UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

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

For the quarterly period ended September 30, 2005

OR

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)

 

1100 Louisiana Street, 13th Floor

P.O. Box 2521

Houston, Texas 77252-2521

(Address of principal executive offices, including zip code)

(713) 381-3636

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x   No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yes x   No o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o   No x

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 October 28, 2005:   69,963,554

 

EXPLANATORY NOTE

This Amended Quarterly Report (“Report”) on Form 10-Q includes restated financial statements as of and for the three months and nine months ended September 30, 2005 and 2004. The restated financial statements include the effect of correcting the accounting for our excess investments in Centennial Pipeline LLC and Seaway Crude Pipeline Company from an intangible asset with an indefinite life and equity method goodwill, respectively, to intangible assets with determinable lives. The restatement caused a $1.3 million, or $0.01 per unit, and $1.1 million, or $0.01 per unit, reduction to net income and earnings per unit as previously reported for the three months ended September 30, 2005 and 2004, respectively. The restatement caused a $3.8 million, or $0.04 per unit, and $2.9 million, or $0.04 per unit, reduction to net income and earnings per unit as previously reported for the nine months ended September 30, 2005 and 2004, respectively.

For further discussion of the effect of the restatement, see Note 15. Restatement of Consolidated Financial Statements in this Report and Note 20. Restatement of Consolidated Financial Statements in our Annual Report on Form 10-K for the fiscal year ended December 31, 2005 (“2005 Annual Report”).

In our 2005 Annual Report, we indicated in the introductory explanatory note that the restatement presented in this filing would be reported in our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2006. We also noted that we did not plan to file any other amendments to our previously filed Quarterly Reports on Form 10-Q since we had included restated financial data for the quarterly periods ended March 31, 2005 and 2004, June 30, 2005 and 2004, and September 30, 2005 and 2004 in our 2005 Annual Report. However, we are amending our Quarterly Report on Form 10-Q for the period ended September 30, 2005, in order to provide investors with a more convenient comparative presentation of the effects of the restatement for the quarterly periods ended September 30, 2005 and 2004.

As a result of the restatement described above, this Report amends the following sections of our Form 10-Q for the period ended September 30, 2005, which was filed with the Securities and Exchange Commission on October 31, 2005 (the “Initial Report”):

Part I—Item 1. Financial Statements

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

Except as specified with respect to certain aspects of the restatement, we have not updated the disclosures contained in this Report to reflect any events that occurred at a date subsequent to the filing of the Initial Report, and this Report continues to speak as of the date of the Initial Report. This Report does not affect the information originally set forth in the Initial Report that has not been amended as described above. However, we have included the remaining portions of the Initial Report that have not been amended herein for ease of reference.

 

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TEPPCO PARTNERS, L.P.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets as of September 30, 2005 (unaudited) (as restated) and December 31, 2004

Consolidated Statements of Income for the three months and nine months ended September 30, 2005 and 2004 (unaudited) (as restated)

Consolidated Statements of Cash Flows for the nine months ended September 30, 2005 and 2004 (unaudited) (as restated)

Consolidated Statement of Partners’ Capital for the nine months ended September 30, 2005 (unaudited) (as restated)

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

 

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

TEPPCO PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS
(in thousands)

		September 30, 2005			December 31, 2004
		(as restated) (Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	72		$	16,422
Accounts receivable, trade (net of allowance for doubtful accounts of $287 and $112)		849,968			553,628
Accounts receivable, related parties		5,322			11,845
Inventories		139,005			19,521
Other		63,483			42,138
Total current assets		1,057,850			643,554
Property, plant and equipment, at cost (net of accumulated depreciation and amortization of $454,787 and $407,670)		1,907,840			1,703,702
Equity investments		360,375			363,307
Intangible assets		385,119			407,358
Goodwill		16,944			16,944
Other assets		60,212			51,419
Total assets		$	3,788,340		$	3,186,284
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities		$	851,206		$	564,464
Accounts payable, related parties		9,858			24,654
Accrued interest		13,501			32,292
Other accrued taxes		18,736			13,309
Other		71,043			46,593
Total current liabilities		964,344			681,312
Senior Notes		1,122,317			1,127,226
Other long-term debt		460,500			353,000
Other liabilities and deferred credits		17,494			13,643
Commitments and contingencies
Partners’ capital:
Accumulated other comprehensive income		35			—
General partner’s interest		(54,880		)	(35,881		)
Limited partners’ interests		1,278,530			1,046,984
Total partners’ capital		1,223,685			1,011,103
Total liabilities and partners’ capital		$	3,788,340		$	3,186,284

 

See accompanying Notes to Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(in thousands, except per Unit amounts)

		Three Months Ended September 30,						Nine Months Ended September 30,
		2005			2004			2005			2004
		(as restated)			(as restated)			(as restated)			(as restated)
Operating revenues:
Sales of petroleum products		$	2,370,710		$	1,359,954		$	5,721,536		$	3,774,874
Transportation — Refined products		38,240			43,386			111,039			113,294
Transportation — LPGs		16,519			16,071			63,220			58,572
Transportation — Crude oil		10,001			9,288			28,215			28,164
Transportation — NGLs		11,829			10,430			33,435			31,022
Gathering — Natural gas		38,833			35,515			112,349			104,444
Other		17,664			15,366			50,987			52,265
Total operating revenues		2,503,796			1,490,010			6,120,781			4,162,635
Costs and expenses:
Purchases of petroleum products		2,352,504			1,345,677			5,668,660			3,730,330
Operating, general and administrative		57,801			60,492			157,798			164,935
Operating fuel and power		12,538			13,464			35,154			36,459
Depreciation and amortization		30,960			30,277			83,015			84,508
Taxes — other than income taxes		5,954			3,868			15,662			13,993
Gains on sales of assets		(31		)	(849		)	(597		)	(973		)
Total costs and expenses		2,459,726			1,452,929			5,959,692			4,029,252
Operating income		44,070			37,081			161,089			133,383
Interest expense — net		(19,726		)	(17,131		)	(60,640		)	(53,190		)
Equity earnings		4,747			4,536			16,592			19,927
Other income — net		484			284			885			1,000
Net income		$	29,575		$	24,770		$	117,926		$	101,120
Net Income Allocation:
Limited Partner Unitholders		$	20,915		$	17,624		$	83,410		$	71,949
General Partner		8,660			7,146			34,516			29,171
Total net income allocated		$	29,575		$	24,770		$	117,926		$	101,120
Basic and diluted net income per Limited Partner Unit		$	0.30		$	0.28		$	1.25		$	1.14
Weighted average Limited Partner Units outstanding		69,964			62,999			66,533			62,999

 

See accompanying Notes to Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)

		Nine Months Ended September 30,
		2005			2004
		(as restated)			(as restated)
Cash flows from operating activities:
Net income		$	117,926		$	101,120
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		83,015			84,508
Earnings in equity investments, net of distributions		11,586			19,498
Gains on sales of assets		(597		)	(973		)
Non-cash portion of interest expense		1,214			177
Increase in accounts receivable		(296,340		)	(139,808		)
(Increase) decrease in accounts receivable, related parties		6,523			(15,129		)
Increase in inventories		(111,094		)	(13,124		)
Increase in other current assets		(21,002		)	(2,855		)
Increase in accounts payable and accrued expenses		283,167			140,663
Decrease in accounts payable, related parties		(14,796		)	(3,335		)
Other		(15,654		)	3,191
Net cash provided by operating activities		43,948			173,933
Cash flows from investing activities:
Proceeds from the sales of assets		510			1,202
Purchase of assets		(112,231		)	(3,421		)
Investment in Centennial Pipeline LLC		—			(1,500		)
Investment in Mont Belvieu Storage Partners, L.P.		(2,635		)	(20,161		)
Capital expenditures		(148,063		)	(110,998		)
Net cash used in investing activities		(262,419		)	(134,878		)
Cash flows from financing activities:
Proceeds from revolving credit facility		549,657			256,300
Repayments on revolving credit facility		(442,157		)	(140,800		)
Issuance of Limited Partner Units, net		278,830			—
Distributions paid		(184,209		)	(174,399		)
Net cash provided by (used in) financing activities		202,121			(58,899		)
Net decrease in cash and cash equivalents		(16,350		)	(19,844		)
Cash and cash equivalents at beginning of period		16,422			29,469
Cash and cash equivalents at end of period		$	72		$	9,625
Non-cash investing activities:
Net assets transferred to Mont Belvieu Storage Partners, L.P.		$	1,429		$	—
Supplemental disclosure of cash flows:
Cash paid for interest (net of amounts capitalized)		$	78,504		$	75,498

 

See accompanying Notes to Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
(Unaudited)
(in thousands, except Unit amounts)

		Outstanding Limited Partner Units		General Partner’s Interest			Limited Partners’ Interests			Accumulated Other Comprehensive Income			Total
Partners’ capital at December 31, 2004		62,998,554		$	(35,881	)	$	1,046,984		$	—		$	1,011,103
Issuance of Limited Partner Units, net		6,965,000		—			278,830			—			278,830
Net income allocation		—		34,516			83,410			—			117,926
Change in fair value of crude oil hedge		—		—			—			35			35
Cash distributions		—		(53,515		)	(130,694		)	—			(184,209		)
Partners’ capital at September 30, 2005 (as restated)		69,963,554		$	(54,880	)	$	1,278,530		$	35		$	1,223,685

 

See accompanying Notes to Consolidated Financial Statements.

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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, and we reimburse EPCO for all direct and indirect expenses that have been incurred in managing us. As a result of the sale of our General Partner, DEFS and Duke Energy will continue to provide some administrative services for us for a period of time until we assume these services. In connection with us assuming the operations of certain of the TEPPCO Midstream assets from DEFS, certain DEFS employees became employees of EPCO effective June 1, 2005.

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 DPIs 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 September 30, 2005, and the results of our operations and cash flows for the periods presented. The results of operations for the three months and nine months ended September 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”).

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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.”

We restated our consolidated financial statements and related financial information for the three months  and nine months ended September 30, 2005 and 2004, for an accounting correction. See Note 15. Restatement of Consolidated Financial Statements for a discussion of the restatement adjustment and the impact on previously issued financial statements.

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 70.0 million and 66.5 million Units for the three months and nine months ended September 30, 2005, respectively, and 63.0 million Units for the three months and nine months ended September 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 9. Partners’ Capital and Distributions). The General Partner was allocated $8.7 million (representing 29.27%) and $7.1 million (representing 28.85%) of our net income for the three months ended September 30, 2005 and 2004, respectively, and $34.5 million (representing 29.27%) and $29.2 million (representing 28.85%) of our net income for the nine months ended September 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 nine-month periods ended September 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 after June 15, 2005. The Securities and Exchange Commission amended the implementation date of SFAS 123(R) to begin with the first interim or annual reporting period of the company’s first fiscal year beginning on or after June 15, 1005. 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.

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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, and early adoption of FIN 47 is encouraged. We will adopt FIN 47 in the fourth quarter of 2005. 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). For existing limited partnerships that have not been modified, the guidance in EITF 04-5 is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. We are currently evaluating what impact EITF 04-5 will have on our financial statements, but at this time we do not believe that the adoption of EITF 04-5 will have a material effect on our financial position, results of operations or cash flows.

In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion 29.  SFAS 153 amends APB Opinion No. 29, Accounting for Nonmonetary Exchanges, to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial

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substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. We adopted SFAS 153 during the second quarter of 2005. The adoption of SFAS 153 did not have a material effect on our financial position, results of operations or cash flows.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS 154 establishes new standards on accounting for changes in accounting principles. All such changes must be accounted for by retrospective application to the financial statements of prior periods unless it is impracticable to do so. SFAS 154 completely replaces APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Periods. However, it carries forward the guidance in those pronouncements with respect to accounting for changes in estimates, changes in the reporting entity, and the correction of errors. SFAS 154 is effective for accounting changes and error corrections made in fiscal years beginning after December 15, 2005, with early adoption permitted for changes and corrections made in years beginning after June 1, 2005. The application of SFAS 154 does not affect the transition provisions of any existing pronouncements, including those that are in the transition phase as of the effective date of SFAS 154. We do not believe that the adoption of SFAS 154 will have a material effect on our financial position, results of operations or cash flows.

In September 2005, the EITF reached consensus in EITF 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, to define when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction subject to APB Opinion No. 29, Accounting for Nonmonetary Transactions. Two or more inventory transactions with the same party should be combined if they are entered into in contemplation of one another. The consensus also requires entities to account for exchanges of inventory in the same line of business at fair value or recorded amounts based on inventory classification. The guidance in EITF 04-13 is effective for new inventory arrangements entered into in reporting periods beginning after March 15, 2006. We are currently evaluating what impact EITF 04-13 will have on our financial statements, but at this time we do not believe that the adoption of EITF 04-13 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, but instead requires testing for impairment at least annually. We test goodwill for impairment annually at December 31.

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

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The following table presents the carrying amount of goodwill at both September 30, 2005, and December 31, 2004, by business segment (in thousands):

 

Other Intangible Assets

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

 

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 $8.2 million and $8.6 million for the three months ended September 30, 2005 and 2004, respectively, and $22.3 million and $25.0 million for the nine months ended September 30, 2005 and 2004, respectively. Amortization expense on excess investments included in equity earnings was $1.3 million and $1.1 million for the three months ended September 30, 2005 and 2004, respectively, and $3.8 million and $2.9 million for the nine months ended September 30, 2005 and 2004, respectively.

The values assigned to our intangible assets for natural gas gathering contracts on the Jonah Gas Gathering Company (“Jonah”) and the Val Verde Gas Gathering Company (“Val Verde”) systems are amortized on a unit-of-production basis, based upon the actual throughput of the systems over the expected total throughput for the lives of the contracts. On a quarterly basis, we may obtain limited production forecasts and updated throughput estimates from some of the producers on the systems, and as a result, we evaluate the remaining expected useful lives of the contract assets 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 system related to future expansions of the system, and as a result, we increased our best estimate of future throughput on the system, which resulted in extensions in the remaining lives of the intangible assets. During the fourth quarter of 2004 and the third quarter of 2005, certain limited coal bed methane production forecasts were obtained from some of the producers on the Val Verde system whose contracts are included in the intangible assets. These forecasts

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indicated lower coal bed methane production estimates over the contract periods, and as a result, we decreased our best estimate of future throughput on the Val Verde system, which resulted in increases to amortization expense on the intangible assets. Further revisions to these estimates may occur as additional production information is made available to us.

The values assigned to our fractionation agreement and other intangible assets are generally amortized on a straight-line basis. Our fractionation agreement 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.

The value assigned to our excess investment in Centennial Pipeline LLC was created upon its formation. Approximately $30.0 million is related to a contract and is being amortized on a unit-of-production basis based upon the volumes transported under the contract compared to the guaranteed total throughput of the contract over a 10-year life. The remaining $3.4 million is related to a pipeline and is being amortized on a straight-line basis over the life of the pipeline, which is 35 years. The value assigned to our excess investment in Seaway Crude Pipeline Company was created upon acquisition of our 50% ownership interest in 2000. We are amortizing the $27.1 million excess investment on a straight-line basis over a 39-year life related primarily to the life of the pipeline.

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

 

NOTE 3. PROPERTY, PLANT AND EQUIPMENT

We evaluate impairment of long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of the carrying amount of assets to be held and used is measured by a comparison of the carrying amount of the asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.

During the third quarter of 2005, our Upstream Segment was notified by a connecting carrier that the flow of its pipeline system would be reversed, which would directly impact the viability of one of our pipeline systems. This system, located in East Texas, consists of approximately 45 miles of pipeline, six tanks of various sizes and other equipment and asset costs. As a result of changes to the connecting carrier, we performed an impairment test of the system and recorded a $1.8 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the fair value of the system.

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During the third quarter of 2005, we completed an evaluation of a crude oil system included in our Upstream Segment. The system, located in Oklahoma, consists of approximately six miles of pipelines, tanks and other equipment and asset costs. The usage of the system has declined in recent months as a result of shifting crude oil production into areas not supported by the system, and as such, it has become more economical to transport barrels by truck to our other pipeline systems. As a result, we performed an impairment test on the system and recorded a $0.8 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the fair value of the system.

In September 2005, our Todhunter facility, near Middletown, Ohio, experienced a propane release and fire at a dehydration unit within the storage facility. The facility is included in our Downstream Segment. The dehydration unit was destroyed due to the propane release and fire, and as a result, we wrote off the remaining book value of the asset of $0.8 million to depreciation and amortization expense during the third quarter of 2005.

During the third quarter of 2004, we completed an evaluation of our marine terminal facility in the Beaumont, Texas, area. The facility consists primarily of a barge dock, a ship dock, four storage tanks and various segments of connecting pipelines and is included in our Downstream Segment. The evaluation indicated that the docks and other assets at the facility needed extensive work to continue to be commercially operational. As a result, we performed an impairment test on the entire marine facility and recorded a $4.4 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the fair value of the facility.

NOTE 4. 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.

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 nine months ended September 30, 2005 and 2004, we recognized reductions in interest expense of $4.6 million and $7.5 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 September 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 $1.3 million and $3.4 million at September 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

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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 September 30, 2005, the unamortized balance of the deferred gains was $33.5 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 5. ACQUISITIONS AND DISPOSITIONS

Rancho Pipeline

In connection with our acquisition of crude oil assets in 2000, we acquired an approximate 23.5% undivided joint interest in the Rancho Pipeline, which was a crude oil pipeline system from West Texas to Houston, Texas. In March 2003, the Rancho Pipeline ceased operations, and segments of the pipeline were sold to certain of the owners that previously held undivided interests in the pipeline. We acquired 241 miles of the pipeline in exchange for cash of $5.5 million and our interests in other portions of the Rancho Pipeline. We sold 183 miles of the segment we acquired to other entities for cash and assets valued at approximately $8.5 million. We recorded a net gain of $3.9 million on the transactions in the second quarter of 2003. During the third quarter of 2004, we sold our remaining interest in the original Rancho Pipeline system for a net gain of $0.4 million. These gains are included in the gains on sales of assets in our consolidated statements of income in the 2004 period.

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 are integrating 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.

Crude Oil 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

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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.

Refined Products Terminal and Truck Rack

On July 12, 2005, we purchased a refined products terminal and two-bay truck loading 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. 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 terminal serves the central Arkansas refined products market and complements our existing Downstream Segment infrastructure in North Little Rock, Arkansas.

Genco Assets

On July 15, 2005, we acquired from Texas Genco LLC (“Genco”) all of its interests in certain companies that own a 90-mile pipeline system and 5.5 million barrels of storage capacity for $62.1 million. We funded the purchase through borrowings under 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. This acquisition was made as part of an expansion of our refined products origin capabilities in the Houston, Texas, and Texas City, Texas, areas. The assets of the purchased companies 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.

NOTE 6. 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 September 30, 2005, and December 31, 2004. The major components of inventories were as follows (in thousands):

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

NOTE 7. 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

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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 nine months ended September 30, 2005 and 2004, we received distributions from Seaway of $17.5 million and $30.9 million, respectively.

TE Products owns a 50% ownership interest in Centennial Pipeline Company LLC (“Centennial”), and Marathon Petroleum Company LLC (“Marathon”) owns the remaining 50% interest. Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois. During the nine months ended September 30, 2005, TE Products has not invested any additional funds in Centennial. During the nine months ended September 30, 2004, TE Products invested an additional $1.5 million in Centennial, which is included in the equity investment balance at September 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 nine months ended September 30, 2005 and 2004, TE Products’ sharing ratio in the earnings of MB Storage was approximately 64.3% and 72.3%, respectively. During the nine months ended September 30, 2005, TE Products received distributions of $10.7 million from MB Storage and contributed $4.0 million to MB Storage, which includes a combination of non-cash asset transfers of $1.4 million and cash contributions of $2.6 million. During the nine months ended September 30, 2004, TE Products received distributions of $8.5 million from MB Storage and contributed $20.2 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 nine months ended September 30, 2005 and 2004, is presented below (in thousands):

 

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

 

NOTE 8. 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 September 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 September 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

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indenture does not limit our ability to incur additional indebtedness. As of September 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 September 30, 2005, and December 31, 2004 (in millions):

 

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 4. Interest Rate Swaps).

Revolving Credit Facility

On June 27, 2003, we entered into a $550.0 million unsecured 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. Restrictive covenants in the Revolving Credit Facility limit our ability to, among other things, incur additional indebtedness, make distributions in excess of Available Cash (see Note 9. Partners’ Capital and Distributions) and complete mergers, acquisitions and sales of assets. 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 the equity offering in May 2005 to repay a portion of the Revolving Credit Facility (see Note 9. Partners’ Capital and Distributions). At September 30, 2005, $460.5 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 4.6%. At September 30, 2005, we were in compliance with the covenants of this credit agreement.

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

 

NOTE 9. 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 unitholders’ cash distributions exceed certain target thresholds as follows:

 

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

 

On November 7, 2005, we will pay a cash distribution of $0.675 per Unit for the quarter ended September 30, 2005. The third quarter 2005 cash distribution will total $66.9 million.

General Partner’s Interest

As of September 30, 2005, and December 31, 2004, we had deficit balances of $54.9 million and $35.9 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 nine months ended September 30, 2005, the General Partner was allocated $34.5 million (representing 29.27%) of our net income and received $53.5 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 September 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 nine months ended September 30, 2005, resulted in deficits in the General Partner’s equity account at December 31, 2004, and September 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.

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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.

NOTE 10. 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, participants will not receive additional pay credits after that date, and all plan participants will be 100% vested regardless of their years of service. The TEPPCO RCBP plan will be terminated effective December 31, 2005, and plan participants will have the option to receive their benefits either through a lump sum payment in 2006 or through an annuity. For those plan participants who elect to receive an annuity, we will purchase an annuity contract from an insurance company in which the plan participant will own the annuity, absolving us of any future obligation to the participant. Participants in the TEPPCO SBP will receive pay credits through November 30, 2005, and will receive lump sum benefit payments in December 2005. Both the RCBP and SBP benefit payments are discussed below.

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

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

 

Other Postretirement Benefits

We provide certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis (“TEPPCO OPB”). Employees become eligible for these benefits if they meet certain age and service requirements at retirement, as defined in the plans. We provide a fixed dollar contribution, which does not increase from year to year, towards retired employee medical costs. The retiree pays all health care cost increases due to medical inflation. We use a December 31 measurement date for this plan.

In May 2005, benefits provided to employees under the TEPPCO OPB were changed. Employees eligible for these benefits will receive them through December 31, 2005, however, effective December 31, 2005, these benefits will be terminated. In June 2005, as a result of this change in benefits and in accordance with SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, we recorded a curtailment credit of approximately $2.6 million in our accumulated postretirement obligation, partially offset by a curtailment charge of approximately $1.0 million related to the accelerated recognition of the unrecognized prior service costs. The net effect of these curtailment adjustments was to reduce our accumulated postretirement obligation to the total of the expected remaining 2005 payments under the TEPPCO OPB. The current employees participating in this plan were transferred to DEFS, who will continue to provide postretirement benefits to these retirees. We recorded a one-time settlement to DEFS in the third quarter of 2005 of $0.4 million for the remaining postretirement benefits.

The components of net postretirement benefits cost for the TEPPCO OPB for the three and nine months ended September 30, 2005 and 2004, were as follows (in thousands):

 

Effective June 1, 2005, the payroll functions performed by DEFS for our General Partner were transferred from DEFS to EPCO. For those employees who were receiving certain other postretirement benefits at the time of

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the acquisition of our General Partner by DFI, DEFS will continue to provide these benefits to those employees. Effective June 1, 2005, EPCO began providing certain other postretirement benefits to those employees who became eligible for the benefits after June 1, 2005, and will charge those benefit related costs to us. As a result of these changes, we recorded a $1.2 million reduction in our other postretirement obligation in June 2005.

Estimated Future Benefit Contributions

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

NOTE 11. 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 7. 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 7. 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

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(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 nine months ended September 30, 2005 and 2004 (in thousands):

		Three Months Ended September 30, 2005
		Downstream Segment			Upstream Segment			Midstream Segment			Segments Total			Partnership and Other			Consolidated
		(as restated)			(as restated)						(as restated)						(as restated)
Sales of petroleum products		$	—		$	2,367,984		$	2,880		$	2,370,864		$	(154	)	$	2,370,710
Operating revenues		66,094			12,750			54,430			133,274			(188		)	133,086
Purchases of petroleum products		—			2,350,107			2,585			2,352,692			(188		)	2,352,504
Operating expenses, including power		41,405			18,956			16,086			76,447			(154		)	76,293
Depreciation and amortization expense		10,098			6,471			14,391			30,960			—			30,960
Gains on sales of assets		(24		)	(7		)	—			(31		)	—			(31		)
Operating income		14,615			5,207			24,248			44,070			—			44,070
Equity earnings (losses)		(651		)	5,398			—			4,747			—			4,747
Other income, net		306			103			75			484			—			484
Earnings before interest		$	14,270		$	10,708		$	24,323		$	49,301		$	—		$	49,301

 

		Three Months Ended September 30, 2004
		Downstream Segment			Upstream Segment			Midstream Segment			Segments Total			Partnership and Other			Consolidated
		(as restated)			(as restated)						(as restated)						(as restated)
Sales of petroleum products		$	—		$	1,358,220		$	1,734		$	1,359,954		$	—		$	1,359,954
Operating revenues		68,546			11,866			49,961			130,373			(317		)	130,056
Purchases of petroleum products		—			1,344,613			1,381			1,345,994			(317		)	1,345,677
Operating expenses, including power		43,419			17,804			16,601			77,824			—			77,824
Depreciation and amortization expense		12,818			3,268			14,191			30,277			—			30,277
Gains on sales of assets		(472		)	(377		)	—			(849		)	—			(849		)
Operating income		12,781			4,778			19,522			37,081			—			37,081
Equity earnings (losses)		(1,234		)	5,770			—			4,536			—			4,536
Other income, net		203			60			21			284			—			284
Earnings before interest		$	11,750		$	10,608		$	19,543		$	41,901		$	—		$	41,901

 

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		Nine Months Ended September 30, 2005
		Downstream Segment			Upstream Segment			Midstream Segment			Segments Total			Partnership and Other			Consolidated
		(as restated)			(as restated)						(as restated)						(as restated)
Sales of petroleum products		$	—		$	5,714,353		$	7,337		$	5,721,690		$	(154	)	$	5,721,536
Operating revenues		207,699			36,161			157,622			401,482			(2,237		)	399,245
Purchases of petroleum products		—			5,665,136			5,761			5,670,897			(2,237		)	5,668,660
Operating expenses, including power		117,271			49,615			41,882			208,768			(154		)	208,614
Depreciation and amortization expense		29,460			13,623			39,932			83,015			—			83,015
Gains on sales of assets		(131		)	(59		)	(407		)	(597		)	—			(597		)
Operating income		61,099			22,199			77,791			161,089			—			161,089
Equity earnings (losses)		(2,718		)	19,310			—			16,592			—			16,592
Other income, net		576			132			177			885			—			885
Earnings before interest		$	58,957		$	41,641		$	77,968		$	178,566		$	—		$	178,566

 

		Nine Months Ended September 30, 2004
		Downstream Segment			Upstream Segment			Midstream Segment			Segments Total			Partnership and Other			Consolidated
		(as restated)			(as restated)						(as restated)						(as restated)
Sales of petroleum products		$	—		$	3,770,006		$	4,868		$	3,774,874		$	—		$	3,774,874
Operating revenues		205,719			37,430			146,994			390,143			(2,382		)	387,761
Purchases of petroleum products		—			3,728,345			4,367			3,732,712			(2,382		)	3,730,330
Operating expenses, including power		122,020			46,880			46,487			215,387			—			215,387
Depreciation and amortization expense		31,106			9,381			44,021			84,508			—			84,508
Gains on sales of assets		(489		)	(484		)	—			(973		)	—			(973		)
Operating income		53,082			23,314			56,987			133,383			—			133,383
Equity earnings (losses)		(4,477		)	24,404			—			19,927			—			19,927
Other income, net		648			257			95			1,000			—			1,000
Earnings before interest		$	49,253		$	47,975		$	57,082		$	154,310		$	—		$	154,310

 

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

		Downstream Segment			Upstream Segment			Midstream Segment			Segments Total			Partnership and Other			Consolidated
September 30, 2005 (as restated):
Total assets		$	1,040,716		$	1,512,362		$	1,241,780		$	3,794,858		$	(6,518	)	$	3,788,340
Capital expenditures		38,617			30,677			78,089			147,383			680			148,063
Non-cash investing activities		1,429			—			—			1,429			—			1,429
December 31, 2004:
Total assets		$	959,042		$	1,069,007		$	1,184,184		$	3,212,233		$	(25,949	)	$	3,186,284
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 nine months ended September 30, 2005 and 2004 (in thousands):

 

NOTE 12. COMMITMENTS AND CONTINGENCIES

Litigation

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.

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