UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2006

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)

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

 

1100 Louisiana Street, Suite 1300
Houston, Texas 77002
(Address of principal executive offices, including zip code)

(713) 381-3636
(Registrant’s telephone number, including area code)

2929 Allen Parkway
P.O. Box 2521
Houston, Texas 77252-2521
(Former address)

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.  (Check one):    Large accelerated filer x     Accelerated Filer o     Non-accelerated Filer 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 August 3, 2006:   75,713,554

TEPPCO PARTNERS, L.P.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2006 (unaudited) and December 31, 2005 (unaudited)
Consolidated Statements of Income for the three months and six months ended June 30, 2006 and 2005 (unaudited)
Consolidated Statements of Cash Flows for the six months ended June 30, 2006 and 2005 (unaudited)
Consolidated Statement of Partners’ Capital for the six months ended June 30, 2006 (unaudited)
Consolidated Statements of Comprehensive Income for the three months and six months ended June 30, 2006 and 2005 (unaudited)
Notes to the Consolidated Financial Statements (unaudited)
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
Cautionary Note Regarding 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 1A. Risk Factors
Item 6.  Exhibits
Signatures

 

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

TEPPCO PARTNERS,  L.P.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands)

		June 30,			December 31,
		2006			2005
ASSETS
Current assets:
Cash and cash equivalents		$	185		$	119
Accounts receivable, trade (net of allowance for doubtful accounts of $100 and $250)		830,129			803,373
Accounts receivable, related parties		2,063			5,207
Inventories		40,077			29,069
Other		56,358			61,361
Total current assets		928,812			899,129
Property, plant and equipment, at cost (net of accumulated depreciation and amortization of $512,814 and $474,332)		1,957,451			1,960,068
Equity investments		353,519			359,656
Intangible assets		360,600			376,908
Goodwill		16,944			16,944
Other assets		69,809			67,833
Total assets		$	3,687,135		$	3,680,538
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities		$	828,270		$	800,033
Accounts payable, related parties		19,661			11,836
Accrued interest		32,036			32,840
Other accrued taxes		18,510			16,532
Other		37,584			75,970
Total current liabilities		936,061			937,211
Senior notes		1,106,677			1,119,121
Other long-term debt		445,000			405,900
Deferred tax liability		514			—
Other liabilities and deferred credits		27,233			16,936
Commitments and contingencies
Partners’ capital:
Accumulated other comprehensive (loss) income		(262		)	11
General partner’s interest		(70,145		)	(61,487		)
Limited partners’ interests		1,242,057			1,262,846
Total partners’ capital		1,171,650			1,201,370
Total liabilities and partners’ capital		$	3,687,135		$	3,680,538

 

See accompanying Notes to Unaudited 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						Six Months Ended
		June 30,						June 30,
		2006			2005			2006			2005
Operating revenues:
Sales of petroleum products		$	2,287,266		$	1,961,302		$	4,683,612		$	3,346,369
Transportation – Refined products		39,443			37,834			71,242			72,799
Transportation – LPGs		13,354			14,470			42,775			46,701
Transportation – Crude oil		10,544			9,042			19,467			18,214
Transportation – NGLs		10,738			11,387			21,391			21,606
Gathering – Natural gas		41,459			36,956			82,834			73,516
Other		22,248			16,394			40,100			31,971
Total operating revenues		2,425,052			2,087,385			4,961,421			3,611,176
Costs and expenses:
Purchases of petroleum products		2,254,756			1,941,890			4,625,796			3,312,980
Operating expense		55,275			43,721			101,778			86,396
Operating fuel and power		12,987			11,546			27,284			22,616
General and administrative		9,158			6,100			18,359			13,305
Depreciation and amortization		28,676			26,138			57,433			51,749
Taxes – other than income taxes		6,048			4,241			11,359			9,647
Gains on sales of assets		(18		)	(68		)	(1,396		)	(566		)
Total costs and expenses		2,366,882			2,033,568			4,840,613			3,496,127
Operating income		58,170			53,817			120,808			115,049
Interest expense – net		(19,198		)	(21,627		)	(40,341		)	(40,914		)
Equity earnings		2,674			7,751			3,663			11,845
Other income – net		454			135			1,353			401
Income before deferred income tax expense		42,100			40,076			85,483			86,381
Deferred income tax expense		514			—			514			—
Income from continuing operations		41,586			40,076			84,969			86,381
Income (loss) from discontinued operations		(110		)	846			1,497			1,970
Gain on sale of discontinued operations		(12		)	—			17,872			—
Discontinued operations		(122		)	846			19,369			1,970
Net income		$	41,464		$	40,922		$	104,338		$	88,351

 

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		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2006			2005			2006			2005
Net Income Allocation:
Limited Partner Unitholders:
Income from continuing operations		$	29,360		$	28,154		$	59,988		$	61,101
Income from discontinued operations		(86		)	594			13,674			1,394
Total Limited Partner Unitholders net income allocation		29,274			28,748			73,662			62,495
General Partner:
Income from continuing operations		12,226			11,922			24,981			25,280
Income from discontinued operations		(36		)	252			5,695			576
Total General Partner net income allocation		12,190			12,174			30,676			25,856
Total net income allocated		$	41,464		$	40,922		$	104,338		$	88,351
Basic and diluted net income per Limited Partner Unit:
Continuing operations		$	0.42		$	0.42		$	0.85		$	0.94
Discontinued operations		—			0.01			0.20			0.02
Basic and diluted net income per Limited Partner Unit		$	0.42		$	0.43		$	1.05		$	0.96
Weighted average Limited Partner Units outstanding		69,964			66,559			69,964			64,789

 

See accompanying Notes to Unaudited Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

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

		Six Months Ended
		June 30,
		2006			2005
Cash flows from operating activities:
Net income		$	104,338		$	88,351
Adjustments to reconcile net income to cash provided by continuing operating activities:
Income from discontinued operations		(19,369		)	(1,970		)
Deferred income tax expense		514			—
Depreciation and amortization		57,433			51,749
Earnings in equity investments		(3,663		)	(11,845		)
Distributions from equity investments		16,297			19,047
Gains on sales of assets		(1,396		)	(566		)
Non-cash portion of interest expense		840			810
Increase in accounts receivable, trade		(26,756		)	(133,049		)
Decrease in accounts receivable, related parties		3,144			8,443
Increase in inventories		(10,981		)	(70,562		)
(Increase) decrease in other current assets		5,003			(15,265		)
Increase in accounts payable and accrued expenses		14,374			116,025
Increase (decrease) in accounts payable, related parties		7,825			(19,234		)
Other		(6,069		)	(4,232		)
Net cash provided by continuing operating activities		141,534			27,702
Net cash provided by discontinued operations		1,521			2,251
Net cash provided by operating activities		143,055			29,953
Cash flows from investing activities:
Proceeds from the sales of assets		39,750			510
Purchase of assets		—			(42,482		)
Investment in Centennial Pipeline LLC		(2,500		)	—
Investment in Mont Belvieu Storage Partners, L.P.		(1,720		)	(1,109		)
Cash paid for linefill on assets owned		(1,371		)	(5,353		)
Capital expenditures		(82,463		)	(82,963		)
Net cash used in investing activities		(48,304		)	(131,397		)
Cash flows from financing activities:
Proceeds from revolving credit facility		305,550			299,307
Repayments on revolving credit facility		(266,450		)	(374,307		)
Issuance of Limited Partner Units, net		—			278,832
Distributions paid		(133,785		)	(117,316		)
Net cash provided by (used in) financing activities		(94,685		)	86,516
Net increase (decrease) in cash and cash equivalents		66			(14,928		)
Cash and cash equivalents at beginning of period		119			16,422
Cash and cash equivalents at end of period		$	185		$	1,494
Supplemental disclosure of cash flows:
Cash paid for interest (net of amounts capitalized)		$	42,074		$	41,067

 

See accompanying Notes to Unaudited Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

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

		Outstanding								Accumulated
		Limited		General			Limited			Other
		Partner		Partner’s			Partners’			Comprehensive
		Units		Interest			Interests			Income (Loss)			Total
Partners’ capital at December 31, 2005		69,963,554		$	(61,487	)	$	1,262,846		$	11		$	1,201,370
Net income allocation		—		30,676			73,662			—			104,338
Cash distributions		—		(39,334		)	(94,451		)	—			(133,785		)
Changes in fair values of interest rate cash flow hedges		—		—			—			1,671			1,671
Changes in fair values of interest rate cash flow hedges		—		—			—			(1,671		)	(1,671		)
Changes in fair values of crude oil cash flow hedges		—		—			—			(273		)	(273		)
Partners’ capital at June 30, 2006		69,963,554		$	(70,145	)	$	1,242,057		$	(262	)	$	1,171,650

 

See accompanying Notes to Unaudited Consolidated Financial Statements.

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TEPPCO PARTNERS,  L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(in thousands)

		Three Months Ended June 30,						Six Months Ended June 30,
		2006			2005			2006			2005
Net income		$	41,464		$	40,922		$	104,338		$	88,351
Changes in fair values of interest rate cash flow hedges		1,671			—			1,671			—
Changes in fair values of interest rate cash flow hedges		(1,671		)	—			(1,671		)	—
Changes in fair values of crude oil cash flow hedges		(509		)	—			(273		)	—
Comprehensive income		$	40,955		$	40,922		$	104,065		$	88,351

 

See accompanying Notes to Unaudited 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.”  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.

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.

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.  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.  In conjunction with an amended and restated administrative services agreement (“ASA”), EPCO performs all management, administrative and operating functions required for us, and we reimburse EPCO for all direct and indirect expenses that have been incurred in managing us.  As a result of the sale of our General Partner, DEFS and Duke Energy continued to provide some administrative services for us for a period of up to one year after the sale, at which time, we or EPCO assumed these services.  Prior to the sale of our General Partner, DEFS also managed and operated certain of our TEPPCO Midstream assets for us under contractual agreements.  We assumed the operations of these assets from DEFS, and certain DEFS employees became employees of EPCO effective June 1, 2005.

In connection with our formation, the Company received 2,500,000 Deferred Participation Interests (“DPIs”).  Effective April 1, 1994, the DPIs were converted to Limited Partner Units, but they have not been listed for trading on the New York Stock Exchange.  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 Limited Partner Units for $104.0 million.  As of June 30, 2006, none of these Limited Partner Units had been sold by DFI.

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, 2006, 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, 2006, are not necessarily indicative of results of our operations for the full year 2006.  You should read these interim financial statements in conjunction with our consolidated financial statements and notes thereto presented in our Current Report on Form 8-K filed on June 16, 2006, which recast certain information from our Annual Report on Form 10-K for the year ended December 31, 2005, as discontinued operations. We have reclassified certain amounts from prior periods to conform to the current presentation.

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Business Segments

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 net income, after deduction of the General Partner’s interest, by the weighted average number of Units outstanding (a total of 70.0 million Units and 66.6 million Units for the three months ended June 30, 2006 and 2005, respectively, and a total of 70.0 million Units and 64.8 million Units for the six months ended June 30, 2006 and 2005, respectively). 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).  The General Partner was allocated $12.2 million (representing 29.4%) and $12.2 million (representing 29.75%) of our net income for the three months ended June 30, 2006 and 2005, respectively, and $30.7 million (representing 29.4%) and $25.9 million (representing 29.27%) of our net income for the six months ended June 30, 2006 and 2005, respectively.  The General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase, in accordance with the Third Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P. (“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, 2006 and 2005, as there were no dilutive instruments outstanding.

Deferred Income Tax Expense for Certain Pipeline Operations

In May 2006, the State of Texas enacted a new business tax (the “Texas Margin Tax”) that replaces its existing franchise tax.  In general, legal entities that do business in Texas are subject to the new margin tax.  Limited partnerships, limited liability companies, corporations, limited liability partnerships and joint ventures are examples of the types of entities subject to the Texas Margin Tax.  As a result of the change in tax law, our tax status in the state of Texas changed from nontaxable to taxable.  The tax is considered an income tax for purposes of adjustments to deferred tax liability, as the tax is determined by applying a tax rate to a base that considers both revenues and expenses.  Our deferred income tax expense for state taxes relates only to Texas Margin Tax obligations.  The Texas Margin Tax becomes effective for franchise tax reports due on or after January 1, 2008.  The Texas Margin Tax due in 2008 will be based on revenues earned during the 2007 fiscal year.

The Texas Margin Tax is assessed at 1% of Texas-sourced taxable margin, which is computed as the lesser of (i) 70% of total revenue or (ii) total revenues less (a) cost of goods sold or (b) compensation.  The deferred tax liability shown on our consolidated balance sheet reflects the net tax effect of temporary differences related to items such as property, plant and equipment; therefore, the deferred tax liability is noncurrent.  We have calculated and recorded an estimated deferred tax liability of approximately $0.5 million associated with the Texas Margin Tax.  The non-cash offsetting charge is shown on our unaudited consolidated statements of income as deferred income tax expense for the three months and six months ended June 30, 2006.

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Since the Texas Margin Tax is determined by applying a tax rate to a base that considers both revenues and expenses, it has characteristics of an income tax.  Accordingly, we determined the Texas Margin Tax should be accounted for as an income tax in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes.

Asset Retirement Obligations

During the second quarter of 2006, we recorded $0.3 million of expense, included in depreciation and amortization expense, related to a conditional asset retirement obligation.  Additionally, we recorded a $0.4 million liability, which represents the fair value, as measured at June 30, 2006, of the conditional asset retirement obligation related to structural restoration work to be completed on leased office space that is required upon our anticipated office lease termination.  This conditional asset retirement obligation was not previously recorded, due to the indeterminate range of settlement dates and settlement methods, during the implementation of SFAS No. 143, Accounting for Asset Retirement Obligations, and Financial Accounting Standards Board (“FASB”) Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143, which we adopted on January 1, 2003 and December 31, 2005, respectively.  With the availability of new information, we were able to assign probabilities for settlement dates and settlement methods for use in an expected present value measurement of fair value.

New Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123(R) (revised 2004), Share-Based Payment.  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) requires that the cost resulting from all share-based payment transactions be recognized in the financial statements at fair value.  In April 2005, both the FASB and the Securities and Exchange Commission decided to delay the effective date for public companies to implement SFAS 123(R).  SFAS 123(R) became effective for public companies for annual periods beginning after June 15, 2005.  Accordingly, we adopted SFAS 123(R) in the first quarter of 2006.  We adopted SFAS 123(R) under the modified prospective transition method.  We have determined that our 1999 and 2005 Phantom Unit Plans are liability awards under the provisions of this statement.  No additional compensation expense has been recorded in connection with the adoption of SFAS 123(R) as we have historically recorded the associated liabilities at fair value.  The adoption of SFAS 123(R) did not have a material effect on our financial position, results of operations or cash flows.

In June 2005, the Emerging Issues Task Force (“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.  Although this EITF did not directly impact us, it did impact our General Partner.  Our General Partner

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adopted this EITF on January 1, 2006.  The adoption of EITF 04-5 resulted in the consolidation of our results of operations and balance sheet into its consolidated financial statements.

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.  The adoption of SFAS 154 did not 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 EITF 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 adopted EITF 04-13 on April 1, 2006, which resulted in crude oil inventory purchases and sales under buy/sell transactions, which were previously recorded as gross purchases and sales, to be treated as inventory exchanges in our consolidated statements of income.  EITF 04-13 reduced gross revenues and purchases, but did not have a material effect on our financial position, results of operations or cash flows.  The treatment of buy/sell transactions under EITF 04-13 reduced the relative amount of revenues and purchases of petroleum products on our consolidated statement of income by approximately $313.7 million for the periods ended June 30, 2006.  The revenues and purchases of petroleum products associated with buy/sell transactions that are reported on a gross basis in our consolidated statements of income for the three months ended June 30, 2005, and for the six months ended June 30, 2006 and 2005, are approximately $326.9 million, $589.1 million and $403.3 million, respectively.

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments, which amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. This statement improves the financial reporting of certain hybrid financial instruments and simplifies the accounting for these instruments. SFAS 155 permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives, and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS 155 is effective for all financial instruments acquired, issued, or subject to a remeasurement event occurring after the fiscal year that begins after September 15, 2006 (January 1, 2007).  At June 30, 2006, we did not have any hybrid financial securities outstanding and, as such, we do not believe that adoption of this statement will have a material effect on our financial position, results of operations or cash flows, unless such hybrid securities are issued by us prior to SFAS 155 becoming effective.

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In June 2006, the EITF reached consensus in EITF 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation).  The accounting guidance permits companies to elect to present on either a gross or net basis sales and other taxes that are imposed on and concurrent with individual revenue-producing transactions between a seller and a customer.  The gross basis includes the taxes in revenues and costs; the net basis excludes the taxes from revenues. The accounting guidance does not apply to tax systems that are based on gross receipts or total revenues.  EITF 06-3 requires companies to disclose their policy for presenting the taxes and disclose any amounts presented on a gross basis if those amounts are significant.  The guidance in EITF 06-3 is effective January 1, 2007.  As a matter of policy, we report such taxes on a net basis.  We believe that adoption of EITF 06-3 will not 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.

The following table presents the carrying amount of goodwill at both June 30, 2006 and December 31, 2005, by business segment (in thousands):

 

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Other Intangible Assets

The following table reflects the components of intangible assets, including excess investments, being amortized at June 30, 2006, and December 31, 2005 (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 $8.0 million and $7.0 million for the three months ended June 30, 2006 and 2005, respectively, and $16.0 million and $14.1 million for the six months ended June 30, 2006 and 2005 respectively.  Amortization expense on excess investments included in equity earnings was $1.2 million and $1.3 million for the three months ended June 30, 2006 and 2005, respectively, and $2.4 million and $2.5 million for the six months ended June 30, 2006 and 2005, respectively.

The values assigned to our intangible assets for natural gas gathering contracts on the Jonah Gas Gathering System (“Jonah” or “Jonah system”) and the Val Verde Gas Gathering System (“Val Verde”) are amortized on a unit-of-production basis, based upon the actual throughput of the systems compared to 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.  Revisions to these estimates may occur as additional production information is made available to us.

The values assigned to our fractionation agreement and other intangible assets are generally amortized on a straight-line basis.  Our fractionation agreement is being amortized over its contract period of 20 years.  The amortization periods for our other intangible assets, which include non-compete and other agreements, range from 3 years to 15 years.  The value of $8.7 million assigned to our crude supply and transportation intangible customer contracts is being amortized on a unit-of-production basis.

The 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

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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 and the estimated amortization expense allocated to equity earnings for the years ending December 31 (in thousands):

 

NOTE 3.  INTEREST RATE SWAPS

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 of 147 basis points, and receives a fixed rate of interest of 7.51%.  During the six months ended June 30, 2006 and 2005, we recognized reductions in interest expense of $1.2 million and $3.3 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.  During the quarters ended June 30, 2006 and 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 loss of approximately $11.3 million and $0.9 million at June 30, 2006, and December 31, 2005, 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, 2006, the unamortized balance of the deferred gains was $30.2 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 for 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.

On January 20, 2006, we entered into interest rate swap agreements with a total notional amount of $200.0 million to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility.  These interest rate swaps mature in January 2008.  For the period from January 20, 2006 through June 30, 2006, changes in the fair value of the swaps were recognized in earnings, which for the six months ended June 30, 2006, was a $2.5 million reduction to interest expense.  Under the swap agreements, we pay a fixed rate of interest ranging from 4.67% to 4.695% and receive a floating rate based on a three-month U.S. Dollar LIBOR rate.  Because these swaps will be designated as cash flow hedges effective in the third quarter of 2006, future changes in fair value, to the extent the swaps are effective, will be recognized in other comprehensive income until the hedged interest costs are recognized in earnings.

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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, and we allocated the purchase price to property, plant and equipment.  We have integrated these assets into our South Texas pipeline system, which is included in our Upstream Segment.

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.

NOTE 5.  DISPOSITIONS AND DISCONTINUED OPERATIONS

Pioneer Plant

On March 31, 2006, we sold our ownership interest in the Pioneer silica gel natural gas processing plant located near Opal, Wyoming, together with Jonah’s rights to process natural gas originating from the Jonah and Pinedale fields, located in southwest Wyoming, to an affiliate of Enterprise Products Partners L.P. (“Enterprise”) for $38.0 million in cash.  The Pioneer plant was not an integral part of our Midstream Segment operations, and natural gas processing is not a core business.  We have no continuing involvement in the operations or results of this plant.    This transaction was reviewed and approved by the Audit and Conflicts Committee of the board of directors of our General Partner and a fairness opinion was rendered by an independent third-party.  The sales proceeds were used to fund organic growth projects, retire debt and for other general partnership purposes.  The carrying value of the Pioneer plant at March 31, 2006, prior to the sale, was $19.7 million.  Costs associated with the completion of the transaction were approximately $0.4 million.

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Condensed statements of income for the Pioneer plant, which is classified as discontinued operations, for the three months and six months ended June 30, 2006 and 2005, are presented below (in thousands):   

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2006			2005			2006			2005
Sales of petroleum products		$	18		$	2,315		$	3,828		$	4,457
Other		11			680			932			1,352
Total operating revenues		29			2,995			4,760			5,809
Purchases of petroleum products		139			1,806			3,000			3,176
Operating expenses		—			158			182			296
Depreciation and amortization		—			154			51			306
Taxes – other than income taxes		—			31			30			61
Total costs and expenses		139			2,149			3,263			3,839
Income (loss) from discontinued operations		$	(110	)	$	846		$	1,497		$	1,970

 

Assets of the discontinued operations consisted of the following at December 31, 2005 (in thousands):

 

Cash flows from discontinued operations for the six months ended June 30, 2006 and 2005, are presented below (in thousands):

 

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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 June 30, 2006, and December 31, 2005.  The major components of inventories were as follows (in thousands):

		June 30, 2006			December 31, 2005
Crude oil (1)		$	10,860		$	3,021
Refined products		—			4,461
LPGs		13,278			7,403
Lubrication oils and specialty chemicals		6,859			5,740
Materials and supplies		9,062			8,203
Other		18			241
Total		$	40,077		$	29,069

 

(1) At June 30, 2006, 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.  We operate the Seaway assets.  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 Seaway.  From June 2002 through December 31, 2005, we received 60% of revenue and expense of Seaway.  For 2006, we are allocated 60% of revenue and expense for the period January 1, 2006, through May 12, 2006, and 40% for the period May 13, 2006, through December 31, 2006.  Our share of revenue and expense of Seaway is 47% for 2006.  Thereafter, we will receive 40% of revenue and expense of Seaway.  During the six months ended June 30, 2006 and 2005, we received distributions from Seaway of $8.5 million and $11.7 million, respectively.  During the six months ended June 30, 2006 and 2005, we did not invest any additional funds in Seaway.

TE Products owns a 50% ownership interest in Centennial Pipeline 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 six months ended June 30, 2006, TE Products contributed $2.5 million to Centennial.  During the six months ended June 30, 2005, TE Products did not invest any additional funds in Centennial.  TE Products has received no cash distributions from Centennial since its formation.

TE Products owns a 50% ownership interest in Mont Belvieu Storage Partners, L.P. (“MB Storage”), and Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”) owns the remaining 50% interest.  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 substantial capacity and flexibility for the transportation, terminaling and storage of NGLs, LPGs and refined products.  MB Storage has no commodity trading activity.  TE Products operates the facilities for MB Storage (see Note 13 regarding expected divestiture of MB Storage).

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For the years ended December 31, 2006 and 2005, TE Products receives 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 Agreement of Limited Partnership of MB Storage.  TE Products’ share of MB Storage’s earnings may be 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 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, 2006 and 2005, TE Products’ sharing ratios in the earnings of MB Storage were approximately 61.4% and 62.6%, respectively.  During the six months ended June 30, 2006, TE Products received distributions from MB Storage of $7.8 million and contributed $1.7 million to MB Storage.  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.

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, 2006 and 2005, is presented below (in thousands):

 

Summarized combined balance sheet information for Seaway, Centennial and MB Storage as of June 30, 2006, and December 31, 2005, 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 may not be redeemed prior to their maturity on 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 the following redemption prices (expressed in percentages of the principal amount) during the twelve months beginning January 15 of the years indicated:

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and thereafter at 100% of the principal amount, together in each case with accrued interest at the redemption date.

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, 2006, 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, 2006, 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, 2006, 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, 2006, and December 31, 2005 (in millions):

 

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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).

Revolving Credit Facility

On October 21, 2004, we entered into a $600.0 million unsecured revolving credit facility with a five year term, including the issuance of letters of credit of up to $100.0 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.  Financial covenants in the Revolving Credit Facility require that we maintain a ratio of Consolidated Funded Debt to Pro Forma EBITDA (as defined and calculated in the facility) of less than 4.75 to 1.00 (subject to adjustment for specified acquisitions) and a ratio of EBITDA to Interest Expense (as defined and calculated in the facility) of at least 3.00 to 1.00, in each case with respect to specified twelve month periods.  Other 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), incur liens, engage in specified transactions with affiliates and complete mergers, acquisitions and sales of assets.  On February 23, 2005, we 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).  During the second quarter of 2005, we used a portion of the proceeds from an equity offering in May 2005 to repay a portion of the Revolving Credit Facility.  On December 13, 2005, we again amended our Revolving Credit Facility as follows:

·                  Total bank commitments increased from $600.0 million to $700.0 million.  The amendment also provided that the commitments under the credit facility may be increased up to a maximum of $850.0 million upon our request, subject to lender approval and the satisfaction of certain other conditions.

·                  The facility fee and the borrowing rate then in effect were reduced by 0.275%.

·                  The maturity date of the credit facility was extended from October 21, 2009, to December 13, 2010.  Also under the terms of the amendment, we may request up to two, one-year extensions of the maturity date.  These extensions, if requested, will become effective subject to lender approval and satisfaction of certain other conditions.

·                  The amendment also removed the $100.0 million limit on the total amount of standby letters of credit that can be outstanding under the credit facility.

At June 30, 2006, $445.0 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 5.8%.  At June 30, 2006, we were in compliance with the covenants of this credit facility. Please see Note 16 for information regarding an amendment to the Revolving Credit Facility.

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The following table summarizes the principal amounts outstanding under all of our debt instruments as of June 30, 2006, and December 31, 2005 (in thousands):

 

Letter of Credit

At June 30, 2006, we had outstanding a $14.2 million standby letter of credit in connection with crude oil purchased in the second quarter of 2006.  The payable related to these purchases of crude oil is expected to be paid during the third quarter of 2006.

NOTE 9.  PARTNERS’ CAPITAL AND DISTRIBUTIONS

Quarterly Distributions of Available Cash

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

 

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The following table reflects the allocation of total distributions paid during the six months ended June 30, 2006 and 2005 (in thousands, except per Unit amounts):

 

On August 7, 2006, we will pay a cash distribution of $0.675 per Unit for the quarter ended June 30, 2006.  The second quarter 2006 cash distribution will total $72.4 million.

General Partner’s Interest

As of June 30, 2006, and December 31, 2005, we had deficit balances of $70.1 million and $61.5 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, 2006, the General Partner was allocated $30.7 million (representing 29.4%) of our net income and received $39.3 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, 2006, and December 31, 2005, 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 reasonable discretion.  Cash distributions in excess of net income allocations and capital contributions during the year ended December 31, 2005, and the six months ended June 30, 2006, resulted in deficits in the General Partner’s equity account at December 31, 2005, and June 30, 2006.  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 our 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.

EPCO Proposal

On April 20, 2006, EPCO submitted a proposal to the Audit and Conflicts Committee of our General Partner’s Board of Directors to reduce the General Partner’s maximum percentage interest in our quarterly distributions from 50% to 25% with respect to that portion of our quarterly cash distribution to partners that exceeds $0.325 per Unit.  In exchange for the agreement to reduce its maximum percentage interest in our quarterly distributions, our General Partner would receive a number of newly-issued Units that, based on the distribution rate and the number of Units outstanding at the time of issuance, would result in our General Partner receiving cash distributions from the newly-issued Units and from its reduced maximum percentage interest in our quarterly distributions that would approximately equal the cash distributions our General Partner would have received from its maximum percentage interest in our quarterly distributions without reduction.  Based on our distribution rate and outstanding Units as of the date of the filing of this Report, the number of newly-issued Units issued to the General Partner would be approximately 14.1 million.  We filed with the Securities and Exchange Commission a preliminary proxy statement that outlines the EPCO proposal for which we will solicit approval from our unitholders at a special meeting.  The proxy statement also contains separate proposals for the adoption of an employee Unit purchase plan and a long term incentive plan.

NOTE 10. RELATED PARTY TRANSACTIONS

EPCO and Affiliates and Duke Energy, DEFS and Affiliates

We do not have any employees.  We are managed by the Company, which prior to February 23, 2005, was an indirect wholly owned subsidiary of DEFS.  According to our Partnership Agreement, the Company was entitled to reimbursement of all direct and indirect expenses related to our business activities.  As a result of the change in ownership of the General Partner on February 24, 2005, all of our management, administrative and operating functions are performed by employees of EPCO, pursuant to the ASA.  We reimburse EPCO for the allocated costs of its employees who perform operating, management and other administrative functions for us (see Note 1).

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The following table summarizes the related party transactions with EPCO and affiliates and DEFS and affiliates for the three months and six months ended June 30, 2006 and 2005 (in millions):

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2006			2005			2006			2005
Revenues from EPCO and affiliates: (1)
Sales of petroleum products		$	2.0		$	—		$	2.1		$	—
Transportation – NGLs		2.9			2.0			4.6			2.9
Transportation – LPGs		0.6			0.7			2.4			1.6
Costs and Expenses from EPCO and affiliates: (1)
Payroll, administrative and other (2)		33.4			8.8			62.4			8.8
Purchases of petroleum products		10.8			—			16.4			—
Revenues from DEFS and affiliates: (3)
Sales of petroleum products		—			—			—			4.3
Transportation – NGLs		—			—			—			2.8
Gathering – Natural gas – Jonah		—			—			—			0.5
Transportation – LPGs		—			—			—			0.7
Other operating revenues		—			—			—			2.4
Costs and Expenses from DEFS and affiliates: (3)
Payroll, administrative and other (5) (4)		—			—			—			16.2
Purchases of petroleum products		—			—			—			38.5

 

(1)          Operating revenues earned and expenses incurred from activities with EPCO and its affiliates are considered related party transactions beginning February 24, 2005, as a result of the change in ownership of the General Partner.

(2)          Substantially all of these costs were related to payroll, payroll related expenses and administrative expenses, including reimbursements related to employee benefits and employee benefit plans, incurred in managing us and our subsidiaries in accordance with the ASA.

(3)          Operating revenues earned and expenses incurred from activities with DEFS and its affiliates are considered related party transactions prior to February 23, 2005, at which time a change in ownership of the General Partner occurred.

(4)          Includes operating costs and expenses related to DEFS managing and operating the Jonah and Val Verde systems and the Chaparral NGL pipeline on our behalf under contractual agreements established at the time of acquisition of each asset.  In connection with the change in ownership of our General Partner, we have assumed these activities.

(5)          Substantially all of these costs were related to payroll, payroll related expenses and administrative expenses incurred in managing us and our subsidiaries.

At June 30, 2006 and December 31, 2005, we had a receivable from EPCO and affiliates of $1.1 million and $4.3 million, respectively, related to sales and transportation services provided to EPCO and affiliates.  At June 30, 2006 and December 31, 2005, we had a payable to EPCO and affiliates of $16.9 million and $9.8 million, respectively, related to direct payroll, payroll related costs and other operational related costs.

Beginning February 24, 2005, the majority of our insurance coverage, including property, liability, business interruption, auto and directors and officers’ liability insurance, was obtained through EPCO.  For the three months and six months ended June 30, 2006, we incurred insurance expense related to premiums paid by EPCO of $4.4 million and $7.1 million, respectively, and $2.1 million for the three months and six months ended June 30, 2005.

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At June 30, 2006 and December 31, 2005, we had insurance reimbursement receivables due from EPCO of $1.8 million and $1.3 million, respectively.

On March 31, 2006, we sold our ownership interest in the Jonah Pioneer silica gel natural gas processing plant located near Opal, Wyoming, together with Jonah’s rights to process natural gas originating from the Jonah and Pinedale fields, located in southwest Wyoming to an affiliate of Enterprise for $38.0 million.  We recognized a gain of approximately $17.9 million on the sale of this asset (see Note 5).

Jonah Joint Venture

On August 1, 2006, Enterprise (through an affiliate) became our joint venture partner by acquiring an interest in our Jonah Gas Gathering Company, the partnership through which we owned the Jonah system.  Prior to entering into the joint venture, Enterprise had managed the construction of the Phase V expansion and funded the initial costs under a letter of intent we entered into in February 2006.  In connection with the joint venture arrangement, we and Enterprise intend to continue the Phase V expansion, which is expected to increase the system capacity of the Jonah system from 1.5 billion cubic feet per day (“Bcf/d”) to approximately 2.4 Bcf/d and to significantly reduce system operating pressures, which is anticipated to lead to increased production rates and ultimate reserve recoveries.  The first portion of the expansion, which is expected to increase the system gathering capacity to approximately 2.0 Bcf/d, is scheduled to be completed in the first quarter of 2007 at an estimated cost of approximately $275.0 million.  The second portion of the expansion is expected to cost approximately $140.0 million and be completed by the end of 2007. 

 

Enterprise will continue to manage the Phase V construction project.  We are entitled to all distributions from the joint venture until specified milestones are achieved, at which point, Enterprise will be entitled to receive 50% of the incremental cash flow from portions of the system placed in service as part of the expansion.  After subsequent milestones are achieved, we and Enterprise will share distributions based on a formula that takes into account the capital contributions of the parties, including expenditures by us prior to the expansion.  In the third quarter of 2006, we will reimburse Enterprise for 50% of the Phase V cost incurred by it through August 1, 2006 (including its cost of capital).  From August 1, 2006, we and Enterprise equally share the costs of the Phase V expansion.  Upon completion of the expansion project and based on the formula in the partnership agreement, we expect to own an interest in Jonah Gas Gathering Company of approximately 80%, with Enterprise owning the remaining 20% and serving as operator and with further costs being allocated based on such ownership interests.  The joint venture will be governed by a management committee comprised of two representatives approved by Enterprise and two representatives approved by us, each with equal voting power.  This transaction was reviewed and approved by the Audit and Conflicts Committee of the board of directors of our General Partner.  Through June 30, 2006, Enterprise had incurred approximately $106.9 million of costs related to the expansion, of which $97.8 million has been paid to vendors by Enterprise.

 

NOTE 11.  EMPLOYEE BENEFIT PLANS

Retirement Plans

The TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) was a non-contributory, trustee-administered pension plan.  In addition, the TEPPCO Supplemental Benefit Plan (“TEPPCO SBP”) was a non-contributory, nonqualified, defined benefit retirement plan, in which certain executive officers participated.  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 was a cash balance formula.  Under a cash balance formula, a plan participant accumulated a retirement benefit based upon pay credits and current interest credits.  The pay credits were based on a participant’s salary, age and service.  We used a December 31 measurement date for 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 June 1, 2005, EPCO adopted the TEPPCO RCBP and the TEPPCO SBP for the benefit of its employees providing services to us.  Effective December 31, 2005, all plan benefits accrued were frozen, participants received no additional pay credits after that date, and all plan participants were 100% vested regardless of their years of service.  The TEPPCO RCBP plan was terminated effective December 31, 2005, and plan participants have the option to receive their benefits either through a lump sum payment in 2006 or through an annuity.  In April 2006, we received a determination letter from the IRS providing IRS approval of the plan

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termination.  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 owns the annuity, absolving us of any future obligation to the participant.  Participants in the TEPPCO SBP received pay credits through November 30, 2005, and received 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 recorded additional settlement charges of approximately $0.2 million in the fourth quarter of 2005 relating to the TEPPCO SBP.  We expect to record additional settlement charges of approximately $4.0 million during the third quarter of 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, 2006 and 2005, were as follows (in thousands):

 

Other Postretirement Benefits

We provided certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis (“TEPPCO OPB”).  Employees became eligible for these benefits if they met certain age and service requirements at retirement, as defined in the plans.  We provided a fixed dollar contribution, which did not increase from year to year, towards retired employee medical costs.  The retiree paid all health care cost increases due to medical inflation.  We used 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 received them through December 31, 2005, however, effective December 31, 2005, these benefits were terminated.  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 $1.7 million in our accumulated postretirement obligation which reduced our accumulated postretirement obligation to the total of the expected remaining 2005 payments under the TEPPCO OPB.  The employees participating in this plan at that time were transferred to DEFS, who is expected to provide postretirement benefits to these retirees.  We

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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 months and six months ended June 30, 2006 and 2005, 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 the acquisition of our General Partner by DFI, DEFS is expected to 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 do not expect to make further contributions to our retirement plans and other postretirement benefit plans.  However, EPCO maintains a 401(k) plan for the benefit of employees providing services to us, and we will continue to reimburse EPCO for the cost of maintaining this plan in accordance with the ASA.

NOTE 12. SEGMENT INFORMATION

We have three reporting segments:

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

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

·                  Our Midstream Segment, which is engaged in the gathering of natural gas, fractionation of NGLs and transportation of NGLs.

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

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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).

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 or delivery 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).  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 gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, and the gathering of coal bed methane and conventional natural gas in the San Juan Basin in New Mexico and Colorado, through Val Verde; 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; and the fractionation of NGLs in Colorado.  Operating results of the Pioneer plant for the three months and six months ended June 30, 2006 and 2005 are shown as discontinued operations.

On April 1, 2006, we adopted EITF 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty (see Note 1), which resulted in crude oil inventory purchases and sales under buy/sell transactions, which were previously recorded as gross purchases and sales, to be treated as inventory exchanges in our consolidated statements of income.  Implementation of EITF 04-13 as of April 1, 2006, reduced gross revenues and purchases for the three months ended June 30, 2006, but did not have a material effect on our financial position, results of operations or cash flows.  Under the consensus reached in EITF 04-13, buy/sell transactions are reported as non-monetary exchanges and consequently not presented on a gross basis in our statements of income.  Implementation of EITF 04-13 reduced revenues and purchases of petroleum products on our consolidated statements of income by approximately $313.7 million for the periods ended June 30, 2006.  Under the provisions of the consensus, retroactive restatement of buy/sell transactions reported in prior periods was not permitted.  The revenues and purchases of petroleum products associated with buy/sell transactions that are reported on a gross basis in our consolidated statements of income for the three months ended June 30, 2005, and for the six months ended June 30, 2006 and 2005, are approximately $326.9 million, $589.1 million and $403.3 million, respectively.

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The table below includes financial information by reporting segment for the three months and six months ended June 30, 2006 and 2005 (in thousands):

		Three Months Ended June 30, 2006
		Downstream Segment			Upstream Segment			Midstream Segment			Segments Total			Partnership and Other			Consolidated
Sales of petroleum products		$	—		$	2,273,878		$	13,776		$	2,287,654		$	(388	)	$	2,287,266
Operating revenues		69,333			13,134			56,569			139,036			(1,250		)	137,786
Purchases of petroleum products		—			2,243,143			12,949			2,256,092			(1,336		)	2,254,756
Operating expenses, including power		37,743			18,160			18,709			74,612			(302		)	74,310
General and administrative expenses		4,701			1,870			2,587			9,158			—			9,158
Depreciation and amortization expense		10,133			3,494			15,049			28,676			—			28,676
Gains on sales of assets		(18		)	—			—			(18		)	—			(18		)
Operating income		16,774			20,345			21,051			58,170			—			58,170
Equity earnings (losses)		(2,366		)	5,040			—			2,674			—			2,674
Other income, net		185			225			44			454			—			454
Earnings before interest, deferred income taxes and discontinued operations		$	14,593		$	25,610		$	21,095		$	61,298		$	—		$	61,298

 

		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		$	—		$	1,961,302		$	—		$	1,961,302
Operating revenues		63,438			11,698			51,656			126,792			(709		)	126,083
Purchases of petroleum products		—			1,942,599			—			1,942,599			(709		)	1,941,890
Operating expenses, including power		35,171			13,995			10,342			59,508			—			59,508
General and administrative expenses		3,509			1,219			1,372			6,100			—			6,100
Depreciation and amortization expense		9,801			3,651			12,686			26,138			—			26,138
Gains on sales of assets		(15		)	(53		)	—			(68		)	—			(68		)
Operating income		14,972			11,589			27,256			53,817			—			53,817
Equity earnings (losses)		(246		)	7,997			—			7,751			—			7,751
Other income, net		121			(46		)	60			135			—			135
Earnings before interest, deferred income tax expense and discontinued operations		$	14,847		$	19,540		$	27,316		$	61,703		$	—		$	61,703

 

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