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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarter Ended June 30, 2002

Commission File No. 1-10403

TEPPCO Partners, L.P.
(Exact name of Registrant as specified in its charter)

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

2929 Allen Parkway
P.O. Box 2521
Houston, Texas 77252-2521
(Address of principal executive offices, including zip code)

(713) 759-3636
(Registrant’s telephone number, including area code)

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

     
Yes [X]   No [   ]

     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 13, 2002: 45,462,597



 


Table of Contents

TEPPCO PARTNERS, L.P.

TABLE OF CONTENTS

           
      Page
     
PART I. FINANCIAL INFORMATION
       
 
       
Item 1. Financial Statements Consolidated Balance Sheets as of June 30, 2002 (unaudited) and December 31, 2001
    1  
 
       
 
Consolidated Statements of Income for the three months and six months ended June 30, 2002 and 2001 (unaudited)
    2  
 
       
 
Consolidated Statements of Cash Flows for the six months ended June 30, 2002 and 2001 (unaudited)
    3  
 
       
 
Notes to the Consolidated Financial Statements (unaudited)
    4  
 
       
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
    26  
 
       
 
Forward-Looking Statements
    40  
 
       
Item 3. Quantitative and Qualitative Disclosures About Market Risk
    41  
 
       
PART II. OTHER INFORMATION
       
 
       
Item 6. Exhibits and Reports on Form 8-K
    42  

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TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K.
SIGNATURES
Supplemental Indenture
Agreement of Limited Partnership of Val Verde Gas
Texas Eastern Products Pipeline 2002 Phantom Unit
Computation of Ratio of Earnings to Fixed Charges
Subsidiaries of the Partnership
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906


Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

TEPPCO PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS
(in thousands)

                         
            June 30,   December 31,
            2002   2001
           
 
            (Unaudited)        
ASSETS
Current assets:
               
 
Cash and cash equivalents
  $ 25,404     $ 25,479  
 
Accounts receivable, trade
    277,811       221,541  
 
Accounts receivable, related party
    6,554       4,310  
 
Inventories
    13,675       17,243  
 
Other
    26,464       14,907  
 
 
   
     
 
   
Total current assets
    349,908       283,480  
 
 
   
     
 
Property, plant and equipment, at cost (Net of accumulated depreciation and amortization of $312,943 and $290,248)
    1,531,349       1,180,461  
Equity investments
    292,506       292,224  
Intangible assets
    502,033       251,487  
Goodwill
    16,939       16,669  
Other assets
    45,911       41,027  
 
 
   
     
 
   
Total assets
  $ 2,738,646     $ 2,065,348  
 
 
   
     
 
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
               
 
Notes payable
  $ 185,394     $ 360,000  
 
Accounts payable and accrued liabilities
    273,711       228,075  
 
Accounts payable, related parties
    7,857       22,680  
 
Accrued interest
    32,131       15,649  
 
Other accrued taxes
    9,031       8,888  
 
Other
    34,659       33,550  
 
 
   
     
 
   
Total current liabilities
    542,783       668,842  
 
 
   
     
 
Senior Notes
    887,714       389,814  
Other long-term debt
    586,606       340,658  
Other liabilities and deferred credits
    29,336       17,223  
Redeemable Class B Units held by related party
    104,360       105,630  
Commitments and contingencies
               
Partners’ capital:
               
 
Accumulated other comprehensive loss
    (19,976 )     (20,324 )
 
General partner’s interest
    10,870       13,190  
 
Limited partners’ interests
    596,953       550,315  
 
 
   
     
 
     
Total partners’ capital
    587,847       543,181  
 
 
   
     
 
   
Total liabilities and partners’ capital
  $ 2,738,646     $ 2,065,348  
 
 
   
     
 

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   Six Months Ended
        June 30,   June 30,
       
 
        2002   2001   2002   2001
       
 
 
 
Operating revenues:
                               
 
Sales of crude oil and petroleum products
  $ 800,107     $ 978,803     $ 1,345,315     $ 1,686,284  
 
Transportation — Refined products
    31,803       51,406       56,947       77,587  
 
Transportation — LPGs
    10,813       13,506       34,173       38,505  
 
Transportation — Crude oil
    7,095       5,959       13,223       12,067  
 
Transportation — NGLs
    10,544       5,449       16,850       10,250  
 
Gathering — Natural gas
    11,454             20,974        
 
Mont Belvieu operations
    2,889       2,997       7,395       5,894  
 
Other
    13,624       15,562       24,589       28,330  
 
 
   
     
     
     
 
   
Total operating revenues
    888,329       1,073,682       1,519,466       1,858,917  
 
 
   
     
     
     
 
Costs and expenses:
                               
 
Purchases of crude oil and petroleum products
    787,933       965,919       1,321,142       1,664,495  
 
Operating, general and administrative
    35,083       29,955       66,528       57,905  
 
Operating fuel and power
    7,243       10,207       15,832       18,821  
 
Depreciation and amortization
    17,599       10,857       33,640       20,764  
 
Taxes — other than income taxes
    3,474       3,675       7,979       7,557  
 
 
   
     
     
     
 
   
Total costs and expenses
    851,332       1,020,613       1,445,121       1,769,542  
 
 
   
     
     
     
 
   
Operating income
    36,997       53,069       74,345       89,375  
Interest expense
    (16,829 )     (15,392 )     (33,616 )     (31,686 )
Interest capitalized
    1,029       590       3,138       935  
Equity earnings
    2,414       4,419       5,986       9,625  
Other income — net
    766       793       1,332       1,227  
 
 
   
     
     
     
 
   
Income before minority interest
    24,377       43,479       51,185       69,476  
Minority interest
          (441 )           (703 )
 
 
   
     
     
     
 
   
Net income
  $ 24,377     $ 43,038     $ 51,185     $ 68,773  
 
 
   
     
     
     
 
Net Income Allocation:
                               
Limited Partner Unitholders
  $ 16,467     $ 31,311     $ 35,061     $ 49,922  
Class B Unitholder
    1,441       3,478       3,234       5,670  
General Partner
    6,469       8,249       12,890       13,181  
 
 
   
     
     
     
 
   
Total net income allocated
  $ 24,377     $ 43,038     $ 51,185     $ 68,773  
 
 
   
     
     
     
 
Basic net income per Limited Partner and Class B Unit
  $ 0.39     $ 0.90     $ 0.84     $ 1.45  
 
 
   
     
     
     
 
Diluted net income per Limited Partner and Class B Unit
  $ 0.39     $ 0.89     $ 0.84     $ 1.45  
 
 
   
     
     
     
 
Weighted average Limited Partner and Class B Units outstanding
    46,346       38,867       45,457       38,380  

See accompanying Notes to Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

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

                         
            Six Months Ended
            June 30,
           
            2002   2001
           
 
Cash flows from operating activities:
               
 
Net income
  $ 51,185     $ 68,773  
 
Adjustments to reconcile net income to cash provided by operating activities:
               
     
Depreciation and amortization
    33,640       20,764  
     
Earnings in equity investments, net of distributions
    7,444       4,457  
     
Non-cash portion of interest expense
    2,284       1,356  
     
Increase in accounts receivable
    (56,270 )     (3,843 )
     
(Increase) decrease in inventories
    3,568       (13,158 )
     
Increase in other current assets
    (11,557 )     (843 )
     
Increase (decrease) in accounts payable and accrued expenses
    74,716       (13,515 )
     
Other
    (7,552 )     (2,459 )
 
 
   
     
 
       
Net cash provided by operating activities
    97,458       61,532  
 
 
   
     
 
Cash flows from investing activities:
               
   
Proceeds from cash investments
          3,236  
   
Purchase of crude oil assets
          (20,000 )
   
Proceeds from the sale of assets
    3,380       1,300  
   
Purchase of Val Verde Gathering system
    (444,150 )      
   
Purchase of Chaparral NGL system
    (132,140 )      
   
Purchase of Jonah Gas Gathering Company
    (7,315 )      
   
Investments in Centennial Pipeline, LLC
    (7,726 )     (25,142 )
   
Capital expenditures
    (63,560 )     (33,398 )
 
 
   
     
 
       
Net cash used in investing activities
    (651,511 )     (74,004 )
 
 
   
     
 
Cash flows from financing activities:
               
   
Proceeds from term and revolving credit facilities
    642,000       33,000  
   
Repayments on term and revolving credit facilities
    (570,660 )     (41,000 )
   
Issuance of Senior Notes
    497,805        
   
Debt issuance costs
    (7,043 )      
   
Issuance of Limited Partner Units, net
    59,234       54,588  
   
General Partner’s contributions
    1,217       1,114  
   
Distributions
    (68,575 )     (49,524 )
 
 
   
     
 
       
Net cash provided by (used in) investing activities
    553,978       (1,822 )
 
 
   
     
 
Net decrease in cash and cash equivalents
    (75 )     (14,294 )
Cash and cash equivalents at beginning of period
    25,479       27,095  
 
 
   
     
 
Cash and cash equivalents at end of period
  $ 25,404     $ 12,801  
 
 
   
     
 
Supplemental disclosure of cash flows:
               
   
Interest paid during the period (net of capitalized interest)
  $ 19,499     $ 32,230  
 
 
   
     
 

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.” Texas Eastern Products Pipeline Company, LLC (the “Company” or “General Partner”), a Delaware limited liability company, serves as our general partner. The General Partner is a wholly-owned subsidiary of Duke Energy Field Services (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”) and Phillips Petroleum Company (“Phillips”). Duke Energy holds an approximate 70% interest in DEFS, and Phillips holds the remaining 30%. The Company, as general partner, performs all management and operating functions required for us, except for the management and operations of certain of the TEPPCO Midstream assets. We have entered into agreements with DEFS in which DEFS manages certain of the TEPPCO Midstream assets on our behalf. We reimburse the General Partner for all reasonable direct and indirect expenses incurred in managing us.

     On July 26, 2001, the Company restructured its general partner ownership of the Operating Partnerships to cause them to be indirectly wholly-owned by us. TEPPCO GP, Inc. (“TEPPCO GP”), our subsidiary, succeeded the Company as general partner of the Operating Partnerships. All remaining partner interests in the Operating Partnerships not already owned by us were transferred to us. In exchange for this contribution, the Company’s interest as our general partner was increased to 2%. The increased percentage is the economic equivalent of the aggregate interest that the Company had prior to the restructuring through its combined interests in us and the Operating Partnerships. As a result, we hold a 99.999% limited partner interest in the Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest. This reorganization was undertaken to simplify required financial reporting by the Operating Partnerships when the Operating Partnerships issue guarantees of our debt.

     As used in this Report, “we,” “us,” “our,” and the “Partnership” means TEPPCO Partners, L.P. and, where the context requires, includes our subsidiary operating partnerships.

     The accompanying unaudited consolidated financial statements reflect all adjustments that are, in the opinion of the management of the Company, of a normal and recurring nature and necessary for a fair statement of our financial position as of June 30, 2002, 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, 2002, are not necessarily indicative of results of our operations for the full year 2002. You should read the 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, as amended, for the year ended December 31, 2001. We have reclassified certain amounts from prior periods to conform with the current presentation.

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

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

     Basic net income per Unit is computed by dividing net income, after deduction of the general partner’s interest, by the weighted average number of Limited Partner and Class B Units outstanding (a total of 45.5 million

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

and 38.4 million Units for the six months ended June 30, 2002, and 2001, respectively, and 46.3 million and 38.9 million Units for the three months ended June 30, 2002, and 2001, respectively). The general partner’s percentage interest in net income is based on its percentage of cash distributions from Available Cash for each period (see Note 9. Quarterly Distributions of Available Cash). The general partner was allocated $12.9 million (representing 25.18%) and $13.2 million (representing 19.17%) of net income for the six months ended June 30, 2002, and 2001, respectively. The General Partner’s percentage interest in our net income increased for the six months ended June 30, 2002, compared to the corresponding period in 2001, as a result of the increase in the quarterly distribution to $0.60 per Unit with respect to the second quarter of 2002 from $0.525 per Unit with respect to the second quarter of 2001.

     Diluted net income per Unit is similar to the computation of basic net income per Unit above, except that the denominator was increased to include the dilutive effect of outstanding Unit options by application of the treasury stock method. For the three months ended June 30, 2002, and 2001, the denominator was increased by 39,958 Units and 44,559 Units, respectively. For the six months ended June 30, 2002, and 2001, the denominator was increased by 45,036 Units and 36,021 Units, respectively.

NOTE 2. NEW ACCOUNTING PRONOUNCEMENTS

     In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations. SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which we incur a legal obligation for the retirement of tangible long-lived assets. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. We are required to adopt SFAS 143 effective January 1, 2003. We are currently evaluating the impact of adopting SFAS 143.

     In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 supercedes SFAS No. 121, Accounting for Long-Lived Assets and For Long-Lived Assets to be Disposed Of, but retains its fundamental provisions for reorganizing and measuring impairment losses on long-lived assets held for use and long-lived assets to be disposed of by sale. We adopted SFAS 144 effective January 1, 2002. The adoption of SFAS 144 did not have a material effect on our financial position, results of operations or cash flows.

     In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. SFAS 145 eliminates the requirement to classify gains and losses from the extinguishment of indebtedness as extraordinary, requires certain lease modifications to be treated the same as a sale-leaseback transaction, and makes other non-substantive technical corrections to existing pronouncements. SFAS 145 is effective for fiscal years beginning after May 15, 2002, with earlier adoption encouraged. We are required to adopt SFAS 145 effective January 1, 2003. We do not believe that the adoption of SFAS 145 will have a material effect on our financial position, results of operations or cash flows.

     In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS 146 requires recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. SFAS 146 is to be applied prospectively to

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

exit or disposal activities initiated after December 31, 2002. We do not believe that the adoption of SFAS 146 will have a material effect on our financial position, results of operations or cash flows.

NOTE 3. GOODWILL AND OTHER INTANGIBLE ASSETS

     In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives.

     Beginning January 1, 2002, effective with the adoption of SFAS 142, we no longer record amortization expense related to goodwill or amortization expense related to the excess investment on our equity investment in Seaway (see Note 7. Equity Investments). Upon adoption of SFAS 142 on January 1, 2002, we had not yet begun to amortize our excess investment in Centennial Pipeline, LLC; therefore, no amortization expense has been recorded in any of the periods presented below related to this excess investment. The following table presents our results on a comparable basis, as if we had not recorded amortization expense of goodwill or amortization expense of our excess investment in Seaway for the three months and six months ended June 30, 2001 (in thousands, except per Unit amounts):

                                   
      Three Months Ended June 30,   Six Months Ended June 30,
     
 
      2002   2001   2002   2001
     
 
 
 
Net income:
                               
 
Reported net income
  $ 24,377     $ 43,038     $ 51,185     $ 68,773  
 
Amortization of goodwill and excess investment
          873             1,263  
 
 
   
     
     
     
 
 
Adjusted net income
  $ 24,377     $ 43,911     $ 51,185     $ 70,036  
 
 
   
     
     
     
 
Net Income Allocation:
                               
 
Limited Partner Unitholders
  $ 16,467     $ 31,946     $ 35,061     $ 50,839  
 
Class B Unitholder
    1,441       3,549       3,234       5,774  
 
General Partner
    6,469       8,416       12,890       13,423  
 
 
   
     
     
     
 
 
Total net income allocated
  $ 24,377     $ 43,911     $ 51,185     $ 70,036  
 
 
   
     
     
     
 
Basic net income per Limited Partner and Class B Unit:
                               
 
As reported
  $ 0.39     $ 0.90     $ 0.84     $ 1.45  
 
Amortization of goodwill and excess investment
          0.01             0.03  
 
 
   
     
     
     
 
 
Adjusted net income per Unit
  $ 0.39     $ 0.91     $ 0.84     $ 1.48  
 
 
   
     
     
     
 
Diluted net income per Limited Partner and Class B Unit:
                               
 
As reported
  $ 0.39     $ 0.89     $ 0.84     $ 1.45  
 
Amortization of goodwill and excess investment
          0.02             0.02  
 
 
   
     
     
     
 
 
Adjusted net income per Unit
  $ 0.39     $ 0.91     $ 0.84     $ 1.47  
 
 
   
     
     
     
 

     Upon the adoption of SFAS 142, we were required to reassess the useful lives and residual values of all intangible assets acquired, and make necessary amortization period adjustments by the end of the first interim period after adoption. We completed this analysis during the first quarter of 2002, resulting in no change to the

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

amortization period for our intangible assets. We will continue to reassess the useful lives and residual values of all intangible assets on an annual basis.

     In connection with the transitional goodwill impairment evaluation required by SFAS 142, we were required to perform an assessment of whether there was an indication that goodwill was impaired as of the date of adoption. We accomplished this by identifying our reporting units and determining the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units as of the date of adoption. We then determined the fair value of each reporting unit and compared it to the carrying value of the reporting unit. We completed this analysis during the second quarter of 2002, resulting in no transitional impairment loss. We will continue to compare the fair value of each reporting unit to the carrying value on an annual basis to determine if an impairment loss has occurred.

     At June 30, 2002, we had $16.9 million of unamortized goodwill and $58.2 million of excess investment in our equity investments (equity method goodwill). We completed an impairment analysis of the excess investment in our equity investments during the six months ended June 30, 2002, and we noted no indication of impairment. The excess investment is included in our equity investments account at June 30, 2002. The following table presents the carrying amount of goodwill and excess investments, at June 30, 2002, by business segment (in thousands):

                                 
    Downstream   Midstream   Upstream   Segments
    Segment   Segment   Segment   Total
   
 
 
 
Goodwill
  $     $ 2,772     $ 14,167     $ 16,939  
Equity method goodwill
  $ 32,683     $     $ 25,502     $ 58,185  

     The following table reflects the components of amortized intangible assets, excluding goodwill (in thousands):

                                     
        June 30, 2002   December 31, 2001
       
 
        Gross Carrying   Accumulated   Gross Carrying   Accumulated
        Amount   Amortization   Amount   Amortization
       
 
 
 
Amortized intangible assets:
                               
 
Fractionation agreement
  $ 38,000     $ (8,075 )   $ 38,000     $ (7,125 )
 
Natural gas transportation contracts
    482,595       (11,451 )     222,800       (3,275 )
 
Other
    1,460       (496 )     1,458       (371 )
 
 
   
     
     
     
 
   
Total
  $ 522,055     $ (20,022 )   $ 262,258     $ (10,771 )
 
 
   
     
     
     
 

     Excluding goodwill, amortization expense on intangible assets was $4.7 million and $0.5 million for the three months ended June 30, 2002 and 2001, respectively, and $9.3 million and $1.1 million for the six months ended June 30, 2002 and 2001, respectively.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

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

         
2002
  $ 37,619  
2003
    60,192  
2004
    62,794  
2005
    63,663  
2006
    57,259  

NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS

     We account for derivative financial instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133. These statements establish accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Special accounting for derivatives qualifying as fair value hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of income. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative cumulative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings.

     We have utilized and expect to continue to utilize derivative financial instruments with respect to a portion of our interest rate and fair value risks and our crude oil marketing activities, as each is explained below. The derivative financial instrument related to our interest rate risk is intended to reduce our exposure to increases in the benchmark interest rates underlying our variable rate revolving credit facility. The derivative financial instruments related to our fair value risks are intended to reduce our exposure to changes in the fair value of the fixed rate Senior Notes resulting from changes in interest rates. Our Upstream Segment uses derivative financial instruments to reduce our exposure to fluctuations in the market price of crude oil. At June 30, 2002, the Upstream Segment had no open positions on derivative financial contracts. By using derivative financial instruments to hedge exposures to changes in interest rates, fair value of fixed rate Senior Notes and crude oil prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk for us. When the fair value of a derivative contract is negative, we owe the counterparty and, therefore, we do not possess credit risk. We minimize the credit risk in derivative instruments by entering into transactions with major financial institutions or commodities trading institutions. These derivative financial instruments generally take the form of swaps and forward contracts. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates or commodity prices. We manage market risk associated with interest-rate and commodity-price contracts by establishing and monitoring parameters that limit the type and degree of market risk that may be undertaken.

     On July 31, 2000, we entered into a three-year interest rate swap agreement to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facilities. The term of the interest rate swap was extended to April 6, 2004, to match the maturity of the credit facilities. We have designated this swap agreement, which hedges exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement is based on a notional amount of $250 million. Under the swap agreement, we pay a fixed rate of interest of 6.955% and receive a floating rate based on a three month U.S. Dollar LIBOR rate. Since this swap is designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. During the six months ended June 30, 2002, and 2001, we recognized $6.3 million and $2.2 million,

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

respectively, in losses, included in interest expense, on the interest rate swap attributable to interest costs occurring in 2002 and 2001. During the quarter ended June 30, 2002, 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 the interest rate swap agreement was a loss of approximately $20 million and $20.3 million at June 30, 2002, and December 31, 2001, respectively. We anticipate that approximately $10.6 million of the fair value will be transferred into earnings over the next twelve months.

     On October 4, 2001, our TE Products subsidiary 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 have designated this swap agreement, which hedges exposure to changes in the fair value of the TE Products Senior Notes, as a fair value hedge. The swap agreement has a notional amount of $210 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 based on a three month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. During the six months ended June 30, 2002, we recognized a gain of $3.6 million, recorded as a reduction of interest expense, on the interest rate swap. During the quarter ended June 30, 2002, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized.

     On February 20, 2002, we entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. We have designated these swap agreements, which hedge exposure to changes in the fair value of the Senior Notes, as fair value hedges. The swap agreements have a combined notional amount of $500 million and mature in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, we pay a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread, and receive a fixed rate of interest of 7.625%. During the six months ended June 30, 2002, we recognized a gain of $6.9 million, recorded as a reduction of interest expense, on the interest rate swaps. During the quarter ended June 30, 2002, we measured the hedge effectiveness of these interest rate swaps and noted that no gain or loss from ineffectiveness was required to be recognized.

NOTE 5. ACQUISITIONS

     On September 30, 2001, our subsidiaries completed the purchase of Jonah Gas Gathering Company (“Jonah”) from Alberta Energy Company for $359.8 million. The acquisition served as our entry into the natural gas gathering industry. We recognized goodwill in the purchase of approximately $2.8 million. We accounted for the acquisition under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated financial statements from September 30, 2001. We paid an additional $7.3 million on February 4, 2002, for final purchase adjustments related primarily to construction projects in progress at the time of closing. Under a contract arrangement on our behalf, DEFS operates and manages Jonah.

     The following table allocates the estimated fair value of the Jonah assets acquired on September 30, 2001, and includes the additional purchase adjustment paid in February 2002 (in thousands):

           
Property, plant and equipment
  $ 141,835  
Intangible assets (primarily gas transportation contracts)
    222,800  
Goodwill
    2,772  
 
   
 
 
Total assets
    367,407  
 
   
 
Total liabilities assumed
    (489 )
 
   
 
 
Net assets acquired
  $ 366,918  
 
   
 

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

     The value assigned to intangible assets relates to contracts with customers that are either for a fixed term or which dedicate total future lease production. We are amortizing the value assigned to intangible assets over the expected lives of the contracts (approximately 16 years) in proportion to the timing of expected contractual volumes.

     On March 1, 2002, we completed the purchase of the Chaparral NGL system (“Chaparral”) for $132 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P. We funded the purchase by a drawdown of our $475 million revolving credit facility (see Note 8. Debt). Chaparral is an NGL pipeline system that extends from West Texas and New Mexico to Mont Belvieu, Texas. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. Under a contractual arrangement, DEFS operates and manages these assets on our behalf. We accounted for the acquisition of the assets under the purchase method of accounting. We allocated the purchase price of $132 million to property, plant and equipment.

     On June 30, 2002, we completed the purchase of the Val Verde Gathering System (“Val Verde”) from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc., for $444.2 million, including acquisition costs of approximately $1.2 million. The Val Verde system gathers coal seam gas from the Fruitland Coal Formation of the San Juan Basin in New Mexico. The system is one of the largest coal seam gas gathering and treating facilities in the United States. Under a contractual arrangement, DEFS will operate and manage these assets on our behalf. We accounted for the acquisition under the purchase method of accounting. Accordingly, the results of the acquisition will be included in the consolidated financial statements from June 30, 2002.

     The following table allocates the estimated fair value of the Val Verde assets acquired on June 30, 2002 (in thousands):

           
Property, plant and equipment
  $ 185,000  
Intangible assets (primarily gas transportation contracts)
    259,795  
 
   
 
 
Total assets
    444,795  
 
   
 
Total liabilities assumed
    (645 )
 
   
 
 
Net assets acquired
  $ 444,150  
 
   
 

     The purchase price allocation for the Val Verde acquisition is based on our best estimate using information currently available. We are in the process of completing the final purchase price allocation for the Val Verde acquisition. We have engaged an independent appraiser to assist us in the allocation of the purchase price paid for the Val Verde assets. Consequently, it is likely that the final purchase price allocation will be different from the purchase price allocation shown above. However, we do not currently anticipate that the difference will be material to our financial position, results of operations or cash flows.

     The value assigned to intangible assets relates to fixed-term contracts with customers. We are amortizing the value assigned to intangible assets over the lives of the contracts (averaging approximately 10 years) in proportion to the expected contractual volumes.

     The following table presents our unaudited pro forma results as though the acquisitions of Jonah and Val Verde occurred at the beginning of 2001 (in thousands, except per Unit amounts). The pro forma results do not include operating efficiencies or revenue growth from historical results.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

                                 
    Three Months Ended   Six Months Ended
    June 30,   June 30,
   
 
    2002   2001   2002   2001
   
 
 
 
Revenues
  $ 908,010     $ 1,102,204     $ 1,557,251     $ 1,916,672  
Operating income
    39,766       57,018       78,248       99,193  
Net income
    23,190       39,495       47,177       63,556  
Basic and diluted net income per Limited Partner and Class B Unit
  $ 0.37     $ 0.82     $ 0.78     $ 1.34  

NOTE 6. INVENTORIES

     Inventories are carried at the lower of cost (based on weighted average cost method) or market. The major components of inventories were as follows (in thousands):

                   
      June 30,   December 31,
      2002   2001
     
 
Crude oil
  $ 1,558     $ 3,783  
Gasolines
    1,145       3,670  
Propane
          1,096  
Butanes
    2,280       1,431  
Other products
    4,300       3,744  
Materials and supplies
    4,392       3,519  
 
   
     
 
 
Total
  $ 13,675     $ 17,243  
 
   
     
 

     The costs of inventories did not exceed market values at June 30, 2002, and December 31, 2001.

NOTE 7. EQUITY INVESTMENTS

     The acquisition of the ARCO Pipe Line Company (“ARCO”) assets in July 2000 included ARCO’s 50-percent ownership interest in Seaway Crude Pipeline Company (“Seaway”), which 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 areas. Seaway is a partnership between TEPPCO Seaway, L.P. (“TEPPCO Seaway”), a subsidiary of TCTM, and Phillips. TCTM purchased the 50-percent ownership interest in Seaway on July 20, 2000, and transferred the investment to TEPPCO Seaway. The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of the Seaway partnership. From July 20, 2000, through May 2002, TEPPCO Seaway received 80% of revenue and expense of Seaway. From June 2002 through May 2006, TEPPCO Seaway receives 60% of revenue and expense of Seaway. Thereafter, the sharing ratio becomes 40% of revenue and expense to TEPPCO Seaway. For the year ended December 31, 2002, our portion of equity earnings on a pro-rated basis will average approximately 67%.

     In August 2000, TE Products entered into agreements with CMS Energy Corporation and Marathon Ashland Petroleum LLC to form Centennial Pipeline, LLC (“Centennial”). Centennial owns and operates an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. Each participant owns a one-third interest in Centennial. CMS Energy Corporation has announced that it is exploring the sale of certain of its assets, including its investment in Centennial. Through December 31, 2001, we contributed approximately $70 million for our investment in Centennial. During the six months ended June 30, 2002, we contributed approximately $7.7 million for our investment in Centennial. These amounts are included in the equity investment balance at June 30, 2002.

     We use the equity method of accounting to account for our investments in Seaway and Centennial. Summarized combined income statement data for Seaway and Centennial for the six months ended June 30, 2002, and 2001, is presented below (in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

                 
    Six Months Ended June 30,
   
    2002   2001
   
 
Revenues
  $ 35,847     $ 35,315  
Net income
    5,256       16,069  

     Summarized combined balance sheet data for Seaway and Centennial as of June 30, 2002, and December 31, 2001, is presented below (in thousands):

                 
    June 30,   December 31,
    2002   2001
   
 
Current assets
  $ 43,420     $ 57,368  
Noncurrent assets
    546,808       528,835  
Current liabilities
    18,512       31,308  
Long-term debt
    140,000       128,000  
Noncurrent liabilities
    14,553        
Partners’ capital
    417,163       426,895  

     Our investment in Seaway at June 30, 2002, and December 31, 2001, includes an excess net investment amount of $25.5 million. At June 30, 2002, our investment in Centennial includes an excess investment of $32.7 million. Excess investment is the amount by which our investment balance exceeds our proportionate share of the net assets of the investment. Prior to January 1, 2002, and the adoption of SFAS 142, we were amortizing the excess investment in Seaway using the straight-line method over 20 years.

NOTE 8. DEBT

Senior Notes

     On January 27, 1998, TE Products completed the issuance of $180 million principal amount of 6.45% Senior Notes due 2008, and $210 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 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 on a parity 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, 2002, TE Products was in compliance with the covenants of the TE Products Senior Notes.

     On February 20, 2002, we received $494.6 million in net proceeds from the issuance of $500 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount and are being accreted to their face value over the term of the notes. We used the proceeds from the offering to reduce a portion of the outstanding balances of our credit facilities, including those issued in connection with the acquisition of Jonah. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

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, 2002, we were in compliance with the covenants of these Senior Notes.

     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. Derivative Financial Instruments.

Other Long Term Debt and Credit Facilities

     On July 14, 2000, we entered into a $475 million revolving credit facility (“Three Year Facility”) to finance the acquisition of the ARCO assets and to refinance existing bank credit facilities. On April 6, 2001, the Three Year Facility was amended to provide for revolving borrowings of up to $500 million including the issuance of letters of credit of up to $20 million. The term of the revised Three Year Facility was extended to April 6, 2004. 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 Three Year Facility contains restrictive financial covenants that require us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA (earnings before interest expense, income tax expense and depreciation and amortization expense) and minimum fixed charge coverage ratios. On November 13, 2001, certain lenders under the agreement elected to withdraw from the facility, and the available borrowing capacity was reduced to $411 million. On February 20, 2002, we repaid $115.7 million of the then outstanding balance of the Three Year Facility with proceeds from the issuance of our 7.625% Senior Notes. On March 1, 2002, we borrowed $132 million under the Three Year Facility to finance the acquisition of Chaparral. On March 22, 2002, we repaid a portion of the Three Year Facility with proceeds we received from the issuance of additional Limited Partner Units. On March 27, 2002, the Three Year Facility was amended to increase the borrowing capacity to $500 million. To facilitate our financing of a portion of the purchase price of the Val Verde assets, on June 27, 2002, the Three Year Facility was amended to increase the maximum debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. We then drew down the existing capacity of the Three Year Facility. At June 30, 2002, $500 million was outstanding under the Three Year Facility at a weighted average interest rate of 3.5%. As of June 30, 2002, we were in compliance with the covenants contained in this credit agreement.

     We have entered into an interest rate swap agreement to hedge our exposure to increases in interest rates on the Three Year Facility discussed above. See Note 4. Derivative Financial Instruments.

Short Term Credit Facilities

     On April 6, 2001, we entered into a 364-day, $200 million revolving credit agreement (“Short-term Revolver”). 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 contains restrictive financial covenants that require us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. On March 27, 2002, the Short-term Revolver was extended for an additional period of 364 days, ending in April 2003. To facilitate our financing of a portion of the purchase price of the Val Verde assets, on June 27, 2002, the Short-term Revolver was amended to increase the maximum debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. We then drew down $72 million under the Short-term Revolver. At June 30, 2002, $72 million was outstanding under the Short-term Revolver at an interest rate of 3.5%. As of June 30, 2002, we were in compliance with the covenants contained in this credit agreement.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

     On September 28, 2001, we entered into a $400 million credit facility with SunTrust Bank (“Bridge Facility”). We borrowed $360 million under the Bridge Facility to acquire the Jonah assets (see Note 5. Acquisitions). The Bridge Facility was payable in June 2002. During the fourth quarter of 2001, we repaid $160 million of the outstanding principal from proceeds received from the issuance of Limited Partner Units in November 2001. On February 5, 2002, we drew down an additional $15 million under the Bridge Facility. On February 20, 2002, we repaid the outstanding balance of the Bridge Facility of $215 million, with proceeds from the issuance of the 7.625% Senior Notes and canceled the facility.

     On June 27, 2002, we entered into a $200 million six-month term loan with SunTrust Bank (“Six-Month Term Loan”). We borrowed $200 million under the Six-Month Term Loan to acquire the Val Verde assets (see Note 5. Acquisitions). The Six-Month Term Loan is payable in December 2002. 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 contains restrictive financial covenants that require us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. At June 30, 2002, $200 million was outstanding under the Six-Month Term Loan at an interest rate of 3.3%. As of June 30, 2002, we were in compliance with the covenants contained in this credit agreement.

     On July 11, 2002, we issued 3 million Limited Partner Units at $30.15 per Unit in an underwritten public offering. The net proceeds from the offering totaled $86.6 million and were used to reduce borrowings under our Six-Month Term Loan. In accordance with SFAS No. 6, Classification of Short-term Obligations Expected to be Refinanced, the amount repaid on July 11, 2002, $86.6 million, is classified as long-term debt at June 30, 2002.

     The following table summarizes the principal outstanding under our credit facilities as of June 30, 2002, and December 31, 2001 (in thousands):

                         
            June 30,   December 31,
            2002   2001
           
 
Short Term Credit Facilities:
               
 
Short-term Revolver, due April 2003
  $ 72,000     $ 160,000  
 
Six-Month Term Loan, due December 2002
    200,000        
 
Bridge Facility, due June 2002
          200,000  
 
Reclassification to Long Term Debt
    (86,606 )      
   
 
   
     
 
   
Total Short Term Credit Facilities
  $ 185,394     $ 360,000  
   
 
   
     
 
Long Term Credit Facilities:
               
 
Reclassification from Short Term Debt
  $ 86,606     $  
 
Three Year Facility, due April 2004
    500,000       340,658  
 
6.45% TE Products Senior Notes, due January 2008
    179,830       179,814  
 
7.51% TE Products Senior Notes, due January 2028
    210,000       210,000  
 
7.625% Senior Notes, due February 2012
    497,884        
   
 
   
     
 
   
Total Long Term Credit Facilities
  $ 1,474,320     $ 730,472  
   
 
   
     
 

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

NOTE 9. 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. According to the Partnership Agreement, the Company receives incremental incentive cash distributions when cash distributions exceed certain target thresholds as follows:

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

     The following table reflects the allocation of total distributions paid during the six months ended June 30, 2002, and 2001 (in thousands, except per Unit amounts).

                   
      Six Months Ended June 30,
     
      2002   2001
     
 
Limited Partner Units
  $ 47,646     $ 35,516  
General Partner Ownership Interest
    1,064       400  
General Partner Incentive
    15,361       8,996  
 
   
     
 
 
Total Partners’ Capital Cash Distributions
    64,071       44,912  
Class B Units
    4,504       4,112  
Minority Interest
          500  
 
   
     
 
 
Total Cash Distributions Paid
  $ 68,575     $ 49,524  
 
   
     
 
Total Cash Distributions Paid Per Unit
  $ 1.150     $ 1.050  
 
   
     
 

     On August 8, 2002, we paid a cash distribution of $0.60 per Limited Partner Unit and Class B Unit for the quarter ended June 30, 2002. The second quarter 2002 cash distribution totaled $39.8 million.

NOTE 10. SEGMENT DATA

     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 intercompany eliminations and assets that we hold that have not been allocated to any of our reporting segments.

     Effective January 1, 2002, we realigned our three business segments to reflect our entry into the natural gas gathering business and the expanded scope of NGLs operations. We transferred the fractionation of NGLs, which were previously reflected as part of the Downstream Segment, to the Midstream Segment. The operation of NGL pipelines, which was previously reflected as part of the Upstream Segment, was also transferred to the Midstream Segment. We have adjusted our period-to-period comparisons to conform with the current presentation.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

     Our Downstream Segment includes the interstate transportation, storage and terminaling of petroleum products and LPGs and intrastate transportation of petrochemicals. Revenues are derived from transportation and storage of refined products and LPGs, storage and short-haul shuttle transportation of LPGs at the Mont Belvieu complex, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. Our Downstream Segment’s pipeline system extends from southeast Texas through the central and midwestern United States to the northeastern United States, and is one of the largest pipeline common carriers of refined petroleum products and LPGs in the United States. Our Downstream Segment also includes the equity losses from our investment in Centennial.

     Our Upstream Segment includes the gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. Our Upstream Segment also includes the equity earnings from our investment in Seaway. Seaway is a large diameter pipeline that transports crude oil from the U.S. Gulf Coast to Cushing, Oklahoma, a central crude oil distribution point for the Central United States.

     Our Midstream Segment includes the fractionation of NGLs in Colorado; the ownership and operation of two trunkline NGL pipelines in South Texas and two NGL pipelines in East Texas; and the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, which was acquired by our subsidiaries on September 30, 2001, from Alberta Energy Company. This segment also includes Chaparral, which we acquired on March 1, 2002 (see Note 5. Acquisitions). Chaparral is an NGL pipeline system that extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. The results of operations of the Jonah and Chaparral acquisitions are included in periods subsequent to September 30, 2001, and March 1, 2002, respectively. On June 30, 2002, we acquired the Val Verde assets, which will be included in the Midstream Segment in periods subsequent to June 30, 2002. The Val Verde system gathers coal seam gas from the Fruitland Coal Formation of the San Juan Basin in New Mexico and is one of the largest coal seam gas gathering and treating facilities in the United States (see Note 5. Acquisitions).

     The table below includes interim financial information by reporting segment for the interim periods ended June 30, 2002, and 2001 (in thousands):

                                                   
      Three Months Ended June 30, 2002
     
      Downstream   Midstream   Upstream   Segments   Partnership        
      Segment   Segment   Segment   Total   and Other   Consolidated
     
 
 
 
 
 
Revenues
  $ 54,656     $ 24,366     $ 809,779     $ 888,801     $ (472 )   $ 888,329  
Operating expenses, including power
    28,715       4,503       800,987       834,205       (472 )     833,733  
Depreciation and amortization expense
    7,364       8,146       2,089       17,599             17,599  
 
   
     
     
     
     
     
 
 
Operating income
    18,577       11,717       6,703       36,997             36,997  
Equity earnings
    (2,190 )           4,604       2,414             2,414  
Other income, net
    70       162       534       766             766  
 
   
     
     
     
     
     
 
 
Earnings before interest
  $ 16,457     $ 11,879     $ 11,841     $ 40,177     $     $ 40,177  
 
   
     
     
     
     
     
 
                                                   
      Three Months Ended June 30, 2001
     
      Downstream   Midstream   Upstream   Segments   Partnership        
      Segment   Segment   Segment   Total   and Other   Consolidated
     
 
 
 
 
 
Revenues
  $ 78,546     $ 7,361     $ 987,775     $ 1,073,682     $     $ 1,073,682  
Operating expenses, including power
    30,529       1,356       977,871       1,009,756             1,009,756  
Depreciation and amortization expense
    6,703       1,413       2,741       10,857             10,857  
 
   
     
     
     
     
     
 
 
Operating income
    41,314       4,592       7,163       53,069             53,069  
Equity earnings
    (339 )           4,758       4,419             4,419  
Other income, net
    388       (9 )     414       793             793  
 
   
     
     
     
     
     
 
 
Earnings before interest
  $ 41,363     $ 4,583     $ 12,335     $ 58,281     $     $ 58,281  
 
   
     
     
     
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

                                                   
      Six Months Ended June 30, 2002
     
      Downstream   Midstream   Upstream   Segments   Partnership        
      Segment   Segment   Segment   Total   and Other   Consolidated
     
 
 
 
 
 
Revenues
  $ 114,242     $ 42,736     $ 1,363,667     $ 1,520,645     $ (1,179 )   $ 1,519,466  
Operating expenses, including power
    57,822       7,996       1,346,842       1,412,660       (1,179 )     1,411,481  
Depreciation and amortization expense
    14,196       15,291       4,153       33,640             33,640  
 
   
     
     
     
     
     
 
 
Operating income
    42,224       19,449       12,672       74,345             74,345  
Equity earnings
    (2,986 )           8,972       5,986             5,986  
Other income, net
    194       181       957       1,332             1,332  
 
   
     
     
     
     
     
 
 
Earnings before interest
  $ 39,432     $ 19,630     $ 22,601     $ 81,663     $     $ 81,663  
 
   
     
     
     
     
     
 
                                                   
      Six Months Ended June 30, 2001
     
      Downstream   Midstream   Upstream   Segments   Partnership        
      Segment   Segment   Segment   Total   and Other   Consolidated
     
 
 
 
 
 
Revenues
  $ 140,847     $ 13,966     $ 1,704,104     $ 1,858,917     $     $ 1,858,917  
Operating expenses, including power
    57,877       2,411       1,688,490       1,748,778             1,748,778  
Depreciation and amortization expense
    13,376       2,802       4,586       20,764             20,764  
 
   
     
     
     
     
     
 
 
Operating income
    69,594       8,753       11,028       89,375             89,375  
Equity earnings
    (339 )           9,964       9,625             9,625  
Other income, net
    681       (9 )     555       1,227             1,227  
 
   
     
     
     
     
     
 
 
Earnings before interest
  $ 69,936     $ 8,744     $ 21,547     $ 100,227     $     $ 100,227  
 
   
     
     
     
     
     
 

     The following table provides the total assets for each segment as of June 30, 2002, and December 31, 2001 (in thousands):

                                                 
    Downstream   Midstream   Upstream   Segments   Partnership        
    Segment   Segment   Segment   Total   and Other   Consolidated
   
 
 
 
 
 
2002
  $ 865,729     $ 1,129,066     $ 862,247     $ 2,857,042     $ (118,396 )   $ 2,738,646  
2001
  $ 844,036     $ 541,195     $ 694,934     $ 2,080,165     $ (14,817 )   $ 2,065,348  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

     The following table reconciles the segments total to consolidated net income (in thousands):

                                   
      Three Months Ended June 30,   Six Months Ended June 30,
     
 
      2002   2001   2002   2001
 
   
     
     
     
 
Earnings before interest
  $ 40,177     $ 58,281     $ 81,663     $ 100,227  
Interest expense
    (16,829 )     (15,392 )     (33,616 )     (31,686 )
Interest capitalized
    1,029       590       3,138       935  
Minority interest
          (441 )           (703 )
 
   
     
     
     
 
 
Net income
  $ 24,377     $ 43,038     $ 51,185     $ 68,773  
 
   
     
     
     
 

NOTE 11. COMMITMENTS AND CONTINGENCIES

     In the fall of 1999 and on December 1, 2000, the Company and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, in Ryan E. McCleery and Marcia S. McCleery, et. al. v. Texas Eastern Corporation, et. al. (including the Company and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et. al. (including the Company and Partnership). In both cases, the plaintiffs contend, among other things, that the Company 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. The Company has filed an answer to both complaints, denying the allegations, as well as various other motions. These cases are in the early stages of discovery and are not covered by insurance. The Company is defending itself vigorously against the lawsuits. The plaintiffs have not stipulated the amount of damages that they are seeking in the suit. We cannot estimate the loss, if any, associated with these pending lawsuits.

     On December 21, 2001, TE Products was named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana, in Rebecca L. Grisham et. al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that our pipeline, which crosses the plaintiff’s property, leaked toxic products onto the plaintiff’s property. The plaintiffs further contend that this leak caused damages to the plaintiffs. We have filed an answer to the plaintiff’s petition denying the allegations. The plaintiffs have not stipulated the amount of damages they are seeking in the suit. We are defending ourself vigorously against the lawsuit. We cannot estimate the damages, if any, associated with this pending lawsuit, however; this case is covered by insurance.

     On April 19, 2002, we, through our subsidiary, TEPPCO Crude Oil, L.P., filed a declaratory judgment action in the U.S. District Court for the Western District of Oklahoma against D.R.D. Environmental Services, Inc. (“D.R.D.”), seeking resolution of billing and other contractual disputes regarding potential overcharges for environmental remediation services provided by D.R.D. On May 28, 2002, D.R.D. filed a counterclaim for alleged breach of contract in the amount of $2,243,525, and for unspecified damages for alleged tortious interference with D.R.D.’s contractual relations with DEFS. We have denied the counterclaims. Discovery is ongoing, and trial has been initially scheduled for May 2003. If D.R.D. should be successful, a substantial portion of the $2,243,525 breach of contract claim will be covered under an indemnity from DEFS. We cannot predict the outcome of the litigation against us, however, we are defending ourselves vigorously against the counterclaim. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

     In addition to the litigation discussed above, we have been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

insurance. We believe that the outcome of these lawsuits and other proceedings will not individually or in the aggregate have a material adverse effect on our consolidated financial position, results of operations or cash flows.

     In February 2002, a producer on the Jonah system notified Alberta Energy Company that it may have a right to acquire all or a portion of the assets comprising the Jonah system. The producer’s inquiry is based upon an alleged right of first refusal contained in a gas gathering agreement between the producer and Jonah. Subsidiaries of Alberta Energy have agreed to indemnify us against losses resulting from the breach of representations concerning the absence of third party rights in connection with the acquisition of the entity that owns the Jonah system. We believe that we have adequate legal defenses if the producer should assert a claim and we also believe that no right of first refusal on any of the underlying Jonah system assets has been triggered.

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

     In 1994, we entered into an Agreed Order with the Indiana Department of Environmental Management (“IDEM”) that resulted in the implementation of a remediation program for groundwater contamination attributable to our operations at the Seymour, Indiana, terminal. In 1999, the IDEM approved a Feasibility Study, which includes our proposed remediation program. We expect the IDEM to issue a Record of Decision formally approving the remediation program. After the Record of Decision is issued, we will enter into a subsequent Agreed Order for the continued operation and maintenance of the remediation program. We have an accrued liability of $0.5 million at June 30, 2002, for future remediation costs at the Seymour terminal. We do not expect that the completion of the remediation program will have a future material adverse effect on our financial position, results of operations or cash flows.

     In 1994, the Louisiana Department of Environmental Quality (“LDEQ”) issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. This contamination may be attributable to our operations, as well as adjacent petroleum terminals operated by other companies. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this containment phase. At June 30, 2002, we have an accrued liability of $0.3 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program that we have proposed will have a future material adverse effect on our financial position, results of operations or cash flows.

     During 2001, we accrued $8.6 million to complete environmental remediation activities at certain of our Upstream Segment sites. In establishing this accrual, we expensed $4.4 million for these environmental remediation costs and recorded a receivable of $4.2 million for the remainder. The receivable is based on a contractual indemnity obligation for specified environmental liabilities that DEFS owes to us in connection with our acquisition of the Upstream Segment from DEFS in November 1998. Under this indemnity obligation, we are responsible for the first $3 million in specified environmental liabilities, and DEFS is responsible for those environmental liabilities in excess of $3 million, up to a maximum amount of $25 million. The majority of the indemnified costs relate to remediation activities at the Velma crude oil site in Stephens County, Oklahoma, attributable to operations prior to our acquisition of the Upstream Segment. Remediation activities at the Velma crude oil site are being conducted

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

according to a work plan approved by the Oklahoma Corporation Commission. At June 30, 2002, an accrual of $5.3 million remains outstanding related to TCTM environmental remediation activities. We do not expect that the completion of remediation programs associated with this release will have a future material adverse effect on our financial position, results of operations or cash flows.

     Centennial has entered into credit facilities totaling $150 million. The proceeds were used to fund construction and conversion costs of its pipeline system. As of June 30, 2002, Centennial had borrowed $140 million under its credit facility. TE Products has guaranteed one-third of the debt of Centennial up to a maximum amount of $50 million.

NOTE 12. COMPREHENSIVE INCOME

     SFAS No. 130, Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments, and unrealized gains and losses on certain investments to be reported in a financial statement. As of and for the six months ended June 30, 2002, and 2001, the components of comprehensive income were due to the interest rate swap related to our variable rate revolving credit facility. The table below reconciles reported net income to total comprehensive income for the three months and six months ended June 30, 2002, and 2001 (in thousands).

                                   
      Three Months Ended June 30,   Six Months Ended June 30,
     
 
      2002   2001   2002   2001
     
 
 
 
Net income
  $ 24,377     $ 43,038     $ 51,185     $ 68,773  
Cumulative effect attributable to adoption of SFAS 133
                      (10,103 )
Net income (loss) on cash flow hedges
    (2,952 )     7,646       348       5,385  
 
   
     
     
     
 
 
Total comprehensive income
  $ 21,425     $ 50,684     $ 51,533     $ 64,055  
 
   
     
     
     
 

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

             
Balance at December 31, 2000
  $  
 
Cumulative effect of accounting change
    (10,103 )
 
Net loss on cash flow hedges
    (10,221 )
 
   
 
Balance at December 31, 2001
  $ (20,324 )
 
Net income on cash flow hedges
    348  
 
   
 
Balance at June 30, 2002
  $ (19,976 )
 
   
 

NOTE 13. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

     In connection with our issuance of Senior Notes on February 20, 2002, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, our significant operating subsidiaries, issued unconditional guarantees of our debt securities. Effective with the

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

acquisition of the Val Verde assets on June 30, 2002, our subsidiary, Val Verde Gas Gathering Company, L.P. also became a significant operating subsidiary and issued unconditional guarantees of our debt securities. The guarantees are full, unconditional, and joint and several. TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. are collectively referred to as the “Guarantor Subsidiaries.”

     The following supplemental condensed consolidating financial information reflects our separate accounts, the combined accounts of the Guarantor Subsidiaries (including Jonah for all periods and dates from and after September 30, 2001, the date Jonah became our subsidiary), the combined accounts of our other non-guarantor subsidiaries, the combined consolidating adjustments and eliminations and our consolidated accounts for the dates and periods indicated. For purposes of the following consolidating information, our investments in our subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for by the equity method of accounting.

                                             
                                        TEPPCO
        TEPPCO   Guarantor   Non-Guarantor   Consolidating   Partners,
June 30, 2002   Partners,L.P.   Subsidiaries   Subsidiaries   Adjustments   L.P. Consolidated

 
 
 
 
 
        (in thousands)
Assets
                                       
 
Current assets
  $ 19,388     $ 68,596     $ 408,352     $ (146,428 )   $ 349,908  
 
Property, plant and equipment — net
          1,068,595       462,754             1,531,349  
 
Equity investments
    710,335       1,080,511       218,357       (1,716,697 )     292,506  
 
Intercompany notes receivable
    1,269,004                   (1,269,004 )      
 
Other assets
    8,725       490,337       65,821             564,883  
 
 
   
     
     
     
     
 
   
Total assets
  $ 2,007,452     $ 2,708,039     $ 1,155,284     $ (3,132,129 )   $ 2,738,646  
 
 
   
     
     
     
     
 
Liabilities and partners’ capital
                                 
 
Current liabilities
  $ 221,407     $ 81,602     $ 387,609     $ (147,835 )   $ 542,783  
 
Long-term debt
    1,084,490       389,830                   1,474,320  
 
Intercompany notes payable
          800,317       467,280       (1,267,597 )      
 
Other long term liabilities and minority interest
    9,349       19,756       231             29,336  
 
Redeemable Class B Units held by related party
    104,360                         104,360  
 
Total partners’ capital
    587,846       1,416,534       300,164       (1,716,697 )     587,847  
 
 
   
     
     
     
     
 
   
Total liabilities and partners’ capital
  $ 2,007,452     $ 2,708,039     $ 1,155,284     $ (3,132,129 )   $ 2,738,646  
 
 
   
     
     
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

                                             
                                      TEPPCO
        TEPPCO   Guarantor   Non-Guarantor   Consolidating   Partners, L.P.
December 31, 2001   Partners, L.P.   Subsidiaries   Subsidiaries   Adjustments   Consolidated

 
 
 
 
 
        (in thousands)
Assets
                                       
 
Current assets
  $ 3,100     $ 59,730     $ 223,345     $ (2,695 )   $ 283,480  
 
Property, plant and equipment — net
          849,978       330,483             1,180,461  
 
Equity investments
    669,370       309,080       222,815       (909,041 )     292,224  
 
Intercompany notes receivable
    700,564       11,269       7,404       (719,237 )      
 
Other assets
    3,853       244,448       65,386       (4,504 )     309,183  
 
 
   
     
     
     
     
 
   
Total assets
  $ 1,376,887     $ 1,474,505     $ 849,433     $ (1,635,477 )   $ 2,065,348  
 
 
   
     
     
     
     
 
Liabilities and partners’ capital
                                       
 
Current liabilities
  $ 367,094     $ 361,547     $ 310,476     $ (370,275 )   $ 668,842  
 
Long-term debt
    340,658       389,814                   730,472  
 
Intercompany notes payable
          45,410       294,801       (340,211 )      
 
Other long term liabilities and minority interest
          8,364       231       8,628       17,223  
 
Redeemable Class B Units held by related party
    105,630                         105,630  
 
Total partners’ capital
    563,505       669,370       243,925       (933,619 )     543,181  
 
 
   
     
     
     
     
 
   
Total liabilities and partners’ capital
  $ 1,376,887     $ 1,474,505     $ 849,433     $ (1,635,477 )   $ 2,065,348  
 
 
   
     
     
     
     
 
                                           
                                      TEPPCO
      TEPPCO   Guarantor   Non-Guarantor   Consolidating   Partners,
Three Months Ended June 30, 2002   Partners, L.P.   Subsidiaries   Subsidiaries   Adjustments   L.P. Consolidated

 
 
 
 
 
      (in thousands)
Operating revenues
  $     $ 66,574     $ 822,227     $ (472 )   $ 888,329  
Costs and expenses
          43,612       808,192       (472 )     851,332  
 
   
     
     
     
     
 
 
Operating income
          22,962       14,035             36,997  
 
   
     
     
     
     
 
Interest expense — net
    (11,706 )     (8,888 )     (6,912 )     11,706       (15,800 )
Equity earnings
    24,377       12,442       4,604       (39,009 )     2,414  
Other income — net
    11,706       220       546       (11,706 )     766  
 
   
     
     
     
     
 
 
Net income
  $ 24,377     $ 26,736     $ 12,273     $ (39,009 )   $ 24,377  
 
   
     
     
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

                                           
                                      TEPPCO
      TEPPCO   Guarantor   Non-Guarantor   Consolidating   Partners, L.P.
Three Months Ended June 30, 2001   Partners, L.P.   Subsidiaries   Subsidiaries   Adjustments   Consolidated

 
 
 
 
 
      (in thousands)
Operating revenues
  $     $ 78,546     $ 995,136     $     $ 1,073,682  
Costs and expenses
          37,233       983,380             1,020,613  
 
   
     
     
     
     
 
 
Operating income
          41,313       11,756             53,069  
 
   
     
     
     
     
 
Interest expense — net
    (8,431 )     (7,355 )     (7,447 )     8,431       (14,802 )
Equity earnings
    43,038       9,132       4,758       (52,509 )     4,419  
Other income — net
    8,431       389       404       (8,431 )     793  
 
   
     
     
     
     
 
 
Income before minority interest
    43,038       43,479       9,471       (52,509 )     43,479  
Minority interest
                      (441 )     (441 )
 
   
     
     
     
     
 
 
Net income
  $ 43,038     $ 43,479     $ 9,471     $ (52,950 )   $ 43,038  
 
   
     
     
     
     
 
                                           
                                      TEPPCO
      TEPPCO   Guarantor   Non-Guarantor   Consolidating   Partners,
Six Months Ended June 30, 2002   Partners, L.P.   Subsidiaries   Subsidiaries   Adjustments   L.P. Consolidated

 
 
 
 
 
      (in thousands)
Operating revenues
  $     $ 136,362     $ 1,384,283     $ (1,179 )   $ 1,519,466  
Costs and expenses
          86,636       1,359,664       (1,179 )     1,445,121  
 
   
     
     
     
     
 
 
Operating income
          49,726       24,619             74,345  
 
   
     
     
     
     
 
Interest expense — net
    (23,139 )     (16,538 )     (13,940 )     23,139       (30,478 )
Equity earnings
    51,185       20,550       8,972       (74,721 )     5,986  
Other income — net
    23,139       353       979       (23,139 )     1,332  
 
   
     
     
     
     
 
 
Net income
  $ 51,185     $ 54,091     $ 20,630     $ (74,721 )   $ 51,185  
 
   
     
     
     
     
 
                                           
                                      TEPPCO
      TEPPCO   Guarantor   Non-Guarantor   Consolidating   Partners,
Six Months Ended June 30, 2001   Partners, L.P.   Subsidiaries   Subsidiaries   Adjustments   L.P. Consolidated

 
 
 
 
 
      (in thousands)
Operating revenues
  $     $ 140,847     $ 1,718,070     $     $ 1,858,917  
Costs and expenses
          71,253       1,698,289             1,769,542  
 
   
     
     
     
     
 
 
Operating income
          69,594       19,781             89,375  
 
   
     
     
     
     
 
Interest expense — net
    (17,803 )     (14,979 )     (15,772 )     17,803       (30,751 )
Equity earnings
    68,773       14,180       9,964       (83,292 )     9,625  
Other income — net
    17,803       681       546       (17,803 )     1,227  
 
   
     
     
     
     
 
 
Income before minority interest
    68,773       69,476       14,519       (83,292 )     69,476  
Minority interest
                      (703 )     (703 )
 
   
     
     
     
     
 
 
Net income
  $ 68,773     $ 69,476     $ 14,519     $ (83,995 )   $ 68,773  
 
   
     
     
     
     
 

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

                                               
                                          TEPPCO
          TEPPCO   Guarantor   Non-Guarantor   Consolidating   Partners,
Six Months Ended June 30, 2002   Partners, L.P.   Subsidiaries   Subsidiaries   Adjustments   L.P. Consolidated

 
 
 
 
 
          (in thousands)
Cash flows from operating activities
                                       
 
Net income
  $ 51,185     $ 54,091     $ 20,630     $ (74,721 )   $ 51,185  
   
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
                                       
     
Depreciation and amortization
          25,021       8,619             33,640  
     
Equity earnings, net of distributions
    17,391       2,142       4,458       (16,547 )     7,444  
     
Changes in assets and liabilities and other
    (564,188 )     25,389       (17,880 )     561,868       5,189  
 
 
   
     
     
     
     
 
Net cash provided by (used in) operating activities
    (495,612 )     106,643       15,827       470,600       97,458  
 
 
   
     
     
     
     
 
Cash flows from investing activities
    (58,406 )     (511,431 )     (140,080 )     58,406       (651,511 )
Cash flows from financing activities
    554,018       408,499       120,467       (529,006 )     553,978  
 
 
   
     
     
     
     
 
Net increase (decrease) in cash and cash equivalents
          3,711       (3,786 )           (75 )
Cash and cash equivalents at beginning of period
          3,655       21,824             25,479  
 
 
   
     
     
     
     
 
Cash and cash equivalents at end of period
  $     $ 7,366     $ 18,038     $     $ 25,404  
 
 
   
     
     
     
     
 
                                               
                                          TEPPCO
          TEPPCO   Guarantor   Non-Guarantor   Consolidating   Partners,
Six Months Ended June 30, 2001   Partners, L.P.   Subsidiaries   Subsidiaries   Adjustments   L.P. Consolidated

 
 
 
 
 
          (in thousands)
Cash flows from operating activities
                                       
 
Net income
  $ 68,773     $ 69,476     $ 14,519     $ (83,995 )   $ 68,773  
   
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
                                       
     
Depreciation and amortization
          13,376       7,388             20,764  
     
Equity earnings, net of distributions
    (19,750 )     1,279       4,212       18,716       4,457  
     
Changes in assets and liabilities and other
    1       (1,792 )     (31,374 )     703       (32,462 )
 
 
   
     
     
     
     
 
Net cash provided by (used in) operating activities
    49,024       82,339       (5,255 )     (64,576 )     61,532  
 
 
   
     
     
     
     
 
Cash flows from investing activities
    (47,139 )     (48,554 )     (25,450 )     47,139       (74,004 )
Cash flows from financing activities
    (1,885 )     (42,951 )     25,577       17,437       (1,822 )
 
 
   
     
     
     
     
 
Net decrease in cash and cash equivalents
          (9,166 )     (5,128 )           (14,294 )
Cash and cash equivalents at beginning of period
          9,166       17,929             27,095  
 
 
   
     
     
     
     
 
Cash and cash equivalents at end of period
  $     $     $ 12,801     $     $ 12,801  
 
 
   
     
     
     
     
 

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

NOTE 14. SUBSEQUENT EVENTS

     On July 16, 2002, we terminated our interest rate swap agreements that were designated as hedges to our exposure to changes in the fair value of our $500 million principal amount of 7.625% fixed rate Senior Notes due 2012. The fair value upon termination of the interest rate swap agreements was $25.8 million. Approximately $7.8 million had been recognized as a reduction to interest expense from the inception of the swap agreement on February 20, 2002, through its termination on July 16, 2002. The remaining gain of $18 million will be amortized as a reduction to future interest expense over the remaining term of the Senior Notes.

     Additionally, on July 16, 2002, we entered into new interest rate swap agreements to hedge our future exposure to changes in the fair value of our $500 million principal amount of 7.625% fixed rate Senior Notes due 2012. We have designated these swap agreements as fair value hedges. The swap agreements have a combined notional amount of $500 million and mature in 2012 to match the principal and maturity of the Senior Notes. Under these swap agreements, we pay a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread, which increased by approximately 50 basis points from the previous swap agreements, and receive a fixed rate of interest of 7.625%.

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

General

     You should read the following review of our financial position and results of operations in conjunction with the Consolidated Financial Statements. Material period-to-period variances in the consolidated statements of income are discussed under “Results of Operations.” The “Financial Condition and Liquidity” section analyzes cash flows and financial position. “Other Considerations” addresses certain trends, future plans or contingencies that could affect future liquidity or earnings. These Consolidated Financial Statements should be read in conjunction with the financial statements and related notes, together with our discussion and analysis of financial position and results of operations included in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2001.

     We operate and report in three business segments:

     
  Downstream Segment — transportation and storage of refined products, LPGs and petrochemicals;
 
  Upstream Segment — gathering, transportation, marketing and storage of crude oil; and distribution of lubrication oils and specialty chemicals; and
 
  Midstream Segment — gathering of natural gas, fractionation of NGLs and transportation of NGLs.

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

     Effective January 1, 2002, we realigned our three business segments to reflect our entry into the natural gas gathering business and the expanded scope of NGLs operations. We transferred the fractionation of NGLs, which were previously reflected as part of the Downstream Segment, to the Midstream Segment. The operation of NGL pipelines, which was previously reflected as part of the Upstream Segment, was also transferred to the Midstream Segment. We have adjusted our period-to-period comparisons to conform to the current presentation.

     Our Downstream Segment revenues are derived from transportation and storage of refined products and LPGs, storage and short-haul shuttle transportation of LPGs at the Mont Belvieu complex, 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 equity losses from our investment in Centennial Pipeline, LLC (“Centennial”).

     The 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 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 logistics for the ultimate sale of the crude oil to local refineries, marketers or other end users. Our Upstream Segment also includes the equity earnings from our investment in Seaway Crude Pipeline Company (“Seaway”). Seaway is a large diameter pipeline that transports crude oil from the U.S. Gulf Coast to Cushing, Oklahoma, a central crude oil distribution point for the Central United States.

     The Midstream Segment revenues are earned from fractionation of NGLs in Colorado, transportation of NGLs and gathering of natural gas. The Midstream Segment includes the operations from the acquisition of Jonah on September 30, 2001, from Alberta Energy Company for $359.8 million. We paid an additional $7.3 million on

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February 4, 2002, for final purchase adjustments related primarily to construction projects in progress at the time of closing. The results of operations of the acquisition are included in our consolidated financial statements beginning in the fourth quarter of 2001. The Jonah assets are managed and operated by DEFS under a contract arrangement.

     On March 1, 2002, we acquired the Chaparral NGL system from Diamond-Koch II, L.P. and Diamond-Koch III, L.P. for $132 million. The Chaparral system is an 800-mile pipeline that extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. The approximately 170-mile Quanah Pipeline is an NGL gathering system located in West Texas. The Quanah Pipeline begins in Sutton County, Texas, and connects to the Chaparral Pipeline near Midland. The pipelines are connected to 27 gas plants in West Texas and have approximately 28,000 horsepower of pumping capacity at 14 stations. These systems are managed and operated by DEFS under a contract arrangement. These assets are included in the Midstream Segment.

     On June 30, 2002, we acquired the Val Verde Gathering System from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc., for $444.2 million. The Val Verde Gathering System gathers coal seam gas from the Fruitland Coal Formation of the San Juan Basin in New Mexico. The system is one of the largest coal seam gas gathering and treating facilities in the United States, gathering coal seam gas from more than 544 separate wells throughout New Mexico. The system provides gathering and treating services pursuant to approximately 60 long-term contracts with approximately 40 different gas producers in the San Juan Basin. Gas gathered on the Val Verde Gathering System is delivered to several interstate pipeline systems serving the western United States and to local New Mexico markets. The Val Verde Gathering System consists of 360 miles of pipeline ranging in size from 4 inches to 36 inches in diameter, 14 compressor stations operating over 93,000 horsepower of compression and a large amine treating facility for the removal of carbon dioxide. The system has a pipeline capacity of approximately one billion cubic feet per day. The assets will be managed and operated by DEFS under a contract arrangement. These assets are included in the Midstream Segment.

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Results of Operations

     The following table summarizes financial data by business segment (in thousands):

                                       
          Three Months Ended June 30,   Six Months Ended June 30,
         
 
          2002   2001   2002   2001
         
 
 
 
Operating revenues:
                               
 
Downstream Segment
  $ 54,656     $ 78,546     $ 114,242     $ 140,847  
 
Upstream Segment
    809,779       987,775       1,363,667       1,704,104  
 
Midstream Segment
    24,366       7,361       42,736       13,966  
 
Intercompany eliminations
    (472 )           (1,179 )      
   
 
   
     
     
     
 
   
Total operating revenues
    888,329       1,073,682       1,519,466       1,858,917  
   
 
   
     
     
     
 
Operating income:
                               
 
Downstream Segment
    18,577       41,314       42,224       69,594  
 
Upstream Segment
    6,703       7,163       12,672       11,028  
 
Midstream Segment
    11,717       4,592       19,449       8,753  
   
 
   
     
     
     
 
   
Total operating income
    36,997       53,069       74,345       89,375  
   
 
   
     
     
     
 
Earnings before interest:
                               
 
Downstream Segment
    16,457       41,363       39,432       69,936  
 
Upstream Segment
    11,841       12,335       22,601       21,547  
 
Midstream Segment
    11,879       4,583       19,630       8,744  
   
 
   
     
     
     
 
     
Total earnings before interest
    40,177       58,281       81,663       100,227  
   
 
   
     
     
     
 
Interest expense
    (16,829 )     (15,392 )     (33,616 )     (31,686 )
Interest capitalized
    1,029       590       3,138       935  
Minority interest
          (441 )           (703 )
   
 
   
     
     
     
 
     
Net income
  $ 24,377     $ 43,038     $ 51,185     $ 68,773  
   
 
   
     
     
     
 

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

Downstream Segment

     The following table presents volume and average rate information for the three months and six months ended June 30, 2002, and 2001:

                                                       
          Three Months Ended           Six Months Ended        
          June 30,   Percentage   June 30,   Percentage
         
  Increase  
  Increase
          2002   2001   (Decrease)   2002   2001   (Decrease)
         
 
 
 
 
 
          (in thousands, except tariff information)
Volumes Delivered
                                               
   
Refined products
    35,344       33,360       6 %     61,109       60,548       1 %
   
LPGs
    7,056       6,907       2 %     19,091       18,558       3 %
   
Mont Belvieu operations
    5,586       4,571       22 %     15,257       10,836       41 %
         
     
     
     
     
     
 
     
Total
    47,986       44,838       7 %     95,457       89,942       6 %
         
     
     
     
     
     
 
Average Tariff per Barrel
                                               
   
Refined products
  $ 0.90     $ 0.97       (7 %)   $ 0.93     $ 0.97       (4 %)
   
LPGs
    1.53       1.96       (22 %)     1.79       2.07       (14 %)
   
Mont Belvieu operations
    0.13       0.18       (28 %)     0.14       0.17       (18 %)
     
Average system tariff per barrel
  $ 0.90     $ 1.04       (14 %)   $ 0.98     $ 1.10       (11 %)
         
     
     
     
     
     
 

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     Three Months ended June 30, 2002 compared to Three Months ended June 30, 2001

     Our Downstream Segment reported earnings before interest of $16.5 million for the three months ended June 30, 2002, compared with earnings before interest of $41.4 million for the three months ended June 30, 2001. Earnings before interest decreased $24.9 million primarily due to a decrease of $23.9 million in operating revenues and losses of $2.2 million from equity investments, partially offset by a decrease of $1.2 million in costs and expenses. We discuss the factors influencing these variances below.

     Revenues from refined products transportation decreased $19.6 million for the three months ended June 30, 2002, compared with the three months ended June 30, 2001, due primarily to $18.9 million of revenue recognized in the 2001 period from a cash settlement received from a canceled transportation agreement with Pennzoil-Quaker State Company (“Pennzoil”) and the recognition of $1.7 million of previously deferred revenue related to the approval of market-based-rates during the second quarter of 2001. These decreases were partially offset by a 6% increase in refined products volumes delivered during the second quarter of 2002, primarily due to barrels received into our pipeline from Centennial at Creal Springs, Illinois. Centennial commenced refined products deliveries to us beginning in April 2002. The overall increase in refined products deliveries was partially offset by a 0.7 million barrel decrease in methyl tertiary butyl ether (“MTBE”) deliveries as a result of the expiration of contract deliveries to our marine terminal near Beaumont, Texas, effective April 2001. As a result of the contract expiration, we no longer transport MTBE through our Products pipeline system. The refined products average rate per barrel decreased 7% from the prior-year period due to the impact of the Midwest origin point for volumes received from Centennial, which was partially offset by decreased short-haul MTBE volumes delivered and higher market-based tariff rates, which went into effect in July 2001.

     Revenues from LPGs transportation decreased $2.7 million for the three months ended June 30, 2002, compared with the three months ended June 30, 2001, primarily due to decreased deliveries of propane in the upper Midwest and Northeast market areas caused by lower prices from competing Canadian and mid-continent propane supply as compared to propane originating from the Gulf Coast. Total LPGs volumes delivered increased 2% as a result of increased short-haul deliveries to a petrochemical facility on the upper Texas Gulf Coast. The LPGs average rate per barrel decreased 22% from the prior-year period as a result of a decreased percentage of long-haul deliveries during the three months ended June 30, 2002.

     Revenues generated from Mont Belvieu operations decreased $0.1 million during the three months ended June 30, 2002, compared with the three months ended June 30, 2001, as a result of increased contract shuttle deliveries, which generally carry lower rates. Total Mont Belvieu shuttle volumes delivered increased 22% during the three months ended June 30, 2002, compared with the three months ended June 30, 2001, due to increased petrochemical demand.

     Other operating revenues decreased $1.5 million during the three months ended June 30, 2002, compared with the three months ended June 30, 2001, primarily due to lower propane deliveries at our Providence, Rhode Island, import facility, lower refined product rental charges and lower margins on product inventory sales. These decreases were partially offset by increased refined products and LPGs loading fees.

     Costs and expenses decreased $1.2 million for the three months ended June 30, 2002, compared with the three months ended June 30, 2001. The decrease was comprised of a $3.7 million decrease in operating fuel and power expense, partially offset by a $1 million increase in operating, general and administrative expenses, a $0.7 million increase in depreciation and amortization expense, and a $0.8 million increase in taxes — other than income taxes. Operating fuel and power expense decreased as a result of decreased mainline throughput and lower electric power costs. Operating, general and administrative expenses increased primarily due to increased consulting and contract services, increased rental charges and increased labor costs. Depreciation expense increased from the prior-year period because of assets placed in service during 2001. Taxes — other than income taxes increased as a result of a higher property base in 2002.

     Net losses from equity investments totaled $2.2 million during the three months ended June 30, 2002, due to start-up expenses of Centennial. Centennial commenced operations in early April 2002.

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     Six Months Ended June 30, 2002 compared to Six Months Ended June 30, 2001

     Our Downstream Segment reported earnings before interest of $39.4 million for the six months ended June 30, 2002, compared with earnings before interest of $69.9 million for the six months ended June 30, 2001. Earnings before interest decreased $30.5 million primarily due to a decrease of $26.6 million in operating revenues, an increase of $0.8 million in costs and expenses and losses of $3 million from equity investments. We discuss the factors influencing these variances below.

     Revenues from refined products transportation decreased $20.6 million for the six months ended June 30, 2002, compared with the six months ended June 30, 2001, due primarily to $18.9 million of revenue recognized in the 2001 period from a cash settlement received from a canceled transportation agreement with Pennzoil and the recognition of $1.7 million of previously deferred revenue related to the approval of market-based-rates during the second quarter of 2001. These decreases were partially offset by a 1% increase in refined products volumes delivered during the six months ended June 30, 2002, primarily due to barrels received into our pipeline from Centennial at Creal Springs, Illinois. Centennial commenced refined products deliveries to us beginning in April 2002. The overall increase in refined products deliveries was partially offset by a 1.3 million barrel decrease in MTBE deliveries as a result of the expiration of contract deliveries to our marine terminal near Beaumont, Texas, effective April 2001. As a result of the contract expiration, we no longer transport MTBE through our Products pipeline system. The refined products average rate per barrel decreased 4% from the prior-year period due to the impact of the Midwest origin point for volumes received from Centennial, which was partially offset by decreased short-haul MTBE volumes delivered and higher market-based tariff rates, which went into effect in July 2001.

     Revenues from LPGs transportation decreased $4.3 million for the six months ended June 30, 2002, compared with the six months ended June 30, 2001, primarily due to decreased deliveries of propane in the upper Midwest and Northeast market areas attributable to warmer than normal weather. The decrease is also due to lower prices from competing Canadian and mid-continent propane supply as compared to propane originating from the Gulf Coast. Total LPGs volumes delivered increased 3% as a result of increased short-haul deliveries to a petrochemical facility on the upper Texas Gulf Coast. The LPGs average rate per barrel decreased 14% from the prior-year period as a result of a decreased percentage of long-haul deliveries during the six months ended June 30, 2002.

     Revenues generated from Mont Belvieu operations increased $1.5 million during the six months ended June 30, 2002, compared with the six months ended June 30, 2001, as a result of increased storage revenue and brine service revenue. Mont Belvieu shuttle volumes delivered increased 41% during the six months ended June 30, 2002, compared with the six months ended June 30, 2001, due to increased petrochemical demand. The Mont Belvieu average rate per barrel decreased during the six months ended June 30, 2002, as a result of increased contract shuttle deliveries, which generally carry lower rates.

     Other operating revenues decreased $3.1 million during the six months ended June 30, 2002, compared with the six months ended June 30, 2001, primarily due to lower propane deliveries at our Providence, Rhode Island, import facility, lower refined product rental charges, lower margins on product inventory sales, and increased losses as a result of exchanging products at different geographic points of delivery to position product in the Midwest market area. These decreases were partially offset by increased refined products and LPGs loading fees.

     Costs and expenses increased $0.8 million for the six months ended June 30, 2002, compared with the six months ended June 30, 2001. The increase was made up of a $3.6 million increase in operating, general and administrative expenses, a $0.8 million increase in depreciation and amortization expense, and a $1 million increase in taxes — other than income taxes. These increases were partially offset by a $4.6 million decrease in operating fuel and power expense. Operating, general and administrative expenses increased, primarily due to higher environmental remediation expenses, increased consulting and contract services and increased labor costs. Depreciation expense increased from the prior-year period because of assets placed in service during 2001. Operating fuel and power expense decreased as a result of decreased mainline throughput and lower power costs. Taxes — other than income taxes increased as a result of a higher property base in 2002.

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     Net losses from equity investments totaled $3 million during the six months ended June 30, 2002, due to pre-operating expenses and start-up costs of Centennial. Centennial commenced operations in early April 2002.

Upstream Segment

     We calculate the margin of the Upstream Segment as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil, less the costs of purchases of crude oil and lubrication oil. Margin is a more meaningful measure of financial performance than operating revenues and operating expenses due to the significant fluctuations in revenues and expenses caused by variations in the level of marketing activity and prices for products marketed. Margin and volume information for the three months and six months ended June 30, 2002, and 2001 is presented below (in thousands, except per barrel and per gallon amounts):

                                                     
        Three Months Ended           Six Months Ended        
        June 30,   Percentage   June 30,   Percentage
       
  Increase  
  Increase
        2002   2001   (Decrease)   2002   2001   (Decrease)
       
 
 
 
 
 
Margins:
                                               
 
Crude oil transportation
  $ 9,721     $ 8,921       9 %   $ 18,909     $ 17,046       11 %
 
Crude oil marketing
    5,306       6,276       (16 %)     10,070       9,827       3 %
 
Crude oil terminaling
    2,543       2,546             4,874       4,674       4 %
 
Lubrication oil sales
    1,230       984       25 %     2,365       2,118       12 %
       
     
     
     
     
     
 
   
Total margin
  $ 18,800     $ 18,727           $ 36,218     $ 33,665       8 %
       
     
     
     
     
     
 
Total barrels:
                                               
 
Crude oil transportation
    21,672       21,851       (1 %)     42,788       37,596       14 %
 
Crude oil marketing
    42,927       44,026       (3 %)     73,279       72,451       1 %
 
Crude oil terminaling
    33,064       32,460       2 %     62,339       57,122       9 %
Lubrication oil volume (total gallons)
    2,698       2,134       26 %     4,892       4,389       12 %
Margin per barrel:
                                               
 
Crude oil transportation
  $ 0.449     $ 0.408       10 %   $ 0.442     $ 0.453       (3 %)
 
Crude oil marketing
    0.124       0.143       (13 %)     0.137       0.136       1 %
 
Crude oil terminaling
    0.077       0.078       (2 %)     0.078       0.082       (4 %)
Lubrication oil margin (per gallon)
    0.456       0.461       (1 %)     0.483       0.483        

     Three Months ended June 30, 2002 compared to Three Months ended June 30, 2001

     Our Upstream Segment reported earnings before interest of $11.8 million for the three months ended June 30, 2002, compared with earnings before interest of $12.3 million for the three months ended June 30, 2001. Earnings before interest decreased $0.5 million primarily due to a $0.2 million decrease in equity earnings of Seaway and a $0.4 million decrease in other revenue. We discuss the factors influencing these variances below.

     Our margin increased $0.1 million during the three months ended June 30, 2002, compared with the three months ended June 30, 2001. Crude oil transportation margin increased $0.8 million primarily due to higher revenues on our Basin and West Texas systems. Lubrication oil sales margin increased $0.3 million due to increased volumes related to the acquisition of a lubrication oil distributor in Amarillo, Texas, in the fourth quarter of 2001. Crude oil marketing margin decreased $1 million primarily due to reduced volumes marketed on Seaway by our marketing affiliate, partially offset by renegotiated supply contracts and lower trucking expenses.

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     Other operating revenues of the Upstream Segment decreased $0.4 million for the three months ended June 30, 2002, compared with the three months ended June 30, 2001, due to lower revenue from documentation and other services to support customers’ trading activity at Midland, Texas, and Cushing, Oklahoma.

     Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, decreased slightly during the three months ended June 30, 2002, compared with the three months ended June 30, 2001. Taxes — other than income taxes decreased by $1 million due to a reduction in estimated property taxes for the period. Depreciation and amortization expense decreased by $0.7 million due to the adoption of SFAS 142 effective January 1, 2002, (see Note 3. Goodwill and Other Intangible Assets), in which goodwill and excess investment are no longer being amortized, and operating fuel and power expense decreased by $0.1 million due to lower electric power costs. These decreases were offset by a $1.7 million increase in operating, general and administrative expenses primarily due to increased labor related costs and increased general and administrative supplies and services expense.

     Equity earnings in Seaway for the three months ended June 30, 2002, decreased $1 million from the three months ended June 30, 2001, due to our portion of equity earnings being decreased from 80 percent to 60 percent on a pro-rated basis in 2002 (averaging approximately 67 percent for the year ended December 31, 2002), coupled with lower third-party transportation volumes.

     Six Months ended June 30, 2002 compared to Six Months ended June 30, 2001

     Our Upstream Segment reported earnings before interest of $22.6 million for the six months ended June 30, 2002, compared with earnings before interest of $21.5 million for the six months ended June 30, 2001. Earnings before interest increased $1.1 million primarily due to a $2.6 million increase in margin and a $0.4 million increase in other income — net. These increases were partially offset by a $1 million decrease in equity earnings of Seaway, a $0.6 million decrease in other revenue and a $0.1 million increase in costs and expenses (excluding purchases of crude oil and lubrication oil). We discuss the factors influencing these variances below.

     Our margin increased $2.6 million during the six months ended June 30, 2002, compared with the six months ended June 30, 2001. Crude oil transportation margin increased $1.9 million primarily due to volumes transported on the pipeline assets acquired from Valero Energy Corp. (formerly Ultramar Diamond Shamrock Corporation) (“UDS”) in March 2001, and higher revenues on our Basin and West Texas systems. Crude oil marketing margin increased $0.2 million primarily due to increased volumes marketed, renegotiated supply contracts and lower trucking expenses. Crude oil terminaling margin increased $0.2 million as a result of higher pumpover volumes at Midland, Texas, and Cushing, Oklahoma. Lubrication oil sales margin increased $0.3 million due to increased volumes related to the acquisition of a lubrication oil distributor in Amarillo, Texas, in the fourth quarter of 2001.

     Other operating revenues of the Upstream Segment decreased $0.6 million for the six months ended June 30, 2002, compared with the six months ended June 30, 2001, due to lower revenue from documentation and other services to support customers’ trading activity at Midland, Texas, and Cushing, Oklahoma.

     Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, increased $0.1 million during the six months ended June 30, 2002, compared with the six months ended June 30, 2001. The increase was comprised of a $1.2 million increase in operating, general and administrative expenses due to increased labor related costs and increased general and administrative supplies and services expense, and a $0.3 million increase in operating fuel and power expense. These increases were partially offset by a $0.9 million decrease in taxes — other than income taxes due to reductions in property tax accruals. Depreciation and amortization expense decreased by $0.4 million due to the adoption of SFAS 142 effective January 1, 2002, in which goodwill and excess investment are no longer being amortized, partially offset by increased depreciation expense on the assets acquired from UDS.

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     Equity earnings in Seaway for the six months ended June 30, 2002, decreased $1 million from the six months ended June 30, 2001, due to our portion of equity earnings being decreased from 80 percent to 60 percent on a pro rated basis in 2002 (averaging approximately 67 percent for the year ended December 31, 2002), coupled with lower third-party transportation volumes.

Midstream Segment

     The following table presents volume and average rate information for the three months and six months ended June 30, 2002, and 2001:

                                                   
      Three Months Ended           Six Months Ended        
      June 30,   Percentage   June 30,   Percentage
     
  Increase  
  Increase
      2002   2001   (Decrease)   2002   2001   (Decrease)
     
 
 
 
 
 
Gathering – Natural Gas:
                                               
 
Million cubic feet
    59,805                   109,976              
 
Million British thermal units (“MMBtu”)
    66,493                   122,221              
 
Average fee per MMBtu
  $ 0.172                 $ 0.172              
Transportation – NGLs:
                                               
 
Thousand barrels
    15,557       5,436       186 %     23,471       10,198       130 %
 
Average rate per barrel
  $ 0.678     $ 1.024       (34 %)   $ 0.718     $ 1.024       (30 %)
Fractionation – NGLs:
                                               
 
Thousand barrels
    1,032       1,044       (1 %)     2,043       2,059       (1 %)
 
Average rate per barrel
  $ 1.840     $ 1.831       1 %   $ 1.827     $ 1.805       1 %
Sales – Condensate:
                                               
 
Thousand barrels
    18.3                   50.6              
 
Average rate per barrel
  $ 28.37                 $ 23.99              

     Three Months ended June 30, 2002 compared to Three Months ended June 30, 2001

     Our Midstream Segment’s earnings before interest totaled $11.9 million for the three months ended June 30, 2002, compared with earnings before interest of $4.6 million for the three months ended June 30, 2001. The $7.3 million increase in earnings before interest was due to a $17 million increase in operating revenues, partially offset by a $9.9 million increase in costs and expenses. We discuss the factors influencing these variances below.

     Operating revenues increased $17 million during the three months ended June 30, 2002, compared with the three months ended June 30, 2001. Natural gas gathering revenues from the Jonah system (acquired on September 30, 2001) totaled $11.5 million and volumes delivered totaled 59.8 billion cubic feet. Other revenues increased $0.5 million due to sales of gas condensate from the Jonah system. NGL transportation revenues increased $5.1 million, primarily due to the acquisition of Chaparral on March 1, 2002, partially offset by lower revenues on a take-or-pay contract on the Dean system that was in effect until the bankruptcy of Enron Corp. in December 2001. The decrease in the NGL transportation average rate per barrel resulted from the cancellation of the Enron Corp. take-or-pay contract, and a lower average rate per barrel on volumes transported on Chaparral.

     Costs and expenses increased $9.9 million during the three months ended June 30, 2002, compared with the three months ended June 30, 2001. The increase was comprised of a $6.7 million increase in depreciation and amortization expense, a $2.4 million increase in operating, general and administrative expense and a $0.8 million increase in operating fuel and power costs. Of these increases, $10.3 million related to the Jonah and Chaparral

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assets acquired on September 30, 2001, and March 1, 2002, respectively, partially offset by a $0.4 million decrease in expenses related to the other assets of the Midstream Segment.

     Six Months ended June 30, 2002 compared to Six Months ended June 30, 2001

     Our Midstream Segment’s earnings before interest totaled $19.6 million for the six months ended June 30, 2002, compared with earnings before interest of $8.7 million for the six months ended June 30, 2001. The $10.9 million increase in earnings before interest was due to a $28.8 million increase in operating revenues, partially offset by an $18.1 million increase in costs and expenses. We discuss the factors influencing these variances below.

     Operating revenues increased $28.8 million during the six months ended June 30, 2002, compared with the six months ended June 30, 2001. Natural gas gathering revenues from the Jonah system totaled $21 million and volumes delivered totaled 110 billion cubic feet. Other revenues increased $1.2 million due to sales of gas condensate from the Jonah system. NGL transportation revenues increased $6.6 million, primarily due to the acquisition of Chaparral on March 1, 2002, partially offset by lower revenues on a take-or-pay contract on the Dean system that was in effect until the bankruptcy of Enron Corp. in December 2001. The decrease in the NGL transportation average rate per barrel resulted from the cancellation of the Enron Corp. take-or-pay contract, and a lower average rate per barrel on volumes transported on Chaparral.

     Costs and expenses increased $18.1 million during the six months ended June 30, 2002, compared with the six months ended June 30, 2001. The increase was comprised of a $12.5 million increase in depreciation and amortization expense, a $3.8 million increase in operating, general and administrative expense, a $1.4 million increase in operating fuel and power costs and a $0.4 million increase in taxes — other than income taxes. Of these increases, $18.7 million related to the Jonah and Chaparral assets acquired on September 30, 2001, and March 1, 2002, respectively, partially offset by a $0.6 million decrease in expenses related to the other assets of the Midstream Segment.

Interest Expense and Capitalized Interest

     Three Months ended June 30, 2002 compared to Three Months ended June 30, 2001

     Interest expense increased $1.4 million during the three months ended June 30, 2002, compared with the three months ended June 30, 2001, primarily due to higher outstanding debt, partially offset by lower LIBOR rates in effect during 2002.

     Capitalized interest increased $0.4 million during the three months ended June 30, 2002, compared with the three months ended June 30, 2001, due to increased balances on construction work-in-progress during the second quarter of 2002.

     Six Months ended June 30, 2002 compared to Six Months ended June 30, 2001

     Interest expense increased $1.9 million during the six months ended June 30, 2002, compared with the six months ended June 30, 2001, primarily due to higher outstanding debt, partially offset by lower LIBOR rates in effect during 2002.

     Capitalized interest increased $2.2 million during the six months ended June 30, 2002, compared with the six months ended June 30, 2001, due to increased balances during 2002 on construction work-in-progress and the investment during the construction of Centennial.

Financial Condition and Liquidity

     Net cash from operations totaled $97.5 million for the six months ended June 30, 2002. This cash was made up of $84.8 million of income before charges for depreciation and amortization and $12.7 million of cash

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provided by working capital changes. This compares with net cash from operations of $61.5 million for the corresponding period in 2001, comprised of $89.5 million of income before charges for depreciation and amortization, partially offset by $28 million of cash used for working capital changes. Net cash from operations for the six months ended June 30, 2002, and 2001, included interest payments of $19.5 million and $32.2 million, respectively.

     Cash flows used in investing activities during the six months ended June 30, 2002, was comprised of $7.3 million for the final purchase price adjustments on the acquisition of Jonah, $63.6 million of capital expenditures, $7.7 million of cash contributions for our interest in Centennial, $132.1 million for the purchase of Chaparral on March 1, 2002, and $444.2 million for the purchase of Val Verde on June 30, 2002. These uses of cash were partially offset by $3.4 million in cash proceeds from the sale of assets. Cash flows used in investing activities during the six months ended June 30, 2001, were comprised of $20 million for the purchase of assets from UDS on March 1, 2001, $33.4 million of capital expenditures, and $25.1 million of cash contributions for our interest in Centennial. These uses of cash were partially offset by $1.3 million of cash received from the sale of vehicles and $3.2 million received on matured cash investments.

     Centennial entered into credit facilities totaling $150 million. The proceeds were used to fund construction and conversion costs of its pipeline system. As of June 30, 2002, Centennial had borrowed $140 million under its credit facility. TE Products has guaranteed one-third of the debt of Centennial up to a maximum amount of $50 million.

     Credit Facilities and Interest Rate Swap Agreements

     On July 14, 2000, we entered into a $475 million revolving credit facility (“Three Year Facility”) to finance the acquisition of the ARCO assets and to refinance existing bank credit facilities. On April 6, 2001, the Three Year Facility was amended to provide for revolving borrowings of up to $500 million including the issuance of letters of credit of up to $20 million. The term of the revised Three Year Facility was extended to April 6, 2004. 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 Three Year Facility contains restrictive financial covenants that require us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA (earnings before interest expense, income tax expense and depreciation and amortization expense) and minimum fixed charge coverage ratios. On November 13, 2001, certain lenders under the agreement elected to withdraw from the facility, and the available borrowing capacity was reduced to $411 million. On February 20, 2002, we repaid $115.7 million of the then outstanding balance of the Three Year Facility with proceeds from the issuance of our 7.625% Senior Notes. On March 1, 2002, we borrowed $132 million under the Three Year Facility to finance the acquisition of Chaparral. On March 22, 2002, we repaid a portion of the Three Year Facility with proceeds we received from the issuance of additional Limited Partner Units. On March 27, 2002, the Three Year Facility was amended to increase the borrowing capacity to $500 million. To facilitate our financing of a portion of the purchase price of the Val Verde assets, on June 27, 2002, the Three Year Facility was amended to increase the maximum debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. We then drew down the existing capacity of the Three Year Facility. At June 30, 2002, $500 million was outstanding under the Three Year Facility at a weighted average interest rate of 3.5%. As of June 30, 2002, we were in compliance with the covenants contained in this credit agreement.

     On April 6, 2001, we entered into a 364-day, $200 million revolving credit agreement (“Short-term Revolver”). 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 contains restrictive financial covenants that require us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. On March 27, 2002, the Short-term Revolver was extended for an additional period of 364 days, ending in April 2003. To facilitate our financing of a portion of the purchase price of the Val Verde assets, on June 27, 2002, the Short-term Revolver was amended to increase the maximum debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. We then drew down $72 million under the Short-term

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Revolver. At June 30, 2002, $72 million was outstanding under the Short-term Revolver at an interest rate of 3.5%. As of June 30, 2002, we were in compliance with the covenants contained in this credit agreement.

     On September 28, 2001, we entered into a $400 million credit facility with SunTrust Bank (“Bridge Facility”). We borrowed $360 million under the Bridge Facility to acquire the Jonah assets (see Note 5. Acquisitions). The Bridge Facility was payable in June 2002. During the fourth quarter of 2001, we repaid $160 million of the outstanding principal from proceeds received from the issuance of Limited Partner Units in November 2001. On February 5, 2002, we drew down an additional $15 million under the Bridge Facility. On February 20, 2002, we repaid the outstanding balance of the Bridge Facility of $215 million, with proceeds from the issuance of the 7.625% Senior Notes and canceled the facility.

     On February 20, 2002, we received $494.6 million in net proceeds from the issuance of $500 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount and are being accreted to their face value over the term of the notes. We used the proceeds from the offering to reduce a portion of the outstanding balances of our credit facilities, described above, including those issued in connection with the acquisition of Jonah. 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 the 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, 2002, we were in compliance with the covenants of these Senior Notes.

     On June 27, 2002, we entered into a $200 million six-month term loan with SunTrust Bank (“Six-Month Term Loan”). We borrowed $200 million under the Six-Month Term Loan to acquire the Val Verde assets (see Note 5. Acquisitions). The Six-Month Term Loan is payable in December 2002. 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 contains restrictive financial covenants that require us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. At June 30, 2002, $200 million was outstanding under the Six-Month Term Loan at an interest rate of 3.3%. As of June 30, 2002, we were in compliance with the covenants contained in this credit agreement.

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

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     The following table summarizes our credit facilities as of June 30, 2002 (in millions):

                         
    As of June 30, 2002
   
            Available        
    Outstanding   Borrowing   Maturity
Description:   Principal   Capacity   Date

 
 
 
Short-term Revolver
  $ 72.0     $ 128.0     April 2003
Six-Month Term Loan
    200.0           December 2002
Three Year Facility
    500.0           April 2004
6.45% Senior Notes
    180.0           January 2008
7.51% Senior Notes
    210.0           January 2028
7.625% Senior Notes
    500.0           February 2012

     Distributions and Issuance of Additional Limited Partner Units

     We paid cash distributions of $68.5 million ($1.15 per Unit) and $49.5 million ($1.05 per Unit) for each of the six months ended June 30, 2002, and 2001, respectively. Additionally, on July 18, 2002, we declared a cash distribution of $0.60 per Limited Partner Unit and Class B Unit for the quarter ended June 30, 2002. We paid the distribution of $39.8 million on August 8, 2002, to unitholders of record on July 31, 2002.

     On February 6, 2001, we issued by public offering 2 million Limited Partner Units at $25.50 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $48.7 million and were used to reduce borrowings under the Three Year Facility. On March 6, 2001, 250,000 Units were issued in connection with the over-allotment provision of the offering on February 6, 2001. Proceeds from the Units issued from the over-allotment totaled $6.1 million and were used for general purposes.

     On November 14, 2001, we issued by public offering 5.5 million Limited Partner Units at $34.25 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $180.3 million and were used to repay $160 million under the Bridge Facility that was used to fund the Jonah acquisition. The remaining proceeds were used to finance contributions to Centennial and for other capital expenditures.

     On March 22, 2002, we issued by public offering 1.92 million Limited Partner Units (which included the overallotment provision) at $29.85 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $57.3 million and were used to repay $50 million of the outstanding balance on the Three Year Facility with the remaining amount being used for general purposes.

     On July 11, 2002, we issued by public offering 3 million Limited Partner Units at $30.15 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $86.6 million and were used to reduce borrowings under our Six-Month Term Loan. In accordance with SFAS No. 6, Classification of Short-term Obligations Expected to be Refinanced, the amount repaid on July 11, 2002, $86.6 million, is classified as long-term debt at June 30, 2002. On August 14, 2002, 175,000 Units were issued in connection with the over-allotment provision of the offering on July 11, 2002. Proceeds from the over-allotment totaled $5.1 million and were used for general purposes.

     Future Capital Needs and Commitments

     We estimate that capital expenditures, excluding acquisitions, for 2002 will be approximately $139 million (which includes $6 million of capitalized interest). We expect to use approximately $100 million for revenue generating projects, approximately $23 million for maintenance capital spending and approximately $10 million for system upgrade projects. Revenue generating projects will include approximately $45 million for Phase II expansion of the Jonah system, $17 million for expansion of other Midstream assets and $38 million to expand our service capabilities including the installation of a brine pond at our Mont Belvieu LPGs storage facility, the installation of improvements at our Princeton, Indiana, LPGs truck loading facilities, and the completion of facilities to support receipt and delivery locations with Centennial. We expect to use approximately $4.1 million of maintenance capital spending for pipeline rehabilitation projects to comply with regulations enacted by the United States Department of Transportation Office of Pipeline Safety. We continually review and evaluate potential capital improvements and expansions that would be complementary to our present business segments. These expenditures can vary greatly depending on the magnitude of our transactions. We may finance capital expenditures through internally generated funds, debt or the issuance of additional equity.

     Our debt repayment obligations consist of payments for principal and interest on (i) outstanding principal amounts under the Six-Month Term Loan due in December 2002 ($200 million at June 30, 2002), (ii) outstanding principal amounts under the Short-term Revolver due in April 2004 ($72 million at June 30, 2002), (iii) outstanding principal amounts under the Three Year Facility due in April 2004 ($500 million at June 30, 2002), (iv) the TE

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Products Senior Notes, $180 million principal amount due January 15, 2008, and $210 million principal amount due January 15, 2028, and (v) our $500 million 7.625% Senior Notes due February 15, 2012.

     TE Products is contingently liable as guarantor for the lesser of one-third or $50 million principal amount (plus interest) of the borrowings of Centennial. We expect to contribute an additional $3 million to Centennial for the remaining six months of 2002. We do not rely on off-balance sheet borrowings to fund our acquisitions. We have no off-balance sheet commitments for indebtedness other than the limited guarantee of Centennial debt and leases covering assets utilized in several areas of our operations.

     The following table summarizes our debt repayment obligations and material contractual commitments as of June 30, 2002 (in millions).

                                           
      Amount of Commitment Expiration Per Period
     
              Less than                   After 5
      Total   1 Year   2-3 Years   4-5 Years   Years
     
 
 
 
 
Six-Month Term Loan
  $ 200.0     $ 200.0     $     $     $  
Short-term Revolver
    72.0       72.0                    
Three Year Facility
    500.0             500.0              
6.45% Senior Notes due 2008 (1)
    180.0                         180.0  
7.51% Senior Notes due 2028 (1)
    210.0                         210.0  
7.625% Senior Notes due 2012
    500.0                         500.0  
Centennial cash contributions
    3.0       3.0                    
Operating leases
    35.6       9.1       15.9       10.3       0.3  
       
     
     
     
     
 
 
Total
  $ 1,700.6     $ 284.1     $ 515.9     $ 10.3     $ 890.3  
       
     
     
     
     
 


(1)   Obligations of TE Products.

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

     Sources of Future Capital

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

     As of June 30, 2002, we had approximately $128 million in available borrowing capacity under the Short-term Revolver.

     We expect cash flows from operating activities will be adequate to fund cash distributions and capital additions necessary to maintain existing operations. However, expansionary capital projects and acquisitions may require funding through proceeds from the sale of additional debt or equity capital markets offerings.

     On May 29, 2002, Moody’s Investors Service downgraded our senior unsecured debt rating to Baa3 from Baa2. Our subsidiary, TE Products was also included in this downgrade. These ratings were given with stable outlooks, and followed our announcement of the $444 million acquisition of Val Verde. The downgrades reflect Moody’s concern that we have a high level of debt relative to many of our peers and that our debt may be continually higher than our long-term targets if we continue to make a series of acquisitions of increasingly larger size. Because of our high distribution rate, we are particularly reliant on external financing to finance our acquisitions. Moody’s

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indicated that our cash flows are becoming less predictable as a result of our acquisitions and expansion into the crude oil and natural gas gathering businesses. We are evaluating alternatives to lowering our debt-to-EBITDA ratio. Further reductions in our credit ratings could increase the debt financing costs or possibly reduce the availability of financing. A rating reflects only the view of a rating agency and is not a recommendation to buy, sell or hold any indebtedness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant such a change.

Other Considerations

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

     In 1994, we entered into an Agreed Order with the IDEM that resulted in the implementation of a remediation program for groundwater contamination attributable to our operations at the Seymour, Indiana, terminal. In 1999, the IDEM approved a Feasibility Study, which includes our proposed remediation program. We expect the IDEM to issue a Record of Decision formally approving the remediation program. After the Record of Decision is issued, we will enter into a subsequent Agreed Order for the continued operation and maintenance of the remediation program. We have an accrued liability of $0.5 million at June 30, 2002, for future remediation costs at the Seymour terminal. We do not expect that the completion of the remediation program will have a future material adverse effect on our financial position, results of operations or cash flows.

     In 1994, the LDEQ issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. This contamination may be attributable to our operations, as well as adjacent petroleum terminals operated by other companies. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this containment phase. At June 30, 2002, we have an accrued liability of $0.3 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program that we have proposed will have a future material adverse effect on our financial position, results of operations or cash flows.

     During 2001, we accrued $8.6 million to complete environmental remediation activities at certain of our Upstream Segment sites. In establishing this accrual, we expensed $4.4 million for these environmental remediation costs and recorded a receivable of $4.2 million for the remainder. The receivable is based on a contractual indemnity obligation for specified environmental liabilities that DEFS owes to us in connection with our acquisition of the Upstream Segment from DEFS in November 1998. Under this indemnity obligation, we are responsible for the first $3 million in specified environmental liabilities, and DEFS is responsible for those environmental liabilities in excess of $3 million, up to a maximum amount of $25 million. The majority of the indemnified costs relate to remediation activities at the Velma crude oil site in Stephens County, Oklahoma, attributable to operations prior to our acquisition of the Upstream Segment. Remediation activities at the Velma crude oil site are being conducted according to a work plan approved by the Oklahoma Corporation Commission. At June 30, 2002, an accrual of $5.3 million remains outstanding related to TCTM environmental remediation activities. We do not expect that the completion of remediation programs associated with this release will have a future material adverse effect on our financial position, results of operations or cash flows.

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     New Accounting Pronouncements

     In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which we incur a legal obligation for the retirement of tangible long-lived assets. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. We are required to adopt SFAS 143 effective January 1, 2003. We are currently evaluating the impact of adopting SFAS 143.

     In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 supercedes SFAS No. 121, Accounting for Long-Lived Assets and For Long-Lived Assets to be Disposed Of, but retains its fundamental provisions for reorganizing and measuring impairment losses on long-lived assets held for use and long-lived assets to be disposed of by sale. We adopted SFAS 144 effective January 1, 2002. The adoption of SFAS 144 did not have a material effect on our financial position, results of operations or cash flows.

     In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. SFAS 145 eliminates the requirement to classify gains and losses from the extinguishment of indebtedness as extraordinary, requires certain lease modifications to be treated the same as a sale-leaseback transaction, and makes other non-substantive technical corrections to existing pronouncements. SFAS 145 is effective for fiscal years beginning after May 15, 2002, with earlier adoption encouraged. We are required to adopt SFAS 145 effective January 1, 2003. We do not believe that the adoption of SFAS 145 will have a material effect on our financial position, results of operations or cash flows.

     In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS 146 requires recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. We do not believe that the adoption of SFAS 146 will have a material effect on our financial position, results of operations or cash flows.

Forward-Looking Statements

     The matters discussed in this Report include “forward-looking statements” within the meaning of various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of our business and operations, plans, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses based on our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including general economic, market or business conditions, the opportunities (or lack thereof) that may be presented to and pursued by us, competitive actions by other pipeline companies, changes in laws or regulations, and other factors, many of which are beyond our control. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to or effect on us or our business or operations. For additional discussion of such risks and uncertainties, see our 2001 Annual Report on Form 10-K, as amended, and other filings we have made with the Securities and Exchange Commission.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

     We have utilized and expect to continue to utilize derivative financial instruments with respect to a portion of our interest rate and fair value risks and our crude oil marketing activities. These transactions generally are swaps and forwards, and we enter into them with major financial institutions or commodities trading institutions. The derivative financial instrument related to our interest rate risk is intended to reduce our exposure to increases in the benchmark interest rates underlying our variable rate revolving credit facility. The derivative financial instruments related to our fair value risks are intended to reduce our exposure to changes in the fair value of the fixed rate Senior Notes resulting from changes in interest rates. Our Upstream Segment uses derivative financial instruments to reduce our exposure to fluctuations in the market price of crude oil. Gains and losses from financial instruments used in our Upstream Segment have been recognized in revenues for the periods to which the derivative financial instruments relate, and gains and losses from our interest rate financial instruments have been recognized in interest expense for the periods to which the derivative financial instrument relate. As of June 30, 2002, the Upstream Segment had no open positions on derivative financial contracts.

     At June 30, 2002, our subsidiary, TE Products had outstanding $180 million principal amount of 6.45% Senior Notes due 2008, and $210 million principal amount of 7.51% Senior Notes due 2028 (collectively the “TE Products Senior Notes”). At June 30, 2002, the estimated fair value of the TE Products Senior Notes was approximately $371 million. At June 30, 2002, $500 million principal amount of 7.625% Senior Notes due 2012 was outstanding. At June 30, 2002, the estimated fair value of the $500 million Senior Notes was approximately $497.8 million.

     As of June 30, 2002, TE Products had an interest rate swap agreement in place to hedge its exposure to changes in the fair value of its fixed rate 7.51% TE Products Senior Notes due 2028. We have designated this swap agreement, which hedges exposure to changes in the fair value of the TE Products Senior Notes, as a fair value hedge. The swap agreement has a notional amount of $210 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 based on a three month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. During the six months ended June 30, 2002, we recognized a gain of $3.6 million, recorded as a reduction of interest expense, on the interest rate swap. During the quarter ended June 30, 2002, we measured the hedge effectiveness of this interest rate swap, and noted that no gain or loss from ineffectiveness was required to be recognized.

     As of June 30, 2002, we had an interest rate swap agreement in place to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facilities. We have designated this swap agreement, which hedges exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement is based on a notional amount of $250 million. Under the swap agreement, we pay a fixed rate of interest of 6.955% and receive a floating rate based on a three month U.S. Dollar LIBOR rate. Since this swap is designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. During the six months ended June 30, 2002, and 2001, we recognized $6.3 million and $2.2 million, respectively, in losses, included in interest expense, on the interest rate swap attributable to interest costs occurring in 2002 and 2001. During the quarter ended June 30, 2002, 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 the interest rate swap agreement was a loss of approximately $20 million and $20.3 million at June 30, 2002, and December 31, 2001, respectively. We anticipate that approximately $10.6 million of the fair value will be transferred into earnings over the next twelve months.

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     As of June 30, 2002, we had interest rate swap agreements in place to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. We have designated these swap agreements, which hedge exposure to changes in the fair value of the Senior Notes, as fair value hedges. The swap agreements have a combined notional amount of $500 million and mature in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, we pay a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread, and receive a fixed rate of interest of 7.625%. During the six months ended June 30, 2002, we recognized a gain of $6.9 million, recorded as a reduction of interest expense, on the interest rate swaps. During the quarter ended June 30, 2002, we measured the hedge effectiveness of these interest rate swaps, and noted that no gain or loss from ineffectiveness was required to be recognized.

     On July 16, 2002, we terminated our interest rate swap agreements that were designated as hedges to our exposure to changes in the fair value of our $500 million principal amount of 7.625% fixed rate Senior Notes due 2012. The fair value upon termination of the interest rate swap agreements was $25.8 million. Approximately $7.8 million had been recognized as a reduction to interest expense from the inception of the swap agreement on February 20, 2002, through its termination on July 16, 2002. The remaining gain of $18 million will be amortized as a reduction to future interest expense over the remaining term of the Senior Notes.

     Additionally, on July 16, 2002, we entered into new interest rate swap agreements to hedge our future exposure to changes in the fair value of our $500 million principal amount of 7.625% fixed rate Senior Notes due 2012. We have designated these swap agreements as fair value hedges. The swap agreements have a combined notional amount of $500 million and mature in 2012 to match the principal and maturity of the Senior Notes. Under these swap agreements, we pay a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread, which increased by approximately 50 basis points from the previous swap agreements, and receive a fixed rate of interest of 7.625%.

PART II. OTHER INFORMATION

Item 6. Exhibits and Reports on Form 8-K.

     (a)  Exhibits:

     
Exhibit    
Number   Description

 
3.1   Certificate of Limited Partnership of TEPPCO Partners, L.P. (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
     
3.2   Third Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated September 21, 2001 (Filed as Exhibit 3.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
4.1   Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
     
4.2   Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership’s Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference).
     
4.3   Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).

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Exhibit    
Number   Description

 
4.4   Form of Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
     
4.5   First Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
     
4.6*   Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee.
     
10.1+   Texas Eastern Products Pipeline Company 1997 Employee Incentive Compensation Plan executed on July 14, 1997 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1997 and incorporated herein by reference).
     
10.2+   Texas Eastern Products Pipeline Company Management Incentive Compensation Plan executed on January 30, 1992 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1992, and incorporated herein by reference).
     
10.3+   Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan executed on October 31, 1990 (Filed as Exhibit 10.9 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1990 and incorporated herein by reference).
     
10.4+   Form of Amendment to Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan (Filed as Exhibit 10.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1995 and incorporated herein by reference).
     
10.5+   Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
     
10.6+   Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
     
10.7+   Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to Form 10-K for TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
     
10.8+   Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan executed on March 8, 1994 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1994 and incorporated herein by reference).
     
10.9+   Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan, Amendment 1, effective January 16, 1995 (Filed as Exhibit 10.12 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 1999 and incorporated herein by reference).

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Exhibit    
Number   Description

 
10.10   Asset Purchase Agreement between Duke Energy Field Services, Inc. and TEPPCO Colorado, LLC, dated March 31, 1998 (Filed as Exhibit 10.14 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference).
     
10.11   Contribution Agreement between Duke Energy Transport and Trading Company and TEPPCO Partners, L.P., dated October 15, 1998 (Filed as Exhibit 10.16 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
     
10.12   Guaranty Agreement by Duke Energy Natural Gas Corporation for the benefit of TEPPCO Partners, L.P., dated November 30, 1998, effective November 1, 1998 (Filed as Exhibit 10.17 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
     
10.13   Letter Agreement regarding Payment Guarantees of Certain Obligations of TCTM, L.P. between Duke Capital Corporation and TCTM, L.P., dated November 30, 1998 (Filed as Exhibit 10.19 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
     
10.14+   Form of Employment Agreement between the Company and Thomas R. Harper, Charles H. Leonard, James C. Ruth, John N. Goodpasture, Leonard W. Mallett, Stephen W. Russell, David E. Owen, and Barbara A. Carroll (Filed as Exhibit 10.20 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
     
10.15   Agreement Between Owner and Contractor between TE Products Pipeline Company, Limited Partnership and Eagleton Engineering Company, dated February 4, 1999 (Filed as Exhibit 10.21 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).
     
10.16   Services and Transportation Agreement between TE Products Pipeline Company, Limited Partnership and Fina Oil and Chemical Company, BASF Corporation and BASF Fina Petrochemical Limited Partnership, dated February 9, 1999 (Filed as Exhibit 10.22 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).
     
10.17   Call Option Agreement, dated February 9, 1999 (Filed as Exhibit 10.23 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).
     
10.18+   Texas Eastern Products Pipeline Company Retention Incentive Compensation Plan, effective January 1, 1999 (Filed as Exhibit 10.24 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).
     
10.19+   Form of Employment and Non-Compete Agreement between the Company and J. Michael Cockrell effective January 1, 1999 (Filed as Exhibit 10.29 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
     
10.20+   Texas Eastern Products Pipeline Company Non-employee Directors Unit Accumulation Plan, effective April 1, 1999 (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
     
10.21+   Texas Eastern Products Pipeline Company Non-employee Directors Deferred Compensation Plan, effective November 1, 1999 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
     
10.22+   Texas Eastern Products Pipeline Company Phantom Unit Retention Plan, effective August 25, 1999 (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

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Exhibit    
Number   Description

 
10.23   Amended and Restated Purchase Agreement By and Between Atlantic Richfield Company and Texas Eastern Products Pipeline Company With Respect to the Sale of ARCO Pipe Line Company, dated as of May 10, 2000. (Filed as Exhibit 2.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2000 and incorporated herein by reference).
     
10.24+   Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Amendment and Restatement, effective January 1, 2000 (Filed as Exhibit 10.28 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).
     
10.25+   TEPPCO Supplemental Benefit Plan, effective April 1, 2000 (Filed as Exhibit 10.29 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).
     
10.26+   Employment Agreement with Barry R. Pearl (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).
     
10.27   Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).
     
10.28   Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).
     
10.29   Purchase and Sale Agreement By and Among Green River Pipeline, LLC and McMurry Oil Company, Sellers, and TEPPCO Partners, L.P., Buyer, dated as of September 7, 2000. (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.30   Credit Agreement Among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, dated as of September 28, 2001 ($400,000,000 Term Facility) (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.31   Amendment 1, dated as of September 28, 2001, to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.33 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.32   Amendment 1, dated as of September 28, 2001, to the Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.34 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.33   Amendment and Restatement, dated as of November 13, 2001, to the Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.35 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
     
10.34   Second Amendment and Restatement, dated as of November 13, 2001, to the Amended and Restated Credit Agreement amount TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.36 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

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Exhibit    
Number   Description

 
10.35   Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, dated September 21, 2001 (Filed as Exhibit 3.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.36   Amended and Restated Agreement of Limited Partnership of TCTM, L.P., dated September 21, 2001 (Filed as Exhibit 3.9 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.37   Contribution, Assignment and Amendment Agreement among TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P., Texas Eastern Products Pipeline Company, LLC, and TEPPCO GP, Inc., dated July 26, 2001 (Filed as Exhibit 3.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2001 and incorporated herein by reference).
     
10.38   Certificate of Formation of TEPPCO Colorado, LLC (Filed as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference).
     
10.39   Agreement of Limited Partnership of TEPPCO Midstream Companies, L.P., dated September 24, 2001 (Filed as Exhibit 3.10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.40   Agreement of Partnership of Jonah Gas Gathering Company dated June 20, 1996 as amended by that certain Assignment of Partnership Interests dated September 28, 2001 (Filed as Exhibit 10.40 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
     
10.41   Unanimous Written Consent of the Board of Directors of TEPPCO GP, Inc. dated February 13, 2002 (Filed as Exhibit 10.41 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
     
10.42   Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and Certain Lenders, as Lenders dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 10.44 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).
     
10.43   Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and LC Issuing Bank and Certain Lenders, as Lenders dated as of March 28, 2002 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.45 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).
     
10.44   Purchase and Sale Agreement between Burlington Resources Gathering Inc. as Seller and TEPPCO Partners, L.P., as Buyer, dated May 24, 2002 (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
     
10.45   Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, as Lenders dated as of June 27, 2002 ($200,000,000 Term Facility) (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
     
10.46   Amendment, dated as of June 27, 2002 to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent, and Certain Lenders, dated as of March 28, 2002 ($500,000,000 Revolving Credit Facility) (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

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Exhibit    
Number   Description

 
10.47   Amendment 1, dated as of June 27, 2002 to the Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 99.4 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
     
10.48*   Agreement of Limited Partnership of Val Verde Gas Gathering Company, L.P., dated May 29, 2002.
     
10.49+*   Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan, effective June 1, 2002.
     
12.1*   Statement of Computation of Ratio of Earnings to Fixed Charges.
     
21*   Subsidiaries of the Partnership.
     
99.1*   Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
     
99.2*   Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


     
  * Filed herewith.
 
  + A management contract or compensation plan or arrangement.
     
(b)   Reports on Form 8-K filed during the quarter ended June 30, 2002:

Reports on Form 8-K were filed on April 16, 2002, April 24, 2002 and June 4, 2002.

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrants have duly caused this report to be signed on its behalf by the undersigned duly authorized officer and principal financial officer.

         
      TEPPCO Partners, L.P.
(Registrant)
(A Delaware Limited Partnership)
 
 
  By:   Texas Eastern Products Pipeline
Company, LLC, as General Partner
 
 
  By:   /s/ BARRY R. PEARL

Barry R. Pearl,
President and Chief Executive Officer
 
 
  By:   /s/ CHARLES H. LEONARD

Charles H. Leonard,
Senior Vice President and Chief
Financial Officer
 

Date: August 14, 2002

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EXHIBIT INDEX

     
Exhibit    
Number   Description

 
3.1   Certificate of Limited Partnership of TEPPCO Partners, L.P. (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
     
3.2   Third Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated September 21, 2001 (Filed as Exhibit 3.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
4.1   Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
     
4.2   Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership’s Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference).
     
4.3   Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
     
4.4   Form of Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
     
4.5   First Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
     
4.6*   Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee.
     
10.1+   Texas Eastern Products Pipeline Company 1997 Employee Incentive Compensation Plan executed on July 14, 1997 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1997 and incorporated herein by reference).
     
10.2+   Texas Eastern Products Pipeline Company Management Incentive Compensation Plan executed on January 30, 1992 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1992, and incorporated herein by reference).
     
10.3+   Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan executed on October 31, 1990 (Filed as Exhibit 10.9 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1990 and incorporated herein by reference).
     
10.4+   Form of Amendment to Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan (Filed as Exhibit 10.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1995 and incorporated herein by reference).
     
10.5+   Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
     
10.6+   Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
     
10.7+   Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to Form 10-K for TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
     
10.8+   Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan executed on March 8, 1994 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1994 and incorporated herein by reference).
     
10.9+   Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan, Amendment 1, effective January 16, 1995 (Filed as Exhibit 10.12 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 1999 and incorporated herein by reference).

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Exhibit    
Number   Description

 
10.10   Asset Purchase Agreement between Duke Energy Field Services, Inc. and TEPPCO Colorado, LLC, dated March 31, 1998 (Filed as Exhibit 10.14 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference).
     
10.11   Contribution Agreement between Duke Energy Transport and Trading Company and TEPPCO Partners, L.P., dated October 15, 1998 (Filed as Exhibit 10.16 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
     
10.12   Guaranty Agreement by Duke Energy Natural Gas Corporation for the benefit of TEPPCO Partners, L.P., dated November 30, 1998, effective November 1, 1998 (Filed as Exhibit 10.17 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
     
10.13   Letter Agreement regarding Payment Guarantees of Certain Obligations of TCTM, L.P. between Duke Capital Corporation and TCTM, L.P., dated November 30, 1998 (Filed as Exhibit 10.19 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
     
10.14+   Form of Employment Agreement between the Company and Thomas R. Harper, Charles H. Leonard, James C. Ruth, John N. Goodpasture, Leonard W. Mallett, Stephen W. Russell, David E. Owen, and Barbara A. Carroll (Filed as Exhibit 10.20 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
     
10.15   Agreement Between Owner and Contractor between TE Products Pipeline Company, Limited Partnership and Eagleton Engineering Company, dated February 4, 1999 (Filed as Exhibit 10.21 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).
     
10.16   Services and Transportation Agreement between TE Products Pipeline Company, Limited Partnership and Fina Oil and Chemical Company, BASF Corporation and BASF Fina Petrochemical Limited Partnership, dated February 9, 1999 (Filed as Exhibit 10.22 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).
     
10.17   Call Option Agreement, dated February 9, 1999 (Filed as Exhibit 10.23 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).
     
10.18+   Texas Eastern Products Pipeline Company Retention Incentive Compensation Plan, effective January 1, 1999 (Filed as Exhibit 10.24 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).
     
10.19+   Form of Employment and Non-Compete Agreement between the Company and J. Michael Cockrell effective January 1, 1999 (Filed as Exhibit 10.29 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
     
10.20+   Texas Eastern Products Pipeline Company Non-employee Directors Unit Accumulation Plan, effective April 1, 1999 (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
     
10.21+   Texas Eastern Products Pipeline Company Non-employee Directors Deferred Compensation Plan, effective November 1, 1999 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
     
10.22+   Texas Eastern Products Pipeline Company Phantom Unit Retention Plan, effective August 25, 1999 (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

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Table of Contents

     
Exhibit    
Number   Description

 
10.23   Amended and Restated Purchase Agreement By and Between Atlantic Richfield Company and Texas Eastern Products Pipeline Company With Respect to the Sale of ARCO Pipe Line Company, dated as of May 10, 2000. (Filed as Exhibit 2.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2000 and incorporated herein by reference).
     
10.24+   Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Amendment and Restatement, effective January 1, 2000 (Filed as Exhibit 10.28 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).
     
10.25+   TEPPCO Supplemental Benefit Plan, effective April 1, 2000 (Filed as Exhibit 10.29 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).
     
10.26+   Employment Agreement with Barry R. Pearl (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).
     
10.27   Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).
     
10.28   Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).
     
10.29   Purchase and Sale Agreement By and Among Green River Pipeline, LLC and McMurry Oil Company, Sellers, and TEPPCO Partners, L.P., Buyer, dated as of September 7, 2000. (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.30   Credit Agreement Among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, dated as of September 28, 2001 ($400,000,000 Term Facility) (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.31   Amendment 1, dated as of September 28, 2001, to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.33 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.32   Amendment 1, dated as of September 28, 2001, to the Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.34 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.33   Amendment and Restatement, dated as of November 13, 2001, to the Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.35 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
     
10.34   Second Amendment and Restatement, dated as of November 13, 2001, to the Amended and Restated Credit Agreement amount TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.36 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

50


Table of Contents

     
Exhibit    
Number   Description

 
10.35   Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, dated September 21, 2001 (Filed as Exhibit 3.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.36   Amended and Restated Agreement of Limited Partnership of TCTM, L.P., dated September 21, 2001 (Filed as Exhibit 3.9 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.37   Contribution, Assignment and Amendment Agreement among TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P., Texas Eastern Products Pipeline Company, LLC, and TEPPCO GP, Inc., dated July 26, 2001 (Filed as Exhibit 3.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2001 and incorporated herein by reference).
     
10.38   Certificate of Formation of TEPPCO Colorado, LLC (Filed as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference).
     
10.39   Agreement of Limited Partnership of TEPPCO Midstream Companies, L.P., dated September 24, 2001 (Filed as Exhibit 3.10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
     
10.40   Agreement of Partnership of Jonah Gas Gathering Company dated June 20, 1996 as amended by that certain Assignment of Partnership Interests dated September 28, 2001 (Filed as Exhibit 10.40 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
     
10.41   Unanimous Written Consent of the Board of Directors of TEPPCO GP, Inc. dated February 13, 2002 (Filed as Exhibit 10.41 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
     
10.42   Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and Certain Lenders, as Lenders dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 10.44 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).
     
10.43   Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and LC Issuing Bank and Certain Lenders, as Lenders dated as of March 28, 2002 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.45 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).
     
10.44   Purchase and Sale Agreement between Burlington Resources Gathering Inc. as Seller and TEPPCO Partners, L.P., as Buyer, dated May 24, 2002 (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
     
10.45   Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, as Lenders dated as of June 27, 2002 ($200,000,000 Term Facility) (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
     
10.46   Amendment, dated as of June 27, 2002 to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent, and Certain Lenders, dated as of March 28, 2002 ($500,000,000 Revolving Credit Facility) (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

51


Table of Contents

     
Exhibit    
Number   Description

 
10.47   Amendment 1, dated as of June 27, 2002 to the Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 99.4 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
     
10.48*   Agreement of Limited Partnership of Val Verde Gas Gathering Company, L.P., dated May 29, 2002.
     
10.49+*   Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan, effective June 1, 2002.
     
12.1*   Statement of Computation of Ratio of Earnings to Fixed Charges.
     
21*   Subsidiaries of the Partnership.
     
99.1*   Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
     
99.2*   Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


     
  * Filed herewith.
 
  + A management contract or compensation plan or arrangement.

52