.7			2.7			6.8			5.0
Net operating revenues		60.4			49.9			127.0			102.5
Operating expense		16.6			12.7			31.2			26.0
Operating fuel and power		2.1			1.9			3.9			3.6
General and administrative		3.2			2.7			5.1			4.5
Depreciation and amortization		6.7			5.0			12.3			9.8
Taxes – other than income taxes		1.9			2.0			3.7			3.7
Operating income	$	29.9		$	25.6		$	70.8		$	54.9

Three Months Ended June 30, 2009 Compared with Three Months Ended June 30, 2008

Sales of petroleum products and purchases of petroleum products decreased $2,272.6 million and $2,284.3 million, respectively, for the three months ended June 30, 2009, compared with the three months ended June 30, 2008. Operating income increased $4.3 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008. The decreases in sales and purchases were primarily a result of a decrease in the price of crude oil. The average New York Mercantile Exchange (“NYMEX”) price of crude oil was $59.79 per barrel for the three months ended June 30, 2009, compared with $123.80 per barrel for the three months ended June 30, 2008. An increase in the crude oil marketing margin, partially offset by decreased volumes transported and increased costs and expenses discussed below, were the primary factors resulting in an increase in operating income.

Crude oil marketing margin increased $10.0 million, primarily due to the contango pricing environment during the three months ended June 30, 2009, contract amendments in light of the current market conditions and decreased transportation costs, including decreased fuel costs, partially offset by decreased volumes marketed. Lubrication oil sales margin decreased $0.4 million, primarily due to decreased sales primarily of lower margin lubrication oils, partially offset by higher volumes and additional margin resulting from the Quality Petroleum, Inc. (“Quality Petroleum”) acquisition on August 1, 2008. Crude oil transportation revenues (prior to intercompany eliminations) decreased $1.6 million, primarily due to lower transportation volumes on our South Texas and West Texas crude oil gathering systems, partially offset by higher transportation volumes on our Red River, Basin and other crude oil gathering systems. Decreased transportation revenues on our South Texas, Red River, Basin and other systems resulted from lower prices of crude oil acquired through our pipeline loss allowance (“PLA”) in certain of our pipeline tariffs, partially offset by increased transportation revenues on our West Texas system primarily due to the completion of organic growth projects. The average tariff per barrel decreased 3% primarily due to lower prices of crude oil acquired through PLA in certain of our pipeline tariffs. Crude oil terminaling volumes and revenues increased 28% and $1.5 million, respectively, as a result of spot market demand, the completion of a storage tank in August 2008 and the completion of two storage tanks in the 2009 period.

Other operating revenues increased $1.0 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008. The increase was primarily due to revenues from fuel transportation services generated as a result of the Quality Petroleum acquisition.

Costs and expenses decreased $2,278.1 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008. Purchases of petroleum products, discussed above, decreased $2,284.3 million compared with the prior year period. Operating expenses increased $3.9 million primarily due to a $1.5 million decrease in product measurement gains, a $1.1 million increase in operating expenses resulting from the Quality Petroleum acquisition, a $0.4 million increase in pipeline operating and maintenance expenses, principally related to periodic tank maintenance requirements and other repairs and maintenance on various pipeline segments, a $0.3 million increase in labor and benefits expense and a $0.3 million increase in LCM adjustments on inventory (see Note 5 in the Notes to Unaudited Condensed Consolidated Financial Statements). Operating fuel and power increased $0.2 million primarily as a result of adjustments in power accruals. General and administrative expenses increased $0.5 million primarily due to a $1.3 million increase in legal and other expenses related to the proposed merger with Enterprise Products Partners, partially offset by a $0.5 million decrease related to the write-off of project costs in the 2008 period. Depreciation and amortization expense increased $1.7 million, primarily due to a $0.8 million increase due to asset retirements, a $0.6 million increase due to assets placed into service and a $0.3 million increase in amortization of equity awards. Taxes – other than income taxes decreased $0.1 million primarily due to adjustments to property tax accruals.

Equity in income of unconsolidated affiliates decreased $35.5 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008, primarily due to a $34.2 million non-cash charge related to the forfeiture of our investment in TOPS and a $1.3 million decrease in equity in income from our investment in Seaway. In April 2009, we recorded a non-cash charge of $34.2 million related to our wholly owned subsidiary’s dissociation from TOPS effective April 16, 2009. This loss represents the cumulative investment that our affiliate had in TOPS at April 16, 2009, which primarily reflects capital contributions for construction in progress amounts (see Note 7 in the Notes to Unaudited Condensed Consolidated Financial Statements for further information). Equity in income from our investment in Seaway decreased $1.3 million primarily due to a decrease in long-haul volumes and transportation revenues and an increase in pipeline operating and maintenance expenses, partially offset by an increase in product measurement gains and lower power costs primarily due to the lower volumes. Long-haul volumes on Seaway averaged 152,000 barrels per day during the three months ended June 30, 2009, compared with 218,000 barrels per day during the three months ended June 30, 2008, primarily due to decreased volumes transported on a spot basis in the 2009 period compared to the 2008 period.

Six Months Ended June 30, 2009 Compared with Six Months Ended June 30, 2008

Sales of petroleum products and purchases of petroleum products decreased $3,639.1 million and $3,657.4 million, respectively, for the six months ended June 30, 2009, compared with the six months ended June 30, 2008. Operating income increased $15.9 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008. The decreases in sales and purchases were primarily a result of a decrease in the price of crude oil. The average NYMEX price of crude oil was $51.55 per barrel for the six months ended June 30, 2009, compared with $110.81 per barrel for the six months ended June 30, 2008. An increase in the crude oil marketing margin partially offset by increased costs and expenses discussed below were the primary factors resulting in an increase in operating income.

Crude oil marketing margin increased $21.9 million, primarily due to the contango pricing environment during the six months ended June 30, 2009, contract amendments in light of the current market conditions and decreased transportation costs, including decreased fuel costs. Lubrication oil sales margin increased $0.1 million, with higher volumes primarily due to sales of lower margin specialty chemicals offset by additional margin resulting from the Quality Petroleum acquisition in August 2008. Crude oil transportation revenues (prior to intercompany eliminations) decreased $4.5 million, primarily due to lower transportation volumes on our South Texas crude oil gathering system, partially offset by higher transportation volumes on our Red River, Basin, West Texas and other crude oil gathering systems. Decreased transportation revenues on our South Texas, Red River, Basin and other systems resulted from lower prices of crude oil acquired through PLA in certain of our pipeline tariffs, partially offset by increased transportation revenues on our West Texas system resulting from the completion of organic growth projects. The average tariff per barrel decreased 10% primarily due to movements on lower tariff segments and due to lower prices of crude oil acquired through PLA in certain of our pipeline tariffs. Crude oil terminaling volumes and revenues increased 34% and $5.2 million, respectively, as a result of spot market demand, the completion of a storage tank in August 2008 and the completion of two storage tanks in the 2009 period.

Other operating revenues increased $1.8 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008. The increase was primarily due to revenues from fuel transportation services generated as a result of the Quality Petroleum acquisition.

Costs and expenses decreased $3,648.8 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008. Purchases of petroleum products, discussed above, decreased $3,657.4 million compared with the prior year period. Operating expenses increased $5.2 million primarily due to a $2.4 million increase in operating expenses resulting from the Quality Petroleum acquisition, a $2.3 million decrease in product measurement gains, a $0.8 million increase in labor and benefits expense and a $0.3 million increase in LCM adjustments on inventory, partially offset by a $0.3 million decrease in pipeline inspection and repair costs associated with our integrity management program and a $0.3 million decrease in environmental assessment and remediation expense. Operating fuel and power increased $0.3 million primarily as a result of higher transportation volumes. General and administrative expenses increased $0.6 million primarily due to a $1.3 million increase in legal and other expenses related to the proposed merger with Enterprise Products Partners, partially offset by a $0.5 million decrease related to the write-off of project costs in the 2008 period. Depreciation and amortization expense increased $2.5 million primarily due to a $1.2 million increase due to assets placed into service, a $0.8 million increase due to asset retirements and a $0.5 million increase in amortization of equity awards. Taxes – other than income taxes remained unchanged between periods.

Equity in income of unconsolidated affiliates decreased $35.2 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008, primarily due to a $34.2 million non-cash charge related to the forfeiture of our investment in TOPS and a $1.0 million decrease in equity in income from our investment in Seaway. Equity in income from our investment in Seaway decreased $1.0 million primarily due to a decrease in long-haul volumes and transportation revenues, an increase in pipeline operating and maintenance expenses and a decrease in product measurement losses, partially offset by lower power costs primarily due to the lower volumes. Long-haul volumes on Seaway averaged 163,000 barrels per day during the six months ended June 30, 2009, compared with 192,000 barrels per day

during the six months ended June 30, 2008, primarily due to decreased volumes transported on a spot basis in the 2009 period compared to the 2008 period.

Midstream Segment

The following table provides financial information for the Midstream Segment for the periods indicated (in millions):

	For the Three Months							For the Six Months
	Ended June 30,				Increase			Ended June 30,				Increase
	2009		2008		(Decrease)			2009		2008		(Decrease)
Operating revenues:
Gathering – Natural gas	$	14.4	$	14.8	$	(0.4	)	$	28.0	$	28.2	$	(0.2	)
Transportation – NGLs (1)		13.6		12.7		0.9			26.1		25.7		0.4
Other		3.1		3.1		--			6.0		6.8		(0.8	)
Total operating revenues		31.1		30.6		0.5			60.1		60.7		(0.6	)

Costs and expenses:
Operating expense		8.4		4.4		4.0			17.0		9.4		7.6
Operating fuel and power		3.1		4.5		(1.4	)		5.7		8.2		(2.5	)
General and administrative		4.8		2.7		2.1			7.8		5.3		2.5
Depreciation and amortization		10.3		10.0		0.3			19.8		19.6		0.2
Taxes – other than income taxes		0.7		0.7		--			1.5		1.5		--
Total costs and expenses		27.3		22.3		5.0			51.8		44.0		7.8

Operating income		3.8		8.3		(4.5	)		8.3		16.7		(8.4	)

Equity in income of unconsolidated affiliates		23.8		21.9		1.9			49.4		45.6		3.8
Other, net		--		0.1		(0.1	)		--		0.2		(0.2	)

Earnings before interest	$	27.6	$	30.3	$	(2.7	)	$	57.7	$	62.5	$	(4.8	)

(1) Includes transportation revenue from Enterprise Products Partners of $3.5 million and $3.4 million for the three months ended June 30, 2009 and 2008, respectively. For the six months ended June 30, 2009 and 2008, such amounts were $7.3 million and $6.8 million, respectively.

The following table presents volume and average rate information for the periods indicated:

	For the Three Months				Percentage		For the Six Months				Percentage
	Ended June 30,				Increase		Ended June 30,				Increase
	2009		2008		(Decrease)		2009		2008		(Decrease)
Gathering – Natural Gas – Jonah: (1)
Bcf		200.3		173.5		15%		395.2		340.6		16%
Btu (in trillions)		221.0		192.5		15%		436.1		377.2		16%
Average fee per Mcf	$	0.261	$	0.258		1%	$	0.261	$	0.258		1%
Average fee per MMBtu	$	0.237	$	0.233		2%	$	0.236	$	0.233		1%

Gathering – Natural Gas – Val Verde: (1)
Bcf		46.1		41.6		11%		88.9		79.8		11%
Btu (in trillions)		41.7		36.8		13%		80.3		71.0		13%
Average fee per Mcf	$	0.312	$	0.356		(12%)	$	0.315	$	0.353		(11%)
Average fee per MMBtu	$	0.345	$	0.402		(14%)	$	0.349	$	0.397		(12%)

Transportation and movements – NGLs:
Transportation barrels (in millions)		15.2		16.0		(5%)		29.3		32.5		(10%)
Lease barrels (in millions) (2)		2.5		2.8		(11%)		5.3		5.9		(10%)
Average rate per barrel	$	0.844	$	0.747		13%	$	0.834	$	0.742		12%

Natural Gas Sales:
Btu (in trillions)		0.8		1.2		(33%)		1.6		2.8		(43%)
Average fee per MMBtu	$	2.369	$	8.552		(72%)	$	2.911	$	7.521		(61%)

Fractionation – NGLs:
Barrels (in millions)		1.0		1.1		(9%)		1.8		2.1		(14%)
Average rate per barrel	$	1.784	$	1.785		--	$	1.785	$	1.722		4%

(1) The majority of volumes in Val Verde’s contracts are measured in Bcf, while the majority of volumes in Jonah’s contracts are measured in Btu. Both measures are shown for each asset for comparability purposes. (2) Revenues associated with capacity leases are classified as other operating revenues in our unaudited condensed statements of consolidated income.

Three Months Ended June 30, 2009 Compared with Three Months Ended June 30, 2008

Natural gas gathering revenues from the Val Verde system decreased $0.4 million, while volumes gathered increased 4.5 Bcf for the three months ended June 30, 2009, compared with the three months ended June 30, 2008. Volumes increased primarily due to an increase in volumes from a third party natural gas connection in Colorado, partially offset by lower production as a result of the natural decline of coal bed methane production in the fields in which the Val Verde gathering system operates. For the three months ended June 30, 2009, Val Verde’s gathering volumes averaged 506 MMcf/d, compared with 457 MMcf/d for the three months ended June 30, 2008. Val Verde’s average natural gas gathering fee per Mcf decreased 12%, primarily due to lower rates on the higher volumes from the third party natural gas connection and lower gathering volumes of coal bed methane, partially offset by annual rate escalations.

Revenues from the transportation of NGLs increased $0.9 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008, primarily due to an increase in the average rate on the Chaparral Pipeline as a result of transporting a higher percentage of long-haul volumes at a higher tariff rate on the system and an increase in the average rate on the Panola Pipeline due to tariff increases. These increases in revenues were partially offset by a decrease in revenues and volumes on the Dean Pipeline and a decrease in the short-haul volumes on the Chaparral Pipeline.

Other operating revenues remained unchanged for the three months ended June 30, 2009, compared with the three months ended June 30, 2008, primarily due to a 9% decrease in the volume of NGLs fractionated, resulting in a decrease of $0.1 million in fractionation revenues, offset by a slight increase in Val Verde’s other operating revenue.

Costs and expenses increased $5.0 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008. Operating expenses increased $4.0 million primarily due to a $2.4 million increase as a result of lower product measurement gains, a $0.6 million increase in pipeline inspection and repair costs associated with our integrity management program and a $0.5 million increase in LCM adjustments on inventory. Operating fuel and power decreased $1.4 million primarily due to lower power costs on the Chaparral Pipeline as a result of a decrease in volumes. General and administrative expenses increased $2.1 million primarily due a $2.6 million increase in legal and other expenses related to the proposed merger with Enterprise Products Partners, partially offset by $0.4 million decrease in labor and benefits expense. Depreciation and amortization expense increased $0.3 million primarily due to a $0.6 million increase due to asset retirements and a $0.4 million increase in the amortization of equity awards, partially offset by a $0.6 million decrease in amortization expense on Val Verde as a result of a decrease in volumes on contracts which are included in intangible assets and amortized under the units-of-production method. Taxes – other than income taxes remained unchanged between periods.

Equity in income from our investment in Jonah increased $1.9 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008. Earnings increased primarily due to a $7.5 million increase in natural gas gathering revenues as a result of an increase in volumes from the system expansion partially offset by a $0.8 million decrease in Jonah’s condensate sales, a $2.6 million increase in depreciation and amortization expense primarily relating to the system expansion and a $2.2 million increase in operating, general and administrative expenses. For the three months ended June 30, 2009 and 2008, Jonah’s gathering volumes averaged approximately 2.2 Bcf/d and 1.9 Bcf/d, respectively, and total volumes gathered increased 26.8 Bcf. For the three months ended June 30, 2009 and 2008, our sharing in the earnings of Jonah was 80.64%.

The decrease in Jonah’s natural gas sales volumes for the three months ended June 30, 2009, compared with the prior year period, was primarily a result of certain producers selling gas themselves, rather than through Jonah. The decrease in Jonah’s natural gas sales average fee per MMBtu was primarily a result of lower market prices in the 2009 period.

Six Months Ended June 30, 2009 Compared with Six Months Ended June 30, 2008

Natural gas gathering revenues from the Val Verde system decreased $0.2 million, while volumes gathered increased 9.1 Bcf for the six months ended June 30, 2009, compared with the six months ended June 30, 2008. Volumes increased primarily due to an increase in volumes from a third party natural gas connection in Colorado, partially offset by lower production as a result of the natural decline of coal bed methane production in the fields in which the Val Verde gathering system operates. For the six months ended June 30, 2009, Val Verde’s gathering volumes averaged 491 MMcf/d, compared with 438 MMcf/d for the six months ended June 30, 2008. Val Verde’s average natural gas gathering fee per Mcf decreased 11% primarily due to lower rates on the higher volumes from the third party natural gas connection and lower gathering volumes of coal bed methane, partially offset by annual rate escalations.

Revenues from the transportation of NGLs increased $0.4 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008, primarily due an increase in the average rate on the Chaparral Pipeline as a result of transporting a higher percentage of long-haul volumes at a higher tariff rate on the system and an increase in the average rate on the Panola Pipeline due to tariff increases. These increases in revenues were partially offset by a decrease in revenues and volumes on the Dean Pipeline, a decrease in the short-haul volumes on the Chaparral Pipeline and a decrease in revenues and volumes on the Panola Pipeline resulting from downtime following a fire during the first quarter of 2009 at a system origination point in East Texas owned by a third party.

Other operating revenues decreased $0.8 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008. Other operating revenues decreased $0.5 million as a result of a 14% decrease in the volume of NGLs fractionated. The average rate per barrel for the fractionation of NGLs increased 4% primarily due to a change in the rate structure in the fractionation agreement, under which volumes of NGLs are fractionated at a fixed rate beginning April 2008. Other operating revenues decreased $0.3 million due to a decrease in Val Verde’s other operating revenue as a result of contractual producer minimum fuel levels equaling actual operating fuel usage. Val Verde retains a portion of its producers’ gas to compensate for fuel used in operations. The actual usage of gas can differ from the amount contractually retained from producers. Value retained from producers or sales generated as a result of efficient fuel usage are recognized as other operating revenues.

Costs and expenses increased $7.8 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008. Operating expenses increased $7.6 million primarily due to a $3.4 million increase as a result of lower product measurement gains, a $1.4 million increase in labor and benefits expense, a $1.2 million increase in LCM adjustments on inventory and a $1.2 million increase in pipeline inspection and repair costs associated with our integrity management program. Operating fuel and power decreased $2.5 million primarily due to lower power costs on the Chaparral Pipeline as a result of a reduced fuel costs in the 2009 period. General and administrative expenses increased $2.5 million primarily due to a $2.6 million increase in legal and other expenses related to the proposed merger with Enterprise Products Partners and $0.5 million of severance expense, partially offset by a $0.7 million decrease in labor and benefits expense. Depreciation and amortization expense increased $0.2 million primarily due to a $0.8 million increase due to asset retirements and a $0.6 million increase in the amortization of equity awards, partially offset by a $1.1 million decrease in amortization expense on Val Verde as a result of a decrease in volumes on contracts which are included in intangible assets and amortized under the units-of-production method. Taxes – other than income taxes remained unchanged between periods.

Equity in income from our investment in Jonah increased $3.8 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008. Earnings increased primarily due to a $15.7 million increase in natural gas gathering revenues as a result of an increase in volumes from the system expansion, partially offset by a $3.6 million decrease in Jonah’s condensate sales, a $4.0 million increase in depreciation and amortization expense primarily relating to the system expansion and additional volumes, a $3.5 million increase in operating, general and administrative expenses and a $0.6 million increase in taxes – other than income taxes primarily relating to the system expansion For the six months ended June 30, 2009 and 2008, Jonah’s gathering volumes averaged approximately 2.2 Bcf/d and 1.9 Bcf/d,

respectively, and total volumes gathered increased 54.6 Bcf. For the six months ended June 30, 2009 and 2008, our sharing in the earnings of Jonah was 80.64%.

The decrease in Jonah’s natural gas sales volumes for the six months ended June 30, 2009, compared with the prior year period, was primarily a result of certain producers selling gas themselves, rather than through Jonah. The decrease in Jonah’s natural gas sales average fee per MMBtu was primarily a result of lower market prices in the 2009 period.

Marine Services Segment

The following table provides financial information for the Marine Services Segment for the periods indicated (in millions):

	For the Three Months							For the Six Months
	Ended June 30,				Increase			Ended June 30,				Increase
	2009		2008		(Decrease)			2009		2008		(Decrease)
Operating revenues:
Transportation – inland	$	36.0	$	39.6	$	(3.6	)	$	69.6	$	60.3	$	9.3
Transportation – offshore		7.7		8.5		(0.8	)		11.0		13.3		(2.3	)
Total Transportation – Marine		43.7		48.1		(4.4	)		80.6		73.6		7.0

Costs and expenses:
Operating expense		20.7		19.0		1.7			39.4		27.6		11.8
Operating fuel and power		5.7		12.2		(6.5	)		10.0		17.7		(7.7	)
General and administrative		1.5		1.1		0.4			2.9		1.8		1.1
Depreciation and amortization		6.5		6.4		0.1			12.9		10.1		2.8
Taxes – other than income taxes		1.0		0.8		0.2			1.9		1.2		0.7
Total costs and expenses		35.4		39.5		(4.1	)		67.1		58.4		8.7

Operating income		8.3		8.6		(0.3	)		13.5		15.2		(1.7	)

Earnings before interest	$	8.3	$	8.6	$	(0.3	)	$	13.5	$	15.2	$	(1.7	)

Information presented in the following table includes gross margin and average daily rate for our Marine Services Segment, which are non-GAAP financial measures under the rules of the SEC. We calculate gross margin as marine transportation revenues less operating expense and operating fuel and power. Average daily rate is calculated as gross margin for the Marine Services Segment divided by fleet operating days. We believe these non-GAAP measures of gross margin and average daily rate are meaningful measures of the financial performance of our Marine Services Segment, in which we provide services under different types of contracts with varying arrangements for the payment of fuel costs and other operational fees. These non-GAAP measures allow for comparability of results across different contracts within a given period, as well as between periods. Further, our management uses these non-GAAP measures to assist them in evaluating results of the Marine Services Segment and making decisions regarding the use and deployment of our marine vessels.

The following table provides operating statistics for the Marine Services Segment at the dates or for the periods indicated:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Number of inland tow boats (1)		59			45			59			45
Number of inland tank barges (1)		127			103			127			103
Number of offshore tow boats (1)		6			6			6			6
Number of offshore tank barges (1)		8			8			8			8
Fleet available days (in thousands) (2)		15.5			14.2			29.4			21.6
Fleet operating days (in thousands) (3)		13.6			13.1			25.9			20.0
Fleet utilization (4)		88	%		92	%		88	%		93	%
Gross margin (in millions)	$	17.3		$	16.9		$	31.2		$	28.3
Average daily rate (in thousands) (5)	$	1.27		$	1.29		$	1.20		$	1.42

(1) Amounts represent equipment that has either been licensed or certified and available for use as of the end of the applicable period. (2) Equal to the number of calendar days in the period (for the six months ended June 30, 2008, number of calendar days from our Cenac acquisition on February 1, 2008 and Horizon Maritime, LLC (“Horizon”) on February 29, 2008 through June 30, 2008) multiplied by the total number of vessels less the aggregate number of days that our vessels are not operating due to scheduled maintenance and repairs or unscheduled instances where vessels may have to be drydocked in the event of accidents and other unforeseen damage. (3) Equal to the number of our fleet available days in the period (for the six months ended June 30, 2008, number of our fleet available days from our acquisition of Cenac on February 1, 2008 and Horizon on February 29, 2008 through June 30, 2008) less the aggregate number of days that our vessels are off-hire. (4) Equal to the number of fleet operating days divided by the number of fleet available days during the period. (5) Equal to gross margin divided by the number of fleet operating days during the period.

The following table reconciles gross margin to operating income using the information presented in our unaudited condensed statements of consolidated income and the Marine Services Segment financial information on the preceding page for the periods indicated (in millions):

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2009			2008			2009			2008
Transportation revenue – Marine	$	43.7		$	48.1		$	80.6		$	73.6
Less: Operating expense		(20.7	)		(19.0	)		(39.4	)		(27.6	)
Less: Operating fuel and power		(5.7	)		(12.2	)		(10.0	)		(17.7	)
Gross margin		17.3			16.9			31.2			28.3
General and administrative		1.5			1.1			2.9			1.8
Depreciation and amortization		6.5			6.4			12.9			10.1
Taxes – other than income taxes		1.0			0.8			1.9			1.2
Operating income	$	8.3		$	8.6		$	13.5		$	15.2

Three Months Ended June 30, 2009 Compared with Three Months Ended June 30, 2008

Revenues are primarily influenced by rates on term contracts along with industry demand, utilization rates of tank barges and reimbursements of costs of fuel and other specified operational fees that are recovered under most of the transportation contracts. Revenues from marine transportation decreased $4.4 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008, primarily due to lower fleet utilization and decreased reimbursements for the cost of fuel and other specified operational fees, which are reimbursed by customers and included in inland and offshore transportation service revenue, partially offset by approximately $2.3 million of revenues generated by the TransMontaigne assets acquired in June 2009. Reimbursable revenues decreased primarily due to a decrease in the price of diesel fuel, as discussed below in operating fuel and power costs. Fleet utilization decreased from 92% to 88% for the three months ended June 30, 2009, compared with the three months ended June 30, 2008, primarily due to reduced demand for barge services as a result of general economic conditions in the industry, which has resulted in some inland customer contracts not being renewed during the fourth quarter of 2008 and in the 2009 period. Renewal rates of contracts have continued to decline; however, most of the marine vessels impacted by these non-renewals are employed in the spot market until we can secure term contracts.

Gross margin and the average daily rate are influenced by rates on term and spot contracts and renewal of term contracts along with industry demand. Operating expenses, such as vessel personnel salaries and related employee benefits and tow boat and tank barge maintenance expenses, also impact gross margin and average daily rate. Gross margin increased $0.4 million, while the average daily rate decreased 2% for the three months ended June 30, 2009, compared with the three months ended June 30, 2008, primarily due to higher operating costs related to increased vessel maintenance expense, as discussed below. These increases in operating expenses and an increase in the fleet operating days resulted in a decrease in the average daily rate in the 2009 period.

Costs and expenses decreased $4.1 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008. Operating expenses (including those reimbursed under the transitional operating agreement) increased $1.7 million primarily due to a $0.8 million increase primarily in labor and benefits expense related to the TransMontaigne acquisition and a $1.4 million increase in vessel personnel labor and benefits expense, partially offset by a $0.4 million decrease in vessel repairs and maintenance expense. Operating fuel and power decreased $6.5 million primarily due to the decline in the price of diesel fuel. Under contract terms, substantially all operating fuel and power consumed is directly reimbursed by the customer. General and administrative expense increased $0.4 million primarily due to increased legal and other expenses related to the proposed merger with Enterprise Products Partners. Depreciation and amortization expense increased $0.1 million primarily due to the acquisition of additional tow boats and tank barges from TransMontaigne. Taxes – other than income taxes increased $0.2 million primarily due to higher payroll taxes relating to increased labor costs. Effective August 1, 2009, the transitional operating agreement was terminated. Personnel providing services thereunder became employees of EPCO and will continue to provide services to TEPPCO Marine Services under the administrative services agreement with EPCO.

Six Months Ended June 30, 2009 Compared with Six Months Ended June 30, 2008

We acquired Cenac and Horizon on February 1, 2008 and February 29, 2008, respectively. Our ownership and operation of these assets for a portion of the six months ended June 30, 2008, as compared to the full six months ended June 30, 2009, accounted for a portion of the changes in the results of operations in this segment.

Revenues from marine transportation increased $7.0 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008, primarily due to the timing of the acquisitions in the 2008 period as discussed above, partially offset by lower fleet utilization, decreased reimbursements for the cost of fuel and other specified operational fees and approximately $2.3 million of revenues generated by the TransMontaigne assets acquired in June 2009. Reimbursable revenues decreased primarily due to a decrease in the price of diesel fuel, as discussed below in operating fuel and power costs. Fleet utilization decreased from 93% to 88% for the six months ended June 30, 2009, compared with the six months ended June 30, 2008, primarily due to reduced demand for barge services as a result of general economic conditions in the industry, which has resulted in some inland customer contracts not being renewed during the fourth quarter of 2008 and in the 2009 period. Renewal rates of contracts have continued to decline; however, most of the marine vessels impacted by these non-renewals are employed in the spot market until we can secure term contracts.

Gross margin increased $2.9 million, while the average daily rate decreased 15% for the six months ended June 30, 2009, compared with the six months ended June 30, 2008, primarily due to the ownership and operation of the Cenac and Horizon assets for only a portion of the six months ended June 30, 2008, as compared to the full six months ended June 30, 2009. This increase in gross margin was partially offset by higher operating costs related to increased vessel maintenance expense, as discussed below. These increases in operating expenses, an increase in the fleet operating days and contract renewals at lower daily rates resulted in a decrease in the average daily rate in the 2009 period.

Costs and expenses increased $8.7 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008. A large portion of the changes in costs and expenses was the timing of the acquisitions in the 2008 period as discussed above. Operating expenses (including those reimbursed

under the transitional operating agreement) also increased due to a $2.6 million increase in vessel personnel labor and benefits expense, a $1.4 million increase in vessel repairs and maintenance expenses and a $0.8 million increase in expenses due to the TransMontaigne acquisition. Operating fuel and power decreased due to the decline in the price of diesel fuel. General and administrative expense increased primarily due to a $0.3 million increase in legal and other expenses related to the proposed merger with Enterprise Products Partners. Depreciation and amortization expense increased primarily due to the acquisition of additional tow boats and tank barges in the 2008 period and the assets purchased with the TransMontaigne acquisition. Taxes – other than income taxes increased primarily due to higher payroll taxes relating to increased labor costs.

Interest Expense

Three Months Ended June 30, 2009 Compared with Three Months Ended June 30, 2008

Interest expense decreased $0.7 million for the three months ended June 30, 2009, compared with the three months ended June 30, 2008, primarily due to lower average interest rates during the 2009 period, partially offset by higher outstanding borrowings in the 2009 period and a $0.3 million increase in capitalized interest primarily due to higher construction work-in-progress balances in the 2009 period as compared to the 2008 period.

Six Months Ended June 30, 2009 Compared with Six Months Ended June 30, 2008

Interest expense decreased $7.2 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008, primarily due to $8.7 million in interest expense recognized in the 2008 period upon the redemption of the 7.51% TE Products Senior Notes on January 28, 2008. Of the $8.7 million of expense, $6.6 million related to a make-whole premium paid with the redemption of the senior notes, $1.0 million related to the remaining unamortized interest rate swap loss that had been deferred as an adjustment to the carrying value of the senior notes and $1.1 million related to unamortized debt issuance costs on the senior notes. Additionally, the decrease in interest expense was due to $3.6 million of interest expense in the 2008 period resulting from interest payments hedged under treasury locks not occurring as forecasted, lower average interest rates during the 2009 period and a $0.6 million increase in capitalized interest primarily due to higher construction work-in-progress balances in the 2009 period as compared to the 2008 period. These decreases in interest expense were partially offset by higher outstanding borrowings in the 2009 period.

Provision for Income Taxes

Provision for income taxes is attributable to our state tax obligations under the Revised Texas Franchise Tax enacted in May 2006. At June 30, 2009 and December 31, 2008, we had current tax liabilities of $1.8 million and $3.9 million, respectively. At June 30, 2009, we had a deferred tax asset of less than $0.1 million. During the three months ended June 30, 2009 and 2008, we recorded an increase in current income tax liabilities of $0.9 million and $1.0 million, respectively. During the six months ended June 20, 2009 and 2008, we recorded an increase in current income tax liabilities of $1.7 million and $1.8 million, respectively. During the six months ended June 30, 2009, adjustments to deferred tax assets and liabilities were not material to our consolidated financial statements. The offsetting net charges to deferred tax expense and income tax expense are shown on our unaudited condensed statements of consolidated income as provision for income taxes.

Financial Condition and Liquidity

Liquidity Outlook

Our primary cash requirements consist of (i) ordinary course operating uses, such as operating expenses, capital expenditures to sustain existing operations, interest payments on our outstanding debt and distributions to our unitholders and General Partner, (ii) growth expenditures, such as capital expenditures for revenue generating activities (including the Motiva Enterprises, LLC (“Motiva”) project and Jonah) and

acquisitions of new assets or businesses and (iii) repayment of principal on our long-term debt. Our ordinary course operating cash requirements and a portion of our growth expenditures for 2009 are expected to be funded through our cash flows from operating activities. Our ability to continue to generate cash from operations to maintain adequate liquidity is subject to a number of factors, including prevailing market conditions, the possibility of a prolonged economic slowdown and general competitive, legislative, regulatory and other market factors that are beyond our control.

In August 2009, we entered into a Loan Agreement with EPO under which EPO agreed to make a revolving loan to us in an aggregate maximum outstanding principal amount not to exceed $100.0 million. Borrowings under the Loan Agreement mature on the earliest to occur of (i) the consummation of our proposed merger with Enterprise Products Partners, (ii) the termination of the related merger agreement in accordance with the provisions thereof, (iii) December 31, 2009, (iv) the date upon which the maturity of the loan is otherwise accelerated upon an event of default, and (v) the date upon which EPO’s commitment to make the loan is terminated by us pursuant to the Loan Agreement. Borrowings under the Loan Agreement will bear interest at a floating rate, equivalent to the one-month LIBOR Rate (as defined in the Loan Agreement) plus 2.00%. Interest is payable monthly. EPO’s obligation to fund any borrowings under the Loan Agreement is subject to specified conditions, including the condition that, on and as of the applicable date of funding, no additional amounts are available to us pursuant to our Revolving Credit Facility (either as borrowings or under any letters of credit). See “Recent Developments” within this Item 2 for further information. Because our access to debt and equity capital markets is constrained while the merger with Enterprise Products Partners is pending, and because we have relied more heavily on borrowings under our Revolving Credit Facility to fund 2009 capital expenditures than previous years, we entered into the Loan Agreement to supplement our near-term liquidity position. However, we currently do not expect to borrow funds under the Loan Agreement.

For the remainder of 2009, we expect cash requirements for our anticipated level of growth expenditures to be funded by a combination of cash flows from operating activities and borrowings under our Revolving Credit Facility. We currently have no material long-term debt obligations that mature in 2009, and our Revolving Credit Facility does not mature until 2012. However, if we were to incur any indebtedness under the Loan Agreement, we would be obligated to repay it no later than December 31, 2009, and we likely would not have availability under our Revolving Credit Facility as a source to repay such amounts. See Item 1A, Part II. Risk Factors.

It is our belief that we will continue to have adequate liquidity to fund future recurring operating and investing activities. For a discussion of our liquidity outlook (which is updated in this report), see “General Outlook for 2009” within Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2008.

Cash Flows from Operating, Investing and Financing Activities

Cash generated from operations, distributions from our joint ventures and borrowings under our credit facilities are our primary sources of liquidity. From time to time we may dispose of assets, which would provide an additional source of liquidity. At June 30, 2009 and December 31, 2008, we had working capital surpluses of $42.9 million and $7.6 million, respectively. At June 30, 2009, we had approximately $197.8 million in available borrowing capacity under our Revolving Credit Facility. Cash flows for the periods indicated were as follows (in millions):

	For the Six Months
	Ended June 30,
	2009			2008
Cash provided by (used in):
Operating activities	$	207.5		$	164.1
Investing activities		(234.6	)		(564.1	)
Financing activities		27.1			400.0

Operating Activities

Net cash flow provided by operating activities was $207.5 million for the six months ended June 30, 2009 compared to $164.1 million for the six months ended June 30, 2008. The following were the principal factors resulting in the $43.4 million increase in net cash flows provided by operating activities:

§	Cash flow from operating activities increased due to the timing of cash receipts and cash disbursements related to working capital components.

Cash distributions received from unconsolidated affiliates increased $9.9 million. Distributions received from our equity investment in Seaway increased $9.8 million primarily due to the timing of distributions received in the 2009 period as compared to the 2008 period. Distributions from our equity investment in Jonah increased $0.1 million primarily due to increased revenues and volumes generated from completion of the system expansion.

Cash paid for interest, net of amounts capitalized, increased $6.5 million for the six months ended June 30, 2009 compared with the six months ended June 30, 2008, primarily due to an increase in debt outstanding, including higher outstanding balances on our variable rate Revolving Credit Facility, partially offset by the redemption of our senior notes in the 2008 period. Excluding the effects of hedging activities and interest capitalized during the year ending December 31, 2009, we expect interest payments on our fixed-rate senior notes and junior subordinated notes for 2009 to be approximately $139.6 million. We expect to make our interest payments with cash flows from operating activities.

Investing Activities

Net cash flow used in investing activities was $234.6 million for the six months ended June 30, 2009, compared to $564.1 million for the six months ended June 30, 2008. The following were the principal factors resulting in the $329.5 million decrease in net cash flows used in investing activities:

Cash used for business combinations was $50.0 million during the six months ended June 30, 2009 for the TransMontaigne acquisition (see Note 8 in the Notes to Unaudited Condensed Consolidated Financial Statements), compared with $345.6 million during the six months ended June 30, 2008, of which $258.1 million was for the Cenac acquisition and $87.5 million was for the Horizon acquisition.

Capital expenditures increased $25.1 million primarily due to higher spending on revenue generating projects for the six months ended June 30, 2009 compared with the six months ended June 30, 2008. Cash paid for linefill on assets owned decreased $13.0 million for the six months ended June 30, 2009 compared with the six months ended June 30, 2008, primarily due to the timing of completion of organic growth projects in our Upstream Segment.

Investments in unconsolidated affiliates decreased $47.1 million, which includes a $45.4 million decrease in contributions to Jonah primarily related to lower system expansion spending in 2009 and a $1.7 million decrease in net contributions to TOPS for the six months ended June 30, 2009. In January 2009, we received a $3.1 million refund of our 2008 contributions to TOPS due to a delay in the timing of the expected project spending. In February and March 2009, we then invested an additional $1.4 million in TOPS. See Note 7 in the Notes to Unaudited Condensed Consolidated Financial Statements for information regarding our dissociation from TOPS.

§	Cash used for the acquisition of intangible assets increased $1.1 million during the six months ended June 30, 2009, compared with the six months ended June 30, 2008.

Financing Activities

Cash flows provided by financing activities totaled $27.1 million for the six months ended June 30, 2009, compared to $400.0 million for the six months ended June 30, 2008. The following were the principal factors resulting in the $372.9 million decrease in cash flows provided by financing activities:

During the six months ended June 30, 2008, we used $1.0 billion of proceeds from our term credit agreement (i) to fund the cash portion of our Cenac and Horizon acquisitions, (ii) to fund the redemption of our 7.51% TE Products Senior Notes in January 2008 and to repay our 6.45% TE Products Senior Notes, which matured in January 2008, (iii) to repay $63.2 million of debt assumed in the Cenac acquisition, and (iv) for other general partnership purposes. We used the proceeds from the issuance of senior notes in March 2008 to repay the outstanding balance of $1.0 billion under the term credit agreement. Debt issuance costs paid during the six months ended June 30, 2008 were $9.3 million.

§	Net borrowings under our Revolving Credit Facility increased $166.7 million primarily due to the Revolving Credit Facility being used to fund a greater portion of capital expenditures for the six months ended June 30, 2009, compared with the six months ended June 30, 2008.

§	We paid $52.1 million to settle treasury locks in March 2008 (see Note 4 in the Notes to Unaudited Condensed Consolidated Financial Statements) upon the issuance of senior notes.

Cash distributions to our partners increased $27.1 million for the six months ended June 30, 2009, compared with the six months ended June 30, 2008, due to an increase in the number of Units outstanding and an increase in our quarterly cash distribution rate per Unit. We paid cash distributions of $182.8 million ($1.450 per Unit) and $155.7 million ($1.405 per Unit) during the six months ended June 30, 2009 and 2008, respectively. Additionally, we declared a cash distribution of $0.725 per Unit for the quarter ended June 30, 2009. We will pay the distribution of $91.6 million on August 7, 2009 to unitholders of record on July 31, 2009.

Net proceeds from the issuance of Units to employees under our EUPP and the issuance of Units in connection with our DRIP were $3.3 million for the six months ended June 30, 2009, compared to $5.6 million for the six months ended June 30, 2008. See below for further information regarding our DRIP and EUPP.

Other Considerations

Registration Statements

We have a universal shelf registration statement on file with the SEC that allows us to issue an unlimited amount of debt and equity securities.

We also have a registration statement on file with the SEC authorizing the issuance of up to 10,000,000 Units in connection with our DRIP. During the six months ended June 30, 2009, 115,703 Units have been issued under this registration statement, generating $2.9 million in net proceeds that we used for general partnership purposes. On July 1, 2009, we suspended the opportunity for investors to acquire additional Units under our DRIP, pursuant to the terms of the definitive merger agreement with Enterprise Products Partners (see Note 15 in the Notes to Unaudited Condensed Consolidated Financial Statements). We expect this suspension to remain in place pursuant to such terms while the transaction is pending.

In addition, we have a registration statement on file related to our EUPP, under which we can issue up to 1,000,000 Units. During the six months ended June 30, 2009, 15,902 Units have been issued to employees under this plan, generating $0.4 million in net proceeds that we used for general partnership purposes. In August 2009, the EUPP will suspend operations pursuant to the terms of the merger agreement. We expect this suspension to remain in place pursuant to such terms while the transaction is pending.

For information regarding our Partnership’s capital, see Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

Debt Obligations

Our available borrowing capacity under our Revolving Credit Facility was approximately $197.8 million at June 30, 2009.

We were in compliance with the covenants of our long-term debt obligations at June 30, 2009.

For information regarding our debt obligations, see Note 10 in the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

See “Recent Developments” within this Item 2 for information regarding a loan agreement we entered into with Enterprise Products Partners.

Future Capital Needs and Commitments

We estimate that capital expenditures, excluding acquisitions and joint venture contributions, for 2009 will be in the range of $315.0 million to $345.0 million (including approximately $19.0 million of capitalized interest). Excluding capitalized interest, we expect to spend in the range of $245.0 million to $275.0 million for revenue generating projects, which includes $160.0 million for our expected spending on the Motiva project. We expect to spend approximately $46.0 million to sustain existing operations (including $16.0 million for pipeline integrity) including life-cycle replacements for equipment at various facilities and pipeline and tank replacements among all of our business segments. We expect to spend approximately $5.0 million to improve operational efficiencies and reduce costs among all of our business segments. Based upon our capital spending for the first half of 2009 (excluding acquisitions and joint venture contributions), we expect that our capital expenditures for the remainder of 2009 will be approximately $29 million to sustain existing operations and our growth capital expenditures will be in the range of $120 million to $150 million.

Additionally, we expect to invest approximately $22.0 million in our Jonah joint venture during 2009 for the completion of additional facilities to expand the Pinedale filed production. During 2009, TE Products may be required to contribute cash to Centennial to cover capital expenditures, debt service requirements or other operating needs. We continually review and evaluate potential capital improvements and expansions that would be complementary to our present business operations. These expenditures can vary greatly depending on the magnitude of our transactions.

Off-Balance Sheet Arrangements

There have been no material changes with regards to our off-balance sheet arrangements since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008.

Contractual Obligations

Operating lease obligations. Lease and rental expense was $4.6 million and $5.1 million for the three months ended June 30, 2009 and 2008, respectively. For the six months ended June 30, 2009 and

2008, lease and rental expense was $9.1 million and $10.3 million, respectively. There have been no material changes in our operating lease commitments since December 31, 2008.

Purchase obligations. Apart from that discussed below, there have been no material changes in our purchase obligations since December 31, 2008.

Due to our exit from TOPS, our capital expenditure commitments decreased by an estimated $68.0 million. See Note 7 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional information regarding this event.

Summary of Related Party Transactions

The following table summarizes related party transactions for the periods indicated (in millions):

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2009		2008		2009		2008
Revenues from EPCO and affiliates:
Sales of petroleum products	$	0.2	$	0.3	$	0.3	$	0.9
Transportation – NGLs		3.5		3.4		7.3		6.8
Transportation – LPGs		1.5		1.0		6.4		3.3
Other operating revenues		6.3		0.2		20.3		0.6
Related party revenues	$	11.5	$	4.9	$	34.3	$	11.6
Costs and Expenses from EPCO and affiliates:
Purchases of petroleum products	$	45.2	$	30.5	$	71.9	$	50.2
Operating expense		29.5		26.7		58.1		48.2
General and administrative		7.4		8.0		15.5		16.8
Costs and Expenses from unconsolidated affiliates:
Purchases of petroleum products		0.7		2.0		--		3.5
Operating expense		0.6		1.6		2.2		3.9
Costs and Expenses from Cenac and affiliates:
Operating expense		13.6		9.8		27.0		17.2
General and administrative		0.5		0.8		1.6		1.3
Related party expenses	$	97.5	$	79.4	$	176.3	$	141.1

The following table summarizes our related party receivable and payable amounts at the dates indicated (in millions):

	June 30,		December 31,
	2009		2008
Accounts receivable, related parties	$	10.7	$	15.8
Accounts payable, related parties		40.9		17.2

For additional information regarding our related party transactions, see Note 13 in the Notes to Unaudited Condensed Consolidated Financial Statements.

Credit Ratings

Our publicly traded debt securities are rated investment-grade. Standard & Poor’s Ratings Group (“S&P”) and Fitch Ratings each assigned a rating of BBB- and Moody’s Investors Service, Inc. (“Moody’s”) assigned a rating of Baa3, all with stable outlooks. Such ratings reflect only the view of the rating agency and should not be interpreted as a recommendation to buy, sell or hold our securities. These ratings may be revised or withdrawn at any time by the agencies at their discretion and should be evaluated independently of any other rating. Based upon the characteristics of the fixed/floating unsecured junior subordinated notes that we issued in May 2007, Moody’s and S&P each assigned 50% equity treatment to these notes. Fitch Ratings assigned 75% equity treatment to these notes.

Fitch Ratings affirmed its BBB- rating of our publicly traded debt securities on June 29, 2009 following the announcement that we had entered into definitive agreements to merge with Enterprise

Products Partners. This rating assumes that (i) our debt and the debt of EPO, the operating subsidiary of Enterprise Products Partners, would be pari passu upon completion of the merger, (ii) EPO would be able to maintain or refinance our Revolving Credit Facility borrowings, and (iii) the pro forma credit measures of EPO remain consistent with Fitch Ratings’ pre-merger estimates. We do not expect a change in our credit ratings if the proposed merger is consummated in accordance with the terms of the definitive merger agreements.

Recent Accounting Pronouncements

The accounting standard setting bodies have recently issued the following accounting guidance since those reported in our Annual Report on Form 10-K for the year ended December 31, 2008 that will or may affect our future financial statements:

§	FSP FAS 157-4 (ASC 820), Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly;

§	FSP FAS 107-1 and APB 28-1 (ASC 825), Interim Disclosures About Fair Value of Financial Instruments;

§	SFAS No. 165 (ASC 855), Subsequent Events;

§	SFAS No. 167 (ASC 810), Amendments to FASB Interpretation No. 46(R); and

§	SFAS No. 168 (ASC 105), The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162.

For additional information regarding recent accounting developments, see Note 2 in the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

Insurance Matters

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

characteristics. Substantially all of our derivatives are used for non-trading activities. See Note 4 in the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report for additional information regarding our derivative instruments and hedging activities.

Our exposures to market risk have not changed materially since those reported under Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2008.

Interest Rate Derivative Instruments

Commodity Derivative Instruments

We seek to maintain a position that is substantially balanced between crude oil purchases and related sales and future delivery obligations. The price of crude oil is subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risk associated with crude oil, we enter into commodity derivative instruments such as forwards, basis swaps and futures contracts. The purpose of such hedging strategy is to either balance our inventory position or to lock in a profit margin.

The following table shows the effect of hypothetical price movements on the estimated fair value (“FV”) of our portfolio at the dates indicated (dollars in millions):

		Portfolio Fair Value at
Scenario	Resulting Classification	June 30, 2009		July 21, 2009
FV assuming no change in underlying commodity prices	Asset (Liability)	$	0.4	$	(0.5	)
FV assuming 10% increase in underlying commodity prices	Asset (Liability)		0.4		(0.6	)
FV assuming 10% decrease in underlying commodity prices	Asset (Liability)		0.4		(0.3	)

Item 4. Controls and Procedures.

As of the end of the period covered by this Quarterly Report, our management carried out an evaluation, with the participation of our principal executive officer (the “CEO”) and our principal financial officer (the “CFO”), of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based on that evaluation, as of the end of the period covered by this Quarterly Report, the CEO and CFO concluded:

(i)

that our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure; and

(ii)	that our disclosure controls and procedures are effective at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

Other than as discussed under “TEPPCO Marine Services Transactions” below, there were no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities

Exchange Act of 1934) or in other factors during the second quarter of 2009, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

TEPPCO Marine Services Transactions

On February 1, 2008, we acquired transportation assets and certain intangible assets that comprised the marine transportation business of Cenac. On February 29, 2008, we purchased marine assets from Horizon, a privately-held Houston-based company and an affiliate of Mr. Cenac. These purchases were recorded using purchase accounting. In recording the TEPPCO Marine Services purchase transactions, we followed our normal accounting procedures and internal controls.

The Office of the Chief Accountant of the SEC has issued guidance regarding the reporting of internal control over financial reporting in connection with a material acquisition. This guidance was reiterated in September 2007 to affirm that management may omit an assessment of an acquired business’ internal control over financial reporting from management’s assessment of internal control over financial reporting for a period not to exceed one year. We excluded the operations acquired from Cenac and Horizon from the scope of our Sarbanes-Oxley Section 404 report on internal control over financial reporting for the year ended December 31, 2008. We expect to complete the implementation of our internal control structure over the operations we acquired from Cenac and Horizon in 2009.

The certifications of our General Partner’s CEO and CFO required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 have been included as exhibits to this Quarterly Report.

PART II. OTHER INFORMATION.

Item 1. Legal Proceedings.

For information on legal proceedings, see Part I, Item 1, Financial Statements, Note 15, “Commitments and Contingencies – Litigation,” in the Notes to Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report, which is incorporated into this item by reference.

Item 1A. Risk Factors.

Security holders and potential investors in our securities should carefully consider the risk factors set forth below and the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2008, in addition to other information in such report and in this Quarterly Report. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

Failure to complete the merger could negatively impact our Unit price and future business and financial results.

We cannot assure you that the merger with Enterprise Products Partners will be approved by our unitholders or that the other conditions to the completion of the merger will be satisfied. In addition, both we and Enterprise Products Partners have the right to terminate the merger agreement and pursue alternative transactions under certain conditions. If the merger is not completed, we will not receive any of the expected benefits of the merger and will be subject to risks and/or liabilities, including the following:

§	failure to complete the merger might be followed by a decline in the market price of our Units;

§	certain costs relating to the merger (such as legal, accounting and financial advisory fees) are payable by us whether or not the merger is completed; and

§	we would continue to face the risks that we currently face as a separate public company.

If the merger is not completed, these risks and liabilities may materially adversely affect our business, financial results, financial condition and Unit price.

Uncertainties associated with the merger may cause us to lose employees, customers and business partners. While the merger is pending, we are subject to restrictions on the conduct of our business.

Current and prospective employees who provide services to us may be uncertain about their future roles and relationships with us or EPCO and its affiliates following the completion of the merger. This uncertainty may adversely affect our ability to attract and retain key management and employees.

Our customers and business partners may not be as willing to continue business with us on the same or similar terms pending the completion of the merger, which would materially and adversely affect our business and results of operations. In addition, the merger agreement restricts us from taking specified actions without Enterprise Products Partners’ approval including, among other things, making certain significant acquisitions, dispositions or investments, making certain significant capital expenditures, and entering into certain material contracts. Our management may also be required to devote substantial time to merger-related activities, which could otherwise be devoted to pursuing other beneficial business opportunities.

Any delay in completing the merger and integrating the businesses may substantially reduce the benefits expected to be obtained from the merger.

In addition to obtaining the required regulatory clearances and approvals, the merger is subject to a number of other conditions beyond our control and the control Enterprise Products Partners that may prevent, delay or otherwise materially adversely affect its completion. We cannot predict whether or when the conditions to closing will be satisfied. Any delay in completing the merger and integrating the partnerships’ businesses may diminish the benefits that we expect to achieve in the merger.

Our prior interest in the TOPS partnership and dissociation from the partnership in April 2009 could subject us to various liabilities.

The TOPS partnership was expected to represent an important component of our business strategy, requiring an estimated $600.0 million in capital contributions from us through 2011. Effective April 16, 2009, we and a subsidiary of Enterprise Products Partners elected to dissociate, or exit, from TOPS. In dissociating from TOPS, we forfeited our investment and one-third ownership interest in the partnership. As a result, our equity earnings and net income for the second quarter of 2009 include a non-cash charge of $34.2 million.

The third partner, an affiliate of Oiltanking, has filed an original petition against Enterprise Offshore Port System, LLC, EPO, TEPPCO O/S Port System, LLC, us and our General Partner in the District Court of Harris County, Texas, 61st Judicial District (Cause No. 2009-31367), asserting, among other things, that the dissociation was wrongful and in breach of the TOPS partnership agreement, citing provisions of the agreement that, if applicable, would continue to obligate us and Enterprise Products Partners to make capital contributions to fund the project and impose liabilities on us. We have not recorded any reserves for potential liabilities relating to this matter, although we may determine in future periods that an accrual of reserves for potential liabilities (including costs of litigation) should be made.

If the merger agreement with Enterprise Products Partners is terminated and we were unable to obtain external financing to repay any borrowings under the Loan Agreement with EPO, we may suffer a default under a substantial majority of our outstanding indebtedness.

In order to supplement our liquidity position during the pendency of the proposed merger with Enterprise Products Partners, we entered into the Loan Agreement with EPO, which is a wholly-owned subsidiary of Enterprise Products Partners. We are not entitled to borrow under the Loan Agreement unless

there is no remaining availability for borrowing under our Revolving Credit Facility. In addition, borrowings under the Loan Agreement mature upon termination by either party of the merger agreement with Enterprise Products Partners, among other events. If we were to incur material indebtedness under the Loan Agreement that became due either because of termination of the merger agreement or otherwise, we would likely be required to seek additional bank financing to fund a repayment to EPO due to the likely unavailability of borrowing capacity under our Revolving Credit Facility and of timely access to the capital markets. Failure to satisfy timely the accelerated obligations under the Loan Agreement would constitute a default under the Loan Agreement, which would entitle EPO to declare unpaid amounts under the Loan Agreement immediately due and payable. Such a default would constitute an event of default under our Revolving Credit Facility and may constitute an event of default under our senior notes, which would allow for the acceleration of a substantial majority of our indebtedness.

Item 5. Other Information.

Loan Agreement with Enterprise Products Operating LLC

On August 5, 2009, we entered into a Loan Agreement with EPO under which EPO agreed to make an unsecured revolving loan to us in an aggregate maximum outstanding principal amount not to exceed $100.0 million. Borrowings under the Loan Agreement mature on the earliest to occur of (i) the consummation of our proposed merger with Enterprise Products Partners, (ii) the termination of the related merger agreement in accordance with the provisions thereof, (iii) December 31, 2009, (iv) the date upon which the maturity of the loan is otherwise accelerated upon an event of default, and (v) the date upon which EPO’s commitment to make the loan is terminated by us pursuant to the Loan Agreement. Borrowings under the Loan Agreement will bear interest at a floating rate equivalent to the one-month LIBOR Rate (as defined in the Loan Agreement) plus 2.00%. Interest is payable monthly.

The Loan Agreement provides that amounts borrowed are non-recourse to our General Partner and our limited partners. The Loan Agreement contains customary events of default, including (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to us; (iii) a change of control; or (iv) an event of default under our Revolving Credit Facility. Any amounts due by us under the Loan Agreement will be unconditionally and irrevocably guaranteed by each of our subsidiaries that guarantee our obligations under our Revolving Credit Facility. EPO’s obligation to fund any borrowings under the Loan Agreement is subject to specified conditions, including the condition that, on and as of the applicable date of funding, no additional amounts are available to us pursuant to our Revolving Credit Facility (either as borrowings or under any letters of credit). The ACG Committee reviewed and approved the Loan Agreement, such approval constituting “Special Approval” under the conflict of interest provisions of our Partnership Agreement. The execution of the Loan Agreement was also unanimously approved by the ACG Committee of EPGP.

The foregoing description of the Loan Agreement is qualified in its entirety by reference to the full and complete terms of the Loan Agreement, which is filed with this Quarterly Report as Exhibit 10.4.

Settlement Agreement

On August 5, 2009, the parties to the Merger Action and the Derivative Action described in Note 15 in the Notes to Unaudited Condensed Consolidated Financial Statements entered into a Stipulation and Agreement of Compromise, Settlement and Release (the “Settlement Agreement”) contemplated by the Memorandum of Understanding. Pursuant to the Settlement Agreement, the board of directors of our General Partner will recommend to our unitholders that they approve the adoption of the merger agreement governing our proposed merger with a subsidiary of Enterprise Products Partners and take all necessary steps to seek unitholder approval for the merger as soon as practicable. Pursuant to the Settlement Agreement, approval of the merger will require, in addition to votes required under our partnership agreement, that the actual votes cast in favor of the proposal by holders of our outstanding Units, excluding

those held by defendants to the Derivative Action, exceed the actual votes cast against the proposal by those holders. The Settlement Agreement further provides that the Derivative Action was considered by the Special Committee to be a significant benefit of ours for which fair value was obtained in the merger consideration.

The Settlement Agreement is subject to customary conditions, including Court of Chanery of the State of Delaware (the “Delaware Court”) approval. There can be no assurance that the Delaware Court will approve the settlement in the Settlement Agreement. In such event, the proposed settlement as contemplated by the Settlement Agreement may be terminated. See Note 13 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional information regarding our relationship with Enterprise Products Partners, including information related to the proposed merger. See Note 15 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional information related to the Merger Action and the Derivative Action, including the Settlement Agreement.

The foregoing description of the Settlement Agreement is qualified in its entirety by reference to the full and complete terms of the Settlement Agreement, which is filed with this Quarterly Report as Exhibit 10.3.

Termination of Transitional Operating Agreement; Entry into Consulting Agreement

Effective August 1, 2009, personnel providing services to us under the transitional operating agreement with Cenac Towing Co., L.L.C., Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr. became employees of EPCO, and the transitional operating agreement was terminated. Concurrently with the termination, TEPPCO Marine Services entered into a two-year consulting agreement with Mr. Cenac and Cenac Marine Services, L.L.C. under which Mr. Cenac has agreed to supervise TEPPCO Marine Services’ day-to-day operations on a part-time basis and, at TEPPCO Marine Services’ request, provide related management and transitional services. The agreement entitles Mr. Cenac to $500,000 per year in fees, plus a one-time retainer of $200,000. The consulting agreement contains noncompetition and nonsolitation provisions similar to those contained in the transitional operating agreement, which apply until the expiration of the two-year period following the date of last service provided under the consulting agreement.

The foregoing description of the consulting agreement is qualified in its entirety by reference to the full and complete terms of such agreement, which is filed with this Quarterly Report as Exhibit 10.6.

Borrowing under Revolving Credit Facility

For a description of the terms and conditions of our Revolving Credit Facility, as amended to date, please see Note 12 in the Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2008 (our “2008 10-K”), which description is incorporated herein by reference. The Revolving Credit Facility and the amendments and supplements thereto to date, are filed as Exhibits 10.42 through 10.49 to our 2008 10-K. For further discussion of our quarterly distribution payments, see Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report.

Item 6. Exhibits.

Exhibit Number	Exhibit
2.1	Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub B LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (Filed as Exhibit 2.1 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on June 29, 2009 and incorporated herein by reference).
2.2	Agreement and Plan of Merger, dated as of June 28, 2009 by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub A LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (Filed as Exhibit 2.2 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on June 29, 2009 and incorporated herein by reference).
3.1	Certificate of Limited Partnership of TEPPCO Partners, L.P. (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
3.2	Fourth Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated December 8, 2006 (Filed as Exhibit 3 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on December 13, 2006 and incorporated herein by reference).
3.3	First Amendment to Fourth Amended and Restated Partnership Agreement of TEPPCO Partners, L.P. dated as of December 27, 2007 (Filed as Exhibit 3.1 to Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed December 28, 2007 and incorporated herein by reference).
3.4	Amendment No. 2 to the Fourth Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated as of November 6, 2008 (Filed as Exhibit 3.5 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2008 and incorporated herein by reference).
3.5	Amended and Restated Limited Liability Company Agreement of Texas Eastern Products Pipeline Company, LLC (Filed as Exhibit 3 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on May 10, 2007 and incorporated herein by reference).
3.6	First Amendment to the Amended and Restated Limited Liability Company Agreement of Texas Eastern Products Pipeline Company, LLC, dated as of November 6, 2008 (Filed as Exhibit 3.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2008 and incorporated herein by reference).
4.1	Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.4 to the Form S-3 of TEPPCO Partners, L.P. filed on September 3, 2008 (Commission File No. 1-10403) and incorporated herein by reference).
4.2	Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
4.3	First Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
4.4	Second Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee (Filed as Exhibit

	4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
4.5	Third Supplemental Indenture among TEPPCO Partners, L.P. as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. as Subsidiary Guarantors, and Wachovia Bank, National Association, as trustee, dated as of January 30, 2003 (Filed as Exhibit 4.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
4.6	Full Release of Guarantee dated as of July 31, 2006 by Wachovia Bank, National Association, as trustee, in favor of Jonah Gas Gathering Company (Filed as Exhibit 4.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2006 and incorporated herein by reference).
4.7	Indenture, dated as of May 14, 2007, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as subsidiary guarantors, and The Bank of New York Trust Company, N.A., as trustee (Filed as Exhibit 99.1 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on May 15, 2007 and incorporated herein by reference).
4.8	First Supplemental Indenture, dated as of May 18, 2007, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as subsidiary guarantors, and The Bank of New York Trust Company, N.A., as trustee (Filed as Exhibit 4.2 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on May 18, 2007 and incorporated herein by reference).
4.9	Second Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. , Val Verde Gas Gathering Company, L.P., TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as subsidiary guarantors, and The Bank of New York Trust Company, N.A., as trustee (Filed as Exhibit 4.2 to the Current Report on Form 8-K of TE Products Pipeline Company, LLC (Commission File No. 1-13603) filed on July 6, 2007 and incorporated herein by reference).
4.10	Fourth Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Val Verde Gas Gathering Company, L.P., TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as subsidiary guarantors, and U.S. Bank National Association, as trustee (Filed as Exhibit 4.3 to the Current Report on Form 8-K of TE Products Pipeline Company, LLC (Commission File No. 1-13603) filed on July 6, 2007 and incorporated herein by reference).
4.11	Fifth Supplemental Indenture, dated as of March 27, 2008, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC, and Val Verde Gathering Company, L.P., as subsidiary guarantors, and U.S. Bank National Association, as trustee (Filed as Exhibit 4.11 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2008 and incorporated herein by reference).
4.12	Sixth Supplemental Indenture, dated as of March 27, 2008, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as subsidiary guarantors, and U.S. Bank National Association, as trustee (Filed as Exhibit 4.12 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2008 and incorporated herein by reference).
4.13	Seventh Supplemental Indenture, dated as of March 27, 2008, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as subsidiary guarantors, and U.S. Bank National Association, as trustee (Filed as Exhibit 4.13 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2008 and incorporated herein by reference).

4.14	Replacement of Capital Covenant, dated May 18, 2007, executed by TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P. in favor of the covered debt holders described therein (Filed as Exhibit 99.1 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on May 18, 2007 and incorporated herein by reference).
10.1*	Second Amendment to Transitional Operating Agreement between Cenac Towing Co., L.L.C., Cenac Offshore, L.L.C., CTCO Benefits Services, L.L.C., Mr. Arlen B. Cenac, Jr., and TEPPCO Marine Services, LLC, effective as of June 5, 2009.
10.2	Memorandum of Understanding, dated June 28, 2009 (Filed as Exhibit 10.1 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on June 29, 2009 and incorporated herein by reference).
10.3*	Stipulation and Agreement of Compromise, Settlement and Release, dated August 5, 2009.
10.4*	Loan Agreement, dated August 5, 2009, by and between Enterprise Products Operating, LLC, as Lender, and TEPPCO Partners, L.P., as Borrower.
10.5*	Termination of Transitional Operating Agreement between Cenac Towing Co., L.L.C., Cenac Offshore, L.L.C., CTCO Benefits Services, L.L.C., Mr. Arlen B. Cenac, Jr., and TEPPCO Marine Services, LLC, effective as of July 31, 2009.
10.6*	Consulting Agreement Between TEPPCO Marine Services, LLC and Cenac Marine Services, L.L.C., effective as of August 1, 2009.
12.1*	Statement of Computation of Ratio of Earnings to Fixed Charges.
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.
32.1**	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.

** Furnished herewith pursuant to Item 601(b)-(32) of Regulation S-K.

+ A management contract or compensation plan or arrangement.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

TEPPCO Partners, L.P.

Date: August 6, 2009	By: /s/ JERRY E. THOMPSON Jerry E. Thompson, President and Chief Executive Officer of Texas Eastern Products Pipeline Company, LLC, General Partner

Date: August 6, 2009	By: /s/ TRACY E. OHMART Tracy E. Ohmart, Acting Chief Financial Officer, Controller, Assistant Secretary and Assistant Treasurer of Texas Eastern Products Pipeline Company, LLC, General Partner