10-Q 1 a05-12511_110q.htm 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2005

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

Commission File No. 1-10403

TEPPCO Partners, L.P.

(Exact name of Registrant as specified in its charter)

Delaware		76-0291058
(State of Incorporation		(I.R.S. Employer
or Organization)		Identification Number)

2929 Allen Parkway

P.O. Box 2521

Houston, Texas 77252-2521

(Address of principal executive offices, including zip code)

(713) 759-3636

(Registrant’s telephone number, including area code)

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

Yes ý No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes ý No o

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. Limited Partner Units outstanding as of August 1, 2005: 69,963,554

TEPPCO PARTNERS, L.P.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2005 (unaudited) and December 31, 2004

Consolidated Statements of Income for the three months and six months ended June 30, 2005 and 2004 (unaudited)

Consolidated Statements of Cash Flows for the six months ended June 30, 2005 and 2004 (unaudited)

Consolidated Statement of Partners’ Capital for the six months ended June 30, 2005 (unaudited)

Notes to the Consolidated Financial Statements (unaudited)

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

Forward-Looking Statements

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Item 4. Controls and Procedures

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 6. Exhibits

Signatures

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

TEPPCO PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

	June 30,			December 31,
	2005			2004
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	1,494		$	16,422
Accounts receivable, trade (net of allowance for doubtful accounts of $182 and $112)	686,677			553,628
Accounts receivable, related parties	4,440			12,921
Inventories	98,487			19,521
Other	57,504			42,138
Total current assets	848,602			644,630
Property, plant and equipment, at cost (net of accumulated depreciation and amortization of $442,282 and $407,670)	1,789,866			1,703,702
Equity investments	373,047			373,652
Intangible assets	393,271			407,358
Goodwill	16,944			16,944
Other assets	58,746			51,419
Total assets	$	3,480,476		$	3,197,705

LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Accounts payable and accrued liabilities	$	685,563		$	564,464
Accounts payable, related parties	6,458			25,730
Accrued interest	32,506			32,292
Other accrued taxes	13,407			13,309
Other	48,641			46,593
Total current liabilities	786,575			682,388
Senior Notes	1,129,394			1,127,226
Other long-term debt	278,000			353,000
Other liabilities and deferred credits	12,729			13,643
Commitments and contingencies
Partners’ capital:
General partner’s interest	(40,272		)	(33,006		)
Limited partners’ interests	1,314,050			1,054,454
Total partners’ capital	1,273,778			1,021,448
Total liabilities and partners’ capital	$	3,480,476		$	3,197,705

See accompanying Notes to Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per Unit amounts)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
Operating revenues:
Sales of petroleum products	$	1,963,617		$	1,232,807		$	3,350,826		$	2,414,920
Transportation – Refined products	37,834			38,937			72,799			69,908
Transportation – LPGs	14,470			13,721			46,701			42,501
Transportation – Crude oil	9,042			9,213			18,214			18,876
Transportation – NGLs	11,387			10,578			21,606			20,592
Gathering – Natural gas	36,956			34,427			73,516			68,929
Other	17,074			14,881			33,323			36,899
Total operating revenues	2,090,380			1,354,564			3,616,985			2,672,625

Costs and expenses:
Purchases of petroleum products	1,943,696			1,217,312			3,316,156			2,384,653
Operating, general and administrative	49,979			52,640			99,997			104,443
Operating fuel and power	11,546			11,035			22,616			22,995
Depreciation and amortization	26,292			26,411			52,055			54,231
Taxes – other than income taxes	4,272			4,831			9,708			10,125
Gains on sales of assets	(68		)	(66		)	(566		)	(124		)
Total costs and expenses	2,035,717			1,312,163			3,499,966			2,576,323

Operating income	54,663			42,401			117,019			96,302

Interest expense – net	(21,627		)	(16,464		)	(40,914		)	(36,059		)
Equity earnings	9,062			11,582			14,308			17,233
Other income – net	135			240			401			716

Net income	$	42,233		$	37,759		$	90,814		$	78,192

Net Income Allocation:
Limited Partner Unitholders	$	29,671		$	26,867		$	64,237		$	55,636
General Partner	12,562			10,892			26,577			22,556
Total net income allocated	$	42,233		$	37,759		$	90,814		$	78,192

Basic and diluted net income per Limited Partner Unit	$	0.45		$	0.43		$	0.99		$	0.88

Weighted average Limited Partner Units outstanding	66,559			62,999			64,789			62,999

See accompanying Notes to Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Six Months Ended
	June 30,
	2005			2004
Cash flows from operating activities:
Net income	$	90,814		$	78,192
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	52,055			54,231
Earnings in equity investments, net of distributions	4,739			3,617
Gains on sales of assets	(566		)	(124		)
Non-cash portion of interest expense	810			(219		)
Increase in accounts receivable	(133,049		)	(93,044		)
Increase in inventories	(70,587		)	(213		)
(Increase) decrease in other current assets	(15,265		)	3,244
Increase in accounts payable and accrued expenses	120,182			93,583
Other	(24,533		)	(7,219		)
Net cash provided by operating activities	24,600			132,048

Cash flows from investing activities:
Proceeds from the sales of assets	510			141
Purchase of assets	(42,482		)	(2,962		)
Investment in Centennial Pipeline LLC	—			(1,500		)
Investment in Mont Belvieu Storage Partners, L.P.	(1,109		)	(17,211		)
Capital expenditures	(82,963		)	(60,390		)
Net cash used in investing activities	(126,044		)	(81,922		)

Cash flows from financing activities:
Proceeds from revolving credit facility	299,307			149,800
Repayments on revolving credit facility	(374,307		)	(99,800		)
Issuance of Limited Partner Units, net	278,832			—
Distributions paid	(117,316		)	(115,741		)
Net cash provided by (used in) financing activities	86,516			(65,741		)

Net decrease in cash and cash equivalents	(14,928		)	(15,615		)

Cash and cash equivalents at beginning of period	16,422			29,469
Cash and cash equivalents at end of period	$	1,494		$	13,854

Supplemental disclosure of cash flows:
Cash paid for interest (net of amounts capitalized)	$	41,067		$	41,208

See accompanying Notes to Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Unaudited)

(in thousands, except Unit amounts)

	Outstanding
	Limited	General			Limited
	Partner	Partner’s			Partners’
	Units	Interest			Interests			Total

Partners’ capital at December 31, 2004	62,998,554	$	(33,006	)	$	1,054,454		$	1,021,448
Issuance of Limited Partner Units, net	6,965,000	—			278,832			278,832
Net income allocation	—	26,577			64,237			90,814
Cash distributions	—	(33,843		)	(83,473		)	(117,316		)

Partners’ capital at June 30, 2005	69,963,554	$	(40,272	)	$	1,314,050		$	1,273,778

See accompanying Notes to Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1. ORGANIZATION AND BASIS OF PRESENTATION

TEPPCO Partners, L.P. (the “Partnership”), a Delaware limited partnership, is a master limited partnership formed in March 1990. We operate through TE Products Pipeline Company, Limited Partnership (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”). Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the “Operating Partnerships.” TEPPCO GP, Inc. (“TEPPCO GP”), our wholly owned subsidiary, is the general partner of our Operating Partnerships. We hold a 99.999% limited partner interest in the Operating Partnerships, and TEPPCO GP holds a 0.001% general partner interest. Texas Eastern Products Pipeline Company, LLC (the “Company” or “General Partner”), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us. Through February 23, 2005, the General Partner was an indirect wholly owned subsidiary of Duke Energy Field Services, LLC (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”) and ConocoPhillips. Through February 23, 2005, Duke Energy held an interest of approximately 70% in DEFS, and ConocoPhillips held the remaining interest of approximately 30%. On February 24, 2005, the General Partner was acquired by DFI GP Holdings L.P. (formerly Enterprise GP Holdings L.P.) (“DFI”), an affiliate of EPCO, Inc. (“EPCO”), a privately held company controlled by Dan L. Duncan, for approximately $1.1 billion. As a result of the transaction, DFI owns and controls the 2% general partner interest in us and has the right to receive the incentive distribution rights associated with the general partner interest.

EPCO performs all management and operating functions required for us, except for some administrative services for certain of the TEPPCO Midstream assets that are currently performed by DEFS on our behalf. We reimburse EPCO for all reasonable direct and indirect expenses that have been incurred in managing us. Under a transition services agreement entered into as part of the sale of the General Partner, DEFS will continue to provide some administrative services for certain of the TEPPCO Midstream assets for us for a period of time until we assume these services on our own. In connection with us assuming the operations of these TEPPCO Midstream assets from DEFS, certain DEFS employees became employees of EPCO effective June 1, 2005. As part of the transition services agreement, Duke Energy will continue to provide some administrative support services to us until we or EPCO assume those activities.

In connection with our formation in 1990, the Company received 2,500,000 Deferred Participation Interests (“DPIs”). Effective April 1, 1994, the DPIs began participating in distributions of cash and allocations of profit and loss in a manner identical to Limited Partner Units and are treated as Limited Partner Units for purposes of this Report. These Limited Partner Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000. On February 24, 2005, DFI entered into an LP Unit Purchase and Sale Agreement with Duke Energy and purchased these 2,500,000 DPIs for approximately $100.0 million.

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.

The accompanying unaudited consolidated financial statements reflect all adjustments that are, in the opinion of our management, of a normal and recurring nature and necessary for a fair statement of our financial position as of June 30, 2005, and the results of our operations and cash flows for the periods presented. The results of operations for the three months and six months ended June 30, 2005, are not necessarily indicative of results of our operations for the full year 2005. 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, 2004. We have reclassified certain amounts from prior periods to conform to the current presentation.

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

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

Net Income Per Unit

Basic net income per Limited Partner Unit (“Unit” or “Units”) is computed by dividing our net income, after deduction of the General Partner’s interest, by the weighted average number of Units outstanding (a total of 66.6 million and 64.8 million Units for the three months and six months ended June 30, 2005, respectively, and 63.0 million Units for the three months and six months ended June 30, 2004). The General Partner’s percentage interest in our net income is based on its percentage of cash distributions from Available Cash for each period (see Note 8. Partners’ Capital and Distributions). The General Partner was allocated $12.6 million (representing 29.74%) and $10.9 million (representing 28.85%) of our net income for the three months ended June 30, 2005 and 2004, respectively, and $26.6 million (representing 29.27%) and $22.6 million (representing 28.85%) of our net income for the six months ended June 30, 2005 and 2004, respectively. The General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase, in accordance with our limited partnership agreement.

Diluted net income per Unit equaled basic net income per Unit for each of the three-month and six-month periods ended June 30, 2005 and 2004, as there were no dilutive instruments outstanding.

New Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 123(R), Share-Based Payment. SFAS 123(R) requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of the compensation cost is to be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards are to be re-measured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees. SFAS 123(R) is effective for public companies as of the first interim or annual reporting period of the first fiscal year beginning on or after June 15, 2005. As such, we will adopt SFAS 123(R) in the first quarter of 2006. Companies are permitted to adopt SFAS 123(R) prior to the extended date. All public companies that adopted the fair-value-based method of accounting must use the modified prospective transition method and may elect to use the modified retrospective transition method. We do not believe that the adoption of SFAS 123(R) will have a material effect on our financial position, results of operations or cash flows.

In November 2004, the Emerging Issues Task Force (“EITF”) reached consensus in EITF 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations, to clarify whether a component of an enterprise that is either disposed of or classified as held for sale qualifies for income statement presentation as discontinued

operations. The FASB ratified the consensus on November 30, 2004. The consensus is to be applied prospectively with regard to a component of an enterprise that is either disposed of or classified as held for sale in reporting periods beginning after December 15, 2004. The consensus may be applied retrospectively for previously reported operating results related to disposal transactions initiated within an enterprise’s reporting period that included the date that this consensus was ratified. The adoption of EITF 03-13 did not have an effect on our financial position, results of operations or cash flows.

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (“FIN 47”). FIN 47 clarifies that the term, conditional asset retirement obligation as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the control of the entity. Even though uncertainty about the timing and/or method of settlement exists and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred generally upon acquisition, construction, or development or through the normal operation of the asset. SFAS 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of reporting periods ending after December 15, 2005. As such, we will adopt FIN 47 in the fourth quarter of 2005. Retrospective application for interim financial information is permitted but is not required. Early adoption of FIN 47 is encouraged. We do not believe that the adoption of FIN 47 will have a material effect on our financial position, results of operations or cash flows.

In June 2005, the EITF reached consensus in EITF 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights, to provide guidance on how general partners in a limited partnership should determine whether they control a limited partnership and therefore should consolidate it. The EITF agreed that the presumption of general partner control would be overcome only when the limited partners have either of two types of rights. The first type, referred to as kick-out rights, is the right to dissolve or liquidate the partnership or otherwise remove the general partner without cause. The second type, referred to as participating rights, is the right to effectively participate in significant decisions made in the ordinary course of the partnership’s business. The kick-out rights and the participating rights must be substantive in order to overcome the presumption of general partner control. The consensus is effective for general partners of all new limited partnerships formed and for existing limited partnerships for which the partnership agreements are modified subsequent to the date of FASB ratification (June 29, 2005). The guidance in this EITF is effective for existing partnerships no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. We are currently evaluating what impact this EITF will have on our financial statements, but at this time, we do not believe that the adoption of this EITF will have a material effect on our financial position, results of operations or cash flows.

NOTE 2. GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization. We account for goodwill under SFAS No. 142,

Goodwill and Other Intangible Assets, which was issued by the FASB in July 2001. SFAS 142 prohibits amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing for impairment at least annually. We test goodwill and intangible assets for impairment annually at December 31.

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

At June 30, 2005, and December 31, 2004, we have $16.9 million of unamortized goodwill and $25.5 million of excess investment in our equity investment in Seaway Crude Pipeline Company (equity method goodwill). The excess investment is included in our equity investments account at June 30, 2005. The following table presents the carrying amount of goodwill and equity method goodwill at June 30, 2005, and December 31, 2004, by business segment (in thousands):

	Downstream Segment		Midstream Segment		Upstream Segment		Segments Total

Goodwill	$	—	$	2,777	$	14,167	$	16,944
Equity method goodwill	—		—		25,502		25,502

Other Intangible Assets

The following table reflects the components of intangible assets being amortized at June 30, 2005, and December 31, 2004 (in thousands):

	June 30, 2005					December 31, 2004
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Intangible assets being amortized:
Gathering and transportation agreements	$	464,337	$	(103,856	)	$	464,337	$	(91,262	)
Fractionation agreement	38,000		(13,775		)	38,000		(12,825		)
Other	11,520		(2,955		)	12,262		(3,154		)
Total	$	513,857	$	(120,586	)	$	514,599	$	(107,241	)

SFAS 142 requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. Amortization expense on intangible assets was $7.0 million and $8.3 million for the three months ended June 30, 2005 and 2004, respectively, and $14.1 million and $16.5 million for the six months ended June 30, 2005 and 2004, respectively.

The value assigned to our intangible assets for natural gas gathering contracts is amortized on a unit-of-production basis, based upon the actual throughput of the system over the expected total throughput for the lives of the contracts. We update throughput estimates and evaluate the remaining expected useful lives of the contract assets on a quarterly basis based on the best available information. During the fourth quarter of 2004 and the first and second quarters of 2005, certain limited production forecasts were obtained from some of the producers on the

Jonah Gas Gathering Company (“Jonah”) system related to future expansions of the system, and as a result, we increased our best estimate of future throughput on the Jonah system. Revisions to these estimates may occur as additional production information is made available to us.

The amortization of the contracts related to the Val Verde Gas Gathering Company (“Val Verde”) assets is also amortized on a unit-of-production basis. During the fourth quarter of 2004, certain limited production forecasts were obtained from some of the producers on the Val Verde system, and as a result, we increased our best estimate of future throughput on the Val Verde system. Revisions to these estimates may occur as additional production information is made available to us.

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

At June 30, 2005, we have $33.4 million of excess investment in our equity investment in Centennial Pipeline LLC, which was created upon formation of the company. The excess investment is included in our equity investments account at June 30, 2005. This excess investment is accounted for as an intangible asset with an indefinite life. We assess the intangible asset for impairment on an annual basis.

The following table sets forth the estimated amortization expense of intangible assets for the years ending December 31 (in thousands):

2005	$	28,417
2006	31,327
2007	33,066
2008	33,148
2009	31,115

NOTE 3. INTEREST RATE SWAPS

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

7.51%. During the six months ended June 30, 2005 and 2004, we recognized reductions in interest expense of $3.3 million and $5.1 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the quarter ended June 30, 2005, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of this interest rate swap was a gain of approximately $7.4 million and $3.4 million at June 30, 2005, and December 31, 2004, respectively.

During 2002, we entered into interest rate swap agreements, designated as fair value hedges, to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, we paid a floating rate of interest based on a U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. These swap agreements were later terminated in 2002 resulting in gains of $44.9 million. The gains realized from the swap terminations have been deferred as adjustments to the carrying value of the Senior Notes and are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the Senior Notes. At June 30, 2005, the unamortized balance of the deferred gains was $34.6 million. In the event of early extinguishment of the Senior Notes, any remaining unamortized gains would be recognized in the consolidated statement of income at the time of extinguishment.

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

NOTE 4. ACQUISITIONS

Mexia Pipeline

On March 31, 2005, we purchased crude oil pipeline assets for $7.1 million from BP Pipelines (North America) Inc. (“BP”). The assets include approximately 158 miles of pipeline which extend from Mexia, Texas, to the Houston, Texas, area and two stations in south Houston with connections to a BP pipeline that originates in south Houston. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment, and we accounted for the acquisition of these assets under the purchase method of accounting. We will integrate these assets into our South Texas pipeline system, included in our Upstream Segment, which will allow us to realize synergies within our existing asset base and will provide future growth opportunities.

Storage and Terminaling Assets

On April 1, 2005, we purchased crude oil storage and terminaling assets in Cushing, Oklahoma, from Koch Supply & Trading, L.P. for $35.4 million. The assets consist of eight storage tanks with 945,000 barrels of storage capacity, receipt and delivery manifolds, interconnections to several pipelines, crude oil inventory and approximately 70 acres of land. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment and inventory, and we accounted for the acquisition of these assets under the purchase method of accounting. The storage and terminaling assets will complement our existing infrastructure in Cushing and strengthen our gathering and marketing business in our Upstream Segment.

NOTE 5. INVENTORIES

Inventories are valued at the lower of cost (based on weighted average cost method) or market. The costs of inventories did not exceed market values at June 30, 2005, and December 31, 2004. The major components of inventories were as follows (in thousands):

	June 30, 2005		December 31, 2004
Crude oil (1)	$	80,971	$	3,690
Refined products	1,440		5,665
LPGs	5,048		—
Lubrication oils and specialty chemicals	4,603		4,002
Materials and supplies	6,237		6,135
Other	188		29
Total	$	98,487	$	19,521

(1) At June 30, 2005, substantially all of our crude oil inventory was subject to forward sales contracts.

NOTE 6. EQUITY INVESTMENTS

Through one of our indirect wholly owned subsidiaries, we own a 50% ownership interest in Seaway Crude Pipeline Company (“Seaway”). The remaining 50% interest is owned by ConocoPhillips. Seaway owns a pipeline that carries mostly imported crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal at Texas City, Texas, to refineries in the Texas City and Houston, Texas, areas. The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of the Seaway partnership. From June 2002 through May 2006, we receive 60% of revenue and expense of Seaway. Thereafter, we will receive 40% of revenue and expense of Seaway. During the six months ended June 30, 2005 and 2004, we received distributions from Seaway of $11.7 million and $15.9 million, respectively.

TE Products owns a 50% ownership interest in Centennial Pipeline Company LLC (“Centennial”), and Marathon Ashland Petroleum LLC (“Marathon”) owns the remaining 50% interest. Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois. During the six months ended June 30, 2005, TE Products has not invested any additional funds in Centennial. During the six months ended June 30, 2004, TE Products invested an additional $1.5 million in Centennial, which is included in the equity investment balance at June 30, 2005. TE Products has not received any distributions from Centennial since its formation.

On January 1, 2003, TE Products and Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”) formed Mont Belvieu Storage Partners, L.P. (“MB Storage”). TE Products and Louis Dreyfus each own a 50% ownership interest in MB Storage. MB Storage owns storage capacity at the Mont Belvieu fractionation and storage complex and a short haul transportation shuttle system that ties Mont Belvieu, Texas, to the upper Texas Gulf Coast energy marketplace. MB Storage is a service-oriented, fee-based venture serving the fractionation, refining and petrochemical industries with transportation, terminaling and storage. MB Storage has no commodity trading activity. TE Products operates the facilities for MB Storage.

For the year ended December 31, 2005, TE Products will receive the first $1.7 million per quarter (or $6.78 million on an annual basis) of MB Storage’s income before depreciation expense, as defined in the operating agreement. For the year ended December 31, 2004, TE Products received the first $1.8 million per quarter (or $7.15

million on an annual basis) of MB Storage’s income before depreciation expense. TE Products’ share of MB Storage’s earnings is adjusted annually by the partners of MB Storage. Any amount of MB Storage’s annual income before depreciation expense in excess of $6.78 million for 2005 and $7.15 million for 2004 is allocated evenly between TE Products and Louis Dreyfus. Depreciation expense on assets each party originally contributed to MB Storage is allocated between TE Products and Louis Dreyfus based on the net book value of the assets contributed. Depreciation expense on assets constructed or acquired by MB Storage subsequent to formation is allocated evenly between TE Products and Louis Dreyfus. For the six months ended June 30, 2005 and 2004, TE Products’ sharing ratio in the earnings of MB Storage was approximately 62.6% and 70.2%, respectively. During the six months ended June 30, 2005, TE Products received distributions of $7.3 million from MB Storage and contributed $1.1 million to MB Storage. During the six months ended June 30, 2004, TE Products received distributions of $5.0 million from MB Storage and contributed $17.2 million to MB Storage, of which $16.5 million was used to acquire storage assets in April 2004.

We use the equity method of accounting to account for our investments in Seaway, Centennial and MB Storage. Summarized combined financial information for Seaway, Centennial and MB Storage for the six months ended June 30, 2005 and 2004, is presented below (in thousands):

	Six Months Ended June 30,
	2005		2004
Revenues	$	81,046	$	79,890
Net income	28,191		33,524

Summarized combined balance sheet information for Seaway, Centennial and MB Storage as of June 30, 2005, and December 31, 2004, is presented below (in thousands):

	June 30, 2005		December 31, 2004
Current assets	$	68,180	$	59,314
Noncurrent assets	625,532		633,222
Current liabilities	40,483		41,209
Long-term debt	140,000		140,000
Noncurrent liabilities	22,330		20,440
Partners’ capital	490,899		490,887

NOTE 7. DEBT

Senior Notes

On January 27, 1998, TE Products completed the issuance of $180.0 million principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the “TE Products Senior Notes”). The 6.45% TE Products Senior Notes were issued at a discount of $0.3 million and are being accreted to their face value over the term of the notes. The 6.45% TE Products Senior Notes due 2008 are not subject to redemption prior to January 15, 2008. The 7.51% TE Products Senior Notes due 2028, issued at par, may be redeemed at any time after January 15, 2008, at the option of TE Products, in whole or in part, at a premium.

The TE Products Senior Notes do not have sinking fund requirements. Interest on the TE Products Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The TE Products Senior Notes are unsecured obligations of TE Products and rank pari passu with all other unsecured and unsubordinated indebtedness

of TE Products. The indenture governing the TE Products Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of June 30, 2005, TE Products was in compliance with the covenants of the TE Products Senior Notes.

On February 20, 2002, we completed the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount of $2.2 million and are being accreted to their face value over the term of the notes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 7.625% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of June 30, 2005, we were in compliance with the covenants of these Senior Notes.

On January 30, 2003, we completed the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount of $1.4 million and are being accreted to their face value over the term of the notes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 6.125% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of June 30, 2005, we were in compliance with the covenants of these Senior Notes.

The following table summarizes the estimated fair values of the Senior Notes as of June 30, 2005, and December 31, 2004 (in millions):

	Face Value		June 30, 2005		December 31, 2004

6.45% TE Products Senior Notes, due January 2008	$	180.0	$	188.5	$	187.1
7.625% Senior Notes, due February 2012	500.0		570.4		569.6
6.125% Senior Notes, due February 2013	200.0		212.0		210.2
7.51% TE Products Senior Notes, due January 2028	210.0		224.1		225.6

We have entered into interest rate swap agreements to hedge our exposure to changes in the fair value on a portion of the Senior Notes discussed above (see Note 3. Interest Rate Swaps).

Other Long Term Debt and Credit Facilities

On June 27, 2003, we entered into a $550.0 million revolving credit facility with a three-year term, including the issuance of letters of credit of up to $20.0 million (“Revolving Credit Facility”). The interest rate is based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Revolving Credit Facility contains certain restrictive financial covenant ratios. On October 21, 2004, we amended our Revolving Credit Facility to (i) increase the facility size to $600.0 million, (ii) extend the term to October 21, 2009, (iii) remove certain restrictive covenants, (iv) increase the available amount for the issuance of letters of credit up to $100.0 million and (v) decrease the LIBOR rate spread charged at the time of each borrowing. On February 23, 2005, we

again amended our Revolving Credit Facility to remove the requirement that DEFS must at all times own, directly or indirectly, 100% of our General Partner, to allow for its acquisition by DFI (see Note 1. Organization and Basis of Presentation). During the second quarter of 2005, we used a portion of the proceeds from equity offerings in May 2005 and June 2005 to repay a portion of the Revolving Credit Facility (see Note 8. Partners’ Capital and Distributions). At June 30, 2005, $278.0 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 4.3%. At June 30, 2005, we were in compliance with the covenants of this credit agreement.

The following table summarizes the principal amounts outstanding under all of our credit facilities as of June 30, 2005, and December 31, 2004 (in thousands):

	June 30, 2005		December 31, 2004

Credit Facilities:
Revolving Credit Facility, due October 2009	$	278,000	$	353,000
6.45% TE Products Senior Notes, due January 2008	179,922		179,906
7.625% Senior Notes, due February 2012	498,548		498,438
6.125% Senior Notes, due February 2013	198,916		198,845
7.51% TE Products Senior Notes, due January 2028	210,000		210,000
Total borrowings	1,365,386		1,440,189
Adjustment to carrying value associated with hedges of fair value	42,008		40,037

Total Credit Facilities	$	1,407,394	$	1,480,226

NOTE 8. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Equity Offering

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

Quarterly Distributions of Available Cash

We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. Pursuant to the Partnership Agreement, the Company receives incremental incentive cash distributions when cash distributions exceed certain target thresholds as follows:

			General
	Unitholders		Partner
Quarterly Cash Distribution per Unit:
Up to Minimum Quarterly Distribution ($0.275 per Unit)	98	%	2	%
First Target – $0.276 per Unit up to $0.325 per Unit	85	%	15	%
Second Target – $0.326 per Unit up to $0.45 per Unit	75	%	25	%
Over Second Target – Cash distributions greater than $0.45 per Unit	50	%	50	%

The following table reflects the allocation of total distributions paid during the six months ended June 30, 2005 and 2004 (in thousands, except per Unit amounts):

	Six Months Ended June 30,
	2005		2004
Limited Partner Units	$	83,473	$	82,686
General Partner Ownership Interest	1,703		1,687
General Partner Incentive	32,140		31,368
Total Cash Distributions Paid	$	117,316	$	115,741
Total Cash Distributions Paid Per Unit	$	1.325	$	1.3125

On August 5, 2005, we will pay a cash distribution of $0.675 per Unit for the quarter ended June 30, 2005. The second quarter 2005 cash distribution will total $66.9 million.

General Partner’s Interest

As of June 30, 2005, and December 31, 2004, we had deficit balances of $40.3 million and $33.0 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. The General Partner’s equity account generally consists of its cumulative share of our net income less cash distributions made to it plus capital contributions that it has made to us (see our Consolidated Statement of Partners’ Capital for a detail of the General Partner’s equity account). For the six months ended June 30, 2005, the General Partner was allocated $26.6 million (representing 29.27%) of our net income and received $33.8 million in cash distributions.

Capital Accounts, as defined under our Partnership Agreement, are maintained for our General Partner and our 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 accounting principles generally accepted in the United States in our financial statements. Under our Partnership Agreement, the General Partner is required to make additional capital contributions to us upon the issuance of any additional Units if necessary to maintain a Capital Account balance equal to 1.999999% of the total Capital Accounts of all partners. At June 30, 2005, and December 31, 2004, the General Partner’s Capital Account balance substantially exceeded this requirement.

Net income 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. This is generally consistent with the manner of allocating net income under our Partnership Agreement. Net income determined under our Partnership Agreement, however, incorporates principles established for U.S. federal income tax purposes and is not comparable to net income reflected under accounting principles generally accepted in the United States in our financial statements.

Cash distributions that we make during a period may exceed our net income for the period. We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. Cash distributions in excess of net income allocations and capital contributions during the year ended December 31, 2004, and the six months ended June 30, 2005, resulted in deficits in the General Partner’s equity account at December 31, 2004, and June 30, 2005. Future cash distributions that exceed net income will result in an increase in the deficit balance in the General Partner’s equity account.

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.

NOTE 9. EMPLOYEE BENEFIT PLANS

Retirement Plans

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

On May 27, 2005, the TEPPCO RCBP and the TEPPCO SBP were amended. Effective May 31, 2005, participation in the TEPPCO RCBP was frozen and no new participants were eligible to be covered by the plan after that date. Effective December 31, 2005, all plan benefits accrued will be frozen and participants will not receive additional pay credits after that date. In addition, all plan participants will be 100% vested regardless of their years of service. Effective January 1, 2006, the TEPPCO RCBP plan will be terminated and plan participants will receive lump sum benefit payments in 2006. Participants in the TEPPCO SBP will receive pay credits through November 30, 2005, and will receive lump sum benefit payments in December 2005. Both lump sum benefit payments are discussed below.

In June 2005, we recorded a curtailment charge of $0.1 million in accordance with SFAS No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, as a result of the TEPPCO RCBP and TEPPCO SBP amendments. As of May 31, 2005, the following assumptions were changed for purposes of determining the net periodic benefit costs for the remainder of 2005: the discount rate, the long-term rate of return on plan assets, and the assumed mortality table. The discount rate was decreased from 5.75% to 5.00% to reflect rates of returns on bonds currently available to settle the liability. The expected long-term rate of return on plan assets was changed from 8% to 2% due to the movement of plan funds from equity investments into short-term money market funds. The mortality table was changed to reflect overall improvements in mortality experienced by the general population. The curtailment charge arose due to the accelerated recognition of the unrecognized prior service costs. We expect to record additional settlement charges of approximately $0.2 million in the fourth quarter of 2005 relating to the TEPPCO SBP and approximately $3.2 million in 2006 relating to the TEPPCO RCBP for any existing unrecognized losses upon the plan termination and final distribution of the assets to the plan participants.

The components of net pension benefits costs for the TEPPCO RCBP and the TEPPCO SBP for the three months and six months ended June 30, 2005 and 2004, were as follows (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
Service cost benefit earned during the period	$	1,069		$	913		$	2,099		$	1,826
Interest cost on projected benefit obligation	234			180			468			360
Expected return on plan assets	(223		)	(220		)	(520		)	(440		)
Amortization of prior service cost	1			2			3			4
Recognized net actuarial loss	30			14			56			28
SFAS 88 curtailment charge	50			—			50			—
Net pension benefits costs	$	1,161		$	889		$	2,156		$	1,778

Estimated Future Benefit Contributions

We expect to contribute approximately $1.1 million to our retirement plans and other postretirement benefit plans in 2005.

NOTE 10. SEGMENT INFORMATION

We have three reporting segments:

• transportation and storage of refined products, LPGs and petrochemicals, which operates as the Downstream Segment;

• gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals, which operates as the Upstream Segment; and

• gathering of natural gas, fractionation of NGLs and transportation of NGLs, which operates as the Midstream Segment.

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

Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. The two largest operating expense items of the Downstream Segment are labor and electric power. We generally realize higher revenues during the first and fourth quarters of each year since our operations are somewhat seasonal. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand in the Northeast for propane, a major fuel for residential heating. Our Downstream Segment also includes the results of operations of the northern portion of the Dean Pipeline, which transports refinery grade propylene from Mont Belvieu to Point Comfort, Texas. Our Downstream Segment also includes our equity investments in Centennial and MB Storage (see Note 6. Equity Investments).

Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals, principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Marketing operations consist primarily of aggregating purchased crude oil along our pipeline systems, or from third party pipeline systems, and arranging the necessary transportation logistics for the ultimate sale of the crude oil to local refineries, marketers or other end users. Our Upstream Segment also includes our equity investment in Seaway (see Note 6. Equity Investments). Seaway consists of large diameter pipelines that transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, a crude oil distribution point for the central United States, and to refineries in the Texas City and Houston areas.

Our Midstream Segment revenues are earned from the fractionation of NGLs in Colorado, transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from West Texas and New Mexico to Mont Belvieu; the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, and the gathering of coal bed methane (“CBM”) and conventional natural gas in the San Juan Basin in New Mexico and Colorado, through Val Verde.

The table below includes financial information by reporting segment for the three months and six months ended June 30, 2005 and 2004 (in thousands):

	Three Months Ended June 30, 2005
	Downstream Segment			Upstream Segment			Midstream Segment		Segments Total			Partnership and Other			Consolidated

Sales of petroleum products	$	—		$	1,961,302		$	2,315	$	1,963,617		$	—		$	1,963,617
Operating revenues	63,438			11,698			52,336		127,472			(709		)	126,763
Purchases of petroleum products	—			1,942,599			1,806		1,944,405			(709		)	1,943,696
Operating expenses, including power	38,680			15,214			11,903		65,797			—			65,797
Depreciation and amortization expense	9,801			3,651			12,840		26,292			—			26,292
Gains on sales of assets	(15		)	(53		)	—		(68		)	—			(68		)
Operating income	14,972			11,589			28,102		54,663			—			54,663
Equity earnings	892			8,170			—		9,062			—			9,062
Other income, net	121			(46		)	60		135			—			135
Earnings before interest	$	15,985		$	19,713		$	28,162	$	63,860		$	—		$	63,860

	Three Months Ended June 30, 2004
	Downstream Segment			Upstream Segment			Midstream Segment		Segments Total			Partnership and Other			Consolidated

Sales of petroleum products	$	—		$	1,231,019		$	1,788	$	1,232,807		$	—		$	1,232,807
Operating revenues	62,364			11,841			48,216		122,421			(664		)	121,757
Purchases of petroleum products	—			1,216,307			1,669		1,217,976			(664		)	1,217,312
Operating expenses, including power	38,551			15,050			14,905		68,506			—			68,506
Depreciation and amortization expense	9,211			3,045			14,155		26,411			—			26,411
Gains on sales of assets	(17		)	(49		)	—		(66		)	—			(66		)
Operating income	14,619			8,507			19,275		42,401			—			42,401
Equity earnings (losses)	(509		)	12,091			—		11,582			—			11,582
Other income, net	173			51			16		240			—			240
Earnings before interest	$	14,283		$	20,649		$	19,291	$	54,223		$	—		$	54,223

	Six Months Ended June 30, 2005
	Downstream Segment			Upstream Segment			Midstream Segment			Segments Total			Partnership and Other			Consolidated

Sales of petroleum products	$	—		$	3,346,369		$	4,457		$	3,350,826		$	—		$	3,350,826
Operating revenues	141,605			23,411			103,192			268,208			(2,049		)	266,159
Purchases of petroleum products	—			3,315,029			3,176			3,318,205			(2,049		)	3,316,156
Operating expenses, including power	75,866			30,659			25,796			132,321			—			132,321
Depreciation and amortization expense	19,362			7,152			25,541			52,055			—			52,055
Gains on sales of assets	(107		)	(52		)	(407		)	(566		)	—			(566		)
Operating income	46,484			16,992			53,543			117,019			—			117,019
Equity earnings	50			14,258			—			14,308			—			14,308
Other income, net	270			29			102			401			—			401
Earnings before interest	$	46,804		$	31,279		$	53,645		$	131,728		$	—		$	131,728

	Six Months Ended June 30, 2004
	Downstream Segment			Upstream Segment			Midstream Segment		Segments Total			Partnership and Other			Consolidated

Sales of petroleum products	$	—		$	2,411,786		$	3,134	$	2,414,920		$	—		$	2,414,920
Operating revenues	137,173			25,564			97,033		259,770			(2,065		)	257,705
Purchases of petroleum products	—			2,383,732			2,986		2,386,718			(2,065		)	2,384,653
Operating expenses, including power	78,601			29,076			29,886		137,563			—			137,563
Depreciation and amortization expense	18,288			6,113			29,830		54,231			—			54,231
Gains on sales of assets	(17		)	(107		)	—		(124		)	—			(124		)
Operating income	40,301			18,536			37,465		96,302			—			96,302
Equity earnings (losses)	(1,747		)	18,980			—		17,233			—			17,233
Other income, net	445			197			74		716			—			716
Earnings before interest	$	38,999		$	37,713		$	37,539	$	114,251		$	—		$	114,251

The following table shows total assets and capital expenditures for each segment as of and for the periods ended June 30, 2005, and December 31, 2004 (in thousands):

	Downstream Segment		Upstream Segment		Midstream Segment		Segments Total		Partnership and Other			Consolidated

June 30, 2005:
Total assets	$	971,980	$	1,321,018	$	1,213,233	$	3,506,231	$	(25,755	)	$	3,480,476
Capital expenditures	27,322		19,746		35,383		82,451		512			82,963

December 31, 2004:
Total assets	$	968,993	$	1,070,477	$	1,184,184	$	3,223,654	$	(25,949	)	$	3,197,705
Capital expenditures	80,930		37,448		45,075		163,453		694			164,147

The following table reconciles the segments’ total earnings before interest to consolidated net income for the three months and six months ended June 30, 2005 and 2004 (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Earnings before interest	$	63,860		$	54,223		$	131,728		$	114,251
Interest expense – net	(21,627		)	(16,464		)	(40,914		)	(36,059		)
Net income	$	42,233		$	37,759		$	90,814		$	78,192

NOTE 11. COMMITMENTS AND CONTINGENCIES

In the fall of 1999 and on December 1, 2000, the General Partner and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. (including the General Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et al. (including the General Partner and Partnership). In both cases, the plaintiffs contend, among other things, that we and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In their complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. On January 27, 2005, we entered into Release and Settlement Agreements with the McCleery plaintiffs and the Richards plaintiffs dismissing all of these plaintiffs’ claims. The settlement terms included a $2.0 million payment to the plaintiffs, which was accrued at December 31, 2004.

Although we did not settle with all plaintiffs and we therefore remain named parties in the Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. action, a co-defendant has agreed to indemnify us for all remaining claims asserted against us. Consequently, we do not believe that the outcome of these remaining claims will have a material adverse effect on our financial position, results of operations or cash flows.

On December 21, 2001, TE Products was named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana, styled Rebecca L. Grisham et al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that our pipeline, which crosses the plaintiffs’ property, leaked toxic products onto their property and, consequently caused damages to them. We have filed an answer to the plaintiffs’

petition denying the allegations, and we are defending ourselves vigorously against the lawsuit. The plaintiffs have not stipulated the amount of damages they are seeking in the suit; however, this case is covered by insurance. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

In May 2003, the General Partner was named as a defendant in a lawsuit styled John R. James, et al. v. J Graves Insulation Company, et al. as filed in the first Judicial District Court, Caddo Parish, Louisiana. There are numerous plaintiffs identified in the action that are alleged to have suffered damages as a result of alleged exposure to asbestos-containing products and materials. According to the petition and as a result of a preliminary investigation, the General Partner believes that the only claim asserted against it results from one individual for the period from July 1971 through June 1972, who is alleged to have worked on a facility owned by the General Partner’s predecessor. This period represents a small portion of the total alleged exposure period from January 1964 through December 2001 for this individual. The individual’s claims involve numerous employers and alleged job sites. The General Partner has been unable to confirm involvement by the General Partner or its predecessors with the alleged location, and it is uncertain at this time whether this case is covered by insurance. Discovery is planned, and the General Partner intends to defend itself vigorously against this lawsuit. The plaintiffs have not stipulated the amount of damages that they are seeking in this suit. We are obligated to reimburse the General Partner for any costs it incurs related to this lawsuit. We cannot estimate the loss, if any, associated with this pending lawsuit. 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 April 2, 2003, Centennial was served with a petition in a matter styled Adams, et al. v. Centennial Pipeline Company LLC, et al. This matter involves approximately 2,000 plaintiffs who allege that over 200 defendants, including Centennial, generated, transported, and/or disposed of hazardous and toxic waste at two sites in Bayou Sorrell, Louisiana, an underground injection well and a landfill. The plaintiffs allege personal injuries, allergies, birth defects, cancer and death. The underground injection well has been in operation since May 1976. Based upon current information, Centennial appears to be a de minimis contributor, having used the disposal site during the two month time period of December 2001 to January 2002. Marathon has been handling this matter for Centennial under its operating agreement with Centennial. TE Products has a 50% ownership interest in Centennial. On November 30, 2004, the court approved a class settlement, which included an $80,000 payment by Centennial. The time period for parties to appeal this settlement expired in March 2005, and the class settlement became final. The terms of the settlement did not have a material adverse effect on our financial position, results of operations or cash flows.

On February 4, 2005, we received a letter notifying us of a claim for approximately $1.45 million in damages allegedly due to a shipper being delivered off-specification gasoline during November 2004. We are contesting liability for this matter, and to the extent there may be liability, we would seek reimbursement from the third party refiner who supplied the gasoline into our pipeline system. We do not believe that the outcome of this matter will have a future material adverse effect on our financial position, results of operations or cash flows.

On February 7, 2005, we received a letter from BP Amoco’s counsel placing us on notice of a lawsuit filed by ConocoPhillips against BP Amoco Seaway Products Pipeline Company. Pursuant to provisions of the Amended and Restated Purchase Agreement dated May 10, 2000, between us and ARCO Pipe Line Company (BP Amoco), BP Amoco requested indemnity should BP Amoco have any liability to ConocoPhillips. The litigation arises out of an income tax liability alleged by ConocoPhillips due to a partnership merger. The plaintiff estimates the income tax liability to be $3,964,788. We have requested information from BP Amoco that will allow us to assess liability, if any, that we may have in this matter. We do not believe that the outcome of this lawsuit will have a future material adverse effect on our financial position, results of operations or cash flows.

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

Our operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of injunctions delaying or prohibiting certain activities and the need to perform investigatory and remedial activities. Although we believe our operations are in material compliance with applicable environmental laws and regulations, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure you that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. We believe that changes in environmental laws and regulations will not have a material adverse effect on our financial position, results of operations or cash flows in the near term.

On March 26, 2004, an initial decision in ARCO Products Co., et al. v. SFPP, Docket OR96-2-000, et al. was issued by the FERC, which made several significant determinations with respect to finding “changed circumstances” under the Energy Policy Act of 1992 (“EP Act”). The decision largely clarifies, but does not fully quantify, the standard required for a complainant to demonstrate that an oil pipeline’s rates are no longer subject to the rate protection of the EP Act by demonstrating that a substantial change in circumstances has occurred since 1992 with respect to the basis of the rates being challenged. In the decision, the FERC found that a limited number of rate elements will significantly affect the economic basis for a pipeline company’s rates. The elements identified in the decision are volume changes, allowed total return and total cost-of-service (including major cost elements such as rate base, tax rates and tax allowances, among others). The FERC did reject, however, the use of changes in tax rates and income tax allowances as standalone factors. Judicial review of that decision, which has been sought by a number of parties to the case, is currently pending before the U.S. Court of Appeals for the District of Columbia Circuit. We have not yet determined the impact, if any, that the decision, if it is ultimately upheld, would have on our rates if they were reviewed under the criteria of this decision.

On July 20, 2004, the District of Columbia Circuit issued an opinion in BP West Coast Products LLC v. FERC. In reviewing a series of orders involving SFPP, L.P., the court held among other things that the FERC had not adequately justified its policy of providing an oil pipeline limited partnership with an income tax allowance equal to the proportion of its income attributable to partnership interests owned by corporate partners. Under the FERC’s initial ruling, SFPP, L.P. was permitted an income tax allowance on its cost-of-service filing for the percentage of its net operating (pre-tax) income attributable to partnership units held by corporations, and was denied an income tax allowance equal to the percentage attributable to partnership units held by non-corporate partners. The court remanded the case back to the FERC for further review. As a result of the court’s remand, on December 2, 2004, the FERC issued a Request for Comments seeking comments on whether the court’s ruling applies only to the specific facts of the SFPP, L.P. proceeding or also extends to other capital structures involving partnerships and other forms of ownership. On May 4, 2005, the FERC issued its Policy Statement on Income Tax Allowances, which permits regulated partnerships, limited liability companies and other pass-through entities an income tax allowance on their income attributable to any owner that has an actual or potential income tax liability on that income, regardless whether the owner is an individual or corporation. If there is more than one level of pass-through entities, the regulated company income must be traced to where the ultimate tax liability lies. The Policy Statement is to be applied in individual cases, and the regulated entity bears the burden of proof to establish the tax status of its owners. On June 1, 2005, the FERC issued an Order on Remand in the SFPP, L.P. proceedings holding the Policy Statement would apply in that case and requesting briefs on whether additional evidence was necessary to apply it. Briefs have

been filed but the FERC has not yet acted on them. The ultimate outcome of the FERC’s inquiry on income tax allowance should not affect our current rates and rate structure because our rates are not based on cost-of-service methodology. However, the outcome of the income tax allowance would become relevant to us should we (i) elect in the future to use cost-of-service to support our rates, or (ii) be required to use such methodology to defend our indexed rates.

In 1994, the Louisiana Department of Environmental Quality (“LDEQ”) issued a compliance order for environmental contamination at our Arcadia, Louisiana facility. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this contamination. At June 30, 2005, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. 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. We do not expect that the completion of the remediation program proposed to the LDEQ will have a future material adverse effect on our financial position, results of operations or cash flows.

On March 17, 2003, we experienced a release of 511 barrels of jet fuel from a storage tank at our Blue Island terminal located in Cook County, Illinois. As a result of the release, we have entered into an Agreed Order with the State of Illinois, which required us to conduct an environmental investigation. At this time, we have complied with the terms of the Agreed Order, and the results of the environmental investigation indicated there were no soil or groundwater impacts from the release. We are in the process of negotiating a final settlement with the State of Illinois, and we do not expect that compliance with the settlement will have a future material adverse effect on our financial position, results of operations or cash flows.

On July 22, 2004, we experienced a release of approximately 12 barrels of jet fuel from a sump at our Lebanon, Ohio, terminal. The released jet fuel was contained within a storm water retention pond located on the terminal property. Six migratory waterfowl were affected by the jet fuel and were subsequently euthanized by or at the request of the United States Fish and Wildlife Service (“USFWS”). On October 1, 2004, the USFWS served us with a Notice of Violation, alleging that we violated 16 USC 703 of the Migratory Bird Treaty Act for the “take[ing] of migratory birds by illegal methods.” On February 7, 2005, we entered into a Memorandum of Understanding (“MOU”) with the USFWS, and on June 23, 2005, we notified the USFWS that we had completed all requirements under the MOU, thus terminating the agreement and settling all aspects of this matter. The terms of this settlement did not have a material effect on our financial position, results of operations or cash flows.

On July 27, 2004, we received notice from the United States Department of Justice (“DOJ”) of its intent to seek a civil penalty against us related to our November 21, 2001, release of approximately 2,575 barrels of jet fuel from our 14-inch diameter pipeline located in Orange County, Texas. The DOJ, at the request of the Environmental Protection Agency, is seeking a civil penalty against us for alleged violations of the Clean Water Act (“CWA”) arising out of this release. The maximum statutory penalty calculated for this alleged violation of the CWA is $2.8 million. We are in discussions with the DOJ regarding this matter and have responded to its request for additional information. We do not expect a civil penalty, if any, to have a material adverse effect on our financial position, results of operations or cash flows.

At June 30, 2005, we have an accrued liability of $4.1 million related to various TCTM and TE Products sites requiring environmental remediation activities. We do not expect that the completion of remediation programs associated with TCTM and TE Products activities will have a future material adverse effect on our financial position, results of operations or cash flows.

Centennial entered into credit facilities totaling $150.0 million, and as of June 30, 2005, $150.0 million was outstanding under those credit facilities. The proceeds were used to fund construction and conversion costs of its pipeline system. TE Products and Marathon have each guaranteed one-half of Centennial’s debt, up to a maximum amount of $75.0 million each.

On February 24, 2005, the General Partner was acquired from DEFS by DFI. The General Partner owns a 2% general partner interest in us and is the general partner of the Partnership. On March 11, 2005, the Bureau of Competition of the Federal Trade Commission (“FTC”) delivered written notice to DFI’s legal advisor that it was conducting a non-public investigation to determine whether DFI’s acquisition of the General Partner may substantially lessen competition. The FTC has contacted the General Partner requesting data. The General Partner intends to cooperate fully with any such investigations and inquiries requested by the FTC or any other regulatory authorities.

NOTE 12. COMPREHENSIVE INCOME

SFAS No. 130, Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments and unrealized gains and losses on certain investments to be reported in a financial statement. As of and for the six months ended June 30, 2004, the components of comprehensive income were due to the interest rate swap related to our variable rate revolving credit facility, which was designated as a cash flow hedge. The interest rate swap matured in April 2004. While the interest rate swap was in effect, changes in the fair value of the cash flow hedge, to the extent the hedge was effective, were recognized in other comprehensive income until the hedge interest costs were recognized in net income. All other comprehensive income was recognized in net income during the six months ended June 30, 2004.

The table below reconciles reported net income to total comprehensive income for the three months and six months ended June 30, 2005 and 2004 (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
Net income	$	42,233	$	37,759	$	90,814	$	78,192
Net income on cash flow hedge	—		220		—		2,902
Total comprehensive income	$	42,233	$	37,979	$	90,814	$	81,094

The accumulated balance of other comprehensive loss related to our cash flow hedge is as follows (in thousands):

Balance at December 31, 2003	$	(2,902	)
Transferred to earnings	2,939
Change in fair value of cash flow hedge	(37		)
Balance at December 31, 2004	$	—

NOTE 13. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Our significant operating subsidiaries, 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., have issued unconditional guarantees of our debt securities. The guarantees are full, unconditional, and joint and several. 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. are collectively referred to as the “Guarantor Subsidiaries.”

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.

	June 30, 2005
	TEPPCO Partners, L.P.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Assets
Current assets	$	36,236	$	70,843	$	794,408	$	(52,885	)	$	848,602
Property, plant and equipment – net	—		1,250,727		539,139		—			1,789,866
Equity investments	1,273,806		478,751		206,639		(1,586,149		)	373,047
Intercompany notes receivable	1,007,646		—		—		(1,007,646		)	—
Intangible assets	—		360,049		33,222		—			393,271
Other assets	5,487		25,561		44,642		—			75,690
Total assets	$	2,323,175	$	2,185,931	$	1,618,050	$	(2,646,680	)	$	3,480,476
Liabilities and partners’ capital
Current liabilities	$	37,913	$	118,669	$	682,878	$	(52,885	)	$	786,575
Long-term debt	1,010,024		397,370		—		—			1,407,394
Intercompany notes payable	—		496,282		511,365		(1,007,647		)	—
Other long term liabilities	1,460		9,759		1,510		—			12,729
Total partners’ capital	1,273,778		1,163,851		422,297		(1,586,148		)	1,273,778
Total liabilities and partners’ capital	$	2,323,175	$	2,185,931	$	1,618,050	$	(2,646,680	)	$	3,480,476

	December 31, 2004
	TEPPCO Partners, L.P.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Assets
Current assets	$	44,125	$	87,068	$	576,365	$	(62,928	)	$	644,630
Property, plant and equipment – net	—		1,211,312		492,390		—			1,703,702
Equity investments	1,021,476		430,688		203,796		(1,282,308		)	373,652
Intercompany notes receivable	1,084,034		—		—		(1,084,034		)	—
Intangible assets	—		372,621		34,737		—			407,358
Other assets	5,980		22,183		40,200		—			68,363
Total assets	$	2,155,615	$	2,123,872	$	1,347,488	$	(2,429,270	)	$	3,197,705
Liabilities and partners’ capital
Current liabilities	$	45,255	$	143,589	$	556,474	$	(62,930	)	$	682,388
Long-term debt	1,086,909		393,317		—		—			1,480,226
Intercompany notes payable	—		676,993		407,040		(1,084,033		)	—
Other long term liabilities	2,003		9,980		1,660		—			13,643
Total partners’ capital	1,021,448		899,993		382,314		(1,282,307		)	1,021,448
Total liabilities and partners’ capital	$	2,155,615	$	2,123,872	$	1,347,488	$	(2,429,270	)	$	3,197,705

	Three Months Ended June 30, 2005
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	103,657		$	1,987,432		$	(709	)	$	2,090,380
Costs and expenses	—		69,269			1,967,225			(709		)	2,035,785
Gains on sales of assets	—		(15		)	(53		)	—			(68		)
Operating income	—		34,403			20,260			—			54,663
Interest expense – net	—		(14,257		)	(7,370		)	—			(21,627		)
Equity earnings	42,233		21,925			8,170			(63,266		)	9,062
Other income – net	—		162			(27		)	—			135
Net income	$	42,233	$	42,233		$	21,033		$	(63,266	)	$	42,233

	Three Months Ended June 30, 2004
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	98,813		$	1,256,415		$	(664	)	$	1,354,564
Costs and expenses	—		71,431			1,241,462			(664		)	1,312,229
Gains on sales of assets	—		(17		)	(49		)	—			(66		)
Operating income	—		27,399			15,002			—			42,401
Interest expense – net	—		(11,219		)	(5,245		)	—			(16,464		)
Equity earnings	37,759		21,393			12,091			(59,661		)	11,582
Other income – net	—		186			54			—			240
Net income	$	37,759	$	37,759		$	21,902		$	(59,661	)	$	37,759

	Six Months Ended June 30, 2005
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	221,582		$	3,397,452		$	(2,049	)	$	3,616,985
Costs and expenses	—		137,048			3,365,533			(2,049		)	3,500,532
Gains on sales of assets	—		(514		)	(52		)	—			(566		)
Operating income	—		85,048			31,971			—			117,019
Interest expense – net	—		(27,275		)	(13,639		)	—			(40,914		)
Equity earnings	90,814		32,696			14,258			(123,460		)	14,308
Other income – net	—		345			56			—			401
Net income	$	90,814	$	90,814		$	32,646		$	(123,460	)	$	90,814

	Six Months Ended June 30, 2004
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	210,701		$	2,463,989		$	(2,065	)	$	2,672,625
Costs and expenses	—		144,847			2,433,665			(2,065		)	2,576,447
Gains on sales of assets	—		(17		)	(107		)	—			(124		)
Operating income	—		65,871			30,431			—			96,302
Interest expense – net	—		(24,011		)	(12,048		)	—			(36,059		)
Equity earnings	78,192		35,840			18,980			(115,779		)	17,233
Other income – net	—		492			224			—			716
Net income	$	78,192	$	78,192		$	37,587		$	(115,779	)	$	78,192

	Six Months Ended June 30, 2005
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Cash flows from operating activities
Net income	$	90,814		$	90,814		$	32,646		$	(123,460	)	$	90,814
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	—			39,820			12,235			—			52,055
Earnings (losses) in equity investments, net of distributions	26,502			(1,732		)	(2,511		)	(17,520		)	4,739
Gains on sales of assets	—			(514		)	(52		)	—			(566		)
Changes in assets and liabilities and other	74,856			(30,004		)	(91,052		)	(76,242		)	(122,442		)
Net cash provided by (used in) operating activities	192,172			98,384			(48,734		)	(217,222		)	24,600

Cash flows from investing activities	(278,832		)	(2,606		)	(62,094		)	217,488			(126,044		)
Cash flows from financing activities	86,516			(108,122		)	108,244			(122		)	86,516
Net decrease in cash and cash equivalents	(144		)	(12,344		)	(2,584		)	144			(14,928		)
Cash and cash equivalents at beginning of period	4,116			13,596			2,826			(4,116		)	16,422
Cash and cash equivalents at end of period	$	3,972		$	1,252		$	242		$	(3,972	)	$	1,494

	Six Months Ended June 30, 2004
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Cash flows from operating activities
Net income	$	78,192		$	78,192		$	37,587		$	(115,779	)	$	78,192
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	—			43,066			11,165			—			54,231
Earnings (losses) in equity investments, net of distributions	(21,109		)	(7,543		)	(3,080		)	35,349			3,617
Gains on sales of assets	—			(17		)	(107		)	—			(124		)
Changes in assets and liabilities and other	(67,886		)	(1,978		)	2,389			63,607			(3,868		)
Net cash provided by (used in) operating activities	(10,803		)	111,720			47,954			(16,823		)	132,048

Cash flows from investing activities	98			(3,690		)	(21,069		)	(57,261		)	(81,922		)
Cash flows from financing activities	(7,083		)	(116,019		)	(31,612		)	88,973			(65,741		)
Net decrease in cash and cash equivalents	(17,788		)	(7,989		)	(4,727		)	14,889			(15,615		)
Cash and cash equivalents at beginning of period	19,744			19,243			5,670			(15,188		)	29,469

Cash and cash equivalents at end of period	$	1,956		$	11,254		$	943		$	(299	)	$	13,854

NOTE 14. SUBSEQUENT EVENTS

On July 12, 2005, we purchased a refined products terminal and truck rack in North Little Rock, Arkansas for $6.8 million from Exxon Mobil Corporation. The assets include three storage tanks and a two-bay truck loading rack. We funded the purchase through borrowings under our revolving credit facility. The terminal serves the central Arkansas refined products market and complements our existing Downstream Segment infrastructure in North Little Rock, Arkansas.

We have initiated an expansion of our refined products origin capabilities in the Houston, Texas, and Texas City, Texas areas. As part of that project, on July 15, 2005, we acquired from Texas Genco LLC (“Genco”) all of its interests in certain companies that own a 90-mile pipeline system and 5.5 million barrels of storage capacity for $70.6 million (including $8.6 million for the estimated value of inventory). According to the terms of the purchase and sale agreement with Genco, we will sell the acquired inventory (anticipated to occur in the third quarter of 2005) and use the proceeds from the sale to offset the purchase price of the inventory, including costs incurred to consummate the sale. To the extent the proceeds from the inventory sale, including costs incurred to consummate the sale, are greater than or less than the estimated amount previously paid to Genco, a final settlement payment will occur between Genco and us, resulting in no gain or loss being recognized by us on the sale of the inventory. We funded the purchase through borrowings under our revolving credit facility. The assets of the purchased companies will be integrated into our Downstream Segment origin infrastructure in Texas City and Baytown, Texas. The integration and other system enhancements should be in service by the fourth quarter of 2006, at an estimated cost of $45.0 million. The strategic location of these assets, with refined products interconnections to major exchange terminals in the Houston area, will provide significant long-term value to our customers and the Texas Gulf Coast refining and logistics system.

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

General

You should read the following review of our financial position and results of operations in conjunction with our Consolidated Financial Statements and the notes thereto. Material period-to-period variances in the consolidated statements of income are discussed under “Results of Operations.” The “Financial Condition and Liquidity” section analyzes our cash flows and financial position. “Other Considerations” addresses trends, future plans and contingencies that are reasonably likely to materially affect our future liquidity or earnings. The Consolidated Financial Statements should 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, 2004.

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 detailed in our consolidated financial statements for the year ended December 31, 2004, included in our Annual Report on Form 10-K. Certain of these accounting policies require the use of estimates. 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; environmental costs; asset impairment analysis related to property, plant and equipment; and amortization expense and asset impairment analysis related to goodwill and other 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 condition and results of operations.

Management Overview of the Three Months and Six Months Ended June 30, 2005

We reported net income of $42.2 million, or $0.45 per Limited Partner Unit (“Unit” or “Units”), for the three months ended June 30, 2005, compared with net income of $37.8 million, or $0.43 per Unit, for the three months ended June 30, 2004. Net income was $90.8 million, or $0.99 per Unit, for the six months ended June 30, 2005, compared with net income of $78.2 million, or $0.88 per Unit, for the six months ended June 30, 2004. The weighted average number of Units outstanding was 66.6 million and 63.0 million for the three months ended June 30, 2005 and 2004, respectively, and 64.8 million and 63.0 million for the six months ended June 30, 2005 and 2004, respectively.

Our Downstream Segment results for the three months ended June 30, 2005, were impacted by increased LPG transportation revenues and long-haul volumes delivered, increased refined products tender deduction revenues and increased revenues from product location exchanges. These increases were partially offset by decreased refined products transportation revenues, increased power costs, increased pipeline operating expenses and increased rental expense from our Centennial Pipeline LLC (“Centennial”) capacity lease agreement. The results for the six months ended June 30, 2005, were impacted by increased refined products and LPG transportation revenues and volumes, partially offset by lower propane inventory fee revenues, increased pipeline operating expenses, increased rental expense from our Centennial capacity lease agreement and increased environmental assessment and remediation expenses. Additionally, pipeline integrity expenses decreased $1.4 million and $5.7 million for the three months and six months ended June 30, 2005, respectively, compared with the prior year periods. We anticipate that our pipeline integrity expenses for our Downstream Segment for 2005 will be approximately $15.2 million lower than our 2004 expenses primarily due to the completion of projects.

Our Upstream Segment results for the three months and six months ended June 30, 2005, were impacted by increased marketing volumes, gains related to marking crude oil grade and location swap contracts to market and increased transportation revenues. Increased pipeline operating costs were partially offset by decreased

32 environmental assessment and remediation expenses. Equity earnings from Seaway Crude Pipeline Company (“Seaway”) decreased compared with the prior year period primarily due to lower transportation volumes, higher operating, general and administrative expenses and a gain recognized on an inventory settlement in 2004. Pipeline integrity expenses decreased $0.3 million and $0.2 million for the three months and six months ended June 30, 2005, respectively, compared with the prior year periods. We anticipate that our 2005 pipeline integrity expenses for our Upstream Segment will be approximately $1.9 million higher than our 2004 expenses as we continue to perform pipeline inspections and repairs under our integrity management program.

Our Midstream Segment benefited from increased revenues and volumes on Jonah Gas Gathering Company (“Jonah”), resulting from our 2003 Phase III expansion and the installation of additional capacity during the fourth quarter of 2004. Revenues on Val Verde Gas Gathering Company (“Val Verde”) increased due to new connections made to the system in May and December 2004, partially offsetting the impact of reduced revenues related to the natural decline of coal bed methane (“CBM”) production from existing wells. Additionally, our operating and gas settlement expenses decreased compared with the prior year period. Pipeline integrity expenses decreased $0.6 million and $0.6 million for the three months and six months ended June 30, 2005, respectively, compared with the prior year periods. These increases to operating income were partially offset by lower gathering rates on the new connections at Val Verde, on which the gathering rates are lower than existing average rates on the system.

We are subject to economic and other factors that affect our industry. The demand for refined products is dependent upon the price, prevailing economic conditions and demographic changes in the markets served, trucking and railroad freight, agricultural usage and military usage; the demand for propane is sensitive to the weather and prevailing economic conditions; the demand for petrochemicals is dependent upon prices for products produced from petrochemicals; the demand for crude oil and petroleum products is dependent upon the price of crude oil and the products produced from the refining of crude oil; and the demand for natural gas is dependent upon the price of natural gas and the locations in which natural gas is drilled. We are also subject to regulatory factors such as the amounts we are allowed to charge our customers for the services we provide on our regulated pipeline systems.

Certain factors are inherent in our business segments as discussed in this Report. These include the safe, reliable and efficient operation of the pipelines and facilities that we own or operate while meeting increased regulations that govern the operation of our assets and the costs associated with such regulations. We are also focused on our continued growth through expansion of the assets that we own and through the acquisition of assets that complement our current operations.

We remain confident that our current strategy and focus will provide continued growth in earnings and cash distributions. These growth opportunities include:

• Continued solid performance in our Upstream Segment, as we build on our existing asset base and concentrate on acquisitions in our core operating areas;

• Continued development of the Jonah system which serves the Jonah and Pinedale fields;

• Gathering of volumes from infill drilling of CBM by producers and new connections of conventional gas in the San Juan Basin, where our Val Verde system is located; and

• Growth in our Downstream Segment, resulting from our recent capacity expansion, grass roots facility investments, acquisitions and growing demand for Gulf Coast sourced products.

On March 31, 2005, we purchased crude oil pipeline assets for $7.1 million from BP Pipelines (North America) Inc. (“BP”). The assets include approximately 158 miles of pipeline which extend from Mexia, Texas, to the Houston, Texas, area and two stations in south Houston with connections to a BP pipeline that originates in south Houston. We will integrate these assets into our South Texas pipeline system, included in our Upstream Segment, which will allow us to realize synergies within our existing asset base and will provide future growth opportunities.

capacity, receipt and delivery manifolds, interconnections to several pipelines, crude oil inventory and approximately 70 acres of land. The storage and terminaling assets will complement our existing infrastructure in Cushing and strengthen our gathering and marketing business in our Upstream Segment.

On July 12, 2005, we purchased a refined products terminal and truck rack in North Little Rock, Arkansas for $6.8 million from Exxon Mobil Corporation. The assets include three storage tanks and a two-bay truck loading rack. The terminal serves the central Arkansas refined products market and complements our existing Downstream Segment infrastructure in North Little Rock, Arkansas.

We have initiated an expansion of our refined products origin capabilities in the Houston, Texas, and Texas City, Texas areas. As part of that project, on July 15, 2005, we acquired from Texas Genco LLC (“Genco”) all of its interests in certain companies that own a 90-mile pipeline system and 5.5 million barrels of storage capacity for $70.6 million (including $8.6 million for the estimated value of inventory). According to the terms of the purchase and sale agreement with Genco, we will sell the acquired inventory (anticipated to occur in the third quarter of 2005) and use the proceeds from the sale to offset the purchase price of the inventory, including costs incurred to consummate the sale. To the extent the proceeds from the inventory sale, including costs incurred to consummate the sale, are greater than or less than the estimated amount previously paid to Genco, a final settlement payment will occur between Genco and us, resulting in no gain or loss being recognized by us on the sale of the inventory. The assets of the purchased companies will be integrated into our Downstream Segment origin infrastructure in Texas City and Baytown, Texas. The integration and other system enhancements should be in service by the fourth quarter of 2006, at an estimated cost of $45.0 million. The strategic location of these assets, with refined products interconnections to major exchange terminals in the Houston area, will provide significant long-term value to our customers and the Texas Gulf Coast refining and logistics system.

Consistent with our business strategy, we continuously evaluate possible acquisitions of assets that would complement our current operations. Such acquisition efforts involve participation by us in processes that have been made public and involve a number of potential buyers, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial position, results of operations or cash flows.

Our Business

transition services agreement entered into as part of the sale of the General Partner, DEFS will continue to provide some administrative services for certain of the TEPPCO Midstream assets for us for a period of time until we assume these services on our own. In connection with us assuming the operations of these TEPPCO Midstream assets from DEFS, certain DEFS employees became employees of EPCO effective June 1, 2005. As part of the transition services agreement, Duke Energy will continue to provide some administrative support services to us until we or EPCO assume those activities.

We operate and report in three business segments:

• Downstream Segment – transportation and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals;

• Upstream Segment – gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals; and

• Midstream Segment – gathering of natural gas, transportation of natural gas liquids (“NGLs”) and fractionation of NGLs.

Our reportable segments offer different products and services and are managed separately because each requires different business strategies. TEPPCO GP, our wholly owned subsidiary, acts as managing general partner of our Operating Partnerships, with a 0.001% general partner interest and manages our subsidiaries.

(Chaparral) from West Texas and New Mexico to Mont Belvieu; the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, and the gathering of CBM and conventional natural gas in the San Juan Basin in New Mexico and Colorado, through Val Verde.

Results of Operations

The following table summarizes financial information by business segment for the three months and six months ended June 30, 2005 and 2004 (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Operating revenues:
Downstream Segment	$	63,438		$	62,364		$	141,605		$	137,173
Upstream Segment	1,973,000			1,242,860			3,369,780			2,437,350
Midstream Segment	54,651			50,004			107,649			100,167
Intersegment eliminations	(709		)	(664		)	(2,049		)	(2,065		)
Total operating revenues	2,090,380			1,354,564			3,616,985			2,672,625

Operating income:
Downstream Segment	14,972			14,619			46,484			40,301
Upstream Segment	11,589			8,507			16,992			18,536
Midstream Segment	28,102			19,275			53,543			37,465
Total operating income	54,663			42,401			117,019			96,302

Earnings before interest:
Downstream Segment	15,985			14,283			46,804			38,999
Upstream Segment	19,713			20,649			31,279			37,713
Midstream Segment	28,162			19,291			53,645			37,539
Total earnings before interest	63,860			54,223			131,728			114,251

Interest expense	(22,780		)	(18,048		)	(43,169		)	(38,507		)
Interest capitalized	1,153			1,584			2,255			2,448
Net income	$	42,233		$	37,759		$	90,814		$	78,192

The following is a detailed analysis of the results of operations, including reasons for changes in results, by each of our operating segments.

Downstream Segment

The following table provides financial information for the Downstream Segment for the three months and six months ended June 30, 2005 and 2004 (in thousands):

	Three Months Ended									Six Months Ended
	June 30,						Increase			June 30,						Increase
	2005			2004			(Decrease)			2005			2004			(Decrease)

Transportation – Refined products	$	37,834		$	38,937		$	(1,103	)	$	72,799		$	69,908		$	2,891
Transportation – LPGs	14,470			13,721			749			46,701			42,501			4,200
Other	11,134			9,706			1,428			22,105			24,764			(2,659		)
Total operating revenues	63,438			62,364			1,074			141,605			137,173			4,432

Operating, general and administrative	28,281			28,864			(583		)	54,896			58,019			(3,123		)
Operating fuel and power	7,957			7,193			764			15,617			15,243			374
Depreciation and amortization	9,801			9,211			590			19,362			18,288			1,074
Taxes – other than income taxes	2,442			2,494			(52		)	5,353			5,339			14
Gains on sales of assets	(15		)	(17		)	2			(107		)	(17		)	(90		)
Total costs and expenses	48,466			47,745			721			95,121			96,872			(1,751		)

Operating income	14,972			14,619			353			46,484			40,301			6,183

Equity earnings (losses)	892			(509		)	1,401			50			(1,747		)	1,797
Other income – net	121			173			(52		)	270			445			(175		)

Earnings before interest	$	15,985		$	14,283		$	1,702		$	46,804		$	38,999		$	7,805

The following table presents volumes delivered in barrels and average tariff per barrel for the three months and six months ended June 30, 2005 and 2004 (in thousands, except tariff information):

	Three Months Ended				Percentage		Six Months Ended				Percentage
	June 30,				Increase		June 30,				Increase
	2005		2004		(Decrease)		2005		2004		(Decrease)
Volumes Delivered:
Refined products	42,097		41,936		1	%	80,692		74,458		8	%
LPGs	7,855		8,794		(11	)%	22,657		22,002		3	%
Total	49,952		50,730		(2	)%	103,349		96,460		7	%

Average Tariff per Barrel:
Refined products	$	0.90	$	0.93	(3	)%	$	0.90	$	0.94	(4	)%
LPGs	1.84		1.56		18	%	2.06		1.93		7	%
Average system tariff per barrel	$	1.05	$	1.04	1	%	$	1.16	$	1.17	(1	)%

Three Months Ended June 30, 2005 Compared with Three Months Ended June 30, 2004

Revenues from refined products transportation decreased $1.1 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, primarily due to a decrease in distillate volumes transported and a decrease in the refined products average rate per barrel, partially offset by an overall increase in the refined products volume delivered. The decrease in distillate volumes was a result of low distillate price differentials. The decrease in the refined products average rate per barrel from the prior year period was primarily due to the impact of greater growth in the volume of products delivered under a Centennial tariff compared with the growth in deliveries under a TEPPCO tariff, which resulted in an increased proportion of lower tariff barrels transported on our system. Prior to the construction of Centennial, deliveries on our pipeline system were limited by our pipeline capacity, and transportation services for our customers were allocated in accordance with a proration policy. With this incremental pipeline capacity, our previously constrained system has expanded deliveries in markets both south and north of Creal Springs, Illinois. In February 2003, we entered into a lease agreement with Centennial that increased our flexibility to deliver refined products to our market areas. Centennial has provided our system

with additional pipeline capacity for movement of products originating in the U.S. Gulf Coast area. The overall increase in refined products volume was primarily due to increased demand and market share for products supplied from the U.S. Gulf Coast into Midwest markets.

Revenues from LPGs transportation increased $0.7 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, due to higher deliveries of propane in the upper Midwest and Northeast market areas. The LPGs average rate per barrel increased from the prior period primarily as a result of decreased short-haul deliveries during the three months ended June 30, 2005.

Other operating revenues increased $1.4 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, primarily due to higher refined products additive and tender deduction revenue and increased margins on product inventory sales.

Costs and expenses increased $0.7 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, due to increased operating fuel and power and increased depreciation and amortization expense, partially offset by decreased operating, general and administrative expenses and decreased taxes – other than income. Operating fuel and power increased $0.8 million primarily due to increased mainline throughput and adjustments to power accruals. Depreciation expense increased $0.6 million primarily due to assets placed into service in 2005. Operating, general and administrative expenses decreased $0.6 million primarily due to a $1.4 million decrease in pipeline inspection and repair costs associated with our integrity management program and a $0.4 million decrease in consulting services and supplies primarily related to acquisition activities in 2004. These decreases were partially offset by a $0.7 million increase in pipeline operating and maintenance expenses, a $0.3 million increase in rental expense from the Centennial pipeline capacity lease agreement and a $0.2 million increase in insurance expense. Increased labor and benefits expenses associated with vesting provisions in certain of our compensation plans as a result of changes in control of our General Partner and higher incentive compensation expenses compared to the prior year period were offset by a $1.6 million decrease in postretirement benefit accruals related to plan amendments (see Note 9. Employee Benefit Plans).

Net earnings from equity investments increased for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, as shown below (in thousands):

	Three Months Ended
	June 30,						Increase
	2005			2004			(Decrease)

Centennial	$	(496	)	$	(2,286	)	$	1,790
MB Storage	1,365			1,785			(420		)
Other	23			(8		)	31
Total equity earnings (losses)	$	892		$	(509	)	$	1,401

Equity losses in Centennial decreased $1.8 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, primarily due to higher transportation revenues and volumes, partially offset by higher transmix related product replacement costs and product measurement losses during the 2005 period. Equity earnings in MB Storage decreased $0.4 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, primarily due to higher pipeline rehabilitation expenses on the MB Storage system.

Six Months Ended June 30, 2005 Compared with Six Months Ended June 30, 2004

Revenues from refined products transportation increased $2.9 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, due to an overall increase in the refined products volumes delivered. This increase was primarily due to deliveries of products moved on Centennial. Volume increases were due to increased demand and market share for products supplied from the U.S. Gulf Coast into Midwest markets. The refined products average rate per barrel decreased from the prior year period primarily due to the impact of

greater growth in the volume of products delivered under a Centennial tariff compared with the growth in deliveries under a TEPPCO tariff, which resulted in an increased proportion of lower tariff barrels transported on our system.

Revenues from LPGs transportation increased $4.2 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, due to higher deliveries of propane in the upper Midwest and Northeast market areas primarily resulting from cold weather in March 2005. Prior year LPG transportation revenues were negatively impacted by a price spike in the Mont Belvieu propane price in late February 2004, which resulted in TEPPCO sourced propane being less competitive than propane from other source points.

Other operating revenues decreased $2.7 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, primarily due to lower propane inventory fees in 2005 and lower volume of product inventory sales, partially offset by higher refined products tender deduction and loading revenues.

Costs and expenses decreased $1.8 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, due to decreased operating, general and administrative expenses, partially offset by increased depreciation and amortization expense and increased operating fuel and power. Operating, general and administrative expenses decreased $3.1 million primarily due to a $5.7 million decrease in pipeline inspection and repair costs associated with our integrity management program, a $1.6 million decrease in postretirement benefit accruals related to plan amendments (see Note 9. Employee Benefit Plans) and a $0.3 million decrease in consulting services primarily related to acquisition related activities in 2004. These decreases were partially offset by a $2.4 million increase in labor and benefits expenses associated with vesting provisions in certain of our compensation plans as a result of changes in control of our General Partner and higher incentive compensation expenses compared to the prior year period, a $1.0 million increase in rental expense from the Centennial pipeline capacity lease agreement, a $0.6 million increase in environmental remediation and assessment costs and a $0.6 million increase in pipeline operating and maintenance expense. Depreciation expense increased $1.1 million primarily due to assets placed into service and assets retired to depreciation expense in 2005. Operating fuel and power increased $0.4 million primarily due to increased mainline throughput and adjustments to power accruals.

Net earnings from equity investments increased for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, as shown below (in thousands):

	Six Months Ended
	June 30,						Increase
	2005			2004			(Decrease)

Centennial	$	(3,967	)	$	(6,143	)	$	2,176
MB Storage	3,998			4,414			(416		)
Other	19			(18		)	37
Total equity earnings (losses)	$	50		$	(1,747	)	$	1,797

Equity losses in Centennial decreased $2.2 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, primarily due to higher transportation revenues and volumes, partially offset by higher transmix related product replacement costs and product measurement losses during the 2005 period. Equity earnings in MB Storage decreased $0.4 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, primarily due to increased depreciation and amortization expense, higher pipeline rehabilitation expenses and higher general and administrative expenses, partially offset by higher revenues and volumes. In April 2004, MB Storage acquired storage and pipeline assets and contracts for approximately $34.0 million, of which TE Products contributed $16.5 million. Increases in storage revenue, shuttle revenue, rental revenue and depreciation and amortization expense for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, are primarily related to the acquired storage assets and contracts.

Other income – net decreased $0.2 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, due to lower interest income earned on cash investments and other investing activities.

Upstream Segment

The following table provides financial information for the Upstream Segment for the three months and six months ended June 30, 2005 and 2004 (in thousands):

	Three Months Ended									Six Months Ended
	June 30,						Increase			June 30,						Increase
	2005			2004			(Decrease)			2005			2004			(Decrease)

Sales of petroleum products	$	1,961,302		$	1,231,019		$	730,283		$	3,346,369		$	2,411,786		$	934,583
Transportation – Crude oil	9,042			9,213			(171		)	18,214			18,876			(662		)
Other	2,656			2,628			28			5,197			6,688			(1,491		)
Total operating revenues	1,973,000			1,242,860			730,140			3,369,780			2,437,350			932,430

Purchases of petroleum products	1,942,599			1,216,307			726,292			3,315,029			2,383,732			931,297
Operating, general and administrative	12,912			12,682			230			25,728			23,867			1,861
Operating fuel and power	1,234			1,393			(159		)	2,462			3,133			(671		)
Depreciation and amortization	3,651			3,045			606			7,152			6,113			1,039
Taxes – other than income taxes	1,068			975			93			2,469			2,076			393
Gains on sales of assets	(53		)	(49		)	(4		)	(52		)	(107		)	55
Total costs and expenses	1,961,411			1,234,353			727,058			3,352,788			2,418,814			933,974
Operating income	11,589			8,507			3,082			16,992			18,536			(1,544		)
Equity earnings	8,170			12,091			(3,921		)	14,258			18,980			(4,722		)
Other income – net	(46		)	51			(97		)	29			197			(168		)
Earnings before interest	$	19,713		$	20,649		$	(936	)	$	31,279		$	37,713		$	(6,434	)

Information presented in the following table includes the margin of the Upstream Segment, which may be viewed as a non-GAAP (Generally Accepted Accounting Principles) financial measure under the rules of the Securities and Exchange Commission. We calculate the margin of the Upstream Segment as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil, less the costs of purchases of crude oil and lubrication oil. We believe that margin is a more meaningful measure of financial performance than sales and purchases of crude oil and lubrication oil due to the significant fluctuations in sales and purchases caused by variations in the level of volumes marketed and prices for products marketed. Additionally, we use margin internally to evaluate the financial performance of the Upstream Segment as we believe margin is a better indicator of performance than operating income as operating, general and administrative expenses, operating fuel and power and depreciation expense are not directly related to the margin activities. Margin and volume information for the three months and six months ended June 30, 2005 and 2004 is presented below (in thousands, except per barrel and per gallon amounts):

	Three Months Ended				Percentage		Six Months Ended				Percentage
	June 30,				Increase		June 30,				Increase
	2005		2004		(Decrease)		2005		2004		(Decrease)

Margins: (1)
Crude oil transportation	$	15,165	$	13,279	14	%	$	29,356	$	26,375	11	%
Crude oil marketing	9,056		6,901		31	%	12,532		12,593		—
Crude oil terminaling	1,848		2,241		(18	)%	4,233		4,966		(15	)%
Lubrication oil sales	1,676		1,504		11	%	3,433		2,996		15	%
Total margin	$	27,745	$	23,925	16	%	$	49,554	$	46,930	6	%

Total barrels:
Crude oil transportation	23,768		24,686		(4	)%	47,522		50,848		(7	)%
Crude oil marketing	48,864		42,270		16	%	93,158		87,924		6	%
Crude oil terminaling	21,287		27,800		(23	)%	48,406		60,888		(20	)%

Lubrication oil volume (total gallons)	3,153		2,949		7	%	7,325		6,419		14	%

Margin per barrel:
Crude oil transportation	$	0.638	$	0.538	19	%	$	0.618	$	0.519	19	%
Crude oil marketing	0.185		0.163		14	%	0.135		0.143		(6	)%
Crude oil terminaling	0.087		0.081		8	%	0.087		0.082		7	%

Lubrication oil margin (per gallon)	0.532		0.510		4	%	0.469		0.467		—

(1) Margins in this table are presented prior to the elimination of intercompany sales, revenues and purchases between TEPPCO Crude Oil, L.P. and TEPPCO Crude Pipeline, L.P.

The following table reconciles the Upstream Segment margin to the consolidated statements of income using the information presented in the consolidated statements of income and the statements of income in Note 10. Segment Information (in thousands):

	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2005				2004			2005			2004
Sales of petroleum products	$		1,961,302		$	1,231,019		$	3,346,369		$	2,411,786
Transportation – Crude oil	9,042				9,213			18,214			18,876
Less: Purchases of petroleum products	(1,942,599			)	(1,216,307		)	(3,315,029		)	(2,383,732		)
Total margin	27,745				23,925			49,554			46,930
Other operating revenues	2,656				2,628			5,197			6,688
Net operating revenues	30,401				26,553			54,751			53,618
Operating, general and administrative	12,912				12,682			25,728			23,867
Operating fuel and power	1,234				1,393			2,462			3,133
Depreciation and amortization	3,651				3,045			7,152			6,113
Taxes – other than income taxes	1,068				975			2,469			2,076
Gains on sales of assets	(53			)	(49		)	(52		)	(107		)
Operating income	$	11,589			$	8,507		$	16,992		$	18,536

Three Months Ended June 30, 2005 Compared with Three Months Ended June 30, 2004

Our margin increased $3.8 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004. Crude oil marketing margin increased $2.1 million primarily due to an increase in volumes marketed and unrealized gains of $1.8 million related to marking crude oil grade and location swap contracts to current market value, partially offset by increased transportation costs. Crude oil transportation margin increased $1.9 million primarily due to increased transportation volumes and revenues on our South Texas system and higher revenues on our Basin system related to movements on higher tariff segments, partially offset by decreases in transportation volumes on our Red River system and on lower tariff segments of our Basin system. Lubrication oil sales margin increased $0.2 million due to increased sales of chemical volumes and the acquisition of a lubrication oil distributor in Casper, Wyoming, in August 2004. Crude oil terminaling margin decreased $0.4 million as a result of a decrease in pumpover volumes at Midland, Texas and Cushing, Oklahoma.

Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, increased $0.7 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, primarily due to increased depreciation and amortization expense, increased operating, general and administrative expenses and increased taxes – other than income taxes, partially offset by decreased operating fuel and power. Depreciation and amortization expense increased $0.6 million as a result of assets placed in service in 2004 and due to assets retired to depreciation expense during the period. Operating, general and administrative expenses increased $0.2 million from the prior year period primarily due to a $1.8 million increase in labor and benefits expense related to vesting provisions in certain of our compensation plans as a result of changes in control of our General Partner, an increase in the number of employees and higher incentive compensation expenses between periods, a $0.9 million increase in supplies and pipeline operating and maintenance expense and a $0.4 million increase in insurance expense, partially offset by a $1.2 million decrease in postretirement benefit accruals related to plan amendments (see Note 9. Employee Benefit Plans), a $1.1 million decrease in expense as a result of measurement gains on the systems and higher crude oil prices and a $0.7 million decrease in environmental assessment and remediation costs. Operating fuel and power decreased $0.2 million primarily as a result of lower transportation volumes in 2005.

Equity earnings from our investment in Seaway decreased $3.9 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, primarily due to decreased transportation volumes attributable to reduced operating pressures as a result of a pipeline release in May 2005, decreased gains on inventory sales, higher operating, general and administrative expenses and higher depreciation expense in the second quarter of 2005.

After Seaway’s pipeline release in May 2005, the maximum operating pressure on the pipeline system was reduced by 20% as is standard procedure until the cause of the failure is determined and any required corrective measures implemented. A study of the failed pipe was performed by independent, metallurgical experts who determined that the pipe failed due to damage that occurred during rail shipment associated with its installation thirty years ago. The corrective actions include running a very sophisticated, high definition inspection tool through the pipe to determine if there are any other sections of pipe that have similar damage. This approach is consistent with directives from the United States Department of Transportation’s Office of Pipeline Safety in past failures of this type. We are in the initial stages of evaluating 300 miles of Seaway's pipeline that have similar vintage pipe. Because of the complexity of the inspection tool being used, we expect that it will take several months to complete the analysis of the data, as well as complete any additional repairs that are identified from the analysis. Based on these projections, we expect Seaway to be operating at reduced maximum pressures through the first quarter of 2006. At this time, we do not believe this will have a material adverse effect on our financial position, results of operations or cash flows.

Six Months Ended June 30, 2005 Compared with Six Months Ended June 30, 2004

Our margin increased $2.6 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004. Crude oil transportation margin increased $3.0 million primarily due to increased transportation volumes and revenues on our South Texas system and other gathering systems and higher revenues on our Basin and West Texas systems related to movements on higher tariff segments, partially offset by decreases in transportation volumes on our Red River system and on lower tariff segments of our Basin system. Lubrication oil sales margin increased $0.4 million due to increased sales of chemical volumes and the acquisition of a lubrication oil distributor in Casper, Wyoming, in August 2004. Crude oil terminaling margin decreased $0.7 million as a result of a decrease in pumpover volumes at Midland, Texas and Cushing, Oklahoma. Crude oil marketing margin decreased $0.1 million, primarily due to increased transportation expenses, partially offset by an increase in volumes marketed and unrealized gains of $0.8 million related to marking crude oil grade and location swap contracts to current market value.

Other operating revenues decreased $1.5 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, primarily due to a $1.4 million favorable settlement of inventory imbalances in the first quarter of 2004 and lower revenues from documentation and other services to support customers’ trading activity at Midland and Cushing in the first six months of 2005.

Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, increased $2.7 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, due to increased operating, general and administrative expenses, increased depreciation and amortization expense and increased taxes – other than income taxes, partially offset by decreased operating fuel and power. Operating, general and administrative expenses increased $1.9 million from the prior year period. This increase was primarily due to a $2.7 million increase in labor and benefits expense related to vesting provisions in certain of our compensation plans as a result of changes in control of our General Partner and an increase in the number of employees between periods, a $2.3 million increase in supplies and pipeline operating and maintenance expense and a $0.4 million increase in insurance expense, partially offset by a $1.2 million decrease in postretirement benefit accruals related to plan amendments (see Note 9. Employee Benefit Plans), a $1.2 million decrease in environmental and remediation costs and a $1.1 million decrease in expense as a result of measurement gains on the systems and higher crude oil prices. Depreciation and amortization expense increased $1.0 million as a result of assets placed in service in 2004, and due to assets retired to depreciation expense during the period. Taxes – other than income taxes increased $0.4 million due to increases in property tax accruals and a higher asset base in 2005. Operating fuel and power decreased $0.7 million primarily as a result of lower transportation volumes in 2005.

Equity earnings from our investment in Seaway decreased $4.7 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, primarily due to decreased transportation volumes attributable to reduced operating pressures as a result of a pipeline release in May 2005, decreased gains on inventory sales, higher operating, general and administrative expenses, higher depreciation expense and a favorable settlement in the first quarter of 2004 with a former owner of Seaway’s crude oil assets regarding inventory imbalances that were not acquired by us.

Midstream Segment

The following table provides financial information for the Midstream Segment for the three months and six months ended June 30, 2005 and 2004 (in thousands):

	Three Months Ended							Six Months Ended
	June 30,				Increase			June 30,					Increase
	2005		2004		(Decrease)			2005			2004		(Decrease)

Sales of petroleum products	$	2,315	$	1,788	$	527		$	4,457		$	3,134	$	1,323
Gathering – Natural Gas	36,956		34,427		2,529			73,516			68,929		4,587
Transportation – NGLs	11,387		10,578		809			21,606			20,592		1,014
Other	3,993		3,211		782			8,070			7,512		558
Total operating revenues	54,651		50,004		4,647			107,649			100,167		7,482

Purchases of petroleum products	1,806		1,669		137			3,176			2,986		190
Operating, general and administrative	8,786		11,094		(2,308		)	19,373			22,557		(3,184		)
Operating fuel and power	2,355		2,449		(94		)	4,537			4,619		(82		)
Depreciation and amortization	12,840		14,155		(1,315		)	25,541			29,830		(4,289		)
Taxes – other than income taxes	762		1,362		(600		)	1,886			2,710		(824		)
Gains on sales of assets	—		—		—			(407		)	—		(407		)
Total costs and expenses	26,549		30,729		(4,180		)	54,106			62,702		(8,596		)

Operating income	28,102		19,275		8,827			53,543			37,465		16,078

Other income – net	60		16		44			102			74		28

Earnings before interest	$	28,162	$	19,291	$	8,871		$	53,645		$	37,539	$	16,106

The following table presents volume and average rate information for the three months and six months ended June 30, 2005 and 2004:

	Three Months Ended				Percentage		Six Months Ended				Percentage
	June 30,				Increase		June 30,				Increase
	2005		2004		(Decrease)		2005		2004		(Decrease)
Gathering – Natural Gas – Jonah:
Million cubic feet (“MMcf”)	99,045		83,469		19	%	196,395		167,397		17	%
Billion British thermal units (“MMmbtu”)	109,516		92,430		18	%	216,817		185,327		17	%
Average fee per Million British thermal unit (“MMBtu”)	$	0.189	$	0.197	(4	)%	$	0.189	$	0.198	(4	)%

Gathering – Natural Gas – Val Verde:
MMcf	44,565		35,989		24	%	87,874		71,480		23	%
MMmbtu	39,457		30,361		30	%	77,529		60,165		29	%
Average fee per MMBtu	$	0.411	$	0.533	(23	)%	$	0.420	$	0.537	(22	)%

Transportation – NGLs:
Thousand barrels	15,540		15,465		—		29,376		30,145		(3	)%
Average rate per barrel	$	0.733	$	0.684	7	%	$	0.735	$	0.683	8	%

Fractionation – NGLs:
Thousand barrels	1,087		956		12	%	2,226		2,070		7	%
Average rate per barrel	$	1.820	$	1.867	(3	)%	$	1.732	$	1.771	(2	)%

Sales – Condensate:
Thousand barrels	13.3		17.9		(25	)%	41.2		59.7		(31	)%
Average rate per barrel	$	53.24	$	37.17	43	%	$	49.77	$	34.61	44	%

The following table reconciles the Midstream Segment margin to operating income in the consolidated statements of income using the information presented in the tables above, in the consolidated statements of income and in the statements of income in Note 10. Segment Information (in thousands):

	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2005				2004			2005			2004
Sales of petroleum products	$		2,315		$	1,788		$	4,457		$	3,134
Less: Purchases of petroleum products	(1,806			)	(1,669		)	(3,176		)	(2,986		)
Total margin	509				119			1,281			148
Gathering – Natural Gas	36,956				34,427			73,516			68,929
Transportation – NGLs	11,387				10,578			21,606			20,592
Other operating revenues	3,993				3,211			8,070			7,512
Net operating revenues	52,845				48,335			104,473			97,181
Operating, general and administrative	8,786				11,094			19,373			22,557
Operating fuel and power	2,355				2,449			4,537			4,619
Depreciation and amortization	12,840				14,155			25,541			29,830
Taxes – other than income taxes	762				1,362			1,886			2,710
Gains on sales of assets	—				—			(407		)	—
Operating income	$	28,102			$	19,275		$	53,543		$	37,465

Three Months Ended June 30, 2005 Compared with Three Months Ended June 30, 2004

Revenues from the gathering of natural gas increased $2.5 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004. Natural gas gathering revenues from the Jonah system increased $2.5 million and volumes gathered increased 15.6 billion cubic feet (“Bcf”) for the three months ended June 30, 2005, primarily due to the expansion of the Jonah system in 2004. Installation of additional capacity of 100 million cubic feet per day was completed during the fourth quarter of 2004. Jonah’s average natural gas gathering rate per MMcf decreased due to higher system wellhead pressures. Natural gas gathering revenues from the Val Verde system remained constant and volumes gathered increased 8.6 Bcf for the three months ended June 30, 2005, primarily due to increased volumes from two new connections made to the Val Verde system in May and December 2004, partially offset by the natural decline of CBM production and slower than anticipated completion and connection of infill wells. Val Verde’s average natural gas gathering rate per MMcf decreased due to contracts entered into relating to the new connections, which have lower rates than the existing Val Verde system’s average rates.

Margin (sales of petroleum products less purchases of petroleum products) resulting from the processing arrangements at the Jonah Pioneer plant increased $0.4 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, primarily due to increased volumes and higher NGL prices. Jonah’s Pioneer gas processing plant was completed during the first quarter of 2004, as a part of the Phase III expansion to increase the processing capacity in southwestern Wyoming. Pioneer’s processing agreements allow the producers to elect annually whether to be charged under a fee-based arrangement or a fee plus keep-whole arrangement. Under the fee-based election, Jonah receives a fee for its processing services. Under the fee plus keep-whole election, Jonah receives a lower fee for its processing services, retains and sells the NGLs extracted during the process and delivers to producers the residue gas equivalent in energy to the natural gas received from the producers. Jonah sells the NGLs it retains and purchases gas to replace the equivalent energy removed in the liquids. For the 2004 and 2005 periods, the producers have elected the fee plus keep-whole arrangement.

Revenues from the transportation of NGLs increased $0.8 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, primarily due to increases in volumes transported on the Panola Pipeline, partially offset by decreases in volumes transported on the Chaparral, Dean and Wilcox Pipelines. The increase in the NGL transportation average rate per barrel resulted from higher average rates per barrel on volumes transported on the Panola Pipeline.

Other operating revenues increased $0.8 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004. Val Verde’s other operating revenues increased $0.5 million due to revenues generated as a result of contractual producer minimum fuel levels exceeding actual operating fuel usage during the three months ended June 30, 2005. Val Verde retains a portion of its producers’ gas to compensate for fuel used in operations. The actual usage of gas can differ from the amount contractually retained from producers. Value retained from producers or sales generated as a result of efficient fuel usage is recognized as other operating revenues. NGL fractionation revenues increased $0.2 million as a result of higher volumes.

Costs and expenses (excluding purchases of petroleum products) decreased $4.3 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, due to decreases in operating, general and administrative expenses, depreciation and amortization expense, taxes – other than income taxes and operating fuel and power. Operating, general and administrative expenses decreased $2.3 million primarily due to a $1.7 million decrease in gas settlement expenses and a $1.6 million decrease in pipeline operating and maintenance expenditures primarily on Val Verde, partially offset by a $1.0 million increase in labor and benefits expense primarily associated with vesting provisions in certain of our compensation plans as a result of changes in control of our General Partner and certain DEFS employees becoming employees of EPCO. Amortization expense on the Jonah system decreased $0.9 million primarily due to revisions to the estimated life of intangible assets under the units-of-production method, partially offset by a $0.3 million increase as a result of higher volumes in the 2005

period. During the fourth quarter of 2004 and the first and second quarters of 2005, updated production forecasts were obtained from some of the producers on the Jonah system related to future expansions of the system, and as a result, we increased our best estimate of future throughput on the Jonah system. This increase in the estimate of future throughput extended the amortization period of Jonah’s natural gas gathering contracts (see Note 2. Goodwill and Other Intangible Assets). Amortization expense on the Val Verde system decreased $0.2 million primarily due to lower volumes in the 2005 period on contracts included in the intangible assets, resulting from the natural decline in CBM production. Depreciation expense decreased $0.2 million primarily due to a $1.0 million decrease on Jonah as a result of increases to the estimated lives of Jonah’s assets, partially offset by a $0.6 million increase on Val Verde as a result of assets placed into service in 2004 and an increase on Panola due to assets retired to depreciation expense. Taxes – other than income taxes decreased $0.6 million due to actual property taxes being lower than previously estimated.

Six Months Ended June 30, 2005 Compared with Six Months Ended June 30, 2004

Revenues from the gathering of natural gas increased $4.6 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004. Natural gas gathering revenues from the Jonah system increased $4.4 million and volumes gathered increased 29.0 Bcf for the six months ended June 30, 2005, primarily due to the expansion of the Jonah system in 2004. Installation of additional capacity of 100 million cubic feet per day was completed during the fourth quarter of 2004. Jonah’s average natural gas gathering rate per MMcf decreased due to higher system wellhead pressures. Natural gas gathering revenues from the Val Verde system increased $0.2 million and volumes gathered increased 16.4 Bcf for the six months ended June 30, 2005, primarily due to increased volumes from two new connections made to the Val Verde system in May and December 2004, partially offset by the natural decline of CBM production and slower than anticipated completion and connection of infill wells. Val Verde’s average natural gas gathering rate per MMcf decreased due to contracts entered into relating to the new connections, which have lower rates than the existing Val Verde system’s average rates.

Margin (sales of petroleum products less purchases of petroleum products) resulting from the processing arrangements at the Jonah Pioneer plant increased $1.1 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, primarily due to increased volumes and higher NGL prices.

Revenues from the transportation of NGLs increased $1.0 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, primarily due to increases in volumes transported on the Panola Pipeline, partially offset by decreases in volumes transported on the Chaparral, Dean and Wilcox Pipelines. The increase in the NGL transportation average rate per barrel resulted from higher average rates per barrel on volumes transported on the Panola Pipeline.

Other operating revenues increased $0.6 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004. Val Verde’s other operating revenues increased $0.6 million due to revenues generated as a result of contractual producer minimum fuel levels exceeding actual operating fuel usage during the six months ended June 30, 2005. NGL fractionation revenues increased $0.2 million as a result of higher volumes. Jonah’s other operating revenues decreased $0.2 million primarily due to lower condensate sales.

Costs and expenses (excluding purchases of petroleum products) decreased $8.8 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, due to decreases in depreciation and amortization expense, operating, general and administrative expenses, taxes – other than income taxes and operating fuel and power, partially offset by a net gain recorded on the sale of an asset. Amortization expense on the Jonah system decreased $1.7 million primarily due to revisions to the estimated life of intangible assets under the units-of-production method, partially offset by a $0.6 million increase as a result of higher volumes in the 2005 period. Amortization expense on the Val Verde system decreased $0.5 million primarily due to lower volumes in the 2005 period on contracts included in the intangible assets, resulting from the natural decline in CBM production. Depreciation expense decreased $2.1 million primarily due to a $3.4 million decrease on Jonah as a result of increases to the estimated lives of Jonah’s assets, partially offset by a $1.2 million increase on Val Verde as a result of assets placed into service in 2004. Operating, general and administrative expenses decreased $3.2 million

primarily due to a $3.5 million decrease in gas settlement expenses and a $1.1 million decrease in pipeline operating and maintenance expenditures primarily on Val Verde, partially offset by a $1.2 million increase in labor and benefits expense primarily associated with vesting provisions in certain of our compensation plans as a result of changes in control of our General Partner and certain DEFS employees becoming employees of EPCO. Taxes – other than income taxes decreased $0.8 million due to actual property taxes being lower than previously estimated. A net gain of $0.4 million was recognized on the sale of equipment in the current period.

Interest Expense and Capitalized Interest

Three Months Ended June 30, 2005 Compared with Three Months Ended June 30, 2004

Interest expense increased $4.7 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, primarily due to higher short term floating interest rates on our revolving credit facility, $2.0 million of expense related to the termination of a treasury lock (see Note 3. Interest Rate Swaps) and higher outstanding debt balances.

Capitalized interest decreased $0.4 million for the three months ended June 30, 2005, compared with the three months ended June 30, 2004, due to lower construction work-in-progress balances in the 2005 period.

Six Months Ended June 30, 2005 Compared with Six Months Ended June 30, 2004

Interest expense increased $4.7 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, primarily due to higher short term floating interest rates on our revolving credit facility, $2.0 million of expense related to the termination of a treasury lock (see Note 3. Interest Rate Swaps) and higher outstanding debt balances. These increases were partially offset by an increased percentage of variable interest rate debt during the six months ended June 30, 2005, that carried a lower rate of interest as compared with fixed interest rate debt. The higher percentage of variable interest rate debt resulted from the expiration of an interest rate swap in April 2004 (see Note 3. Interest Rate Swaps).

Capitalized interest decreased $0.2 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, due to lower construction work-in-progress balances in the 2005 period.

Financial Condition and Liquidity

Cash generated from operations, credit facilities and debt and equity offerings are our primary sources of liquidity. At June 30, 2005, we had a working capital surplus of $62.0 million, while at December 31, 2004, we had a working capital deficit of $37.8 million. At June 30, 2005, we had approximately $278.6 million in available borrowing capacity under our revolving credit facility to cover any working capital needs. Cash flows for the six months ended June 30, 2005 and 2004 were as follows (in millions):

	Six Months Ended
	June 30,
	2005			2004
Cash provided by (used in):
Operating activities	$	24.6		$	132.0
Investing activities	(126.0		)	(81.9		)
Financing activities	86.5			(65.7		)

Operating Activities

Net cash from operating activities for the six months ended June 30, 2005 and 2004, was comprised of the following (in millions):

	Six Months Ended
	June 30,
	2005			2004
Net income	$	90.8		$	78.2
Depreciation and amortization	52.1			54.2
Earnings in equity investments	(14.3		)	(17.2		)
Distributions from equity investments	19.0			20.8
Gains on sales of assets	(0.6		)	(0.1		)
Non-cash portion of interest expense	0.8			(0.2		)
Cash used in working capital and other	(123.2		)	(3.7		)

Net cash from operating activities	$	24.6		$	132.0

For a discussion of changes in earnings before interest, depreciation and amortization, equity earnings, gain on sales of assets by segment and consolidated interest expense – net, see Results of Operations for the Downstream Segment, Upstream Segment and Midstream Segment in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Cash provided by operating activities decreased $107.4 million for the six months ended June 30, 2005, compared with the six months ended June 30, 2004, primarily due to the timing of cash disbursements and cash receipts for crude oil inventory and other working capital components and a decrease in distributions received from our equity investments during the six months ended June 30, 2005, partially offset by higher net income and lower depreciation and amortization expense in the 2005 period.

During the second quarter of 2005, we purchased crude oil and simultaneously entered into offsetting sales contracts for physical delivery during the third quarter of 2005. The purpose of these contracts was to lock in a margin on the crude oil while it is stored in our facilities. These purchases had a negative impact on cash flows from operating activities when the invoices for the crude oil were paid during the second quarter of 2005. We utilized borrowings under our revolving credit facility to fund a large portion of the crude oil purchases. These borrowings on our revolving credit facility are shown as financing activities in the statement of cash flows. As such, until we deliver the crude oil and receive payment from our customers, operating activities in the statement of cash flows will be negatively impacted by this activity.

We believe that we will continue to have adequate liquidity to fund future recurring operating and investing activities. Our primary cash requirements consist of normal operating expenses, capital expenditures to sustain existing operations and revenue generating expenditures, interest payments on our Senior Notes and revolving credit facility, distributions to our General Partner and unitholders and acquisitions of new assets or businesses. Short-term cash requirements, such as operating expenses, capital expenditures to sustain existing operations and quarterly distributions to our General Partner and unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for expansion projects and acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under credit facilities, and the issuance of additional equity and debt securities. Our ability to complete future debt and equity offerings and the timing of any such offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and our credit rating at the time.

Net cash from operating activities for the six months ended June 30, 2005 and 2004, included interest payments, net of amounts capitalized, of $41.1 million and $41.2 million, respectively. Excluding the effects of hedging activities and interest capitalized during the year ended December 31, 2005, we expect interest payments on

our fixed rate Senior Notes to be approximately $77.8 million. We expect to pay our interest payments with cash flows from operating activities.

Investing Activities

Cash flows used in investing activities totaled $126.0 million for the six months ended June 30, 2005, and were comprised of $82.9 million of capital expenditures, $42.5 million for the acquisition of crude oil assets and $1.1 million of cash contributions for TE Products’ ownership interest in MB Storage, partially offset by $0.5 million in net cash proceeds from an asset sale in our Midstream Segment. Cash flows used in investing activities totaled $81.9 million for the six months ended June 30, 2004, and were comprised of $60.3 million of capital expenditures, $1.5 million of cash contributions for TE Products’ ownership interest in Centennial, $17.2 million of cash contributions for TE Products’ ownership interest in MB Storage and $3.0 million for the acquisition of assets, partially offset by $0.1 million in net cash proceeds from asset sales in our Upstream and Downstream Segments.

Financing Activities

Cash flows provided by financing activities totaled $86.5 million for the six months ended June 30, 2005, and were comprised of $278.8 million from the issuance of 7.0 million Units in May and June 2005, partially offset by $117.3 million of distributions paid to unitholders and $75.0 million in repayments, net of borrowings, on our revolving credit facility. Cash flows used in financing activities totaled $65.7 million for the six months ended June 30, 2004, and were comprised of $115.7 million of distributions paid to unitholders, partially offset by $50.0 million in borrowings, net of repayments, from our revolving credit facility.

Centennial entered into credit facilities totaling $150.0 million and, as of June 30, 2005, $150.0 million was outstanding under those credit facilities. The proceeds were used to fund construction and conversion costs of Centennial’s pipeline system. TE Products and Marathon Ashland Petroleum LLC (“Marathon”) have each guaranteed one-half of Centennial’s debt, up to a maximum of $75.0 million each.

Universal Shelf

We have filed with the Securities and Exchange Commission a universal shelf registration statement that, subject to agreement on terms at the time of use and appropriate supplementation, allows us to issue, in one or more offerings, up to an aggregate of $2.0 billion of equity securities, debt securities or a combination thereof. During the three months ended June 30, 2005, we issued $279.2 million of equity securities. At June 30, 2005, we had $1.7 billion remaining under this shelf registration, subject to customary marketing terms and conditions.

Credit Facilities and Interest Rate Swap Agreements

May 2005 and June 2005 to repay a portion of the Revolving Credit Facility (see Note 8. Partners’ Capital and Distributions). At June 30, 2005, $278.0 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 4.3%. At June 30, 2005, we were in compliance with the covenants of this credit agreement.

We have entered into interest rate swap agreements to hedge our exposure to cash flows and fair value changes. These agreements are more fully described in Item 3. Quantitative and Qualitative Disclosures About Market Risk.

The following table summarizes our credit facilities as of June 30, 2005 (in millions):

	As of June 30, 2005
			Available
	Outstanding		Borrowing		Maturity
Description:	Principal		Capacity		Date
Revolving Credit Facility (1)	$	278.0	$	322.0	October 2009
6.45% Senior Notes (2)	180.0		—		January 2008
7.625% Senior Notes (2)	500.0		—		February 2012
6.125% Senior Notes (2)	200.0		—		February 2013
7.51% Senior Notes (2)	210.0		—		January 2028
Total	$	1,368.0	$	322.0

(1) Our Revolving Credit Facility contains restrictive covenants that require us to maintain certain financial ratios. Under the most restrictive financial covenant, approximately $278.6 million was available to be borrowed for working capital needs at June 30, 2005. Certain of these restrictive covenants are adjusted in the event of an acquisition by us, which would permit additional borrowings under the facility.

(2) Our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its 7.51% Senior Notes due 2028. At June 30, 2005, the 7.51% Senior Notes include an adjustment to increase the fair value of the debt by $7.4 million related to this interest rate swap agreement. We also entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our 7.625% Senior Notes due 2012. At June 30, 2005, the 7.625% Senior Notes include a deferred gain, net of amortization, from previous interest rate swap terminations of $34.6 million. At June 30, 2005, our 6.45% Senior Notes, our 7.625% Senior Notes and our 6.125% Senior Notes include $2.6 million of unamortized debt discounts. The fair value adjustments, the deferred gain adjustment and the unamortized debt discounts are excluded from this table.

Distributions and Issuance of Additional Limited Partner Units

We paid cash distributions of $117.3 million ($1.325 per Unit) and $115.7 million ($1.3125 per Unit) during the six months ended June 30, 2005 and 2004, respectively. Additionally, we declared a cash distribution of $0.675 per Unit for the quarter ended June 30, 2005. We will pay the distribution of $66.9 million on August 5, 2005, to unitholders of record on July 29, 2005.

General Partner Interest

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.

Future Capital Needs and Commitments

We estimate that capital expenditures, excluding acquisitions, for 2005 will be approximately $283.0 million (which includes $7.0 million of capitalized interest). We expect to spend approximately $209.8 million for revenue generating projects and facility improvements. Capital spending on revenue generating projects and facility improvements will include approximately $43.8 million for the expansion of our Downstream Segment facilities. We expect to spend $25.7 million to expand our Upstream Segment pipelines and facilities in West Texas and Oklahoma and approximately $140.3 million to expand our Midstream Segment assets, with further expansions on our Jonah system. We expect to spend approximately $41.0 million to sustain existing operations, 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 $25.2 million to improve operational efficiencies and reduce costs among all of our business segments. We continually review and evaluate potential capital improvements and expansions that would be complementary to our present business operations. These expenditures can vary greatly

depending on the magnitude of our transactions. We may finance capital expenditures through internally generated funds, debt or the issuance of additional equity.

Our debt repayment obligations consist of payments for principal and interest on (i) the TE Products $180.0 million 6.45% Senior Notes due January 15, 2008, (ii) outstanding principal amounts under the Revolving Credit Facility due in October 2009 ($278.0 million outstanding at June 30, 2005), (iii) our $500.0 million 7.625% Senior Notes due February 15, 2012, (iv) our $200.0 million 6.125% Senior Notes due February 1, 2013, and (v) the TE Products $210.0 million 7.51% Senior Notes due January 15, 2028.

TE Products is contingently liable as guarantor for the lesser of one-half or $75.0 million principal amount (plus interest) of the borrowings of Centennial. In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years that contains a minimum throughput requirement. For the year ended December 31, 2004, TE Products exceeded the minimum throughput requirements on the lease agreement.

During the six months ended June 30, 2005, TE Products contributed $1.1 million to MB Storage. No amounts were contributed to Centennial during the six months ended June 30, 2005. During the six months ended June 30, 2004, TE Products contributed $1.5 million to Centennial to cover operating needs and capital expenditures and $17.2 million to MB Storage, of which $16.5 million was used to acquire storage assets in April 2004. During the remainder of 2005, TE Products may be required to contribute cash to Centennial to cover capital expenditures, acquisitions or other operating needs and to MB Storage to cover significant capital expenditures or additional acquisitions.

Off-Balance Sheet Arrangements

We do not rely on off-balance sheet borrowings to fund our acquisitions. We have no off-balance sheet commitments for indebtedness other than the limited guaranty of Centennial debt and leases covering assets utilized in several areas of our operations.

Contractual Obligations

The following table summarizes our debt repayment obligations and material contractual commitments as of June 30, 2005 (in millions):

	Amount of Commitment Expiration Per Period
	Total		Less than 1 Year		1-3 Years		4-5 Years		After 5 Years

Revolving Credit Facility	$	278.0	$	—	$	278.0	$	—	$	—
6.45% Senior Notes due 2008 (1) (2)	180.0		—		—		180.0		—
7.625% Senior Notes due 2012 (2)	210.0		—		—		—		210.0
6.125% Senior Notes due 2013 (2)	500.0		—		—		—		500.0
7.51% Senior Notes due 2028 (1) (2)	200.0		—		—		—		200.0
Debt subtotal	1,368.0		—		278.0		180.0		910.0

Operating leases	78.1		19.0		30.0		12.8		16.3
Capital expenditure obligations (3)	17.2		17.2		—		—		—
Other liabilities and deferred credits (4)	3.6		—		2.9		0.7		—

Total	$	1,466.9	$	36.2	$	310.9	$	193.5	$	926.3

(1) Obligations of TE Products.

(3) Includes accruals for costs incurred but not yet paid relating to capital projects.

(4) Excludes approximately $9.1 million of long-term deferred revenue payments, which are being transferred to income over the term of the respective revenue contracts. The amount of commitment by year is our best estimate of projected payments of these long-term liabilities.

We expect to repay the long-term, senior unsecured obligations and bank debt through the issuance of additional long-term senior unsecured debt at the time the 2008, 2012, 2013 and 2028 debt matures, issuance of additional equity, with proceeds from dispositions of assets, cash flow from operations or any combination of the above items.

In addition to the items in the table above, we have entered into various operational commitments and agreements related to pipeline operations and to the marketing, transportation, terminaling and storage of crude oil. The majority of contractual commitments for the purchase of crude oil that are made range in term from a thirty-day evergreen to three years. A substantial portion of the contracts for the purchase of crude oil that extend beyond thirty days include cancellation provisions that allow us to cancel the contract with thirty days written notice. During the six months ended June 30, 2005, crude oil purchases averaged approximately $552.5 million per month.

Sources of Future Capital

Historically, we have funded our capital commitments from operating cash flow and borrowings under bank credit facilities or bridge loans. We repaid these loans in part by the issuance of long term debt in capital markets and the public offering of Units. We expect future capital needs would be similarly funded to the extent not otherwise available from cash flow from operations.

As of June 30, 2005, we had $278.6 million in available borrowing capacity under the Revolving Credit Facility, subject to compliance with prescribed financial covenants. We expect that cash flows from operating activities will be adequate to fund cash distributions and capital additions necessary to sustain existing operations. However, future expansionary capital projects and acquisitions will require funding through borrowings under our Revolving Credit Facility or proceeds from the sale of additional debt or equity offerings, or any combination thereof.

Our senior unsecured debt is rated BBB- by Standard and Poors (“S&P”) and Baa3 by Moody’s Investors Service (“Moody’s”). S&P assigned this rating on June 14, 2005, following its review of the ownership structure, corporate governance issues, and proposed funding after the acquisition of the General Partner by DFI. Both ratings are with a stable outlook. A rating reflects only the view of a rating agency and is not a recommendation to buy, sell or hold any indebtedness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it determines that the circumstances warrant such a change. The senior unsecured debt of our subsidiary, TE Products, is also rated BBB- by S&P and Baa3 by Moody’s. Both ratings are with a stable outlook.

Other Considerations

the need to perform investigatory and remedial activities. Although we believe our operations are in material compliance with applicable environmental laws and regulations, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure you that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. We believe that changes in environmental laws and regulations will not have a material adverse effect on our financial position, results of operations or cash flows in the near term.

In 1994, the Louisiana Department of Environmental Quality (“LDEQ”) issued a compliance order for environmental contamination at our Arcadia, Louisiana facility. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this contamination. At June 30, 2005, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. Effective in 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. 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.

Competition of the Federal Trade Commission (“FTC”) delivered written notice to DFI’s legal advisor that it was conducting a non-public investigation to determine whether DFI’s acquisition of the General Partner may substantially lessen competition. The FTC has contacted the General Partner requesting data. The General Partner intends to cooperate fully with any such investigations and inquiries requested by the FTC or any other regulatory authorities.

Recent Accounting Pronouncements

See discussion of new accounting pronouncements in Note 1. Organization and Basis of Presentation - New Accounting Pronouncements in the accompanying consolidated financial statements.

Corporate Governance Guidelines

Effective March 22, 2005, the General Partner’s LLC Agreement was amended to delete a provision requiring that members of our General Partner’s board of directors must retire at the first meeting of the board of directors following attainment of the age of 70 years. The agreement was amended to allow for the election of the new members of the board of directors, one of whom is over the age of 70. As a result of the amendment, there is now no retirement age for the members of the General Partner’s board of directors. Our Corporate Governance Guidelines, which were also amended to reflect this change, are available on our website at www.teppco.com.

On March 22, 2005, the members of the board of directors of the General Partner, Jim W. Mogg, Mark A. Borer, Michael J. Bradley, Milton Carroll, Derrill Cody, John P. DesBarres, William H. Easter III and Paul F. Ferguson, Jr., each of whom had been elected to the board of the General Partner by DEFS, resigned and new directors were elected. The newly elected directors are Ralph S. Cunningham, Lee W. Marshall, Sr., Murray H. Hutchison and Michael B. Bracy. Barry R. Pearl will continue to serve the General Partner as chief executive officer, president and a director. The newly elected board is comprised of a majority of outside directors who are independent under the criteria of the New York Stock Exchange and the U.S. Securities and Exchange Commission.

Retirement and Election of Officers

On July 12, 2005, we announced that Charles H. Leonard elected to retire effective July 8, 2005, as Senior Vice President and Chief Financial Officer of our General Partner. Tracy E. Ohmart, Controller of the General Partner, became the acting Chief Financial Officer.

Mr. Ohmart, age 37, has served as Controller of our General Partner since May 2002. Mr. Ohmart joined our General Partner in January 2001 and has held various positions within the Company until he became Assistant Controller in May 2001. Prior to his employment with our General Partner, Mr. Ohmart spent 12 years in various positions at ARCO Pipe Line Company, most recently serving as supervisor of general accounting and policy.

Mr. William Ordemann was elected Senior Vice President of our General Partner effective July 25, 2005. Mr. Ordemann will be responsible for leading commercial development activities for Jonah. Mr. Ordemann also serves as Senior Vice President of Enterprise Products GP, LLC (“Enterprise GP”), the general partner of Enterprise Products Partners L.P. Prior to joining Enterprise GP, Mr. Ordemann served as vice president of Tejas Natural Gas Liquids, LLC from February 1998 to September 1999, and vice president of Shell Midstream Enterprises, LLC from January 1997 to February 1998.

Mr. Stephen O. McNair was elected Vice President of our General Partner effective July 25, 2005. Mr. McNair will have leadership responsibility for our Natural Gas Services organization, including Jonah operations and Val Verde activities. Mr. McNair joined our General Partner in June 2005. He was previously Rockies Region vice president for DEFS. He joined DEFS as general manager of Operations, West Permian Region in 2000. Prior to his employment with DEFS, Mr. McNair held various engineering, commercial and operations management positions with Conoco Inc. and GPM Gas Corporation.

Forward-Looking Statements

The matters discussed in this Report include “forward-looking statements” within the meaning of various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of our business and operations, plans, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and

predictions is subject to a number of risks and uncertainties, including general economic, market or business conditions, the opportunities (or lack thereof) that may be presented to and pursued by us, competitive actions by other pipeline companies, changes in laws or regulations and other factors, many of which are beyond our control. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to or effect on us or our business or operations. For additional discussion of such risks and uncertainties, see our Annual Report on Form 10-K for the year ended December 31, 2004, and other filings we have made with the Securities and Exchange Commission.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We may be exposed to market risk through changes in crude oil commodity prices and interest rates. We do not have foreign exchange risks. Our Risk Management Committee has established policies to monitor and control these market risks. The Risk Management Committee is comprised, in part, of senior executives of the Company.

We seek to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. On the majority of our crude oil derivative contracts, we take the normal purchase and normal sale exclusion in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133. At June 30, 2005, we have $75.8 million of crude oil inventory for which we have entered into forward crude sales contracts to mitigate the risk of price volatility.

Occasionally, customers require pricing terms which do not allow us to balance our position. Additionally, certain pricing terms may expose us to movements in margin. On a small portion of our crude oil marketing business, we enter into derivative contracts such as swaps and other business hedging devices for which we cannot take the normal purchase and normal sale exclusion and for which we do not elect hedge accounting. The terms of these contracts are less than one year. The purpose is to balance our position or lock in a margin and, as such, do not expose us to any additional significant market risk. We mark these transactions to market and the changes in the fair value are recognized in current earnings. This results in some financial statement variability during quarterly periods; however, any unrealized gains and losses reflected in the financial statements related to marking these transactions to market are offset by realized gains and losses in different quarterly periods when the transactions are settled.

At June 30, 2005, we had $278.0 million outstanding under our variable interest rate revolving credit facility. The interest rate is based, at our option, on either the lender’s base rate plus a spread or LIBOR plus a spread in effect at the time of the borrowings and is adjusted monthly, bimonthly, quarterly or semiannually. Utilizing the balances of our variable interest rate debt outstanding at June 30, 2005, and assuming market interest rates increase 100 basis points, the potential annual increase in interest expense would be $2.8 million.

At June 30, 2005, TE Products had outstanding $180.0 million principal amount of 6.45% Senior Notes due 2008 and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively, the “TE Products Senior Notes”). At June 30, 2005, the estimated fair value of the TE Products Senior Notes was approximately $412.6 million. At June 30, 2005, we had outstanding $500.0 million principal amount of 7.625% Senior Notes due 2012 and $200.0 million principal amount of 6.125% Senior Notes due 2013. At June 30, 2005, the estimated fair value of the $500.0 million 7.625% Senior Notes and the $200.0 million 6.125% Senior Notes was approximately $570.4 million and $212.0 million, respectively.

We have utilized and expect to continue to utilize interest rate swap agreements to hedge a portion of our cash flow and fair value risks. Interest rate swap agreements are used to manage the fixed and floating interest rate mix of our total debt portfolio and overall cost of borrowing. Interest rate swaps that manage our cash flow risk reduce our exposure to increases in the benchmark interest rates underlying variable rate debt. Interest rate swaps that manage our fair value risks are intended to reduce our exposure to changes in the fair value of the fixed rate debt. Interest rate swap agreements involve the periodic exchange of payments without the exchange of the notional amount upon which the payments are based. The related amount payable to or receivable from counterparties is included as an adjustment to accrued interest.

In October 2001, TE Products entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating rate of interest based on a three-month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. During the six months ended June 30, 2005, and 2004, we recognized reductions in interest expense of $3.3 million and $5.1 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the quarter ended June 30, 2005, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of this interest rate swap was a gain of approximately $7.4 million and $3.4 million at June 30, 2005, and December 31, 2004, respectively. Utilizing the balance of the 7.51% TE Products Senior Notes outstanding at June 30, 2005 and including the effects of hedging activities, assuming market interest rates increase 100 basis points, the potential annual increase in interest expense is $2.1 million.

Item 4. Controls and Procedures

The principal executive officer and principal financial officer of our General Partner, after evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of June 30, 2005, have concluded that, as of such date, our disclosure controls and procedures are adequate and effective to ensure that material information relating to us and our consolidated subsidiaries would be made known to them by others within those entities.

Changes in Internal Control over Financial Reporting

Through February 23, 2005, our General Partner was an indirect subsidiary of Duke Energy, and Duke Energy’s Audit Services Department provided our internal audit functions. On February 24, 2005, the General Partner was acquired by DFI, an affiliate of EPCO. EPCO, using its own personnel and third party providers, will provide us with internal audit services. EPCO expects the transition of internal audit functions to be completed in the third quarter of 2005. This change is not expected to adversely affect our internal audit process or our internal control over financial reporting.

There has been no significant change in our internal control over financial reporting during the second quarter of 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. As a result, no corrective actions were required or undertaken.

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. We believe that the outcome of these lawsuits and other proceedings will not individually or in the aggregate have a material adverse effect on our consolidated financial position, results of operations or cash flows. See discussion of legal proceedings in Note 11. Commitments and Contingencies in the accompanying consolidated financial statements.

Item 6. Exhibits

Exhibit Number		Description

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		Third Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated September 21, 2001 (Filed as Exhibit 3.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
4.1		Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
4.2		Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership’s Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference).
4.3		Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).

4.4		Form of 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).
4.5		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).
4.6		Second Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee (Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
4.7		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).
10.1*		Amendments to the TEPPCO Retirement Cash Balance Plan and the TEPPCO Supplemental Benefit Plan dated as of May 27, 2005.
10.2*		Agreement and Release between Charles H. Leonard and Texas Eastern Products Pipeline Company, LLC dated as of July 11, 2005.
12.1*		Statement of Computation of Ratio of Earnings to Fixed Charges.
31.1*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Chief Financial Officer 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 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.
	(Registrant)
	(A Delaware Limited Partnership)

	By: Texas Eastern Products Pipeline
	Company, LLC, as General Partner

	By:	/s/ BARRY R. PEARL
		Barry R. Pearl,
		President and Chief Executive Officer

	By:	/s/ TRACY E. OHMART
		Tracy E. Ohmart,
		Chief Financial Officer

Date: August 2, 2005

Senior Notes

Other Long Term Debt and Credit Facilities

Quarterly Distributions of Available Cash

Retirement Plans

Other Postretirement Benefits

Estimated Future Benefit Contributions

Management Overview of the Three Months and Six Months Ended June 30, 2005

32

Our Business

Distributions and Issuance of Additional Limited Partner Units

Sources of Future Capital