- Quarterly Report (10-Q)

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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 March 31, 2009

 

OR

 

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)
	[phone]
	(Registrant’s Telephone Number, Including Area Code)

 

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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 104,767,316 limited partner units of TEPPCO Partners, L.P. outstanding at May 1, 2009.  These limited partner units trade on the New York Stock Exchange under the ticker symbol “TPP.”

 

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Table of Contents

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	8
	4.  Derivative Instruments and Hedging Activities	11
	5.  Inventories	15
	6.  Property, Plant and Equipment	15
	7.  Investments in Unconsolidated Affiliates	16
	8.  Intangible Assets and Goodwill	17
	9. Debt Obligations	18
	10. Partners’ Capital and Distributions	19
	11. Business Segments	21
	12. Related Party Transactions	24
	13. Earnings Per Unit	27
	14. Commitments and Contingencies	28
	15. Supplemental Cash Flow Information	33
	16. Supplemental Condensed Consolidating Financial Information	33
	17. Subsequent Events	37
Item 2.	Management’s Discussion and Analysis of Financial Condition
	and Results of Operations.	39
	Cautionary Note Regarding Forward-Looking Statements.	39
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	57
Item 4.	Controls and Procedures.	58
PART II.  OTHER INFORMATION.
Item 1.	Legal Proceedings.	59
Item 1A.	Risk Factors.	59
Item 5.	Other Information.	60
Item 6.	Exhibits.	60
Signatures		62

 

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PART I.  FINANCIAL INFORMATION.

 

Item 1.   Financial Statements .

 

TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

 (Dollars in millions)

		March 31,				December 31,
ASSETS		2009				2008
Current assets:
Cash and cash equivalents		$	2.2			$	--
Accounts receivable, trade (net of allowance for doubtful accounts of
$2.6 at March 31, 2009 and December 31, 2008)			741.6				790.4
Accounts receivable, related parties			10.7				15.8
Inventories			52.6				52.9
Other			33.4				48.5
Total current assets			840.5				907.6
Property, plant and equipment, at cost (net of accumulated depreciation of
$703.8 at March 31, 2009 and $678.8 at December 31, 2008)			2,517.2				2,439.9
Investments in unconsolidated affiliates			1,244.8				1,255.9
Intangible assets (net of accumulated amortization of $165.1 at        March 31, 2009 and $158.3 at December 31, 2008)			202.3				207.7
Goodwill			106.6				106.6
Other assets			131.3				132.1
Total assets		$	5,042.7			$	5,049.8
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities		$	755.2			$	792.5
Accounts payable, related parties			20.6				17.2
Accrued interest			45.7				36.4
Other accrued taxes			18.0				23.0
Other			14.9				30.9
Total current liabilities			854.4				900.0
Long-term debt:
Senior notes			1,712.1				1,713.3
Junior subordinated notes			299.6				299.6
Other long-term debt			565.6				516.7
Total long-term debt			2,577.3				2,529.6
Other liabilities and deferred credits			28.5				28.7
Commitments and contingencies
Partners’ capital:
Limited partners’ interests:
Limited partner units (104,618,116 units outstanding at March 31, 2009         and 104,547,561 units outstanding at December 31, 2008)			1,737.7				1,746.2
Restricted limited partner units (149,200 units outstanding at March 31,         2009 and 157,300 units outstanding at December 31, 2008)			1.7				1.4
General partner’s interest			(112.5	)			(110.3	)
Accumulated other comprehensive loss			(44.4	)			(45.8	)
Total partners’ capital			1,582.5				1,591.5
Total liabilities and partners’ capital		$	5,042.7			$	5,049.8

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Dollars in millions, except per unit amounts)

 

		For the Three Months
		Ended March 31,
		2009				2008
Operating revenues:
Sales of petroleum products		$	1,277.9			$	2,644.6
Transportation – Refined products			35.9				37.3
Transportation – LPGs			38.3				36.2
Transportation – Crude oil			21.9				15.3
Transportation – NGLs			12.5				13.0
Transportation – Marine			36.9				25.5
Gathering – Natural gas			13.6				13.4
Other			20.6				23.2
Total operating revenues			1,457.6				2,808.5
Costs and expenses:
Purchases of petroleum products			1,235.5				2,606.6
Operating expense			66.8				53.8
Operating fuel and power			19.7				21.4
General and administrative			10.0				8.8
Depreciation and amortization			33.0				28.3
Taxes – other than income taxes			6.9				6.1
Total costs and expenses			1,371.9				2,725.0
Operating income			85.7				83.5
Other income (expense):
Interest expense			(32.1	)			(38.6	)
Equity in earnings of unconsolidated affiliates			25.1				19.7
Other, net			0.3				0.3
Income before provision for income taxes			79.0				64.9
Provision for income taxes			0.8				0.8
Net income		$	78.2			$	64.1
Net income allocation:
Limited partners’ interest in net income		$	65.0			$	53.4
General partner’s interest in net income		$	13.2			$	10.7
Earnings per unit, basic and diluted		$	0.62			$	0.57

 

 

 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME

(Dollars in millions)

 

		For the Three Months
		Ended March 31,
		2009				2008
Net income		$	78.2			$	64.1
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				--
Changes in fair values of commodity derivative instruments			--				(6.5	)
Reclassification adjustment for loss included in net income
related to commodity derivative instruments			--				9.6
Total cash flow hedges			1.4				(20.1	)
Total other comprehensive income (loss)			1.4				(20.1	)
Comprehensive income		$	79.6			$	44.0

 

 

 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in millions)

 

		For the Three Months
		Ended March 31,
		2009				2008
Operating activities:
Net income		$	78.2			$	64.1
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization			33.0				28.3
Amortization of deferred compensation			0.2				0.3
Amortization in interest expense			0.7				2.9
Changes in fair market value of derivative instruments			(0.6	)			(0.4	)
Equity in earnings of unconsolidated affiliates			(25.1	)			(19.7	)
Distributions received from unconsolidated affiliates			47.7				37.2
Loss on early extinguishment of debt			--				8.7
Net effect of changes in operating accounts (see Note 15)			22.5				(62.7	)
Net cash provided by operating activities			156.6				58.7
Investing activities:
Cash used for business combinations			--				(338.5	)
Investment in Jonah Gas Gathering Company			(12.3	)			(31.8	)
Investment in Texas Offshore Port System (see Notes 7 and 17)			1.7				--
Acquisition of intangible assets			(1.4	)			(0.3	)
Cash paid for linefill classified as other assets			--				(14.3	)
Capital expenditures			(101.6	)			(51.6	)
Net cash used in investing activities			(113.6	)			(436.5	)
Financing activities:
Borrowings under debt agreements			301.8				2,512.6
Repayments of debt			(252.8	)			(2,001.8	)
Net proceeds from issuance of limited partner units			1.6				2.7
Debt issuance costs			--				(8.7	)
Settlement of interest rate derivative instruments - treasury locks			--				(52.1	)
Distributions paid to partners			(91.4	)			(74.9	)
Net cash provided by (used in) financing activities			(40.8	)			377.8
Net change in cash and cash equivalents			2.2				--
Cash and cash equivalents, January 1			--				--
Cash and cash equivalents, March 31		$	2.2			$	--

 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED PARTNERS’ CAPITAL

(Dollars in millions)

 

		Limited				General
		Partners				Partner				AOCI				Total
Balance, December 31, 2008		$	1,747.6			$	(110.3	)		$	(45.8	)		$	1,591.5
Net proceeds from issuance of limited partner units			1.6				--				--				1.6
Net income			65.0				13.2				--				78.2
Distributions paid to partners			(76.0	)			(15.4	)			--				(91.4	)
Non-cash contributions			0.2				--				--				0.2
Amortization of equity awards			1.0				--				--				1.0
Reclassification adjustment for loss included in net
income related to interest rate derivative instruments			--				--				1.4				1.4
Balance, March 31, 2009		$	1,739.4			$	(112.5	)		$	(44.4	)		$	1,582.5

 

		Limited				General
		Partners				Partner				AOCI				Total
Balance, December 31, 2007		$	1,395.2			$	(88.0	)		$	(42.6	)		$	1,264.6
Net proceeds from issuance of limited partner units			2.7				--				--				2.7
Issuance of limited partner units in connection with         Cenac acquisition on February 1, 2008			186.6				--				--				186.6
Net income			53.4				10.7				--				64.1
Distributions paid to partners			(62.5	)			(12.4	)			--				(74.9	)
Non-cash contributions			0.1				--				--				0.1
Amortization of equity awards			0.2				--				--				0.2
Changes in fair values of commodity derivative         instruments			--				--				(6.5	)			(6.5	)
Reclassification adjustment for loss included in net         income related to commodity derivative instruments			--				--				9.6				9.6
Changes in fair values of interest rate derivative         instruments			--				--				(23.2	)			(23.2	)
Balance, March 31, 2008		$	1,575.7			$	(89.7	)		$	(62.7	)		$	1,423.3

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

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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.

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 and other heated oil products, 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 March 31, 2009, and the results of our operations and cash flows for the periods presented.  The results of operations for the three months ended March 31, 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 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.

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TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 2.  General Accounting Matters

Estimates

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

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 FAS 157-4, 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 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, 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 will adopt these FSPs effective July 1, 2009. We do not expect that this new guidance will have a material impact on our financial statements.

Note 3.  Accounting for Equity Awards

We account for equity awards in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 123(R), 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 our consolidated businesses was $1.0 million and $0.3 million for the three months ended March 31, 2009 and 2008, 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 consolidated 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 15,800 phantom units were outstanding under the 1999 Plan at March 31, 2009, as 2,800 additional phantom units outstanding at December 31, 2008 under the 1999 Plan were forfeited during the three months ended March 31, 2009.  The 15,800 outstanding phantom unit awards cliff vest as follows: 13,000 in April 2009 and

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TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

2,800 in January 2010.  At March 31, 2009 and December 31, 2008, we had accrued liability balances of $0.4 million 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 March 31, 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 March 31, 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 March 31, 2009, a total of 4,388,184 additional Units could be issued under the 2006 LTIP in the future.

Unit o ptions .   The following table presents unit option activity under the 2006 LTIP for the periods indicated:

										Weighted-
						Weighted-				Average
						Average				Remaining
		Number				Strike Price				Contractual
		of Units				(dollars/Unit)				Term (in years)
Unit Options:
Outstanding at December 31, 2008			355,000			$	40.00
Granted (1)			154,000			$	20.32
Forfeited			(47,000	)		$	40.30
Outstanding at March 31, 2009 (2)			462,000			$	33.41				4.80
(1)     The total grant date fair value of these awards granted on February 23, 2009 was $0.6 million based upon the following assumptions: (i) expected life of the option of 4.9 years; (ii) risk-free interest rate of 1.8%; (iii) expected distribution yield on Units of 12.93%; (iv) estimated forfeiture rate of 17%; and (v) expected unit price volatility on Units of 71.79%. (2)     No unit options were exercisable at March 31, 2009.

At March 31, 2009, the estimated total unrecognized compensation cost related to nonvested unit options granted under the 2006 LTIP was $1.1 million.  We expect to recognize this cost over a weighted average period of 3.43 years in accordance with the ASA.

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TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Restricted u nits .   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
Forfeited			(8,100	)		$	40.31
Restricted Units at March 31, 2009			149,200
(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 awards is determined before an allowance for forfeitures.

None of our restricted units vested during the three months ended March 31, 2009.  At March 31, 2009, the estimated total unrecognized compensation cost related to restricted units under the 2006 LTIP was $3.3 million. We expect to recognize this cost over a weighted average period of 2.55 years in accordance with the ASA.

Phantom units .  At March 31, 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.

UARs .   At March 31, 2009, a total of 401,608 UARs were outstanding, which have been awarded 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 March 31, 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 units discussed above), became interim executive chairman in March 2009.

§

Employees .  At March 31, 2009, a total of 305,954 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 March 31, 2009, there was an estimated $1.6 million and $1.3 million of unrecognized compensation cost related to TEPPCO Unit and TEPPCO Unit II, respectively.  We will recognize our share of these costs in accordance with the ASA over a weighted average period of 4.52 years.

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TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

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, 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.

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, 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 March 31, 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

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this loss in interest expense during the three months ended March 31, 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 March 31, 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 March 31, 2009:

		Accounting
Derivative Purpose	Volume (1)	Treatment
Derivatives not designated as hedging instruments under SFAS 133:
Crude oil risk management activities (2)	2.8 MMBbls	Mark-to-market
(1)     Volumes for derivatives not designated as hedging instruments reflect 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  June 2009.

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.

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

March 31, 2009

December 31, 2008

March 31, 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

$

1.8

Other current  assets

$

15.7

Other current liabilities

$

1.1

Other current liabilities

$

15.7

Total derivatives not

designated as hedging

instruments

$

1.8

$

15.7

$

1.1

$

15.7

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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			Gain/(Loss) Recognized in					Gain/(Loss) Recognized in
Fair Value			Income on Derivative					Income on Hedged Item
Hedging Relationships			Amount			Location		Amount			Location
			For the Three Months					For the Three Months
			Ended March 31,					Ended March 31,
			2009		2008			2009		2008
Interest rate derivatives		$	--		$                      --	Interest expense	$	--		$                        (1.0)	Interest expense
Total		$	--		$                      --		$	--		$                        (1.0)

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:

			Change in Value
Derivatives			Recognized in OCI on
in SFAS 133 Cash Flow			Derivative
Hedging Relationships			(Effective Portion)
			For the Three Months
			Ended March 31,
			2009		2008
Interest rate derivatives		$	--		$                        (23.2)
Commodity derivatives			--		(6.5)
Total		$	--		$                        (29.7)

			Amount of Gain/(Loss)
Derivatives	Location of Gain/(Loss)		Reclassified from AOCI
in SFAS 133 Cash Flow	Reclassified from AOCI		to Income
Hedging Relationships	into Income (Effective Portion)		(Effective Portion)
			For the Three Months
			Ended March 31,
			2009				2008
Interest rate derivatives	Interest expense		$	(1.4	)		$	--
Commodity derivatives	Revenue			--				(9.6	)
Total			$	(1.4	)		$	(9.6	)

	Location of Gain/(Loss)		Amount of Gain/(Loss)
Derivatives	Recognized in Income		Recognized in Income on
in SFAS 133 Cash Flow	on Ineffective Portion		Ineffective Portion of
Hedging Relationships	of Derivative		Derivative
			For the Three Months
			Ended March 31,
			2009				2008
Interest rate derivatives	Interest expense		$	--			$	(3.6	)
Commodity derivatives	Revenue			--				--
Total			$	--			$	(3.6	)

Over the next twelve months, we expect to reclassify $5.9 million of accumulated other comprehensive loss attributable to settled treasury locks to earnings as an increase to interest expense.

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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			Gain/(Loss) Recognized in
Designated as SFAS 133			Income on Derivative
Hedging Instruments			Amount			Location
			For the Three Months
			Ended March 31,
			2009		2008
Commodity derivatives		$	0.8		$               0.4	Revenue
Total		$	0.8		$               0.4

Credit-Risk Related Contingent Features in Derivative Instruments

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

SFAS 157 – Fair Value Measurements

SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date.  The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured on a recurring basis at March 31, 2009.  These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

 

		Level 2				Level 3				Total
Financial assets:
Commodity derivative instruments		$	1.4			$	0.4			$	1.8
Total		$	1.4			$	0.4			$	1.8
Financial liabilities:
Commodity derivative instruments		$	1.1			$	--			$	1.1
Total		$	1.1			$	--			$	1.1

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 Three Months
		Ended March 31,
		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			$	--

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.

 

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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:

		March 31,				December 31,
		2009				2008
Crude oil (1)		$	21.5			$	32.8
Refined products and LPGs (2)			10.2				0.4
Lubrication oils and specialty chemicals			11.2				11.1
Materials and supplies			9.1				8.6
NGLs			0.6				--
Total		$	52.6			$	52.9
(1)    At March 31, 2009 and December 31, 2008, $21.2 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 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 March 31, 2009 and 2008, we recognized LCM adjustments of approximately $1.0 million and less than $0.1 million, 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				March 31,				December 31,
		in Years				2009				2008
Plants and pipelines (1)			5-40(4)			$	1,926.9			$	1,919.7
Underground and other storage facilities (2)			5-40(5)				306.4				296.8
Transportation equipment (3)			5-10				11.9				11.3
Marine vessels			20-30				453.0				453.0
Land and right of way							143.9				143.8
Construction work in progress							378.9				294.1
Total property, plant and equipment						$	3,221.0			$	3,118.7
Less: accumulated depreciation							703.8				678.8
Property, plant and equipment, net						$	2,517.2			$	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)   The estimated useful lives of major components of this category are as follows: pipelines, 20-40 years (with some equipment at 5 years); terminal facilities, 10-40 years; office furniture and equipment, 5-10 years; buildings, 20-40 years; and laboratory and shop equipment, 5-40 years. (5)   The estimated useful lives of major components of this category are as follows: underground storage facilities, 20-40 years (with some components at 5 years); and storage tanks, 20-30 years.

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

 

		For the Three Months
		Ended March 31,
		2009			2008
Depreciation expense (1)		$             25.3			$          21.9
Capitalized interest (2)		5.3			4.4
(1)    Depreciation expense is a component of depreciation and amortization expense as presented in our statements of consolidated income. (2)   Capitalized interest (included in interest expense on our statements of consolidated income) increases the carrying value of the associated asset and reduces interest expense during the period it is recorded.

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 March 31, 2009 and December 31, 2008 was $1.5 million.  Accretion expense was less than $0.1 million for the three months ended March 31, 2009.  Property, plant and equipment at March 31, 2009 includes $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 below by reporting business segment (see Note 11 for a general discussion of our business segments).  The following table presents our investments in unconsolidated affiliates at the dates indicated:

 

		Ownership
		Percentage at
		March 31,				March 31,				December 31,
		2009				2009				2008
Downstream Segment:
Centennial Pipeline LLC (“Centennial”)			50.0%			$	70.2			$	71.8
Other			25.0%				0.4				0.4
Upstream Segment:
Seaway Crude Pipeline Company (“Seaway”)			50.0%				184.1				190.1
Texas Offshore Port System (1)			33.3%				34.2				35.9
Midstream Segment:
Jonah Gas Gathering Company (“Jonah”)			80.64%				955.9				957.7
Total						$	1,244.8			$	1,255.9
(1)    In January 2009, we received a $3.1 million refund of our 2008 contributions to Texas Offshore Port System 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 Texas Offshore Port System. See Note 17 for information regarding our dissociation with this partnership.

Our investments in Centennial, Seaway and Jonah included excess cost amounts totaling $73.1 million and $72.9 million at March 31, 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 in earnings of unconsolidated

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affiliates in a manner similar to depreciation over the life of applicable contracts or assets acquired or constructed.  Amortization of such excess cost amounts was $1.5 million and $1.1 million for the three months ended March 31, 2009 and 2008, respectively. For the remainder of 2009, amortization expense associated with our excess investments is currently estimated at $4.2 million.

 

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

 

		For the Three Months
		Ended March 31,
		2009			2008
Downstream Segment		$                (3.1)			$      (4.1)
Upstream Segment		3.3			3.0
Midstream Segment		25.6			23.7
Intersegment eliminations		(0.7)			(2.9)
Total		$                 25.1			$      19.7

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 first 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 below (on a 100% basis):

 

		Summarized Income Statement Information For the Three Months Ended
		March 31, 2009												March 31, 2008
						Operating				Net								Operating				Net
		Revenues				Income				Income (Loss)				Revenues				Income				Income (Loss)
Downstream Segment		$	9.7			$	2.2			$	(0.5	)		$	9.6			$	0.9			$	(1.8	)
Upstream Segment			19.7				8.7				8.7				20.6				10.4				10.4
Midstream Segment			59.4				31.9				32.0				58.2				29.3				29.4

Note 8.  Intangible Assets and Goodwill

Intangible Assets

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

 

		March 31, 2009												December 31, 2008
		Gross				Accum.				Carrying				Gross				Accum.				Carrying
		Value				Amort.				Value				Value				Amort.				Value
Downstream Segment		$	8.0			$	(1.3	)		$	6.7			$	6.6			$	(1.2	)		$	5.4
Upstream Segment			11.5				(3.5	)			8.0				11.5				(3.4	)			8.1
Midstream Segment			277.9				(150.8	)			127.1				277.9				(146.3	)			131.6
Marine Services Segment			70.0				(9.5	)			60.5				70.0				(7.4	)			62.6
Total		$	367.4			$	(165.1	)		$	202.3			$	366.0			$	(158.3	)		$	207.7

 

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

 

		For the Three Months
		Ended March 31,
		2009				2008
Downstream Segment		$	0.1			$	0.1
Upstream Segment			0.1				0.1
Midstream Segment			4.5				5.0
Marine Services Segment			2.1				1.2
Total		$	6.8			$	6.4

For the remainder of 2009, amortization expense associated with our intangible assets is currently estimated at $19.7 million.

Goodwill

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

 

		March 31,				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 9.  Debt Obligations

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

 

		March 31,				December 31,
		2009				2008
Senior debt obligations: (1)
Revolving Credit Facility, due December 2012 (2)		$	565.6			$	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			2,265.6				2,216.7
7.000% Junior Subordinated Notes, due June 2067 (1)			300.0				300.0
Total principal amount of long-term debt obligations			2,565.6				2,516.7
Adjustment to carrying value associated with hedges of fair value and
unamortized discounts (3)			11.7				12.9
Total long-term debt obligations			2,577.3				2,529.6
Total Debt Instruments (3)		$	2,577.3			$	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 March 31, 2009 was 1.13%. (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 March 31, 2009 and December 31, 2008, amount includes $5.1 million and $5.2 million of unamortized discounts, respectively, and $16.8 million and $18.1 million, respectively, related to fair value hedges.

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E xcept 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.  Assuming that future fundings are not received for the Lehman percentage commitment, aggregate available capacity would be reduced by approximately $28.9 million.  At March 31, 2009, our available borrowing capacity under the Revolving Credit Facility was approximately $355.5 million.

Covenants

We were in compliance with the covenants of our long-term debt obligations at March 31, 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 March 31, 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%			$	127.4			$	7.4			$	9.1			$	9.0			$	8.9			$	8.6			$	84.4

At March 31, 2009 and December 31, 2008, Centennial’s debt obligations consisted of $127.4 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 14).

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 10.  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.  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 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,

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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 481,281 Units have been issued under this registration statement from inception of the DRIP through March 31, 2009.

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 35,111 Units have been issued to employees under this plan from inception of the EUPP through March 31, 2009.

During the three months ended March 31, 2009, a total of 70,555 Units were issued in connection with the DRIP and the EUPP.  Total net proceeds received during the three months ended March 31, 2009 from these Unit offerings was $1.6 million.

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.

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

		For the Three Months Ended March 31,
		2009				2008
Limited Partner Units		$	76.0			$	62.5
General Partner Ownership Interest			1.5				1.3
General Partner Incentive			13.9				11.1
Total Cash Distributions Paid		$	91.4			$	74.9
Total Cash Distributions Paid Per Unit		$	0.725			$	0.695

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

		Distribution			Record		Payment
		per Unit			Date		Date
1st Quarter 2009 (1)		$	0.725		Apr. 30, 2009	May 7, 2009
(1)   The first quarter 2009 cash distribution totaled approximately $91.4 million.

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S ummary of Changes in Outstanding Units

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

		Limited
		Partner				Restricted
		Units				Units				Total
Balance, December 31, 2008			104,547,561				157,300				104,704,861
Units issued in connection with DRIP			63,048				--				63,048
Units issued in connection with EUPP			7,507				--				7,507
Forfeiture of restricted units			--				(8,100	)			(8,100	)
Balance, March 31, 2009			104,618,116				149,200				104,767,316

General Partner’s Interest

At March 31, 2009 and December 31, 2008, we had deficit balances of $112.5 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 Income (Loss)

Our accumulated other comprehensive loss balance consisted of losses of $44.4 million and $45.8 million related to interest rate and treasury lock derivative instruments at March 31, 2009 and December 31, 2008, respectively.

Note 11.  Business Segments

We have four reporting segments:

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

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

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

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

 

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

		For the Three Months
		Ended March 31,
		2009			2008
Total operating revenues		$              1,457.6			$            2,808.5
Less: Total costs and expenses		1,371.9			2,725.0
Operating income		85.7			83.5
Add: Equity in earnings of unconsolidated affiliates		25.1			19.7
Other, net		0.3			0.3
Earnings before interest expense and provision for income taxes		$                 111.1			$              103.5

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
		Ended March 31,
		2009				2008
Earnings before interest expense and provision for income taxes		$	111.1			$	103.5
Interest expense			(32.1	)			(38.6	)
Income before provision for income taxes			79.0				64.9
Provision for income taxes			0.8				0.8
Net income		$	78.2			$	64.1

The amounts indicated below 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 below 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).

 

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The table below 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 March 31, 2009		$	76.6			$	1,296.1			$	25.2			$	36.9			$	--			$	1,434.8
Three months ended March 31, 2008			94.5				2,655.1				26.6				25.5				--				2,801.7
Revenues from related parties:
Three months ended March 31, 2009			18.9				0.1				3.8				--				--				22.8
Three months ended March 31, 2008			3.1				0.2				3.5				--				(0.1	)			6.7
Total revenues:
Three months ended March 31, 2009			95.5				1,296.2				29.0				36.9				--				1,457.6
Three months ended March 31, 2008			97.7				2,655.3				30.1				25.5				(0.1	)			2,808.5
Depreciation and amortization:
Three months ended March 31, 2009			11.5				5.6				9.5				6.4				--				33.0
Three months ended March 31, 2008			10.2				4.8				9.6				3.7				--				28.3
Operating income:
Three months ended March 31, 2009			34.4				40.9				4.5				5.2				0.7				85.7
Three months ended March 31, 2008			36.3				29.3				8.4				6.6				2.9				83.5
Equity in earnings (losses) of unconsolidated   affiliates:
Three months ended March 31, 2009			(3.1	)			3.3				25.6				--				(0.7	)			25.1
Three months ended March 31, 2008			(4.1	)			3.0				23.7				--				(2.9	)			19.7
Earnings before interest expense and provision
for income taxes:
Three months ended March 31, 2009			31.6				44.2				30.1				5.2				--				111.1
Three months ended March 31, 2008			32.4				32.3				32.2				6.6				--				103.5
Capital expenditures:
Three months ended March 31, 2009			78.1				11.4				4.2				7.2				0.7				101.6
Year ended December 31, 2008			209.8				33.4				5.2				43.6				8.5				300.5
Segment assets:
At March 31, 2009			1,387.9				1,482.1				1,536.0				647.9				(11.2	)			5,042.7
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 March 31, 2009			61.8				218.3				955.9				--				8.8				1,244.8
At December 31, 2008			63.2				226.0				957.7				--				9.0				1,255.9
Intangible assets, net:
At March 31, 2009			6.7				8.0				127.1				60.5				--				202.3
At December 31, 2008			5.4				8.1				131.6				62.6				--				207.7
Goodwill:
At March 31, 2009			1.3				14.9				--				90.4				--				106.6
At December 31, 2008			1.3				14.9				--				90.4				--				106.6

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Note 12.  Related Party Transactions

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

		For the Three Months
		Ended March 31,
		2009				2008
Revenues from EPCO and affiliates:
Sales of petroleum products (1)		$	0.1			$	0.6
Transportation – NGLs (2)			3.8				3.4
Transportation – LPGs (3)			4.9				2.3
Other operating revenues (4)			14.0				0.4
Related party revenues		$	22.8			$	6.7
Costs and Expenses from EPCO and affiliates:
Purchases of petroleum products (5)		$	26.7			$	19.7
Operating expense (6)			28.6				26.1
General and administrative (7)			8.1				8.5
Costs and Expenses from unconsolidated affiliates:
Purchases of petroleum products (8)			(0.7	)			1.6
Operating expense (9)			1.6				2.3
Costs and Expenses from Cenac and affiliates:
Operating expense (10)			13.4				7.4
General and administrative (11)			1.1				0.5
Related party costs and expenses		$	78.8			$	66.1
(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 $20.6 million and $15.6 million for the three months ended March 31, 2009 and 2008, respectively, from Enterprise Products Partners and certain of its subsidiaries. (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 March 31, 2009 and 2008, respectively, of $3.2 million and $2.9 million, related to premiums paid by EPCO on our behalf. 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)   I ncludes 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. and Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr., the sole owner of Cenac Towing Co., Inc. and Cenac Offshore, L.L.C. (collectively, “Cenac”) pursuant to which, our fleet of acquired tow boats and tank barges (including those acquired from Horizon Maritime, L.L.C. (“Horizon”)) are operated by employees of Cenac for a period of up to two years following the acquisition. (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 related party balances at the dates indicated:

		March 31,				December 31,
		2009				2008
Accounts receivable, related parties (1)		$	10.7			$	15.8
Accounts payable, related parties (2)			20.6				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 $3.9 million related to operational related charges from Cenac.

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

Relationship with EPCO and affiliates

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

§	EPCO and its privately-held subsidiaries;

§	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;

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

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

See Note 17 for information regarding our dissociation and that of Enterprise Offshore Port System, LLC from the Texas Offshore Port System partnership in April 2009.

In April 2009, we announced a proposal made by Enterprise Products Partners in March 2009 to acquire all of our outstanding partnership interests.  See Note 17 for further information regarding this subsequent event.

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 subsidiaries and affiliates depend on the cash distributions they receive from our General Partner and other investments to fund their operations and to

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meet their debt obligations.  We paid cash distributions to our General Partner of $15.4 million and $12.4 million during the three months ended March 31, 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 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.

EPCO Administrative Services Agreement . 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.

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 March 31, 2009, we have reimbursed Enterprise Products Partners $308.5 million ($2.0 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 March 31, 2009 and December 31, 2008, we had payables to Enterprise Products Partners for costs incurred of $0.2 million and $1.0 million, respectively.  At March 31, 2009 and December 31, 2008, we had receivables from Jonah of $8.4 million and $4.7 million, respectively, for operating expenses.  During the three months ended March 31, 2009 and 2008, we received distributions from Jonah of $38.9 million and $37.2 million, respectively.  During the three months ended March 31, 2009 and 2008, Jonah paid distributions of $9.3 million and $8.9 million, respectively, 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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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 our consolidated businesses.

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 12 for a description of ongoing transactions involving our Jonah joint venture with Enterprise Products Partners.

Note 13.  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
		Ended March 31,
		2009			2008
Net income attributable to TEPPCO Partners, L.P.		$                   78.2			$                   64.1
Distributions Declared During Quarter:
Distributions to General Partner (including incentive distributions)		$                   15.4			$                   13.6
Distributions to limited partners		76.0			67.3
Total distributions declared during quarter		$                   91.4			$                   80.9
Excess of distributions over net income		$                (13.2)			$                (16.8)
General Partner’s interest in net income		16.93%			16.74%
Earnings allocation adjustment to General Partner under EITF 07-4 (1)		$                  (2.2)			$                  (2.9)
Distributions to General Partner (including incentive distributions)		$                   15.4			$                  13.6
Earnings allocation adjustment to General Partner under EITF 07-4		(2.2)			(2.9)
Net income available to our General Partner		$                   13.2			$                  10.7
(1)    For purposes of computing basic and diluted earnings per Unit, we used the provisions of EITF 07-4, 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 10).

 

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

		For the Three Months
		Ended March 31,
		2009				2008
BASIC EARNINGS PER UNIT:
Numerator:
Limited partners’ interest in net income		$	65.0			$	53.4
Denominator:
Weighted average Units			104.6				93.1
Weighted average time-vested restricted units			0.1				0.1
Total			104.7				93.2
Basic earnings per Unit:
Net income attributable to TEPPCO Partners, L.P.		$	0.75			$	0.69
General Partner’s interest in net income			(0.13	)			(0.12	)
Limited partners’ interest in net income		$	0.62			$	0.57
DILUTED EARNINGS PER UNIT:
Numerator:
Limited partners’ interest in net income		$	65.0			$	53.4
Denominator:
Weighted average Units			104.6				93.1
Weighted average time-vested restricted units			0.1				0.1
Weighted average incremental option units			*				--
Total			104.7				93.2
Diluted earnings per Unit:
Net income attributable to TEPPCO Partners, L.P.		$	0.75			$	0.69
General Partner’s interest in net income			(0.13	)			(0.12	)
Limited partners’ interest in net income		$	0.62			$	0.57
*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 March 31, 2009 and 2008, we had outstanding 104,767,316 and 94,839,660 Units, respectively.

Note 14.  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.

On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of the State of Delaware, 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

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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 the 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 the sale by us to an Enterprise Products Partners’ affiliate of the Pioneer plant in March 2006.  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 Court of Chancery dismissed Mr. Brinckerhoff’s individual and putative class action claims with respect to the amendments to our partnership agreement.  Pre-trial discovery in this proceeding is underway.  Although we believe there are valid defenses to the claims and we will defend ourselves vigorously, this lawsuit is at an early stage, and in view of the inherent risks and unpredictability of litigation, no assurance can be given as to the outcome of this litigation.  

In October 2005, Williams Gas Processing, n/k/a Williams Field Services Company, LLC (“Williams”) notified Jonah that the gas delivered to Williams’ Opal Gas Processing Plant (“Opal Plant”) allegedly failed to conform to quality specifications of the Interconnect and Operator Balancing Agreement (“Interconnect Agreement”) which has allegedly caused damages to the Opal Plant in excess of $28.0 million.  On July 24, 2007, Jonah filed suit against Williams in Harris County, Texas seeking a declaratory order that Jonah was not liable to Williams.  In addition, on August 24, 2007, Williams filed a complaint in the 3rd Judicial District Court of Lincoln County, Wyoming alleging that Jonah was delivering non-conforming gas from its gathering customers in the Jonah system to the Opal Plant, in violation of the Interconnect Agreement.  Jonah denies any liability to Williams.  Discovery is ongoing.

See Note 17 for a subsequent event regarding new litigation involving us and Enterprise Products Partners.

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

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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 March 31, 2009 and December 31, 2008, our accrued liabilities for environmental remediation projects totaled $6.9 million.

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 March 31, 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

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million civil penalty.  We responded on June 30, 2005 by admitting certain of the alleged violations, contesting others and requesting a reduction in the proposed civil penalty.  We do not expect any settlement, fine or penalty to have a material adverse effect on our financial position, results of operations or cash flows.

The  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.

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 $4.5 million and $5.4 million during the three months ended March 31, 2009 and 2008, 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.

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Due to our exit from the Texas Offshore Port System partnership, our capital expenditure commitments decreased by an estimated $68.0 million.  See Note 17 for additional information regarding this subsequent event.

Other

Guarantees .   At March 31, 2009 and December 31, 2008, Centennial’s debt obligations consisted of $127.4 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 $63.7 million each at March 31, 2009.  At March 31, 2009, we have a liability of $8.8 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 March 31, 2009, TE Products has a liability of $3.8 million, which is based upon the expected present value of amounts we would have to pay under the guarantee.  If a catastrophic event were to occur and we were required to contribute cash to Centennial, such contributions might be covered by our insurance (net of deductible), depending upon the nature of the catastrophic event.

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 March 31, 2009, we have spent approximately $220.0 million on this construction project.  Under the terms of the agreement, if Motiva cancels the agreement prior to the commencement date of the project, Motiva will reimburse us the actual reasonable expenses we have incurred after the effective date of the agreement, including both internal and external costs that would be capitalized as a part of the project, plus a ten percent cancellation fee.

Texas Offshore Port System .   We, through a subsidiary, owned a one-third interest in the Texas Offshore Port System partnership 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 17), our obligations under this commitment terminated.

 

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Note 15.  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 Three Months
		Ended March 31,
		2009				2008
Decrease (increase) in:
Accounts receivable, trade		$	48.7			$	(189.2	)
Accounts receivable, related parties			5.9				1.5
Inventories			0.3				(7.2	)
Other current assets			1.1				(2.8	)
Other			0.3				(4.3	)
Increase (decrease) in:
Accounts payable and accrued liabilities			(28.9	)			157.7
Accounts payable, related parties			3.5				(6.9	)
Other			(8.4	)			(11.5	)
Net effect of changes in operating accounts		$	22.5			$	(62.7	)
Non-cash investing activities:
Payable to Enterprise Gas Processing, LLC for spending for       Phase V expansion of Jonah Gas Gathering Company		$	0.2			$	7.4
Liabilities for construction work in progress		$	18.2			$	16.6
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)		$	22.1			$	47.4

Note 16.  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.

 

 

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		March 31, 2009
		TEPPCO Partners, L.P.				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				TEPPCO Partners, L.P. Consolidated
Assets
Current assets		$	15.6			$	78.8			$	1,171.0			$	(424.9	)		$	840.5
Property, plant and equipment – net			13.6				1,360.9				1,142.7				--				2,517.2
Investments in unconsolidated affiliates			8.8				1,017.7				218.3				--				1,244.8
Investments in consolidated affiliates			1,673.0				441.6				--				(2,114.6	)			--
Goodwill			--				--				106.6				--				106.6
Intercompany notes receivable			2,789.1				--				--				(2,789.1	)			--
Intangible assets			--				115.3				87.0				--				202.3
Other assets			13.9				33.2				84.2				--				131.3
Total assets		$	4,514.0			$	3,047.5			$	2,809.8			$	(5,328.6	)		$	5,042.7
Liabilities and partners’ capital
Current liabilities		$	345.6			$	149.6			$	784.1			$	(424.9	)		$	854.4
Long-term debt			2,577.3				--				--				--				2,577.3
Intercompany notes payable			--				1,503.6				1,285.5				(2,789.1	)			--
Other long-term liabilities			8.6				16.9				3.0				--				28.5
Total partners’ capital			1,582.5				1,377.4				737.2				(2,114.6	)			1,582.5
Total liabilities and partners’ capital		$	4,514.0			$	3,047.5			$	2,809.8			$	(5,328.6	)		$	5,042.7

		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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		For the Three Months Ended March 31, 2009
		TEPPCO Partners, L.P.				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				TEPPCO Partners, L.P. Consolidated
Operating revenues		$	--			$	100.7			$	1,356.9			$	--			$	1,457.6
Costs and expenses			--				68.0				1,304.6				(0.7	)			1,371.9
Operating income			--				32.7				52.3				0.7				85.7
Interest expense			--				(20.3	)			(11.8	)			--				(32.1	)
Equity in earnings of unconsolidated affiliates			78.2				65.4				3.3				(121.8	)			25.1
Other, net			--				0.3				--				--				0.3
Income before provision for income taxes			78.2				78.1				43.8				(121.1	)			79.0
Provision for income taxes			--				0.3				0.5				--				0.8
Net income		$	78.2			$	77.8			$	43.3			$	(121.1	)		$	78.2

		For the Three Months Ended March 31, 2008
		TEPPCO Partners, L.P.				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				TEPPCO Partners, L.P. Consolidated
Operating revenues		$	--			$	102.9			$	2,705.6			$	--			$	2,808.5
Costs and expenses			--				67.9				2,660.0				(2.9	)			2,725.0
Operating income			--				35.0				45.6				2.9				83.5
Interest expense			--				(26.8	)			(11.8	)			--				(38.6	)
Equity in earnings of unconsolidated affiliates			64.1				53.0				3.0				(100.4	)			19.7
Other, net			--				0.3				--				--				0.3
Income before provision for income taxes			64.1				61.5				36.8				(97.5	)			64.9
Provision for income taxes			--				0.2				0.6				--				0.8
Net income		$	64.1			$	61.3			$	36.2			$	(97.5	)		$	64.1

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		For the Three Months Ended March 31, 2009
		TEPPCO Partners, L.P.				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				TEPPCO Partners, L.P. Consolidated
Operating activities:
Net income		$	78.2			$	77.8			$	43.3			$	(121.1	)		$	78.2
Adjustments to reconcile net income to net cash
from operating activities:
Depreciation and amortization			--				17.8				15.2				--				33.0
Equity in earnings of unconsolidated     affiliates			--				(22.5	)			(3.3	)			0.7				(25.1	)
Distributions received from unconsolidated     affiliates			--				38.9				8.8				--				47.7
Other, net			7.8				(24.9	)			(88.0	)			127.9				22.8
Net cash from operating activities			86.0				87.1				(24.0	)			7.5				156.6
Cash flows from investing activities:
Investment in Jonah			--				(12.3	)			--				--				(12.3	)
Investment in Texas Offshore Port System			--				--				1.7				--				1.7
Capital expenditures			--				(77.0	)			(24.6	)			--				(101.6	)
Other, net			--				(1.4	)			--				--				(1.4	)
Net cash flows from investing activities			--				(90.7	)			(22.9	)			--				(113.6	)
Cash flows from financing activities:
Borrowings under debt agreements			301.8				--				--				--				301.8
Repayments of debt			(252.8	)			--				--				--				(252.8	)
Net proceeds from issuance of limited partner     units			--				--				--				1.6				1.6
Intercompany debt activities			(48.9	)			76.7				83.4				(111.2	)			--
Distributions paid to partners			(91.4	)			(73.1	)			(36.5	)			109.6				(91.4	)
Net cash flows from financing activities			(91.3	)			3.6				46.9				--				(40.8	)
Net change in cash and cash equivalents			(5.3	)			--				--				7.5				2.2
Cash and cash equivalents, January 1			16.1				--				--				(16.1	)			--
Cash and cash equivalents, March 31		$	10.8			$	--			$	--			$	(8.6	)		$	2.2

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		For the Three Months Ended March 31, 2008
		TEPPCO Partners, L.P.				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				TEPPCO Partners, L.P. Consolidated
Operating activities:
Net income		$	64.1			$	61.3			$	36.2			$	(97.5	)		$	64.1
Adjustments to reconcile net income to net cash
from operating activities:
Depreciation and amortization			--				16.9				11.4				--				28.3
Equity in earnings of unconsolidated     affiliates			--				(19.6	)			(3.0	)			2.9				(19.7	)
Distributions received from unconsolidated     affiliates			--				37.2				--				--				37.2
Other, net			66.1				83.0				(188.6	)			(11.7	)			(51.2	)
Net cash from operating activities			130.2				178.8				(144.0	)			(106.3	)			58.7
Cash flows from investing activities:
Cash used for business combinations			--				--				(338.5	)			--				(338.5	)
Investment in Jonah			--				(31.8	)			--				--				(31.8	)
Capital expenditures			--				(42.4	)			(9.2	)			--				(51.6	)
Other, net			--				(0.3	)			(14.3	)			--				(14.6	)
Net cash flows from investing activities			--				(74.5	)			(362.0	)			--				(436.5	)
Cash flows from financing activities:
Borrowings under debt agreements			2,512.6				--				--				--				2,512.6
Repayments of debt			(1,577.1	)			(361.6	)			(63.1	)			--				(2,001.8	)
Net proceeds from issuance of limited partner     units			2.7				--				--				--				2.7
Debt issuance costs			(8.7	)			--				--				--				(8.7	)
Settlement of interest rate derivative     instruments – treasury locks			(52.1	)			--				--				--				(52.1	)
Intercompany debt activities			(935.5	)			332.2				596.0				7.3				--
Distributions paid to partners			(74.9	)			(74.9	)			(26.9	)			101.8				(74.9	)
Net cash flows from financing activities			(133.0	)			(104.3	)			506.0				109.1				377.8
Net change in cash and cash equivalents			(2.8	)			--				--				2.8				--
Cash and cash equivalents, January 1			8.2				--				--				(8.2	)			--
Cash and cash equivalents, March 31		$	5.4			$	--			$	--			$	(5.4	)		$	--

Note 17.  Subsequent Events

TEPPCO Exits Texas Offshore Port System Partnership

On April 21, 2009, we announced that, effective April 16, 2009, our affiliate elected to dissociate, or exit from, the Texas Offshore Port System partnership and forfeit our investment and one-third ownership interest in the partnership.  An affiliate of Enterprise Products Partners also elected to dissociate from the Texas Offshore Port System partnership at the same time.  As a result, we expect to record a non-cash charge of approximately $34.2 million against our earnings for the second quarter of 2009.  The decision to dissociate from the Texas Offshore Port System partnership was in connection with a disagreement with one of our partners, an affiliate of Oiltanking Holding Americas, Inc. (“Oiltanking”).  The total cost of the project had been estimated at $1.8 billion.

In a response to the notices of dissociation, Oiltanking has alleged that the dissociation of our affiliate and Enterprise Products Partners’ affiliate were wrongful and in breach of the Texas Offshore Port System partnership agreement.  We believe that our actions in dissociating from the partnership are

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permitted by, and in accordance with, the terms of the Texas Offshore Port System partnership agreement and, should the need arise, we intend to vigorously defend such actions.

 

Discussions with Enterprise Products Partners Regarding Potential Combinations

  and Related Matters

On April 29, 2009, we announced that we received a proposal on March 9, 2009 from Enterprise Products Partners to acquire all of our outstanding partnership interests (the “Proposed Merger”).  The proposed consideration for our Units consisted of 1.043 Enterprise Products Partners common units and $1.00 in cash for each of our Units.  In order to evaluate the Proposed Merger, our ACG Committee formed a special committee consisting of Donald H. Daigle, Irvin Toole, Jr. and Duke R. Ligon (the “Special Committee”).  After considering Enterprise Products Partners’ proposal with the assistance of its financial and legal advisors, the Special Committee unanimously concluded that it did not support the proposal and advised Enterprise Products Partners of its decision.  The Special Committee informed Enterprise Products Partners that it remained willing to consider a revised proposal.

 

Our general partner and the general partner of Enterprise Products Partners are owned by Enterprise GP Holdings, which also owns approximately 4.2% and 3.0%, respectively, of the outstanding limited partner units of us and Enterprise Products Partners.

 

We do not intend to comment further on discussions with Enterprise Products Partners unless and until a definitive agreement is reached and we give no assurance that any such agreement will be executed or that any transaction will be approved or consummated.

 

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 Court of Chancery of New Castle County in the State of Delaware, as putative class actions on behalf of other unitholders of TEPPCO, concerning the Proposed Merger.  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 complaints allege, among other things, that the terms of the Proposed Merger 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, without consideration and without adequate information having been provided to our unitholders to cast a vote with respect to the Proposed Merger, a separate derivative action that previously had been filed in September 2006 by Mr. Brinckerhoff concerning proposals made in our Proxy Statement and other transactions involving us and Enterprise Products Partners or its affiliates.  See Note 14 for additional information regarding this proceeding.  The complaints further allege that the process through which a 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 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 defendants to account to plaintiffs and the purported class for all damages suffered or to be suffered by them as a result of defendants’ alleged wrongful conduct; and (iv) awarding plaintiffs costs of the actions, including fees and expenses of their attorneys and experts.

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

For the three months ended March 31, 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.

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
	MMBbls	= 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

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II, Item 1A of 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, liquefied petroleum gases (“LPGs”) and natural gas liquids (“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 refined products, crude oil, asphalt, condensate, heavy fuel oil and other heated oil products via tow boats and tank barges. 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 refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges (“Marine Services Segment”).

Our reportable segments offer different products and services and are managed separately because each requires different business strategies.  We operate through TE Products, TCTM and TEPPCO Midstream, and beginning February 1, 2008, through TEPPCO Marine Services.  Texas Eastern Products Pipeline Company, LLC, a Delaware limited liability company, serves as our general partner and owns a

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2% general partner interest in us.  We refer to refined products, LPGs, petrochemicals, crude oil, lubrication oils and specialty chemicals, NGLs, natural gas, asphalt, heavy fuel oil and other heated oil products in this Quarterly Report, collectively, as “ petroleum products ” or “ products .”

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.

Discussions with Enterprise Products Partners Regarding Potential Combination

  and Related Matters

On April 29, 2009, we announced that we received a proposal on March 9, 2009 from Enterprise Products Partners to acquire all of our outstanding partnership interests (the “Proposed Merger”).  The proposed consideration for our Units consisted of 1.043 Enterprise Products Partners common units and $1.00 in cash for each of our Units.  In order to evaluate the Proposed Merger, our ACG Committee formed a special committee consisting of Donald H. Daigle, Irvin Toole, Jr. and Duke R. Ligon (the “Special Committee”).  After considering Enterprise Products Partners’ proposal with the assistance of its financial and legal advisors, the Special Committee unanimously concluded that it did not support the proposal and advised Enterprise Products Partners of its decision.  The Special Committee informed Enterprise Products Partners that it remained willing to consider a revised proposal.

 

The general partners of both us and Enterprise Products Partners are owned by Enterprise GP Holdings, which also owns approximately 4.2% and 3.0%, respectively, of the outstanding limited partner units of us and Enterprise Products Partners.

 

We do not intend to comment further on discussions with Enterprise Products Partners unless and until a definitive agreement is reached and we give no assurance that any such agreement will be executed or that any transaction will be approved or consummated.

 

For information regarding lawsuits filed in connection with the Proposed Merger, please see Part II, Item 1 – Legal Proceedings in this Quarterly Report.

TEPPCO Exits Texas Offshore Port System Partnership

In April 2009, we announced that our affiliate elected to dissociate, or exit from, the Texas Offshore Port System partnership and forfeit our investment and one-third ownership interest in the partnership.  An affiliate of Enterprise Products Partners also elected to dissociate from the Texas Offshore Port System partnership at the same time.  As a result, we expect to record a non-cash charge of approximately $34.2 million against our earnings for the second quarter of 2009.  For additional information, see Note 17 in the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

 

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Results of Operations

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

		For the Three Months Ended March 31,
		2009				2008
Operating revenues:
Downstream Segment		$	95.5			$	97.7
Upstream Segment			1,296.2				2,655.3
Midstream Segment			29.0				30.1
Marine Services Segment			36.9				25.5
Intersegment eliminations			--				(0.1	)
Total operating revenues			1,457.6				2,808.5
Operating income:
Downstream Segment			34.4				36.3
Upstream Segment			40.9				29.3
Midstream Segment			4.5				8.4
Marine Services Segment			5.2				6.6
Intersegment eliminations			0.7				2.9
Total operating income			85.7				83.5
Equity in earnings (losses) of unconsolidated affiliates:
Downstream Segment			(3.1	)			(4.1	)
Upstream Segment			3.3				3.0
Midstream Segment			25.6				23.7
Intersegment eliminations			(0.7	)			(2.9	)
Total equity in earnings of unconsolidated affiliates			25.1				19.7
Earnings before interest: (1)
Downstream Segment			31.6				32.4
Upstream Segment			44.2				32.3
Midstream Segment			30.1				32.2
Marine Services Segment			5.2				6.6
Interest expense			(32.1	)			(38.6	)
Income before provision for income taxes			79.0				64.9
Provision for income taxes			0.8				0.8
Net income		$	78.2			$	64.1
(1)    See Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements for a reconciliation of earnings before interest to net income.

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

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D ownstream Segment

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

 

		For the Three Months
		Ended March 31,								Increase
		2009				2008				(Decrease)
Operating revenues:
Sales of petroleum products		$	6.7			$	7.0			$	(0.3	)
Transportation – Refined products			35.9				37.3				(1.4	)
Transportation – LPGs			38.3				36.2				2.1
Other			14.6				17.2				(2.6	)
Total operating revenues			95.5				97.7				(2.2	)
Costs and expenses:
Purchases of petroleum products			6.6				6.9				(0.3	)
Operating expense			24.9				26.9				(2.0	)
Operating fuel and power			11.0				10.5				0.5
General and administrative			3.7				3.7				--
Depreciation and amortization			11.5				10.2				1.3
Taxes – other than income taxes			3.4				3.2				0.2
Total costs and expenses			61.1				61.4				(0.3	)
Operating income			34.4				36.3				(1.9	)
Equity in losses of unconsolidated affiliates			(3.1	)			(4.1	)			1.0
Other, net			0.3				0.2				0.1
Earnings before interest		$	31.6			$	32.4			$	(0.8	)

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
		Ended March 31,								Increase
		2009				2008				(Decrease)
Volumes Delivered:
Refined products			36.6				38.5				(5 %)
LPGs			12.6				12.9				(2 %)
Total			49.2				51.4				(4 %)
Average Tariff per Barrel:
Refined products		$	0.98			$	0.97				1 %
LPGs			3.05				2.81				9 %
Average system tariff per barrel			1.51				1.43				6 %

Three Months Ended March 31, 2009 Compared with Three Months Ended March 31, 2008

Sales and purchases related to petroleum products marketing activities at our Aberdeen and Boligee terminals decreased $0.3 million each for the three months ended March 31, 2009, compared with the three months ended March 31, 2008.  The decreases in purchases and sales were primarily a result of lower fuel prices in the 2009 period compared to the prior year period, partially offset by the start-up of the Boligee terminal in August 2008.

Revenues from refined products transportation decreased $1.4 million for the three months ended March 31, 2009, compared with the three months ended March 31, 2008, primarily due to a 5% decrease in refined products volumes delivered, partially offset by a 1% increase in the average tariff per barrel.  Volume decreases were primarily due to lower long-haul jet fuel and diesel movements resulting from a decline in product demand, partially offset by higher long-haul motor fuel and blendstock movements due to higher demand in the Midwest and East Texas markets resulting from refineries in those areas undergoing maintenance.  The refined products average tariff per barrel increased primarily due to increases in system tariffs that went into effect in April and July 2008.

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Revenues from LPG transportation increased $2.1 million for the three months ended March 31, 2009, compared with the three months ended March 31, 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 LPGs 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 unexpected downtime of the plant.  Propane transportation volumes were slightly lower in the 2009 period compared to the prior year period primarily due to the unexpected downtime of the Midwest petrochemical plant during the 2009 period.

Other operating revenues decreased $2.6 million for the three months ended March 31, 2009, compared with the three months ended March 31, 2008, primarily due to a $2.2 million decrease in product inventory sales, a $2.1 million decrease in refined products excess inventory revenue and a $0.9 million decrease in refined products terminaling revenue, partially offset by a $0.9 million increase in refined products storage rental, a $0.8 million increase in LPG rental and location exchange revenues and a $0.4 million increase in refinery grade propylene transportation revenue due to higher volumes.

Costs and expenses decreased $0.3 million for the three months ended March 31, 2009, compared with the three months ended March 31, 2008.  Purchases of petroleum products, discussed above, decreased $0.3 million, compared with the prior year period.  Operating expenses decreased $2.0 million primarily due to a $4.1 million increase in product measurement gains, a $0.7 million decrease in transportation expense related to movements on the Centennial pipeline and a $0.4 million decrease in insurance premiums.  These decreases in operating expenses were partially offset by a $1.1 million increase in labor and benefits expense, a $1.0 million increase in pipeline operating and maintenance costs principally related to periodic tank maintenance requirements and other repairs and maintenance expenses on various pipeline segments, a $0.6 million increase in pipeline inspection and repair costs associated with our integrity management program, a $0.3 million increase in environmental assessments and remediation costs and a $0.3 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 increased $0.5 million, primarily due to higher power rates in the 2009 period as a result of the increased cost of fuel and true-ups of power accruals.  General and administrative expenses remained virtually unchanged with $0.5 million in severance expense and a $0.2 million increase in consulting and contract services, offset by a $0.6 million decrease in labor and benefits expense.  Depreciation expense increased $1.3 million, primarily due to assets placed into service.  Taxes – other than income taxes increased $0.2 million, primarily due to true-ups of property tax accruals.

Equity in losses from our equity investment in Centennial decreased $1.0 million for the three months ended March 31, 2009, compared with the three months ended March 31, 2008, primarily due to lower operating expenses and improved tariff rates on slightly reduced transportation volumes.  Volumes on Centennial averaged 118,000 barrels per day during the three months ended March 31, 2009, compared with 122,000 barrels per day during the three months ended March 31, 2008.

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U pstream Segment

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

 

		For the Three Months
		Ended March 31,								Increase
		2009				2008				(Decrease)
Operating revenues: (1)
Sales of petroleum products (2)		$	1,271.2			$	2,637.7			$	(1,366.5	)
Transportation – Crude oil			21.9				15.3				6.6
Other			3.1				2.3				0.8
Total operating revenues			1,296.2				2,655.3				(1,359.1	)
Costs and expenses: (1)
Purchases of petroleum products (2)			1,229.6				2,602.7				(1,373.1	)
Operating expense			14.6				13.3				1.3
Operating fuel and power			1.8				1.7				0.1
General and administrative			1.9				1.8				0.1
Depreciation and amortization			5.6				4.8				0.8
Taxes – other than income taxes			1.8				1.7				0.1
Total costs and expenses			1,255.3				2,626.0				(1,370.7	)
Operating income			40.9				29.3				11.6
Equity in earnings of unconsolidated affiliates			3.3				3.0				0.3
Earnings before interest		$	44.2			$	32.3			$	11.9
(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 (Generally Accepted Accounting Principles) 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 ended March 31, 2009 and 2008 is presented below (in millions, except per barrel and per gallon amounts):

 

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		For the Three Months								Percentage
		Ended March 31,								Increase
		2009				2008				(Decrease)
Margins: (1)
Crude oil marketing		$	32.2			$	20.3				59%
Lubrication oil sales			3.2				2.7				19%
Revenues: (1)
Crude oil transportation			20.5				23.4				(12%)
Crude oil terminaling (2)			7.6				3.9				95%
Total margin/revenues		$	63.5			$	50.3				26%
Total barrels/gallons:
Crude oil marketing (barrels) (3)			45.4				43.0				6%
Lubrication oil volumes (gallons)			5.4				3.9				38%
Crude oil transportation (barrels)			29.2				27.8				5%
Crude oil terminaling (barrels)			46.8				33.1				41%
Margin per barrel:
Lubrication oil margin (per gallon)		$	0.603			$	0.695				(13%)
Average tariff per barrel:
Crude oil transportation		$	0.702			$	0.842				(17%)
Crude oil terminaling			0.163				0.116				41%
(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 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 ended March 31, 2008, we previously reported 57.6 million barrels, which included inter-region transfers.

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

		For the Three Months
		Ended March 31,
		2009				2008
Sales of petroleum products		$	1,271.2			$	2,637.7
Transportation – Crude oil			21.9				15.3
Less:  Purchases of petroleum products			(1,229.6	)			(2,602.7	)
Total margin/revenues			63.5				50.3
Other operating revenues			3.1				2.3
Net operating revenues			66.6				52.6
Operating expense			14.6				13.3
Operating fuel and power			1.8				1.7
General and administrative			1.9				1.8
Depreciation and amortization			5.6				4.8
Taxes – other than income taxes			1.8				1.7
Operating income		$	40.9			$	29.3

Three Months Ended March 31, 2009 Compared with Three Months Ended March 31, 2008

Sales of petroleum products and purchases of petroleum products decreased $1,366.5 million and $1,373.1 million, respectively, for the three months ended March 31, 2009, compared with the three months ended March 31, 2008.  Operating income increased $11.6 million for the three months ended March 31, 2009, compared with the three months ended March 31, 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 $43.31 per barrel for the three months ended March 31, 2009,

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compared with $97.82 per barrel for the three months ended March 31, 2008.  Increased volumes transported and 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 $11.9 million, primarily due to the contango pricing environment during the three months ended March 31, 2009, increased volumes marketed, contract amendments in light of the current market conditions and decreased transportation costs, including decreased fuel costs.  Lubrication oil sales margin increased $0.5 million on higher volumes, primarily due to increased sales of higher margin specialty chemicals and additional margin resulting from the acquisition of Quality Petroleum, Inc. (“Quality Petroleum”) on August 1, 2008.  Crude oil transportation revenues (prior to intercompany eliminations) decreased $2.9 million, primarily due to lower transportation volumes on our South Texas crude oil gathering system, partially offset by higher transportation volumes on our Basin and West Texas crude oil gathering systems.  Additionally, decreased transportation revenues on our South Texas and other systems resulted from movements on lower tariff segments and from lower prices of crude oil acquired through our pipeline loss allowance in certain of our pipeline tariffs, which resulted in a 17% decrease in the average tariff per barrel.  Crude oil terminaling volumes and revenues increased 41% and $3.7 million, respectively, as a result of spot market demand and the completion of a storage tank in August 2008.

Other operating revenues increased $0.8 million for the three months ended March 31, 2009, compared with the three months ended March 31, 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 $1,370.7 million for the three months ended March 31, 2009, compared with the three months ended March 31, 2008.  Purchases of petroleum products, discussed above, decreased $1,373.1 million compared with the prior year period.  Operating expenses increased $1.3 million from the prior year period, primarily due to a $1.3 million increase in operating expenses resulting from the acquisition of Quality Petroleum, a $0.8 million increase in product measurement losses and a $0.5 million increase in labor and benefits expense, partially offset by a $0.5 million decrease in pipeline inspection and repair costs associated with our integrity management program, a $0.5 million decrease in pipeline operating and maintenance expenses, mostly related to periodic tank maintenance requirements and a $0.3 million increase in environmental assessment and remediation expense.  Operating fuel and power increased $0.1 million primarily as a result of higher transportation volumes.  General and administrative expenses increased $0.1 million primarily due to severance expenses.  Depreciation and amortization expense increased $0.8 million primarily due to assets placed into service and an increase in the amortization of equity awards.  Taxes – other than income taxes increased $0.1 million due to true-ups of other tax accruals.

Equity in earnings from our investment in Seaway increased $0.3 million for the three months ended March 31, 2009, compared with the three months ended March 31, 2008, primarily due to an increase in long-haul volumes and a decrease in pipeline operating and maintenance expenses, offset by a decrease in transportation revenues and an increase in product measurement losses.  Long-haul volumes on Seaway averaged 174,000 barrels per day during the three months ended March 31, 2009, compared with 166,000 barrels per day during the three months ended March 31, 2008.

 

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M idstream Segment

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

 

		For the Three Months
		Ended March 31,								Increase
		2009				2008				(Decrease)
Operating revenues:
Gathering – Natural gas		$	13.6			$	13.4			$	0.2
Transportation – NGLs (1)			12.5				13.0				(0.5	)
Other			2.9				3.7				(0.8	)
Total operating revenues			29.0				30.1				(1.1	)
Costs and expenses:
Operating expense			8.6				5.0				3.6
Operating fuel and power			2.6				3.7				(1.1	)
General and administrative			3.0				2.6				0.4
Depreciation and amortization			9.5				9.6				(0.1	)
Taxes – other than income taxes			0.8				0.8				--
Total costs and expenses			24.5				21.7				2.8
Operating income			4.5				8.4				(3.9	)
Equity in earnings of unconsolidated affiliates			25.6				23.7				1.9
Other, net			--				0.1				(0.1	)
Earnings before interest		$	30.1			$	32.2			$	(2.1	)
(1)    Includes transportation revenue from Enterprise Products Partners of $3.8 million and $3.4 million for the three months ended March 31, 2009 and 2008, respectively.

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

		For the Three Months								Percentage
		Ended March 31,								Increase
		2009				2008				(Decrease)
Gathering – Natural Gas – Jonah: (1)
Bcf			194.9				167.1				17%
Btu (in trillions)			215.1				184.6				17%
Average fee per Mcf		$	0.261			$	0.258				1%
Average fee per MMBtu		$	0.236			$	0.234				1%
Gathering – Natural Gas – Val Verde: (1)
Bcf			42.8				38.2				12%
Btu (in trillions)			38.6				34.2				13%
Average fee per Mcf		$	0.318			$	0.351				(9%)
Average fee per MMBtu		$	0.352			$	0.392				(10%)
Transportation and movements – NGLs:
Transportation barrels (in millions)			14.1				16.6				(15%)
Lease barrels (in millions) (2)			2.8				3.0				(7%)
Average rate per barrel		$	0.824			$	0.736				12%
Natural Gas Sales:
Btu (in trillions)			0.8				1.7				(53%)
Average fee per MMBtu		$	3.377			$	6.806				(50%)
Fractionation – NGLs:
Barrels (in millions)			0.8				1.1				(27%)
Average rate per barrel		$	1.785			$	1.661				7%
(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 statements of consolidated income.

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Three Months Ended March 31, 2009 Compared with Three Months Ended March 31, 2008

Natural gas gathering revenues from the Val Verde system increased $0.2 million, and volumes gathered increased 4.6 Bcf for the three months ended March 31, 2009, compared with the three months ended March 31, 2008, primarily due to an increase in volumes from a third party natural gas connection and annual rate escalations, 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 March 31, 2009, Val Verde’s gathering volumes averaged 476 MMcf/d, compared with 420 MMcf/d for the three months ended March 31, 2008.  Val Verde’s average natural gas gathering fee per Mcf decreased 9%, primarily due to the lower rates on the higher volumes from the third party natural gas connection and lower gathering volumes, partially offset by the annual rate escalations.

Revenues from the transportation of NGLs decreased $0.5 million for the three months ended March 31, 2009, compared with the three months ended March 31, 2008, primarily due to 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, a decrease in revenues and volumes on the Dean Pipeline and a decrease in the short-haul volumes on the Chaparral Pipeline.  These decreases in revenues and volumes were partially offset by 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.

Other operating revenues decreased $0.8 million for the three months ended March 31, 2009, compared with the three months ended March 31, 2008, primarily due to a 27% decrease in the volume of NGLs fractionated.  The average rate per barrel for the fractionation of NGLs increased 7% 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.

Costs and expenses increased $2.8 million for the three months ended March 31, 2009, compared with the three months ended March 31, 2008.  Operating expenses increased $3.6 million from the prior year period primarily due to a $1.2 million increase in labor and benefits expense, a $1.0 million increase as a result of higher product measurement losses, a $0.7 million increase in LCM adjustments and a $0.6 million increase in pipeline inspection and repair costs associated with our integrity management program.  Operating fuel and power decreased $1.1 million primarily due to lower power costs on the Chaparral Pipeline as a result of a decrease in volumes.  General and administrative expenses increased $0.4 million primarily due to $0.5 million of severance expense and a $0.2 million increase in administrative consulting services and supplies and expenses, partially offset by a $0.3 million decrease in labor and benefits expense.  Depreciation and amortization expense decreased $0.1 million primarily due to a 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, partially offset by an increase in the amortization of equity awards.  Taxes – other than income taxes remained unchanged period-to-period.

Equity in earnings from our investment in Jonah increased $1.9 million for the three months ended March 31, 2009, compared with the three months ended March 31, 2008.  Earnings increased primarily due to an $8.3 million increase in natural gas gathering revenues and an increase in volumes from the system expansion, partially offset by a $0.9 million decrease in the margin on natural gas sales, a $2.8 million decrease in Jonah’s condensate sales, a $1.3 million increase in depreciation and amortization expense primarily relating to the system expansion and a $1.3 million increase in operating, general and administrative expenses. For the three months ended March 31, 2009 and 2008, Jonah’s gathering volumes averaged approximately 2.2 Bcf/d and 1.8 Bcf/d, respectively, and total volumes gathered increased 27.8 Bcf.  For the three months ended March 31, 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 March 31, 2009, compared with the prior year period, was primarily a result of certain shippers 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.

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M arine Services Segment

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

 

		For the Three Months
		Ended March 31,								Increase
		2009				2008				(Decrease)
Operating revenues:
Transportation – inland		$	33.6			$	20.7			$	12.9
Transportation – offshore			3.3				4.8				(1.5	)
Total Transportation – Marine			36.9				25.5				11.4
Costs and expenses:
Operating expense			18.7				8.6				10.1
Operating fuel and power			4.3				5.5				(1.2	)
General and administrative			1.4				0.7				0.7
Depreciation and amortization			6.4				3.7				2.7
Taxes – other than income taxes			0.9				0.4				0.5
Total costs and expenses			31.7				18.9				12.8
Operating income			5.2				6.6				(1.4	)
Earnings before interest		$	5.2			$	6.6			$	(1.4	)

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 for the periods indicated:

		For the Three Months Ended March 31,
		2009				2008
Number of inland tow boats		45				43
Number of inland tank barges		105				98
Number of offshore tow boats		6				6
Number of offshore tank barges		8				8
Fleet available days (in thousands) (1)		13.9				7.4
Fleet operating days (in thousands) (2)		12.4				6.9
Fleet utilization (3)		89%				93%
Gross margin (in millions)		$                 13.9				$                 11.4
Average daily rate (in thousands) (4)		$                 1.12				$                 1.66
(1)    Equal to the number of calendar days in the period (for 2008 period, number of calendar days from our acquisition of Cenac Towing Co., Inc. and Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr., the sole owner of Cenac Towing Co., Inc. and Cenac Offshore, L.L.C. (collectively, “Cenac”) on February 1, 2008 and Horizon Maritime, LLC (“Horizon”) on February 29, 2008 through March 31, 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. (2)    Equal to the number of our fleet available days in the period (for 2008 period, number of our fleet available days from our acquisition of Cenac on February 1, 2008 and Horizon on February 29, 2008 through March 31, 2008) less the aggregate number of days that our vessels are off-hire. (3)     Equal to the number of fleet operating days divided by the number of fleet available days during the period. (4)    Equal to gross margin divided by the number of fleet operating days during the period.

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T he following table reconciles gross margin to operating income using the information presented in the 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 March 31,
		2009				2008
Transportation revenue – Marine		$	36.9			$	25.5
Less:  Operating expense			(18.7	)			(8.6	)
Less:  Operating fuel and power			(4.3	)			(5.5	)
Gross margin			13.9				11.4
General and administrative			1.4				0.7
Depreciation and amortization			6.4				3.7
Taxes – other than income taxes			0.9				0.4
Operating income		$	5.2			$	6.6

Three Months Ended March 31, 2009 Compared with Three Months Ended March 31, 2008

We acquired Cenac and Horizon on February 1, 2008 and February 29, 2008, respectively.  Our ownership and operation of these assets for only a portion of the three months ended March 31, 2008, as compared to the full three months ended March 31, 2009, accounted for a substantial portion of the changes in the results of operations in this segment.

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 increased $11.4 million for the three months ended March 31, 2009, compared with the three months ended March 31, 2008, primarily due to the timing of the acquisitions in the 2008 period as discussed above, partially offset by 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.  These 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 89% for the three months ended March 31, 2009, compared with the three months ended March 31, 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.  Most of the marine vessels impacted by these non-renewals are employed in the spot market until we can secure term contracts.

G ross 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 $2.5 million, while the average daily rate decreased 33% for the three months ended March 31, 2009, compared with the three months ended March 31, 2008, primarily due to the ownership and operation of the Cenac and Horizon assets for only a portion of the three months ended March 31, 2008, as compared to the full three months ended March 31, 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 and an increase in the fleet operating days resulted in a decrease in the average daily rate in the 2009 period.

Costs and expenses increased $12.8 million for the three months ended March 31, 2009, compared with the three months ended March 31, 2008.  The largest single impact to costs and expenses was the timing of the acquisitions in the 2008 period as discussed above.  Operating expenses also increased due to a $1.8 million increase in tow boat and tank barge maintenance expenses, a $1.0 million increase in payments under the transitional operating agreement for vessel personnel salaries, related employee benefits and other expenses and a $0.7 million increase in operating supplies and expenses.  Operating fuel and power decreased 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

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expense increased primarily due to higher labor and benefits expense.  Depreciation and amortization expense increased primarily due to the acquisition of additional tow boats and tank barges in the 2008 period.  Taxes – other than income taxes increased primarily due to higher payroll taxes relating to increased labor costs.

Interest Expense

Interest expense decreased $5.6 million for the three months ended March 31, 2009, compared with the three months ended March 31, 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, and a $0.9 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 March 31, 2009 and December 31, 2008, we had current tax liabilities of $4.7 million and $3.9 million, respectively.  At March 31, 2009, we had a deferred tax asset of less than $0.1 million.  During each of the three months ended March 31, 2009 and 2008, we recorded an increase in current income tax liabilities of $0.8 million.  During the three months ended March 31, 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 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 Jonah) and acquisitions of new assets or businesses and (iii) repayment of principal on our long-term debt.  Our ordinary course operating cash requirements for 2009 are expected to be funded through our cash flows from operating activities.  We have no material long-term debt obligations that mature in 2009, and our revolving credit facility (“Revolving Credit Facility”) does not mature until 2012.  We expect cash requirements for growth expenditures and long-term debt repayments will be funded by a combination of several sources, including cash flows from operating activities, borrowings under credit facilities, joint venture distributions, the issuance of additional equity and debt securities and the possible disposition of assets.

Our ability to maintain adequate liquidity depends on our ability to have continued access to the financial markets and continue to generate cash from operations, both of which are 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.

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, 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.

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Cash Flows from Operating, Investing and Financing Activities

Cash generated from operations, distributions from our joint ventures, borrowings under our credit facilities and debt and equity offerings are our primary sources of liquidity.  From time to time we may dispose of assets, which would provide an additional source of liquidity.  At March 31, 2009, we had a working capital deficit of $13.9 million, while at December 31, 2008, we had a working capital surplus of $7.6 million.  At March 31, 2009, we had approximately $355.5 million in available borrowing capacity under our Revolving Credit Facility.  Cash flows for the periods indicated were as follows (in millions):

		For the Three Months
		Ended March 31,
		2009				2008
Cash provided by (used in):
Operating activities		$	156.6			$	58.7
Investing activities			(113.6	)			(436.5	)
Financing activities			(40.8	)			377.8

O perating Activities

Net cash flow provided by operating activities was $156.6 million for the three months ended March 31, 2009 compared to $58.7 million for the three months ended March 31, 2008.  The following were the principal factors resulting in the $97.9 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 $10.5 million. Distributions received from our equity investment in Seaway increased $8.8 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 $1.7 million primarily due to increased revenues and volumes generated from completion of the system expansion.

§

Cash paid for interest, net of amounts capitalized, decreased $25.3 million for the three months ended March 31, 2009 compared with the three months ended March 31, 2008, primarily due to the redemption of our senior notes in the 2008 period, partially offset by an increase in debt outstanding, including higher outstanding balances on our variable rate Revolving Credit Facility.  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.

I nvesting Activities

Net cash flow used in investing activities was $113.6 million for the three months ended March 31, 2009 compared to $436.5 million for the three months ended March 31, 2008.  The following were the principal factors resulting in the $322.9 million decrease in net cash flows used in investing activities:

§	Cash used for business combinations was $338.5 million during the three months ended March 31, 2008, of which $257.7 million was for the Cenac acquisition and $80.8 million was for the Horizon acquisition.

§

Capital expenditures increased $50.0 million primarily due to higher spending on revenue generating projects for the three months ended March 31, 2009 compared with the three months ended March 31, 2008.  Cash paid for linefill on assets owned decreased $14.3 million for the three months ended March 31, 2009 compared with the three months ended

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March 31, 2008, primarily due to the timing of completion of organic growth projects in our Upstream Segment.

§

Investments in unconsolidated affiliates decreased $21.2 million, which includes a $19.5 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 Texas Offshore Port System for the three months ended March 31, 2009.  In January 2009, we received a $3.1 million refund of our 2008 contributions to Texas Offshore Port System 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 Texas Offshore Port System.  See Note 17 in the Notes to Unaudited Condensed Consolidated Financial Statements for information regarding our dissociation from the Texas Offshore Port System partnership.

§	During the three months ended March 31, 2009 and 2008, we paid $1.4 million and $0.3 million, respectively, related to the acquisition of intangible assets.

F inancing Activities

Cash flows used in financing activities totaled $40.8 million for the three months ended March 31, 2009, compared to cash flows provided by financing activities of $377.8 million for the three months ended March 31, 2008.  The following were the principal factors resulting in the $418.6 million increase in cash flows used in financing activities:

§

During the three months ended March 31, 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 three months ended March 31, 2008 were $8.7 million.

§	Net borrowings under our Revolving Credit Facility increased $109.8 million.

§	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 $16.5 million for the three months ended March 31, 2009 compared with the three months ended March 31, 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 $91.4 million ($0.725 per Unit) and $74.9 million ($0.695 per Unit) during the three months ended March 31, 2009 and 2008, respectively.  Additionally, we declared a cash distribution of $0.725 per Unit for the quarter ended March 31, 2009.  We paid the distribution of $91.4 million on May 7, 2009 to unitholders of record on April 30, 2009.

§

Net proceeds from the issuance of Units to employees under the employee unit purchase plan  (“EUPP”) and the issuance of Units in connection with our distribution reinvestment plan (“DRIP”) were $1.6 million for the three months ended March 31, 2009, compared to $2.7 million for the three months ended March 31, 2008.

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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 three months ended March 31, 2009, 63,048 Units have been issued under this registration statement, generating $1.4 million in net proceeds that we used for general partnership purposes.

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 three months ended March 31, 2009, 7,507 Units have been issued to employees under this plan, generating $0.2 million in net proceeds that we used for general partnership purposes.

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

Debt Obligations

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.  Assuming that future fundings are not received for the Lehman percentage commitment, aggregate available capacity would be reduced by approximately $28.9 million. Our available borrowing capacity under the facility was approximately $355.5 million at March 31, 2009.

We were in compliance with the covenants of our long-term debt obligations at March 31, 2009.

For information regarding our debt obligations, see Note 9 in the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this Quarterly Report.

Future Capital Needs and Commitments

We estimate that capital expenditures, excluding acquisitions and joint venture contributions, for 2009 will be in the range of $320.0 million to $370.0 million (including approximately $19.0 million of capitalized interest).  Excluding capitalized interest, we expect to spend in the range of $250.0 million to $300.0 million for revenue generating projects, which includes $170.0 million for our expected spending on the Motiva Enterprises, LLC project.  We expect to spend approximately $47.0 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 $4.0 million to improve operational efficiencies and reduce costs among all of our business segments.

Additionally, we expect to invest approximately $28.0 million in our Jonah joint venture during 2009 for the completion of additional facilities to expand the Pinedale field production.  We do not expect to make further investments in the Texas Offshore Port System partnership due to our exit from the partnership (see Note 17 in the Notes to Unaudited Condensed Consolidated Financial Statements).

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

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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.  We may finance capital expenditures through internally generated funds, joint venture distributions, debt or the issuance of additional equity, and the possible disposition of assets.

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

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 $4.5 million and $5.4 million during the three months ended March 31, 2009 and 2008, 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 the Texas Offshore Port System partnership, our capital expenditure commitments decreased by an estimated $68.0 million.  See Note 17 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional information regarding this subsequent event.

Summary of Related Party Transactions

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

		For the Three Months Ended March 31,
		2009				2008
Revenues from EPCO and affiliates:
Sales of petroleum products		$	0.1			$	0.6
Transportation – NGLs			3.8				3.4
Transportation – LPGs			4.9				2.3
Other operating revenues			14.0				0.4
Related party revenues		$	22.8			$	6.7
Costs and Expenses from EPCO and affiliates:
Purchases of petroleum products		$	26.7			$	19.7
Operating expense			28.6				26.1
General and administrative			8.1				8.5
Costs and Expenses from unconsolidated affiliates:
Purchases of petroleum products			(0.7	)			1.6
Operating expense			1.6				2.3
Costs and Expenses from Cenac and affiliates:
Operating expense			13.4				7.4
General and administrative			1.1				0.5
Related party expenses		$	78.8			$	66.1

For additional information regarding our related party transactions, see Note 12 in the Notes to Unaudited Condensed Consolidated Financial Statements.

 

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Credit Ratings

Our debt securities are rated BBB- by Standard & Poor’s Ratings Group (“S&P”), Baa3 by Moody’s Investors Service, Inc. (“Moody’s”) and BBB- by Fitch Ratings, 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.

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, 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 ; and
§	FSP FAS 107-1 and APB 28-1, Interim Disclosures About Fair Value of Financial Instruments.

 

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.

Item 3.   Quantitative and Qualitative Disclosures a bout Market Risk.

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.  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

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 March 31, 2009, we had no interest rate derivative instruments outstanding.

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

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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		March 31, 2009				April 20, 2009
FV assuming no change in underlying commodity prices	Asset		$	0.6			$	0.5
FV assuming 10% increase in underlying commodity prices	Asset			0.6				0.2
FV assuming 10% decrease in underlying commodity prices	Asset			0.7				0.9

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 first 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.

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PART II.  OTHER INFORMATION.

Item 1.   Legal Proceedings .

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.  See discussion of legal proceedings in Note 14 in the Notes to Unaudited Condensed Consolidated Financial Statements under the headings “– Litigation” and “– Regulatory Matters,” which is incorporated into this item by reference.

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 Court of Chancery of New Castle County in the State of Delaware, as putative class actions on behalf of other unitholders of TEPPCO, concerning a proposal made by Enterprise Products Partners to our General Partner to acquire by merger our Units (the “Proposed Merger”).  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 complaints allege, among other things, that the terms of the Proposed Merger 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, without consideration and without adequate information having been provided to our unitholders to cast a vote with respect to the Proposed Merger, a separate derivative action that previously had been filed in September 2006 by Mr. Brinckerhoff concerning proposals made in our Proxy Statement and other transactions involving us and Enterprise Products Partners or its affiliates.  See Note 14 for additional information regarding this proceeding.  The complaints further allege that the process through which a 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 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 defendants to account to plaintiffs and the purported class for all damages suffered or to be suffered by them as a result of defendants’ alleged wrongful conduct; and (iv) awarding plaintiffs costs of the actions, including fees and expenses of their attorneys and experts.

Item 1A.   Risk Factors .

Security holders and potential investors in our securities should carefully consider the risk factor 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.

Our prior interest in the Texas Offshore Port System partnership and dissociation from the

  partnership in April 2009 could subject us to various liabilities .

The Texas Offshore Port System partnership was expected to represent an important component of our Upstream Segment, requiring an estimated $600.0 million in capital contributions from us through 2011.  Effective April 16, 2009, we and an affiliate of Enterprise Products Partners elected to dissociate, or exit, from the partnership.  In dissociating from the partnership, we forfeited our investment and one-third ownership interest in the partnership.  The third partner, Oiltanking, has asserted that the dissociation was wrongful and in breach of the Texas Offshore Port System partnership agreement, citing provisions of the agreement that, if applicable, would continue to obligate us to make capital contributions to fund the project and impose additional liabilities on us.

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Item 5.   Other Information .

None.

Item 6.   Exhibits .

Exhibit Number	Exhibit
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).
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).

 

 

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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,

 

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	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	Fifth Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC, Enterprise Products OLPGP, Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership L.P., TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company,
10.2	LLC, TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc. dated January 30, 2009 (Filed as Exhibit 10.1 to Current Report on Form 8-K of Enterprise Products Partners L.P. (Commission File No. 1-14323) filed on February 5, 2009 and incorporated herein by reference). Agreement and Release between William G. Manias and EPCO, Inc. dated January 19, 2009 (Filed as Exhibit 10.1 to Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on January 23, 2009 and incorporated herein by reference).
10.3*	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 March 5, 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:  May 11, 2009	By:   /s/   JERRY E.  THOMPSON                                                Jerry E. Thompson,                   President and Chief Executive Officer of Texas Eastern Products Pipeline Company, LLC, General Partner
Date:  May 11, 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

 

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