Back to GetFilings.com



Table of Contents



FORM 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

     
þ
  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
 
   
  For the Quarterly Period Ended November 30, 2004
 
   
  OR
 
   
¨
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from        to

Commission file number 1-11727

ENERGY TRANSFER PARTNERS, L.P.

(Exact name of registrant as specified in its charter)
     
Delaware   73-1493906
 
(state or other jurisdiction or
incorporation or organization)
  (I.R.S. Employer
Identification No.)

2838 Woodside Street
Dallas, Texas 75204

(Address of principal
executive offices
and zip code)

(214)981-0700
(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  þ     No ¨

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

Yes  þ     No ¨

At January 9, 2005, the registrant had units outstanding as follows:

Energy Transfer Partners, L.P.           44,640,806           Common Units

 




Table of Contents

FORM 10-Q

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Partners, L.P. and Subsidiaries
(Formerly Energy Transfer Company and surviving legal entity in the Energy Transfer Transactions)

         
    Page  
       
       
    1  
    3  
    4  
    5  
    6  
    8  
    25  
    38  
    40  
       
    40  
    46  
 Certification of CEO Pursuant to Section 302
 Certification of CEO Pursuant to Section 302
 Certification of CEO Pursuant to Section 906
 Certification of CEO Pursuant to Section 906

i


Table of Contents

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Partners, L.P., (Energy Transfer Partners or the Partnership) in periodic press releases and some oral statements of Energy Transfer Partners officials during presentations about the Partnership, include certain “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although the Partnership believes such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that every objective will be reached.

Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see the Partnership’s Annual Report on Form 10-K for the fiscal year ended August 31, 2004 filed with the Securities and Exchange Commission on November 15, 2004.

Definitions

The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:

         
  /d   per day
  Bbls   barrels
  Btu   British thermal unit, an energy measurement
  Mcf   thousand cubic feet
  MMBtu   million British thermal unit
  MMcf   million cubic feet
  Bcf   billion cubic feet
  NGL   natural gas liquid, such as propane, butane and natural gasoline
  LIBOR   London Interbank Offered Rate
  Nymex   New York Mercantile Exchange

ii


Table of Contents

PART I  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
( FORMERLY ENERGY TRANSFER COMPANY)

CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
(unaudited)

                 
    November 30,     August 31,  
    2004     2004  
ASSETS
               
 
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 59,245     $ 81,745  
Marketable securities
    1,873       2,464  
Accounts receivable, net of allowance for doubtful accounts
    340,334       275,424  
Accounts receivable from related companies
    166       34  
Exchanges receivable
    8,274       8,852  
Inventories
    74,922       53,324  
Deposits paid to vendors
    11,179       3,023  
Price risk management assets
    20,941       4,615  
Prepaid expenses and other
    13,763       7,401  
 
           
Total current assets
    530,697       436,882  
 
               
PROPERTY, PLANT AND EQUIPMENT, net
    1,557,053       1,467,649  
INVESTMENT IN AFFILIATES
    8,013       8,010  
GOODWILL
    309,645       313,720  
INTANGIBLES AND OTHER ASSETS, net
    109,586       100,844  
 
           
 
               
Total assets
  $ 2,514,994     $ 2,327,105  
 
           

1


Table of Contents

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
( FORMERLY ENERGY TRANSFER COMPANY)

CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
(unaudited)

                 
    November 30,     August 31,  
    2004     2004  
LIABILITIES AND PARTNERS’ CAPITAL
               
 
               
CURRENT LIABILITIES:
               
Working capital facility
  $ 33,096     $ 14,550  
Accounts payable
    378,238       274,122  
Accounts payable to related companies
    3,737       4,276  
Exchanges payable
    6,464       2,846  
Customer deposits
    13,952       11,378  
Accrued and other current liabilities
    67,094       55,394  
Price risk management liabilities
    5,660       1,262  
Income taxes payable
    2,004       2,252  
Current maturities of long-term debt
    33,220       30,957  
 
           
 
               
Total current liabilities
    543,465       397,037  
 
               
LONG-TERM DEBT, less current maturities
    1,122,370       1,070,871  
DEFERRED TAXES
    108,385       109,896  
OTHER NONCURRENT LIABILITIES
    835       846  
MINORITY INTERESTS
    1,936       1,475  
 
           
 
               
 
    1,776,991       1,580,125  
 
           
 
               
COMMITMENTS AND CONTINGENCIES
               
 
               
PARTNERS’ CAPITAL:
               
Common Unitholders (44,639,306 and 44,559,031 units authorized, issued and outstanding at November 30, 2004 and August 31, 2004, respectively)
    710,610       720,187  
Class C Unitholders (1,000,000 units authorized, issued and outstanding at November 30, 2004 and August 31, 2004 , respectively)
           
Class E Unitholders (4,426,916 authorized, issued and outstanding at November 30, 2004 and August 31, 2004, respectively – held by subsidiary and reported as treasury units)
           
General Partner
    28,686       26,761  
Accumulated other comprehensive income (loss)
    (1,293 )     32  
 
           
Total partners’ capital
    738,003       746,980  
 
           
 
               
Total liabilities and partners’ capital
  $ 2,514,994     $ 2,327,105  
 
           

The accompanying notes are an integral part of these consolidated financial statements.

2


Table of Contents

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
( FORMERLY ENERGY TRANSFER COMPANY)

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit and unit data)
(unaudited)

                         
    Three Months  
    Ended November 30,  
    2004     2003     2003  
            (Energy Transfer        
            Company)     (Heritage)  
REVENUES:
                       
Midstream and transportation
  $ 737,150     $ 419,097     $  
Propane
    151,233             104,730  
Other
    19,279             18,996  
 
                 
Total revenues
    907,662       419,097       123,726  
 
                 
 
                       
COSTS AND EXPENSES:
                       
Cost of products sold
    765,570       381,681       66,370  
Operating expenses
    61,461       7,386       38,042  
Depreciation and amortization
    20,269       4,147       9,415  
Selling, general and administrative
    11,310       4,879       3,190  
 
                 
Total costs and expenses
    858,610       398,093       117,017  
 
                 
 
                       
OPERATING INCOME
    49,052       21,004       6,709  
 
                       
OTHER INCOME (EXPENSE):
                       
Interest expense
    (17,331 )     (3,834 )     (8,166 )
Equity in earnings of affiliates
    36       147       219  
Gain (loss) on disposal of assets
    (91 )           173  
Interest income and other
    134       86       (46 )
 
                 
 
                       
INCOME (LOSS) BEFORE MINORITY INTERESTS AND INCOME TAXES
    31,800       17,403       (1,111 )
 
                       
Minority interests
    (158 )           (135 )
 
                 
 
                       
INCOME (LOSS) BEFORE INCOME TAXES
    31,642       17,403       (1,246 )
 
                       
Income tax expense
    1,032       1,709       50  
 
                 
 
                       
NET INCOME (LOSS)
    30,610       15,694       (1,296 )
 
                       
GENERAL PARTNER’S INTEREST IN NET INCOME (LOSS)
    6,089       314       311  
 
                 
 
                       
LIMITED PARTNERS’ INTEREST IN NET INCOME (LOSS)
  $ 24,521     $ 15,380     $ (1,607 )
 
                 
 
                       
BASIC NET INCOME (LOSS) PER LIMITED PARTNER UNIT
  $ 0.55     $ 2.32     $ (0.09 )
 
                 
 
                       
BASIC AVERAGE NUMBER OF UNITS OUTSTANDING
    44,621,955       6,621,737       18,020,137  
 
                 
 
                       
DILUTED NET INCOME (LOSS) PER LIMITED PARTNER UNIT
  $ 0.55     $ 2.32     $ (0.09 )
 
                 
 
                       
DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING
    44,695,921       6,621,737       18,020,137  
 
                 

The accompanying notes are an integral part of these consolidated financial statements.

3


Table of Contents

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
( FORMERLY ENERGY TRANSFER COMPANY)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
(unaudited)

                         
    Three Months Ended November 30,  
    2004     2003     2003  
            (Energy Transfer        
            Company)     (Heritage)  
Net income (loss)
  $ 30,610     $ 15,694     $ (1,296 )
 
                       
Other comprehensive income (loss)
                       
Reclassification adjustment for losses on derivative instruments included in net income accounted for as hedges
    14,787       481        
Change in value of derivative instruments accounted for as hedges
    (15,522 )     (999 )      
Change in value of available-for-sale securities
    (590 )           131  
 
                 
 
                       
Comprehensive income (loss)
  $ 29,285     $ 15,176     $ (1,165 )
 
                 
 
                       
Reconciliation of Accumulated Other Comprehensive Income (Loss)
                       
 
                       
Balance, beginning of period
  $ 32     $     $ (349 )
 
                       
Current period reclassification to earnings
    14,787       481        
Current period change
    (16,112 )     (999 )     131  
 
                 
 
                       
Balance, end of period
  $ (1,293 )   $ (518 )   $ (218 )
 
                 

The accompanying notes are an integral part of these consolidated financial statements.

4


Table of Contents

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
( FORMERLY ENERGY TRANSFER COMPANY)

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands, except unit data)
(unaudited)

                                                         
                                            Accumulated        
    Number of                                     Other        
    Common                             General     Comprehensive        
    Units     Common     Class C     Class E     Partner     Income (Loss)     Total  
Balance, August 31, 2004
    44,559,031     $ 720,187     $     $     $ 26,761     $ 32     $ 746,980  
Unit distribution
          (36,809 )                 (4,215 )           (41,024 )
General Partner capital contribution
                            51             51  
Issuance of Common Units in connection with certain acquisitions
    60,275       2,500                               2,500  
Issuance of restricted Common Units
    20,000                                      
Net change in accumulated other comprehensive income per accompanying statement
                                  (1,325 )     (1,325 )
Other
          211                               211  
Net income
          24,521                   6,089             30,610  
 
                                         
Balance, November 30, 2004
    44,639,306     $ 710,610     $     $     $ 28,686     $ (1,293 )   $ 738,003  
 
                                         

The accompanying notes are an integral part of these consolidated financial statements.

5


Table of Contents

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
( FORMERLY ENERGY TRANSFER COMPANY)

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

                         
    Three Months Ended November 30,  
    2004     2003     2003  
            (Energy Transfer     (Heritage)  
            Company)          
CASH FLOWS FROM OPERATING ACTIVITIES:
                       
Net income (loss)
  $ 30,610     $ 15,694     $ (1,296 )
Reconciliation of net income to net cash provided by (used in) operating activities:
                       
Depreciation and amortization
    20,269       4,147       9,415  
Amortization of deferred finance costs charged to interest expense
    664       884        
Provision for loss on accounts receivable
    168             298  
(Gain) loss on disposal of assets
    91             (173 )
Deferred compensation on restricted units and long-term incentive plan
    402             90  
Undistributed earnings of affiliates
    (3 )     (147 )     (193 )
Deferred income taxes
    (1,511 )     385        
Minority interests
    461             (5 )
Other, net
          37        
Changes in assets and liabilities, net of effect of acquisitions:
                       
Accounts receivable
    (65,457 )     (35,621 )     (16,571 )
Accounts receivable from related companies
    (133 )            
Inventories
    (21,451 )     (955 )     (11,889 )
Deposits paid to vendors
    (8,156 )     (1,045 )      
Exchanges receivable
    579       227        
Prepaid expenses and other
    (6,208 )     (937 )     (2,904 )
Intangibles and other assets
    (77 )           (457 )
Accounts payable
    103,476       15,908       11,958  
Accounts payable to related companies
    (538 )     (947 )     574  
Exchanges payable
    3,618       699        
Deposits from customers
    2,574       (8,520 )      
Accrued and other current liabilities
    10,198       (85 )     1,525  
Other long-term liabilities
    (10 )     6        
Income taxes payable
    (248 )     (1,135 )      
Price risk management assets and liabilities, net
    (12,663 )     1,569        
 
                 
Net cash provided by (used in) operating activities
    56,655       (9,836 )     (9,628 )
 
                 
 
                       
CASH FLOWS FROM INVESTING ACTIVITIES:
                       
Cash paid for acquisitions, net of cash acquired
    (67,267 )           (6,799 )
Capital expenditures
    (43,382 )     (11,830 )     (12,240 )
Proceeds from the sale of assets
    1,275       4       592  
 
                 
Net cash used in investing activities
    (109,374 )     (11,826 )     (18,447 )
 
                 
 
                       
CASH FLOWS FROM FINANCING ACTIVITIES:
                       
Proceeds from borrowings
    91,214             73,298  
Principal payments on debt
    (19,831 )     (7,500 )     (32,371 )
Other
    (191 )            
Capital contribution from General Partner
    51              
Unit distributions
    (41,024 )           (12,149 )
 
                 
Net cash provided by (used in) financing activities
    30,219       (7,500 )     28,778  
 
                 
 
                       
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    (22,500 )     (29,162 )     703  
 
                       
CASH AND CASH EQUIVALENTS, beginning of period
    81,745       53,122       7,117  
 
                 
 
                       
CASH AND CASH EQUIVALENTS, end of period
  $ 59,245     $ 23,960     $ 7,820  
 
                 

6


Table of Contents

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
( FORMERLY ENERGY TRANSFER COMPANY)

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

                         
    Three Months Ended November 30,  
    2004     2003     2003  
            (Energy Transfer        
            Company)       (Heritage)  
NONCASH FINANCING ACTIVITIES:
                       
 
                       
Notes payable incurred on noncompete agreements and other long term debt
  $ 925     $     $ 455  
 
                 
Issuance of Common Units in connection with certain acquistions
  $ 2,500     $     $  
 
                 
 
                       
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
                       
 
                       
Cash paid during the period for interest
  $ 18,421     $ 3,080     $ 9,571  
 
                 
Cash paid during the period for income taxes
  $ 2,708     $ 2,450     $  
 
                 

The accompanying notes are an integral part of these consolidated financial statements.

7


Table of Contents

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
(FORMERLY ENERGY TRANSFER COMPANY)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollar amounts in thousands, except unit and per unit data)
(unaudited)

1. OPERATIONS AND ORGANIZATION :

The accompanying unaudited consolidated financial statements and notes thereto of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States of America for interim consolidated financial information and pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete consolidated financial statements. Due to the seasonal nature of the Partnership's propane operations, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of Energy Transfer Partners and subsidiaries as of November 30, 2004 and the results of operations and cash flows for the three-month periods ended November 30, 2004 and 2003, respectively, and the three months ended November 30, 2003 for Heritage. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of Energy Transfer Partners presented in the Partnership’s Annual Report on Form 10-K as filed with the Securities and Exchange Commission on November 15, 2004 for the fiscal year ended August 31, 2004.

Certain prior period amounts have been reclassified to conform with the 2004 presentation. These reclassifications have no impact on net income or total partners’ capital.

Energy Transfer Transactions

On January 20, 2004, Heritage Propane Partners, L.P., (“Heritage”) and La Grange Energy, L.P. (“La Grange Energy”) completed the series of transactions whereby La Grange Energy contributed its subsidiary, La Grange Acquisition, L.P. and its subsidiaries and affiliates who conduct business under the assumed name of Energy Transfer Company, (“ETC OLP”) to Heritage. Simultaneously, La Grange Energy acquired U.S. Propane and Limited Partner Units, Class D Units and Special Units of Heritage, thereby gaining control of Heritage. Simultaneous with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“Heritage Holdings”) from U.S. Propane, L.P.

Accounting Treatment of the Energy Transfer Transactions

The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standard No. 141, Business Combinations (SFAS 141). Although Heritage is the surviving parent entity for legal purposes, ETC OLP is the acquiror for accounting purposes. As a result, ETC OLP’s historical financial statements are now the historical financial statements of the registrant. The operations of Heritage prior to the Energy Transfer Transactions are referred to as Heritage. The assets and liabilities of Heritage were initially recorded at fair value to the extent acquired by La Grange Energy through its acquisition of the General Partner and limited partner interests of Heritage of approximately 35.4%, determined in accordance with Emerging Issues Task Force (EITF) 90-13 Accounting for Simultaneous Common Control Mergers and SFAS 141. The assets and liabilities of ETC OLP have been recorded at historical cost. Although the partners’ capital accounts of ETC OLP became the capital accounts of the Partnership, Heritage’s partnership structure and partnership units survive. Accordingly, the partners’ capital accounts of ETC OLP were restated based on the general partner interests and units received by La Grange Energy in the Energy Transfer Transactions.

The acquisition of Heritage Holdings by Heritage was accounted for as a capital transaction as the primary asset held by Heritage Holdings was 4,426,916 Common Units of Heritage. Following the acquisition of Heritage Holdings by Heritage, these Common Units were converted to Class E Units. The Class E Units are recorded as treasury units in the consolidated financial statements.

In June 2004, the Special Units, which initially had no value assigned, were converted to Common Units, which resulted in additional consideration being recorded. The additional consideration adjusted the percent of Heritage

8


Table of Contents

acquired to 41.5% and resulted in an additional fair value step-up to Heritage’s assets of approximately $38,000 as determined in accordance with EITF 90-13.

The excess purchase price over Heritage’s cost was determined as follows:

         
Net book value of Heritage at January 20, 2004
  $ 239,102  
Historical goodwill at January 20, 2004
    (170,500 )
Equity investment from public offering
    355,948  
Treasury Class E Unit purchase
    (157,340 )
 
     
 
    267,210  
Percent of Heritage acquired by La Grange Energy
    41.5 %
 
     
Equity interest acquired
  $ 110,892  
 
     
 
       
Fair market value of Limited Partner Units
    668,534  
Purchase price of General Partner Interest
    30,000  
Equity investment from public offering
    355,948  
Treasury Class E Unit purchase
    (157,340 )
 
     
 
    897,142  
Percent of Heritage acquired by La Grange Energy
    41.5 %
 
     
Fair value of equity acquired
    372,314  
Net book value of equity acquired
    110,892  
 
     
Excess purchase price over Heritage cost
  $ 261,422  
 
     

The excess purchase price over Heritage cost was allocated as follows:

         
Property, plant and equipment (25 year life)
  $ 35,269  
Customer lists (15 year life)
    18,926  
Trademarks
    19,251  
Goodwill
    187,976  
 
     
 
  $ 261,422  
 
     

Management obtained an independent valuation and has made the final modifications to the purchase price. The table above reflects the adjustments made to the allocation of the purchase price during the three months ended November 30, 2004.

Business Operations

In order to simplify the obligations of Energy Transfer Partners under the laws of several jurisdictions in which it conducts business, the Partnership’s activities are conducted through two subsidiary operating partnerships, ETC OLP, a Texas limited partnership which is engaged in midstream and transportation natural gas operations, and HOLP, a Delaware limited partnership, which is engaged in retail and wholesale propane operations (collectively the “Operating Partnerships”). The Partnership, the Operating Partnerships, and their other subsidiaries are collectively referred to in this report as “Energy Transfer.”

As of November 30, 2004, ETC OLP owned and operated approximately 7,750 miles of natural gas gathering and transportation pipelines with an aggregate throughput capacity of 5.2 billion cubic feet of natural gas per day, with natural gas treating and processing plants located in Texas, Oklahoma, and Louisiana. Its major asset groups consist of the Southeast Texas System, Elk City System, Oasis Pipeline, East Texas Pipeline System and ET Fuel System. On November 1, 2004, the Partnership closed on the acquisition of certain midstream natural gas assets of Devon Energy Corporation (“Devon”). The assets, known as the Texas Chalk and Madison Systems, include approximately 1,800 miles of gathering and mainline pipeline systems, four natural gas treating plants, condensate stabilization facilities, fractionation facilities and the 80 MMcf/d Madison gas processing plant. These assets are in the Southeast Texas System, which is included in the midstream segment.

HOLP sells propane and propane-related products to more than 650,000 active residential, commercial, industrial, and agricultural customers in 32 states. HOLP is also a wholesale propane supplier in the United States and in Canada, the latter through its participation in MP Energy Partnership. MP Energy Partnership, a Canadian partnership in which the Partnership owns a 60% interest is engaged in lower-margin wholesale distribution and in supplying HOLP’s northern U.S. locations. HOLP buys and sells financial instruments for its own account through its wholly owned subsidiary, Heritage Energy Resources, L.L.C. (“Resources”).

9


Table of Contents

2. PRESENTATION OF FINANCIAL INFORMATION:

The accompanying financial statements for the three months ended November 30, 2004 include the results of operations for ETC OLP, consolidated with the results of operations of HOLP and Heritage Holdings. On June 2, 2004, ETC OLP acquired the ET Fuel System from TXU Fuel Company, a subsidiary of TXU Corp. The results of operations for the ET Fuel System are included in the consolidated statement of operations since the acquisition date.

As stated previously, the financial statements of ETC OLP are the financial statements of the registrant, as ETC OLP was deemed the accounting acquiror from the Energy Transfer Transactions. ETC OLP was formed on October 1, 2002, and has an August 31 year-end. The accompanying combined financial statements of ETC OLP as of November 30, 2003 present the combined financial statements of ETC OLP and subsidiaries after the elimination of significant intercompany balances and transactions.

The following unaudited pro forma consolidated results of operations are presented as if the ET Fuel System acquisition and the Energy Transfer Transactions had been made at the beginning of the period presented.

         
    Three
Months Ended
 
    November 30,  
    2003  
Revenues
    555,629  
Net income
    14,940  
Basic earnings per Limited Partner Unit
  $ 0.40  
Diluted earnings per Limited Partner Unit
  $ 0.40  

The pro forma consolidated results of operations include adjustments to give effect to depreciation on the step-up of property, plant and equipment, amortization of customer lists, interest expense on acquisition debt, and certain other adjustments. The pro forma consolidated results of operations do not include the effects of the Texas Chalk and Madison systems or the two propane companies that were acquired during the three months ended November 30, 2004. The unaudited pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

3. USE OF ESTIMATES:

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream and transportation segments are estimated using volume estimates and market prices. Any difference between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the three months ending November 30, 2004 represents the actual results in all material respects.

Some of the other more significant estimates made by management include, but are not limited to, allowances for doubtful accounts, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, and general business and medical self-insurance reserves. Actual results could differ from those estimates.

4. ACCOUNTS RECEIVABLE:

ETC OLP’s midstream and transportation operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty or prepayment). Management reviews midstream and transportation accounts receivable balances each week. Credit limits are assigned and monitored for all counterparties of the midstream and transportation operations. Management believes that the occurrence of bad debt in the midstream and transportation segments is not significant; therefore, an

10


Table of Contents

allowance for doubtful accounts for the midstream and transportation segments was not deemed necessary at November 30, 2004 or August 31, 2004. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. There was no bad debt expense recognized for the three months ended November 30, 2004 and 2003 in the midstream and transportation segments.

ETC OLP enters into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.

HOLP grants credit to its customers for the purchase of propane and propane-related products. Included in accounts receivable are trade accounts receivable arising from the HOLP’s retail and wholesale propane operations and receivables arising from liquids marketing activities. Accounts receivable for retail and wholesale propane and liquids marketing activities are recorded as amounts billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts for the retail and wholesale propane and liquids marketing segments is based on management’s assessment of the realizability of customer accounts. Management’s assessment is based on the overall creditworthiness of the Partnership’s customers, historical trends in collectability, and any specific disputes. The accounts receivable for HOLP were marked to fair market value in connection with the Energy Transfer Transactions. Accounts receivable consisted of the following:

                 
    November 30,     August 31,  
    2004     2004  
Accounts receivable midstream and transportation
  $ 275,910     $ 230,101  
Accounts receivable propane
    66,259       46,990  
Less – allowance for doubtful accounts
    (1,835 )     (1,667 )
 
           
Total, net
  $ 340,334     $ 275,424  
 
           

The activity in the allowance for doubtful accounts for the retail and wholesale propane and liquids marketing segments consisted of the following:

                 
    Three Months Ended  
    November 30,  
    2004     2003  
Balance, beginning of the period
  $ 1,667     $  
Provision for loss on accounts receivable
    168        
Accounts receivable written off, net of recoveries
           
 
           
Balance, end of period
  $ 1,835     $  
 
           

5. INVENTORIES:

Midstream and transportation inventories consist principally of natural gas held in storage and NGLs required to be maintained in certain pipelines. Natural gas held in storage is valued at the lower of cost or market. NGL inventory is valued at market prices as these amounts turn over monthly, and management believes the costs approximate market value. Propane inventories are valued at the lower of cost or market. The cost of propane inventories is determined using weighted-average cost of propane delivered to the customer service locations, and includes storage fees and inbound freight costs, while the cost of appliances, parts, and fittings is determined by the first-in, first-out method. Inventories consisted of the following:

11


Table of Contents

                 
    November 30,     August 31,  
    2004     2004  
Natural gas, propane and other NGLs
  $ 63,564     $ 40,989  
Appliances, parts and fittings and other
    11,358       12,335  
 
           
Total inventories
  $ 74,922     $ 53,324  
 
           

6. GOODWILL:

Goodwill is associated with acquisitions made for the Partnership’s midstream and retail propane segments. There is no goodwill associated with the transportation segment. Of the $309,645 balance in goodwill, $25,596 is expected to be tax deductible. Goodwill is tested for impairment annually in accordance with Statement of Accounting Standards No. 142, Goodwill and Other Intangible Assets, (“SFAS 142”). The changes in the carrying amount of goodwill, including the final purchase allocation related to the Energy Transfer Transactions, for the three months ended November 30, 2004 were as follows:

                         
    Midstream     Retail Propane     Total  
Balance as of August 31, 2004
  $ 13,409     $ 300,311     $ 313,720  
Fair value adjustment for final purchase allocation related to the ETC Transactions
          (4,842 )     (4,842)  
Goodwill acquired during the period
          767       767  
Impairment losses
                 
 
                 
Balance as of November 30, 2004
  $ 13,409     $ 296,236     $ 309,645  
 
                 

7. DEPOSITS:

Deposits are paid to vendors in the midstream and transportation business as prepayments for natural gas deliveries in the following month. The Partnership makes prepayments when the volume of business with a vendor exceeds the Partnership’s credit limit and/or when it is economically beneficial to do so. Deposits with vendors for gas purchases were $711 and $3,000 as of November 30, 2004 and August 31, 2004, respectively. The Partnership also has deposits with derivative counterparties of $10,468 and $23 as of November 30, 2004 and August 31, 2004, respectively.

Deposits are received from midstream and transportation customers as prepayments for natural gas deliveries in the following month and deposits from propane customers as security for future propane deliveries. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit. Deposits received from customers were $13,952 and $11,378 as of November 30, 2004 and August 31, 2004, respectively.

8. SHIPPING AND HANDLING COSTS:

In accordance with the Emerging Issues Task Force Issue 00-10, Accounting for Shipping and Handling Fees and Costs, the Partnership has classified $16,825 and $3,943 from producer payments for natural gas, compression and treating, which can be considered handling costs, as revenue for the three months ended November 30, 2004 and 2003, respectively. Shipping and handling costs related to fuel sold are included in cost of sales, while the remaining costs of approximately $7,215 and $1,946, which are included in operating expenses, reflect the cost of fuel consumed for compression and treating for the three months ended November 30, 2004 and 2003, respectively. The Partnership does not separately charge shipping and handling costs of propane to customers.

9. INCOME (LOSS) PER LIMITED PARTNER UNIT:

Basic net income (loss) per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of Common Units outstanding. Diluted net income (loss) per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of Common Units outstanding and the weighted average number of restricted units (“Phantom Units”) granted under the Restricted Unit Plan. A reconciliation of net income (loss) and weighted average units used in computing basic and diluted net income (loss) per unit is as follows:

12


Table of Contents

                         
    For the Three Months Ended November 30,  
    2004     2003     2003  
            (Energy Transfer        
            Company)     (Heritage)  
Basic Net Income (Loss) per Limited Partner Unit:
                       
Limited Partners’ interest in net income (loss)
  $ 24,521     $ 15,380     $ (1,607 )
 
                 
 
                       
Weighted average limited partner units
    44,621,955       6,621,737       18,020,137  
 
                 
 
                       
Basic net income (loss) per limited partner unit
  $ 0.55     $ 2.32     $ (0.09 )
 
                 
 
                       
Diluted Net Income (Loss) per Limited Partner Unit:
                       
Limited partners’ interest in net income (loss)
  $ 24,521     $ 15,380     $ (1,607 )
 
                 
 
                       
Weighted average limited partner units
    44,621,955       6,621,737       18,020,137  
Dilutive effect of phantom units (a)
    73,966              
 
                 
Weighted average limited partner units, assuming dilutive effect of phantom units
    44,695,921       6,621,737       18,020,137  
 
                 
 
                       
Diluted net income (loss) per limited partner unit
  $ 0.55     $ 2.32     $ (0.09 )
 
                 

(a) For the three months ended November 30, 2003 of Heritage, 46,100 phantom units were excluded from the calculation of diluted net loss as such units were anti-dilutive due to the net loss for the period.

10. UNIT BASED COMPENSATION PLANS

The Partnership follows the fair value recognition provisions of Statement of Financial Accounting Standards No. 123 Accounting for Stock-based Compensation (SFAS 123). SFAS 123 requires that significant assumptions be used during the period to estimate the fair value, which includes the risk-free interest rate used, the expected life of the grants under each of the plans and the expected distributions on each of the units granted. The Partnership assumed a weighted average risk free interest rate of 2.83% for the three months ended November 30, 2004, in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each grant. Annual average cash distributions at the grant date were estimated to be $3.27 for the three months ended November 30, 2004. The expected life of each grant is assumed to be the minimum vesting period under certain performance criteria of each grant. There were no grants outstanding at November 30, 2003. The Partnership recognized deferred compensation expense of $402 for the three months ended November 30, 2004 related to unit based compensation plans.

2004 Unit Plan

On June 23, 2004 at a special meeting of the Common Unitholders, the Common Unitholders approved the terms of the Partnership’s 2004 Unit Plan (the “Plan”), which provides for awards of Common Units and other rights to the Partnership’s employees, officers, and directors. The maximum number of Common Units that may be granted under this Plan is 900,000 total units issued. Any awards that are forfeited or which expire for any reason or any units, which are not used in the settlement of an award, will be available for grant under the Plan. Units to be delivered upon the vesting of awards granted under the Plan may be (i) units acquired by the Partnership in the open market, (ii) units already owned by the Partnership or its General Partner, (iii) units acquired by the Partnership or its General Partner directly from the Partnership, or any other person, (iv) units that are registered under a registration statement for this Plan, (v) Restricted Units, or (vi) any combination of the foregoing.

Employee Grants. The Compensation Committee, in its discretion, may from time to time grant awards to any employee, upon such terms and conditions as it may determine appropriate and in accordance with specific general guidelines as defined by the Plan. All outstanding awards shall fully vest into units upon any change in control as defined by the Plan or upon such terms as the Compensation Committee may require at the time the award is granted. As of November 30, 2004, 129,600 awards were outstanding under the 2004 Unit Plan, all of which were granted during the three months ended November 30, 2004. These awards will vest proportionately subject to vesting over a three-year period based upon the achievement of certain performance criteria. Vested awards will convert into Common Units upon the third anniversary of the date of the grants. The measuring date for vesting is September 1 of each year. The performance criteria for vesting is based upon the total return to the Partnership’s Unitholders as compared to a group of master limited partnership peer companies. The issuance of Common Units

13


Table of Contents

pursuant to the 2004 Unit Plan is intended to serve as a means of incentive compensation, therefore, no consideration will be payable by the plan participants upon vesting and issuance of the Common Units.

Director Grants. Each director who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of USP LLC, the Partnership, or a subsidiary (“Director Participant”), who is elected or appointed to the Board for the first time shall automatically receive, on the date of his or her election or appointment, an award of up to 2,000 Units (the “Initial Director’s Grant”). Commencing on September 1, 2004 and each September 1 thereafter that this Plan is in effect, each Director Participant who is in office on such September 1, shall automatically receive an award of Units equal to $15,000 divided by the fair market value of a Common Units on such date (“Annual Director’s Grant”). Each grant of an award to a Director Participant will vest one-third per year, beginning on the first anniversary date of the Award; provided however, notwithstanding the foregoing, (i) all awards to a Director Participant shall become fully vested upon a change in control, as defined by the Plan, unless voluntarily waived by such Director Participant, and (ii) all awards which have not yet vested on the date a Director Participant ceases to be a director shall vest on such terms as may be determined by the Compensation Committee. As of November 30, 2004, Initial Director’s Grants and annual Director’s Grants totaling 8,422 units have been made, of which, 4,422 were granted during the three months ended November 30, 2004.

Long-Term Incentive Grants. The Compensation Committee may, from time to time, grant awards under the Plan to any executive officer or any employee it may designate as a participant in accordance with general guidelines under the Plan. These guidelines include (i) options to purchase a specified number of units at a specified exercise price, which are clearly designated in the award as either an “incentive stock option” within the meaning of Section 422 of the Internal Revenue Code, or a “non-qualifying stock option” that is not intended to qualify as an incentive stock option under Section 422; (ii) Unit Appreciation Rights that specify the terms of the fair market value of the award on the date the unit appreciation right is exercised and the strike price; (iii) units; or (iv) any combination hereof. As of November 30, 2004, there have been no Long-Term Incentive Grants made under the Plan.

This Plan will be administered by the Compensation Committee of the Board of Directors and may be amended from time to time by the Board; provided however, that no amendment will be made without the approval of a majority of the Unitholders (i) if so required under the rules and regulations of the New York Stock Exchange or the Securities and Exchange Commission; (ii) that would extend the maximum period during which an award may be granted under the Plan; (iii) materially increase the cost of the Plan to the Partnership; or (iv) result in this Plan no longer satisfying the requirements of Rule 16b-3 of Section 16 of the Securities and Exchange Act of 1934. This Plan shall terminate no later that the 10th anniversary of its original effective date.

11. ACQUISITIONS:

In November 2004, the Partnership acquired the Texas Chalk and Madison Systems from Devon for $64,632 in cash which was principally financed with $60,000 from the ETC OLP's Revolving Credit Facility. These assets include approximately 1,800 miles of gathering and mainline pipeline systems, four natural gas treating plants, condensate stabilization facilities and an 80 MMcf/d gas processing plant. These assets will be integrated into the Southeast Texas System and are expected to provide increased throughput capacity to our existing midstream assets. The acquisition was accounted for using the purchase method, and the purchase price has been initially allocated based on the estimated fair value of the individual assets acquired and the liabilities assumed at the date of the acquisition. The final allocation of the purchase price is pending completion of an independent appraisal. The results of operations for the Texas Chalk and Madison Systems are included in the Consolidated Statement of Operations beginning November 1, 2004.

The assets acquired and purchase price allocations were as follows:

         
Property, plant and equipment
  $ 66,402  
Accounts payable – Devon
    (525 )
Accrued expenses
    (1,245 )
 
     
Total
  $ 64,632  
 
     

During the three months ended November 30, 2004, HOLP acquired substantially all of the assets of two propane companies, Boland Energy of Beaufort, Missouri, and Trenton Propane of Trenton, Texas. The aggregate purchase price for these acquisitions totaled $6,432, which included cash paid of $2,635, 60,275 Common Units issued valued at $2,500 and liabilities assumed of $1,297. In the aggregate, these acquisitions are not material for pro forma

14


Table of Contents

disclosure purposes. These acquisitions were financed primarily with the HOLP Senior Revolving Acquisition facility and were accounted for by the purchase method under SFAS 141.

12. WORKING CAPITAL FACILITY AND LONG-TERM DEBT:

Effective August 31, 2004, ETC OLP entered into the Third Amendment to the Second Amended and Restated Credit Agreement. The terms of the Agreement are as follows:

A $725,000 Term Loan Facility that matures on January 18, 2008. Amounts borrowed under the ETC OLP Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 5.20% as of November 30, 2004. The Term Loan Facility is secured by substantially all of the ETC OLP’s assets. As of November 30, 2004, the Term Loan Facility had a balance outstanding of $725,000.

A $225,000 Revolving Credit Facility is available through January 18, 2008. Amounts borrowed under the ETC OLP Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 4.99% as of November 30, 2004. The maximum commitment fee payable on the unused portion of the facility is 0.50%. The facility is fully secured by substantially all of ETC OLP’s assets. As of November 30, 2004, there was $60,000 outstanding under the Revolving Credit Facility, and $1,050 in Letters of Credit outstanding, which reduce the amount available for borrowing under the Revolving Credit Facility. Letters of Credit under the Revolving Credit Facility may not exceed $40,000.

Effective March 31, 2004, HOLP entered into the Third Amended and Restated Credit Agreement. The terms of the Agreement are as follows:

A $75,000 Senior Revolving Working Capital Facility is available through December 31, 2006. Amounts borrowed under the Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 3.7119% for the amount outstanding at November 30, 2004. The maximum commitment fee payable on the unused portion of the facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10,000 for a period of not less than 30 consecutive days at least one time during each fiscal year. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Working Capital Facility. As of November 30, 2004, the Senior Revolving Working Capital Facility had a balance outstanding of $43,096, of which $10,000 was long-term and $33,096 was short-term. A $5,000 Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of the Senior Revolving Working Capital Facility. Letter of Credit Exposure plus the Working Capital Loan cannot exceed the $75,000 maximum Working Capital Facility. HOLP had outstanding Letters of Credit of $1,002 at November 30, 2004.

A $75,000 Senior Revolving Acquisition Facility is available through December 31, 2006. Amounts borrowed under the Senior Revolving Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 3.7119% for the amount outstanding at November 30, 2004. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Acquisition Facility. As of November 30, 2004, the Senior Revolving Acquisition Facility had a balance outstanding of $19,000.

13. COMMITMENTS AND CONTINGENCIES:

Commitments

The Partnership has forward commodity contracts, which will be settled by physical delivery. Short-term contracts, which expire in less than one year, require delivery of up to 13 MMBtu/d/. Long-term contracts total require delivery of up to 160 MMBtu/d. The long-term contracts run through July 2013.

15


Table of Contents

The Partnership has signed long-term agreements with several parties committing firm transportation volumes into the Bossier Pipeline which is part of the East Texas Pipeline System. Those commitments include an agreement with XTO Energy Inc. (XTO) to deliver approximately 200 MMBtu/d of natural gas into the pipeline. The term of the XTO agreement began in June 2004 when the pipeline became operational, and expires in June 2012.

The Partnership in the normal course of business, purchases, processes and sells natural gas pursuant to long-term contracts. Such contracts contain terms that are customary in the industry. The Partnership believes that such terms are commercially reasonable and will not have a material adverse effect on the Partnership’s financial position or results of operations.

The Partnership has also entered into several propane purchase and supply commitments with varying terms as to quantities and prices, which expire at various dates through March 2005.

Litigation

Although the midstream operating partnership, ETC OLP, may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, ETC OLP is not currently a party to any material legal proceedings. In addition, management is not aware of any material legal or governmental proceedings against ETC OLP, or contemplated to be brought against ETC OLP, under the various environmental protection statutes to which it is subject.

Propane is a flammable, combustible gas. Serious personal injury and significant property damage can arise in connection with its storage, transportation or use. In the ordinary course of business, HOLP is sometimes threatened with or is named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. The Partnership maintains liability insurance with insurers in amounts and with coverage and deductibles that management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. Although any litigation is inherently uncertain, based on past experience, the information currently available and the availability of insurance coverage, we do not believe that pending or threatened litigation matters will have a material adverse effect on our financial condition or results of operations.

Of the pending or threatened matters in which the Partnership is a party, none have arisen outside the ordinary course of business except for an action filed by Heritage on November 30, 1999 against SCANA Corporation, Cornerstone Ventures, L.P. and Suburban Propane, L.P. (the “SCANA litigation”). Prior to trial, a settlement was reached with Defendant Cornerstone Ventures, L.P., and they were dismissed from the litigation. The trial began on October 4, 2004 against the remaining defendants and testimony was concluded on October 20, 2004. On October 21, 2004, the jury returned a verdict in favor of Heritage against SCANA and in favor of defendant Suburban. The jury found in favor of Heritage on all four claims against SCANA, awarding a total of $48 million in actual and punitive damages. As of this date, the court has not yet rendered a final judgment, pending post-trial motions. SCANA has publicly stated that it plans to appeal any adverse judgment by the court. The Partnership cannot predict whether the final judgment will affirm the jury verdict without any modification or whether any appeal of the final judgment by SCANA will be successful. As a result, management cannot yet predict whether the Partnership will receive any of the damages award covered by this verdict. Please read Note 8 of the Partnership’s Form 10-K for the year ended August 31, 2004 filed with the Securities and Exchange Commission on November 15, 2004 for additional discussion of rights relating to the SCANA litigation.

The Partnership is a party to various legal proceedings and/or regulatory proceedings incidental to its business. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against the Partnership. In the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, the Partnership accrues the related deductible. As of November 30, 2004 and August 31, 2004, an accrual of $826 and $930, respectively, was recorded as accrued and other current liabilities on the Partnership’s consolidated balance sheets.

16


Table of Contents

Environmental

The Partnership’s operations are subject to extensive federal, state and local environmental laws and regulations that require expenditures for remediation at operating facilities and waste disposal sites. Although the Partnership believes its operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the natural gas pipeline and processing business, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities. Accordingly, the Partnership has adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financial liability which could result from such events. However, some risk of environmental or other damage is inherent in the natural gas pipeline and processing business, as it is with other companies engaged in similar businesses.

In conjunction with the October 1, 2002 acquisition of the Texas and Oklahoma natural gas gathering and gas processing assets from Aquila Gas Pipeline, Aquila, Inc. (Aquila) agreed to indemnify ETC OLP for any environmental liabilities that arose from the operation of the assets for the period prior to October 1, 2002. Aquila also agreed to indemnify ETC OLP for 50% of any environmental liabilities that arose from the operations of Oasis Pipe Line Company prior to October 1, 2002.

Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites, on which the Partnership presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, Heritage obtained indemnification for expenses associated with any remediation from the former owners or related entities. The Partnership has not been named as a potentially responsible party at any of these sites, nor has the Partnership’s operations contributed to the environmental issues at these sites. Accordingly, no related liabilities have been recorded in the Partnership’s November 30, 2004 and August 31, 2004 balance sheets. Based on information currently available to the Partnership, such projects are not expected to have a material adverse effect on the Partnership’s financial condition or results of operations.

In July 2001, Heritage acquired a company that had previously received a request for information from the U.S. Environmental Protection Agency (the “EPA”) regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred long before the facility acquired by Heritage was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called “Superfund”). Based upon information currently available to the Partnership, it is believed that the Partnership’s liability if such action were to be taken by the EPA would not have a material adverse effect on the Partnership’s financial condition or results of operations.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of the Partnership’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, the Partnership believes that such costs will not have a material adverse effect on its financial position. The Partnership has accounted for the environmental liabilities in accordance with Statement of Position 96-1, Environmental Remediation Liabilities. As of November 30, 2004 and August 31, 2004, an accrual of $885 and $896 was recorded in the Partnership’s balance sheets to cover material environmental liabilities. A receivable of $418 and $423 was recorded in the Partnership’s balance sheets as of November 30, 2004 and August 2004, respectively, to account for Aquila’s share of certain environmental liabilities.

14. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

The Partnership applies Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133) as amended. This statement requires that all derivatives be

17


Table of Contents

recognized in the balance sheet as either an asset or liability measured at fair value. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.

The Partnership has established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. The midstream and transportation segments do not use derivative financial instruments for speculative purposes. At inception, the Partnership formally documents the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. The Partnership also assesses, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in its hedging transactions are highly effective in offsetting changes in cash flows. Furthermore, management meets on a weekly basis to assess the creditworthiness of the derivative counterparties to manage against the risk of default. If the Partnership determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.

The Partnership utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit its exposure to margin fluctuations in natural gas and NGL prices. These contracts consist primarily of futures and swaps. The Partnership designates various futures and certain associated basis contracts as cash flow hedging instruments in accordance with SFAS 133. All derivatives are recognized in the balance sheet as price risk management assets and liabilities measured at fair value. For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated statement of operations in cost of products sold. The fair value of price risk management assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income. The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income and when the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in earnings in the consolidated statement of operations. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the consolidated statement of operations. The Partnership reclassified into earnings losses of $14,787 and $481 for the three months ended November 30, 2004 and 2003, respectively, related to the commodity financial instruments, that were initially recorded in accumulated other comprehensive income (loss). Losses of $15,342 and $67 attributable to hedge ineffectiveness were recorded in costs of products sold for the quarter ended November 30, 2004 and 2003, respectively.

In the course of normal operations, the Partnership routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs that qualify for and are designated as a normal purchase and sales contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for using traditional accrual accounting.

The market prices used to value the financial derivative transactions reflect management’s estimates considering various factors including closing exchange and over-the-counter quotations, and the time value of the underlying commitments. The values are adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under present market conditions.

18


Table of Contents

The following table details the outstanding derivatives as of November 30, 2004 and August 31, 2004, respectively:

                             
        Notional                
        Volume             Fair  
November 30, 2004:   Commodity   MMBTU     Maturity     Value  
Basis Swaps IFERC/Nymex
  Gas     37,756,000       2004-2005     $ (9,900 )
Basis Swaps IFERC/Nymex
  Gas     72,789,500       2004-2005       39,906  
 
                         
 
                      $ 30,006  
 
                           
Swing Swaps IFERC
  Gas     89,816,487       2004-2005     $ (767 )
Swing Swaps IFERC
  Gas     50,828,000       2004-2005     $ 1,122  
Swing Swaps IFERC
  Gas     76,720,000       2006-2008     $  
 
                         
 
                      $ 355  
 
                           
Futures Nymex
  Gas     4,732,500       2004-2005     $ (1,666 )
Futures Nymex
  Gas     40,940,000       2004-2005       (32,925 )
 
                         
 
                      $ (34,591 )
                             
        Barrels                  
NGL Swaps
  Condensate     105,000       2004-2005     $ (915 )
                             
        Notional                
        Volume             Fair  
August 31, 2004:   Commodity   MMBTU     Maturity     Value  
Basis Swaps IFERC/Nymex
  Gas     54,472,500       2004-2005     $ 1,451  
Basis Swaps IFERC/Nymex
  Gas     62,767,500       2004-2005       592  
 
                         
 
                      $ 2,043  
 
                           
Swing Swaps IFERC
  Gas     119,495,000       2004-2005     $ 704  
Swing Swaps IFERC
  Gas     45,265,000       2004-2005       (399 )
Swing Swaps IFERC
  Gas     76,720,000       2006-2008        
 
                         
 
                      $ 305  
 
                           
Futures Nymex
  Gas     10,057,500       2004-2005     $ (1,311 )
Futures Nymex
  Gas     12,677,500       2004-2005       2,941  
 
                         
 
                      $ 1,630  
                             
        Barrels                  
 
  Condensate                        
NGL Swaps
  Propane, Ethane     250,000       2004-2005     $ (86 )

Estimates related to the Partnership’s gas marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. The Partnership believes it is protected from the volatility in the energy commodities markets because it does not have unbalanced positions. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, will provide the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, will be offset with financial contracts to balance the Partnership’s positions.

Interest Rate Risk

The Partnership is exposed to market risk for changes in interest rates related to the bank credit facilities of ETC OLP. An interest rate swap agreement is used to manage a portion of the exposure related to ETC OLP’s Term Loan Facility to changing interest rates by converting floating rate debt to fixed-rate debt. On October 9, 2002, ETC OLP entered into an interest rate swap agreement to manage its exposure to changes in interest rates. The interest rate swap has a notional value of $75,000 and matures on October 9, 2005. Under the terms of the interest rate swap agreement, the Partnership will pay a fixed rate of 2.76% and will receive three-month LIBOR with quarterly settlement commencing on January 9, 2003. The value of the interest rate swap is marked to market and recorded in interest expense. The value of the interest rate swap at November 30, 2004 and August 31, 2004 was a liability of

19


Table of Contents

$38 and $539, respectively, and was recorded as a component of price risk management liabilities on the Partnership’s consolidated balance sheets.

The following represents gain (loss) on derivative activity for the periods presented:

                 
    Three Months Ended  
    November 30,  
    2004     2003  
            (Energy Transfer  
            Company)  
Unrealized loss recognized in cost of products sold related to Partnership’s derivative activity
  $ (8,903 )   $ (998 )
Realized gain included in cost of products sold
  $ 12,536     $ 4,479  
Unrealized gain (loss) on interest rate swap included in interest expense
  $ 502     $ (121 )
Realized loss on interest rate swap included in interest expense
  $ (233 )   $ (316 )

15. QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH:

The Partnership Agreement requires that the Partnership will distribute all of its Available Cash to its Unitholders and its General Partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of Incentive Distribution Rights to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of the Partnership, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by the General Partner in its sole discretion to provide for the proper conduct of the Partnership’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in the Partnership Agreement.

Distributions by the Partnership in an amount equal to 100% of Available Cash will generally be made 98% to the Common and Class E Unitholders and 2% to the General Partner, subject to the payment of incentive distributions to the General Partner to the extent that certain target levels of cash distributions are achieved.

On October 15, 2004, the Partnership paid a quarterly distribution of $0.825 per unit, or $3.30 per unit annually, to the Unitholders of record at the close of business on October 7, 2004. On December 15, 2004, the Partnership declared a cash distribution for the first quarter ended November 30, 2004 of $0.875 per unit, or $3.50 per unit annually, payable on January 14, 2005 to Unitholders of record at the close of business on January 5, 2005. In addition to these quarterly distributions, the General Partner received quarterly distributions for its general partner interest in the Partnership, and incentive distributions to the extent the quarterly distribution exceeded $0.55 per unit. The total amount of distributions declared relating to the quarter ended November 30, 2004 on Common Units, the Class E, the General Partner interests and the Incentive Distribution Rights totaled $39,061, $3,121, $973, and $5,477, respectively. All such distributions were made from Available Cash from Operating Surplus.

16. RELATED PARTY TRANSACTIONS:

Accounts payable to related companies as of November 30, 2004 and August 31, 2004 included $2,856 due to La Grange Energy. This amount represents the balance of funds due to La Grange Energy subject to final settlement of the Energy Transfer Transactions that have not yet been distributed.

Accounts payable to related companies as of November 30, 2004 and August 31, 2004 also included approximately $800 and $1,400, respectively, payable to unconsolidated affiliates for purchases of natural gas and operating expenses incurred in the normal course of business.

The Partnership’s natural gas midstream operations secure compression services from third parties. Energy Transfer Technologies, Ltd. is one of the entities from which compression services are obtained. Energy Transfer Group,

20


Table of Contents

LLC is the general partner of Energy Transfer Technologies, Ltd. These entities are collectively referred to as the “ETG Entities”. The ETG Entities were not acquired by the Partnership in conjunction with the January 2004 Energy Transfer Transactions. The Partnership’s Co-Chief Executive Officers have an indirect ownership in the ETG Entities. In addition, two of the General Partner’s directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of management, no less favorable than those available from other providers of compression services. For the three months ending November 30, 2004, payments totaling $370 were made to the ETG Entities for compression services provided to and utilized in the Partnership’s natural gas midstream operations.

One of the Partnership’s natural gas midstream subsidiaries owns a 50% interest in South Texas Gas Gathering, a joint venture that owns an 80% interest in the Dorado System, a 61-mile gathering system located in South Texas. The other 50% equity interest in South Texas Gas Gathering is owned by one of the General Partner’s directors. The Partnership is the operator of the Dorado System. At November 30, 2004 and August 31, 2004, there was a balance of $248 owing to the Partnership by a director of the General Partner for services the Partnership provided as operator.

17. REPORTABLE SEGMENTS:

The Partnership’s financial statements reflect five reportable segments: ETC OLP’s midstream and transportation operations, HOLP’s retail and domestic wholesale propane operations, and the foreign wholesale propane operations of MP Energy Partnership. Segments below the quantitative thresholds are classified as “other”. None of these segments has ever met any of the quantitative thresholds for determining reportable segments. The operations which focus on the gathering, compression, treating, processing, transportation and marketing of natural gas, primarily at the Southeast Texas System and Elk City Systems, generate revenue primarily by the volumes of natural gas gathered, compressed, treated, processed, transported, purchased and sold through the Partnership’s pipeline (excluding the transportation pipelines) and gathering systems and the level of natural gas and NGL prices. The transportation operations focus on transporting natural gas through the Partnership’s Oasis Pipeline ET Fuel System and East Texas Pipeline System. Revenue is generated from fees charged to customers to reserve firm capacity on or move gas on the pipeline on an interruptible basis. The fee structure on the Oasis Pipe Line is derived from the gas price differential between the Waha and Katy hubs. A monetary fee, and/or fuel retention are components of the fee structure. Excess fuel retained after consumption is valued at the first of the month Katy tailgate price and strategically sold when market prices are high.

The Partnership’s retail and wholesale propane segments sell products and services to retail and wholesale customers. Intersegment sales by the foreign wholesale segment to the domestic segment are priced in accordance with the partnership agreement of MP Energy Partnership. The Partnership manages its propane segments separately as each segment involves different distribution, sale, and marketing strategies. The Partnership evaluates the performance of its operating segments based on operating income exclusive of general partnership selling, general, and administrative expenses of $1,115 and $0 for the three months ended November 30, 2004 and 2003, respectively. Investment in affiliates and equity in earnings (losses) of affiliates relates primarily to the Partnership’s investment in Vantex Gas Pipeline Company and Vantex Energy Services, Ltd, and is part of the midstream segment. In addition, the Partnership’s two largest customers’ revenues are included in the midstream segment’s revenues. The following table presents the unaudited financial information by segment for the following periods:

21


Table of Contents

                         
    For the Three Months Ended  
    November 30,  
    2004     2003     2003  
            (Energy Transfer     (Heritage)  
            Company)        
Volumes:
                       
Midstream
                       
Natural gas MMBtu/d
    1,265,341       923,308        
NGLs bbls/d
    15,353       15,109        
Transportation
                       
Natural gas MMBtu/d
    2,400,989       910,216        
 
                       
Propane gallons
                       
(in thousands)
                       
Retail
    86,435             78,641  
Domestic wholesale
    3,916             3,294  
Foreign wholesale
                       
Affiliated
    22,977             20,947  
Unaffiliated
    14,393             12,169  
Elimination
    (22,977 )           (20,947 )
 
                 
Total gallons
    104,744             94,104  
 
                 
 
                       
Revenues:
                       
Midstream
  $ 691,089     $ 409,409     $  
Transportation
    46,061       9,688        
Retail propane and other propane related
    150,765             112,376  
Domestic wholesale propane
    4,010             2,287  
Foreign wholesale propane
                       
Affiliated
    21,630             13,973  
Unaffiliated
    14,475             8,055  
Eliminations
    (21,630 )           (13,973 )
Other
    1,262             1,008  
 
                 
Total
  $ 907,662     $ 419,097     $ 123,726  
 
                 
 
                       
Cost of Sales:
                       
Midstream
  $ 648,960     $ 381,177     $  
Transportation
    10,620       504        
Retail propane and other propane related
    88,139             56,594  
Domestic wholesale propane
    3,799             2,098  
Foreign wholesale propane
    13,694             7,403  
Other
    358             275  
 
                 
Total
  $ 765,570     $ 381,681     $ 66,370  
 
                 
 
                       
Operating Income:
                       
Midstream
  $ 28,435     $ 18,569     $  
Transportation
    17,672       2,435        
Retail propane and other propane related
    4,350             7,082  
Domestic wholesale propane
    (644 )           (516 )
Foreign wholesale propane
                       
Affiliated
    193             153  
Unaffiliated
    429             372  
Elimination
    (193 )           (153 )
Other
    (75 )           (229 )
Selling general and administrative expenses not allocated to segments
    (1,115 )            
 
                 
Total
  $ 49,052     $ 21,004     $ 6,709  
 
                 

22


Table of Contents

                         
    For the Three Months Ended  
    November 30,  
    2004     2003     2003  
            (Energy Transfer     (Heritage)  
            Company)        
Gain (Loss) on Disposal of Assets:
                       
 
Midstream
  $ 1     $     $  
Transportation
    (17 )            
Retail propane
    (84 )           162  
Domestic wholesale propane
    6             11  
Other
    3              
 
                 
Total
  $ (91 )   $     $ 173  
 
                 
 
                       
Minority Interest Expense:
                       
Other
  $     $     $ (13 )
Foreign wholesale propane
    158             148  
 
                 
Total
  $ 158     $     $ 135  
 
                 
 
                       
Depreciation and Amortization:
                       
Midstream
  $ 3,502     $ 3,091     $  
Transportation
    3,442       1,056        
Retail propane
    13,061             9,196  
Domestic wholesale propane
    162             108  
Foreign wholesale propane
    7             6  
Other
    95             105  
 
                 
Total
  $ 20,269     $ 4,147     $ 9,415  
 
                 
 
                       
Interest Expense:
                       
Midstream
  $ 9,657     $ 3,388     $  
Transportation
    46       446        
Retail propane
    7,628             8,166  
 
                 
Total
  $ 17,331     $ 3,834     $ 8,166  
 
                 
 
                       
Earnings from Equity Investments:
                       
Midstream
  $ 14     $ 147     $  
Foreign wholesale
    22             219  
 
                 
Total
  $ 36     $ 147     $ 219  
 
                 
 
                       
Income Tax Expense (Benefit):
                       
Midstream
  $ 32     $     $  
Transportation
    (90 )     1,709        
Other
    1,090             50  
 
                 
Total
  $ 1,032     $ 1,709     $ 50  
 
                 
 
    November 30,     August 31,          
    2004     2004          
Total Assets:
                       
Midstream
  $ 837,476     $ 519,543          
Transportation
    624,007       785,754          
Retail propane and other propane related
    996,307       956,021          
Domestic wholesale propane
    16,603       12,567          
Foreign wholesale propane
    15,583       10,034          
Other
    25,018       43,186          
 
                   
Total
  $ 2,514,994     $ 2,327,105          
 
                   

23


Table of Contents

                         
    For the Three Months Ended  
    November 30,  
    2004     2003     2003  
            (Energy Transfer     (Heritage)  
            Company)        
Additions to Property, Plant and Equipment Including Acquisitions:
                       
Midstream
  $ 70,777     $ 11,553     $  
Transportation
    24,915       277        
Retail propane
    15,400             16,970  
Domestic wholesale propane
    138             106  
Foreign wholesale propane
                 
Corporate
    2,642              
 
                 
Total
  $ 113,872     $ 11,830     $ 17,076  
 
                 

24


Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Energy Transfer Partners, L.P. (the “Registrant” or “Partnership”), is a Delaware limited partnership. The Partnership’s Common Units are listed on the New York Stock Exchange under the symbol “ETP”. Our business activities are primarily conducted through our subsidiaries, ETC OLP, a Texas limited partnership, and HOLP, a Delaware limited partnership (the “Operating Partnerships”). References to “we,” “us,” “our,” or the “Partnership” are intended to mean Energy Transfer Partners, L.P., our operating limited partnerships and subsidiaries. The business of Heritage Propane Partners, L.P. and Heritage Operating, L.P. prior to the Energy Transfer Transactions in January 2004, is referred to as Heritage. The Partnership and the Operating Partnerships are sometimes referred to collectively in this report as “Energy Transfer.”

The following is a discussion of the historical financial condition and results of operations of the Partnership and its subsidiaries, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q.

Energy Transfer Transactions

On January 20, 2004, Heritage Propane Partners, L.P., (“Heritage”) and La Grange Energy, L.P. (“La Grange Energy”) completed the series of transactions whereby La Grange Energy contributed its subsidiary, La Grange Acquisition, L.P. and its subsidiaries and affiliates who conduct business under the assumed name of Energy Transfer Company, (“ETC OLP”) to Heritage. Simultaneously, La Grange Energy acquired U.S. Propane and Limited Partner Units, Class D Units and Special Units of Heritage, thereby gaining control of Heritage. Simultaneous with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“Heritage Holdings”) from U.S. Propane, L.P.

General

The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations” (SFAS 141). Although Heritage was the surviving parent entity for legal purposes, ETC OLP was the acquiror for accounting purposes. As a result, ETC OLP’s historical financial statements are the historical financial statements of the registrant.

Overview

     Midstream and transportation segments

ETC OLP’s operations are divided into two business segments, consisting of the midstream segment and the transportation segment. We own an interest in and operate approximately 7,750 miles of natural gas gathering and transportation pipelines, four natural gas processing plants connected to our gathering systems with a total processing capacity of 470 MMcf/d, thirteen natural gas treating facilities with a total treating capacity of 1,050 MMcf/d and two natural gas storage facilities with a total storage capacity of 14.0 Bcf. Our midstream segment focuses on the gathering, compression, treating, blending, processing and marketing of natural gas and is currently concentrated in the Austin Chalk trend of southeast Texas, the Anadarko Basin of western Oklahoma, the Permian Basin of west Texas, the Bossier sands area in east Texas and the Fort Worth Basin in north Texas. Our transportation segment focuses on the transportation of natural gas between major markets from various natural gas producing areas through connections with other pipeline systems as well as through our Oasis Pipeline, East Texas Pipeline System and ET Fuel System.

Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate our midstream revenues and gross margins principally under fee-based arrangements or other arrangements. Under fee-based arrangements, we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue we earn from these arrangements is directly related to the volume of natural gas that flows through its systems and is not directly dependent on commodity prices.

We also utilize other types of arrangements in the midstream segment, including (i) discount-to-index price

25


Table of Contents

arrangements which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, selling the resulting residue gas and NGL volumes at market prices and remitting to producers an agreed-upon percentage of the proceeds based on an index price, and (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based upon gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. The contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

We conduct our marketing operations through our producer services business, in which we market the natural gas that flows through our assets, which we refer to as on-system gas, and attracts other customers by marketing volumes of natural gas that do not move through our assets, which we refer to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

Results from our transportation segment are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through our transportation pipelines. Under transportation contracts, we charge our customers (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay us even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, and (iii) a fuel retention based on a percentage of gas transported on the pipeline, or a combination of the three, generally payable monthly.

     Retail and Wholesale Propane segments

Our propane related segments are operated by HOLP and its subsidiaries who are engaged in the sale, distribution and marketing of propane and other related products through its retail, domestic wholesale and foreign wholesale propane segments, (the propane segments) and also through the liquids marketing activity of Heritage Energy Resources. HOLP derives its revenue primarily from the retail propane segment. We believe that Heritage was, and we are now, the fourth largest retail marketer of propane in the United States, based on retail gallons sold. We serve more than 650,000 propane customers from 310 customer service locations in 32 states.

The propane segments are margin-based businesses in which gross profits depend on the excess of sales price over propane supply cost. The market price of propane is often subject to volatile changes as a result of supply or other market conditions over which we will have no control. Product supply contracts are one-year agreements subject to annual renewal and generally permit suppliers to charge posted prices (plus transportation costs) at the time of delivery or the current prices established at major delivery points. Since rapid increases in the wholesale cost of propane may not be immediately passed on to retail customers, such increases could reduce gross profits. We generally have attempted to reduce price risk by purchasing propane on a short-term basis. We have on occasion purchased significant volumes of propane during periods of low demand, which generally occur during the summer months, at the then current market price, for storage both at our customer service locations and in major storage facilities for future resale.

Our retail propane business consists principally of transporting propane purchased in the contract and spot markets, primarily from major fuel suppliers, to our customer service locations and then to propane tanks located on the customers’ premises, as well as to portable propane cylinders. In the residential and commercial markets, propane is primarily used for space heating, water heating, and cooking. In the agricultural market, propane is primarily used for crop drying, tobacco curing, poultry brooding, and weed control. In addition, propane is used for certain industrial applications, including use as an engine fuel to power vehicles and forklifts and as a heating source in manufacturing and mining processes.

Since the formation of the Partnership, we have grown primarily through acquisitions of retail propane operations and, to a lesser extent, through internal growth. Since its inception through January 19, 2004, The Partnership completed 103 propane acquisitions for an aggregate purchase price approximating $720 million. Since the Energy Transfer Transactions on January 20, 2004 through August 31, 2004, we have completed three additional retail

26


Table of Contents

propane acquisitions. During the three months ended November 30, 2004, we completed two additional retail propane acquisitions.

Our propane distribution business is largely seasonal and dependent upon weather conditions in our service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements. Historically, approximately two-thirds of Heritage’s retail propane volume and in excess of 80% of Heritage’s EBITDA, as adjusted, is attributable to sales during the six-month peak-heating season of October through March. This generally results in higher operating revenues and net income in the propane segments during the period from October through March of each year, and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Consequently, sales and operating profits for the propane segments are concentrated in the first and second fiscal quarters, however, cash flow from operations is generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the six-month peak-heating season. Sales to industrial and agricultural customers are much less weather sensitive.

A substantial portion of our propane is used in the heating-sensitive residential and commercial markets causing the temperatures realized in our areas of operations, particularly during the six-month peak-heating season, to have a significant effect on the financial performance in our propane operations. In any given area, sustained warmer-than-normal temperatures will tend to result in reduced propane use, while sustained colder-than-normal temperatures will tend to result in greater propane use. We use information on normal temperatures in understanding how temperatures that are colder or warmer than normal affect historical results of operations and in preparing forecasts related to our future operations.

The retail propane segment’s gross profit margins are not only affected by weather patterns, but also vary according to customer mix. Sales to residential customers generate higher margins than sales to certain other customer groups, such as commercial or agricultural customers. Wholesale propane segment’s margins are substantially lower than retail margins. In addition, propane gross profit margins vary by geographical region. Accordingly, a change in customer or geographic mix can affect propane gross profit without necessarily affecting total revenues.

Amounts discussed below reflect 100% of the results of MP Energy Partnership (the foreign wholesale propane segment). MP Energy Partnership is a Canadian general partnership in which HOLP owns a 60% interest. Because MP Energy Partnership is primarily engaged in lower-margin wholesale distribution, its contribution to our net income is not significant and the minority interest of this partnership is excluded from the EBITDA, as adjusted, calculation.

Analysis of Historical Results of Operations

The Energy Transfer Transactions affect the comparability of our financial statements for the three months ended November 30, 2004 to the three months ended November 30, 2003 because our consolidated financial statements for the three months ended November 30, 2003 reflect only the results of ETC OLP and its subsidiaries (see note 2 to the Partnership’s consolidated financial statements). The changes in the line items discussed below are a result of these transactions. The aggregate results disclosed below reflect Heritage’s historical results for the three months ended November 30, 2003 combined with the historical results of Energy Transfer Company for the three months ended November 30, 2003, and are presented for comparability purposes only. This aggregate information (i) is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations and (ii) is not a measure of performance calculated in accordance with generally accepted accounting principles.

In addition to the Energy Transfer Transactions, the acquisition of ET Fuel System affects the comparability of the historical results of operations in our transportation segment for the three months ended November 30, 2004 compared to the three months ended November 30, 2003. We acquired the ET Fuel System in June 2004; therefore, the results of operations for the three months ended November 30, 2003 do not reflect the impact of this acquisition.

Three Months Ended November 30, 2004 Compared to the Three Months Ended November 30, 2003

     Volume. Total volumes of natural gas sales, NGL sales including propane, and natural gas transported by our midstream, transportation, retail propane, domestic wholesale propane, and foreign wholesale propane segments for the three months ended November 30, 2004 and 2003 are as follows:

27


Table of Contents

                         
    Three Months Ended  
    November 30,  
    2004     2003     2003  
    (Actual)     (ETC OLP)     (Aggregate)  
Midstream
                       
Natural gas MMBtu/d
    1,265,341       923,308       923,308  
NGLs Bbls/d
    15,353       15,109       15,109  
Transportation
                       
Natural gas MMBtu/d
    2,400,989       910,216       910,216  
 
                       
Propane gallons
                       
(in thousands)
                       
Retail
    86,435             78,641  
Domestic wholesale
    3,916             3,294  
Foreign wholesale
    14,393             12,169  

Natural gas sales volumes were 1,265,341 MMBtu/d for the three months ended November 30, 2004 compared to 923,308 MMBtu/d for the three months ended November 30, 2003, an increase of 342,033 MMBtu/d or 37.0%. NGLs sales volumes were 15,353 Bbls/d/ and 15,109 Bbls/d/ for three months ended November 30, 2004 and 2003, respectively. The increased natural gas sales volumes are a result of our expanded marketing efforts, enhanced relationships with producers and expanded credit facilities with commodity counter parties. The increase was also attributable to the acquisition of the Texas Chalk and Madison Systems on November 1, 2004. As a result of this acquisition, the number of producing wells connected to our Southeast Texas System increased from approximately 1,050 wells to 2,000 wells. We expect the acquisition of these assets to continue to provide increased volumes in our midstream segment. Our sales volumes of NGLs vary due to our ability to by-pass our processing plants when conditions exist that make it less favorable to process and extract NGLs from our processing plants.

Transportation natural gas volumes increased by 1,490,773 MMBtu/d or 163.8% from 910,216 MMBtu/d for the three months ended November 30, 2003 to 2,400,989 MMBtu/d for the three months ended November 30, 2004. The increase in transportation volumes is principally due to the increased volumes experienced on our Oasis Pipeline as a result of favorable price differentials between the Waha market hub and the Katy market hub, the acquisition of the ET Fuel System in June 2004 which contributed approximately 967,000 MMBtu/d of natural gas during the three months ended November 30, 2004, and the completion of the Bossier Pipeline in June 2004. The East Texas Pipeline System, which includes the Bossier Pipeline, contributed approximately 239,000 MMBtu/d of natural gas during the three months ended November 30, 2004.

Total retail propane gallons sold in the three months ended November 30, 2004 were 86.4 million gallons, with no retail propane gallons reflected in the three months ended November 30, 2003. The difference in retail gallons sold is due to the fact that the Energy Transfer Transactions described above resulted in reverse acquisition accounting, and ETC OLP had no propane operations. We also sold 3.9 million and 14.4 million domestic and foreign wholesale propane gallons, respectively, in the three months ended November 30, 2004, with no domestic or foreign wholesale propane gallons reflected for the three months ended November 30, 2003. As a comparison, Heritage reflected volumes of 78.6 million retail propane gallons for the three months ended November 30, 2003. Of the 7.8 million gallon aggregate increase, 7.4 million gallons are the result of volumes sold by customer service locations added through acquisitions, and 0.4 million gallons were weather related. We experienced temperatures that were slightly colder in the three months ended November 30, 2004 compared to the same three-month period in the previous year. Also, as a comparison, Heritage reflected volumes of 3.3 million and 12.2 million domestic wholesale and foreign wholesale propane gallons, respectively, for the fiscal three months ended November 30, 2003. The 0.6 million gallon increase in domestic wholesale propane gallons is primarily due to customers added from the acquisition of Bi-State Propane in December 2003 and other customers turning to propane when diesel prices rose, and the 2.2 million gallon increase in foreign wholesale volumes is due to increased marketing efforts in our foreign markets.

28


Table of Contents

Set forth in the table below is certain unaudited financial data for the periods presented.

                         
    Three Months Ended  
    November 30,  
    2004     2003     2003  
    (Actual)     (ETC OLP)     (Aggregate)  
Midstream Segment:
                       
Revenues
  $ 691,089     $ 409,409     $ 409,409  
Cost of sales
    648,960       381,177       381,177  
Operating expenses
    5,177       3,771       3,771  
Selling, general and administrative
    5,015       2,801       2,801  
Depreciation and amortization
    3,502       3,091       3,091  
 
                 
Segment operating income
  $ 28,435     $ 18,569     $ 18,569  
 
                       
Transportation Segment:
                       
Revenues
  $ 46,061     $ 9,688     $ 9,688  
Cost of sales
    10,620       504       504  
Operating expenses
    12,178       3,615       3,615  
Selling, general and administrative
    2,149       2,078       2,078  
Depreciation and amortization
    3,442       1,056       1,056  
 
                 
Segment operating income
  $ 17,672     $ 2,435     $ 2,435  
 
                       
Retail Propane Segment:
                       
Retail propane revenues
  $ 132,748     $     $ 94,388  
Other propane related revenues
    18,017             17,988  
Retail propane cost of sales
    82,175             51,322  
Other propane related cost of sales
    5,964             5,272  
Operating expenses
    42,529             36,589  
Selling, general and administrative
    2,686             2,916  
Depreciation and amortization
    13,061             9,195  
 
                 
Segment operating income
  $ 4,350     $     $ 7,082  
 
                       
Domestic Wholesale Propane Segment:
                       
Revenues
  $ 4,010     $     $ 2,287  
Cost of sales
    3,799             2,098  
Operating expenses
    693             597  
Depreciation and amortization
    162             108  
 
                 
Segment operating loss
  $ (644 )   $     $ (516 )
 
                       
Foreign Wholesale Segment:
                       
Revenues
  $ 14,475     $     $ 8,055  
Cost of sales
    13,694             7,403  
Selling, general and administrative
    345             274  
Depreciation and amortization
    7             6  
 
                 
Segment operating income
  $ 429     $     $ 372  
 
                       
Other
                       
Revenue
  $ 1,262     $     $ 1,008  
Cost of sales
    358             275  
Operating expenses
    884             856  
Depreciation and amortization
    95             106  
 
                 
Other operating income
  $ (75 )   $       $ (229 )
 
                       
Unallocated selling, general and administrative expenses
  $ 1,115     $     $  

29


Table of Contents

                         
    Three Months Ended  
    November 30,  
    2004     2003     2003  
    (Actual)     (ETC OLP)     (Aggregate)  
Consolidated Information:
                       
Revenues
  $ 907,662     $ 419,097     $ 542,823  
Cost of sales
    765,570       381,681       448,051  
 
                 
Gross profit
    142,092       37,416       94,772  
Operating expenses
    61,461       7,386       45,428  
Selling, general and administrative
    11,310       4,879       8,069  
Depreciation and amortization
    20,269       4,147       13,562  
 
                 
Consolidated operating income
  $ 49,052     $ 21,004     $ 27,713  
Equity in earnings of affiliates
    36       147       366  
Interest expense
    17,331       3,834       12,000  
Gain (loss) on disposal of assets
    (91 )           173  
Interest income and other
    134       86       40  
Minority interests
    (158 )           (135 )
Income tax expense
    1,032       1,709       1,759  
 
                 
Net income
  $ 30,610     $ 15,694     $ 14,398  
 
                 

Revenues. Total revenues were $907.7 million for the three months ended November 30, 2004 compared to $419.1 million for the three months ended November 30, 2003. The aggregate revenues for the three months ended November 30, 2003 would have been $542.8 million.

Total midstream and transportation revenues were $737.2 million for the three months ended November 30, 2004 compared to $419.1 million for the three months ended November 30, 2003, an increase of $318.1 million or 75.9%. Midstream revenues increased $281.7 million or 68.8% from $409.4 million for the three months ended November 30, 2003 to $691.1 million for the three months ended November 30, 2004. As noted above, the increases are principally attributable to expanding our producer services activities, increases in sales volumes during the three months ended November 30, 2004 compared to the same period in the previous year as noted above, and additional volumes resulting from the acquisition of the Texas Chalk and Madison Systems on November 1, 2004.

Midstream segment revenues also increased due to an increase in natural gas sales prices. Our average natural gas sales prices were $5.49 per MMBtu for the three months ended November 30, 2004 compared to $4.40 per MMBtu for the three months ended November 30, 2003, an increase of $1.09 per MMBtu or 24.8%. Average NGLs sales prices also increased by $0.30 or 62.5% from $0.48 per gallon for the three months ended November 30, 2003 compared to $0.78 per gallon for the three months ended November 30, 2004. The market price for NGLs tends to correlate with the price of crude oil.

Transportation revenues were $46.1 million for the three months ended November 30, 2004 compared to $9.7 million for the three months ended November 30, 2003, an increase of $36.4 million. The increase in transportation revenues is principally due to the following:

•   Increased volumes and average rates on our Oasis Pipeline. Volumes increased 28.6% during the three months ended November 30, 2004 when compared to the same period in the previous year. The volume increase is a result of our decision to pursue additional volumes on the middle and west end of the system on the Oasis Pipeline and a wider basis differential between the Waha and Katy market hubs which provides an incentive to transport increased volumes of natural gas to a more attractive marketplace. The average differential for the three months ended November 30, 2004 was $0.31 compared to $0.12 for the three months ended November 30, 2003, an increase of $0.19 or 158.3%. Our average transportation rate on the Oasis Pipeline was $0.14 per MMBtu for the three months ended November 30, 2004 compared to $0.12 per MMBtu for the three months ended November 30, 2003, an increase of $0.02 per MMBtu or 16.7%.

•   ET Fuel System acquisition in June 2004. Revenues from the ET Fuel System for the three months ended November 30, 2004 were $14.6 million. In connection with our acquisition of the ET Fuel System, we entered an eight-year transportation agreement with TX Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115.6 MMBtu per year. We also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System. Approximately 29% of the revenues on the ET Fuel System were attributable to these three contracts.

•   Excess gas sales. The transportation segment generally retains a portion of each shipper’s gas to compensate for fuel used in operating the pipeline. The actual usage of gas can differ from the amounts retained from our customers. We recognized $25.3 million in revenues attributable to excess gas retained or sold during the three

30


Table of Contents

    months ended November 30, 2004 compared to $4.5 million for the three months ended November 30, 2003. The increase is principally due to the ET Fuel System acquisition and the Bossier Pipeline completed in June 2004 and operating efficiencies experienced in our Oasis Pipeline.

For the three months ended November 30, 2004, we had retail propane revenues of $132.7 million, domestic wholesale propane revenues of $4.0 million, foreign wholesale propane revenues of $14.5 million, other propane related revenues of $18.0 million, and other revenue of $1.3 million with no propane revenues reflected in the three months ended November 30, 2003. As a comparison, for the three months ended November 30, 2003, Heritage had retail propane revenues of $94.4 million. Of the $38.3 million increase from Heritage, $11.3 million is due to the increase in volumes sold by customer service locations added through acquisitions, $26.4 million is due to higher selling prices, and $0.6 million is due to the increase in weather related volumes described above. Heritage’s domestic wholesale propane revenues were $2.3 million for the three months ended November 30, 2003. Of the increase, $1.2 million is due to the increase in gallons described above, and a $0.5 million is related to higher selling prices for the three months ended November 30, 2004 compared to the same three month period for Heritage last year. Heritage’s foreign wholesale propane revenues were $8.0 million for the three months ended November 30, 2003. The increase in the three months ended November 30, 2004 is due to a $4.2 million increase related to higher selling prices and $2.3 million from the increase in volumes described above. Heritage’s other propane related revenues were $18.0 million for the three months ended November 30, 2003. Heritage’s other revenues were $1.0 for the three months ended November 30, 2003.

Costs of Sales. Total cost of products sold increased to $765.6 million for the three months ended November 30, 2004 as compared to $381.7 million for the three months ended November 30, 2003. Aggregate total cost of sales for the periods presented would have been $448.0 million for the three months ended November 30, 2003.

Total cost of sales for our midstream and transportation segments was $659.6 million for the three months ended November 30, 2004, compared to $381.7 million for the three months ended November 30, 2003, an increase of $277.9 million or 72.8%.

Midstream cost of sales was $649.0 million for the three months ended November 30, 2004 compared to $381.2 million for the three months ended November 30, 2003, an increase of $267.8 million or 70.3%. The increase was principally attributable to the increase in sales volumes and prices during the three months ended November 30, 2004 as discussed above. Transportation cost of sales was $10.6 million for the three months ended November 30, 2004 and $0.5 million for the three months ended November 30, 2003. Cost of sales activity is typically generated from the sale of excess inventory or the recognition, either positive or negative, of unaccounted fuel within the pipeline system.

For the three months ended November 30, 2004, we had retail propane cost of sales of $82.2 million, domestic wholesale propane cost of sales of $3.8 million, foreign wholesale propane cost of sales of $13.7 million, other propane related cost of sales of $6.0 million, and other cost of sales of $0.3 million with no propane cost of sales reflected in the three months ended November 30, 2003. As a comparison, for the three months ended November 30, 2003, aggregated retail propane cost of sales would have been $51.3. Of the $30.9 million aggregate increase from Heritage, $7.4 million reflects changes in volumes described above and $23.5 reflects the increase due to higher cost of fuel. Aggregate domestic wholesale propane cost of sales would have been $2.1 million for the three months ended November 30, 2003. The increase of $1.7 million is due to volume increases described above. Aggregate foreign wholesale propane cost of sales would have been $7.4 million for the three months ended November 30, 2003. Of the $6.3 million aggregate increase in foreign wholesale cost of sales, $4.2 million is related to higher selling prices and $2.1 million is due to volume increases described above. Aggregate other propane cost of sales would have been $5.3 million for the three months ended November 30, 2003. Aggregate other cost of sales would have been $0.3 million for the three months ended November 30, 2003.

Operating Expenses. Operating expenses increased $54.1 million to $61.5 million for the three months ended November 30, 2004 as compared to $7.4 million for the three months ended November 30, 2003. Aggregate total operating expenses for the periods presented would have been $45.4 million for the three months ended November 30, 2003.

Total midstream and transportation operating expenses were $17.4 million for the three months ended November 30, 2004 compared to $7.4 million for the three months ended November 30, 2003, an increase of $10.0 million.

31


Table of Contents

Midstream operating expenses increased $1.4 million from $3.8 million for the three months ended November 30, 2003 to $5.2 million for the three months ended November 30, 2004. The increase was principally attributable to $0.7 million in incremental operating expenses related to the Texas Chalk and Madison Systems acquisition and $0.7 is attributable to an increase in employee costs. Certain employee costs for the three months ended November 30, 2003 were capitalized as a result of significant capital projects taking place during that time period. There were fewer capital projects in the midstream segment during the three months ended November 30, 2004. Transportation operating expenses were $12.2 million for the three months ended November 30, 2004 compared to $3.6 million for the three months ended November 30, 2003, an increase of $8.6 million. The increase was principally attributable to $4.3 million in operating expenses related to the ET Fuel System that was acquired in June 2004, $1.5 million in operating expenses related to the East Texas Pipeline that was completed in June 2004 and an increase of $2.7 million in operating expenses related to the Oasis Pipeline principally due to increased gas consumption to transport natural gas through its pipelines..

Total operating expenses for the propane and other segments were $44.1 million for the three months ended November 30, 2004 compared to Heritage’s historical total operating expenses of $38.0 million for the three months ended November 30, 2003, or an increase of $6.1 million. Of this aggregate increase approximately $3.6 million related to employee related expenses due to an increase in our employee base from acquisitions and the remaining $2.5 million is primarily due to general increase in other expenses also from acquisitions and higher fuel costs to run our vehicles.

Selling, General and Administrative Expenses. Selling, general and administrative expenses were $11.3 million for the three months ended November 30, 2004 compared to $4.9 million for the three months ended November 30, 2003. Aggregate total selling, general, and administrative expenses for the periods presented, would have been $8.1 million for the three months ended November 30, 2004.

Total general and administrative operating expenses for our midstream and transportation segments were $7.2 million for the three months ended November 30, 2004 compared to $4.9 million for the three months ended November 30, 2003, an increase of $2.3 million or 46.9%. Midstream general and administrative expenses increased 78.6% or $2.2 million from $2.8 million for the three months ended November 30, 2003 to $5.0 million principally due to an increase in employee compensation costs. Higher incentive compensation expenses accounted for $1.4 million of the increase and the remaining $0.8 million was attributed to increased salaries and wages. Transportation general and administrative expenses remained flat at $2.1 million for the three months ended November 30, 2004 and 2003, respectively. A $0.3 million decrease in legal fees related to a lawsuit settled in January 2004 was offset by a $0.5 million increase in general and administrative expenses related to the ET Fuel System.

Selling, general and administrative expenses for our retail propane and foreign segments were $2.7 million and $0.3 million for the three months ended November 30, 2004, compared to aggregate retail propane and foreign selling, general and administrative expenses of $2.9 million and $0.3 million for the three months ended November 30, 2003, respectively. Selling, general and administrative expenses that related to the general operations of the Partnership are not allocated to our segments. The total unallocated selling, general, and administrative expenses were $1.1 million for the three months ended November 30, 2004 with no unallocated selling, general, and administrative expense for the three months ended November 30, 2003. The increase in unallocated selling, general, and administrative expenses is due to the expenses related to the general operations of the Partnership after the Energy Transfer Transactions.

Depreciation and Amortization. Depreciation and amortization expense for the three months ended November 30, 2004 was $20.3 million compared to $4.1 million for the three months ended November 30, 2003, an increase of $16.2 million. Of the increase $13.3 million is due to the Energy Transfer Transactions which includes additional depreciation and amortization as a result of the step-up of Heritage’s assets to fair value to the extent acquired by La Grange Energy in the Energy Transfer Transactions. Aggregate depreciation and amortization expense would have been $13.6 million for the three months ended November 30, 2003.

Midstream depreciation and amortization was $3.5 million for the three months ended November 30, 2004 compared to $3.1 million for the three months ended November 30, 2003, an increase of $0.4 million or 13.3%. The increase was principally due to the Texas Chalk and Madison Systems acquisition. Transportation depreciation and amortization increased $2.3 million from $1.1 million for the three months ended November 30, 2003 to $3.4 million for the three months ended November 30, 2004. The increase was principally attributable to the acquisition of the ET Fuel System and the completion of the Bossier Pipeline in June 2004. Depreciation in our propane and

32


Table of Contents

other segments was $13.3 million for the three months ended November 30, 2004 compared to aggregate depreciation of $9.4 million for the three months ended November 30, 2003. The aggregate increase of $3.9 million is due primarily to the increase in depreciation of assets added through acquisitions and the additional depreciation of the assets stepped up to fair market value as a result of the Energy Transfer Transactions.

Operating Income. For the three months ended November 30, 2004, we had operating income of $49.1 million as compared to operating income of $21.0 million for the three months ended November 30, 2003. This increase is primarily due to changes in revenues and expenses described above. Aggregate total operating income for the three months ended November 30, 2003 would have been $27.7 million.

Equity in Earnings of Affiliates. Equity in earnings of affiliates was $0.04 million for the three months ended November 30, 2003 compared to $0.1 million for the three months ended November 30, 2004.

Interest Expense. Interest expense was $17.3 million for the three months ended November 30, 2004 as compared to $3.8 million for the three months ended November 30, 2003. Of this increase, $7.6 million is related to the interest expense of HOLP after the Energy Transfer Transactions and $5.9 million is the result of additional interest in our midstream and transportation segments due to the Energy Transfer Transactions and the acquisition of ET Fuel System in June 2004. This increase includes interest expense on $8.2 million in deferred financing costs related to the Energy Transfer Transactions and the ET Fuel System acquisition, which we are amortizing on a straight-line basis over the remaining term of the related credit facility.

Income Tax Expense. Income tax expense was $1.0 million for the three months ended November 30, 2004 compared to $1.7 million for the three months ended November 30, 2003. As a partnership, we are not subject to income taxes. However, Oasis Pipeline, Heritage Service Company, and Heritage Holdings, wholly-owned subsidiaries, are corporations that are subject to income taxes. The decrease in income taxes is due to lower taxable income in Oasis Pipeline partially offset by the increase from the income taxes in Heritage Holdings after the Energy Transfer Transactions.

Net Income. Net income for the three months ended November 30, 2004 was $30.6 million for the three months ended November 30, 2004 compared to $15.7 million for the three months ended November 30, 2003. The effect of the Energy Transactions described above, together with the increase in acquisition related income, attributed to this increase.

EBITDA, as adjusted. EBITDA, as adjusted, increased $44.3 million to $69.7 million for the three months ended November 30, 2004 as compared to EBITDA, as adjusted, of $25.4 million for the three months ended November 30, 2003. This increase is due to the Energy Transfer Transactions and operating performance results described above. Aggregate total EBITDA, as adjusted, for the three months ended November 30, 2003, would have been $41.9 EBITDA, as adjusted, and is computed as follows:

                         
    Three months Ended  
    November 30,  
    2004     2003     2003  
    (Actual)     (ETC OLP)     (Heritage)  
Net income reconciliation
                       
Net income (loss)
  $ 30,610     $ 15,694     $ (1,296 )
Depreciation and amortization
    20,269       4,147       9,415  
Interest expense
    17,331       3,834       8,166  
Income taxes
    1,032       1,709       50  
Non-cash compensation expense
    402             90  
Interest (income) and other
    (134 )     (86 )     46  
Depreciation, amortization, and interest of investee
    105       109       234  
Minority interests in Operating Partnership
                (27 )
(Gain) loss on disposal of assets
    91             (173 )
 
                 
EBITDA, as adjusted (a)
  $ 69,706     $ 25,407     $ 16,505  
 
                 
Heritage EBITDA, as adjusted
  $     $ 16,505          
 
                   
Aggregate EBITDA, as adjusted (b)
  $ 69,706     $ 41,912          
 
                   

33


Table of Contents

(a)   EBITDA, as adjusted, is defined as the Partnership’s earnings before interest, taxes, depreciation, amortization and other non-cash items, such as compensation charges for unit issuances to employees, gain or loss on disposal of assets, and other expenses. We present EBITDA, as adjusted, on a Partnership basis, which includes both the general and limited partner interests. Non-cash compensation expense represents charges for the value of the Common Units awarded under the Partnership’s compensation plans that have not yet vested under the terms of those plans and are charges which do not, or will not, require cash settlement. Non-cash income or loss such as the gain or loss arising from our disposal of assets is not included when determining EBITDA, as adjusted. EBITDA, as adjusted, (i) is not a measure of performance calculated in accordance with generally accepted accounting principles and (ii) should not be considered in isolation or as a substitute for net income, income from operations or cash flow as reflected in our consolidated financial statements.
 
    EBITDA, as adjusted, is presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of our fundamental business activities. Management believes that the presentation of EBITDA, as adjusted, is useful to lenders and investors because of its use in the natural gas and propane industries and for master limited partnerships as an indicator of the strength and performance of the Partnership’s ongoing business operations, including the ability to fund capital expenditures, service debt and pay distributions. Additionally, management believes that EBITDA, as adjusted, provides additional and useful information to our investors for trending, analyzing and benchmarking the operating results of our partnership from period to period as compared to other companies that may have different financing and capital structures. The presentation of EBITDA, as adjusted, allows investors to view our performance in a manner similar to the methods used by management and provides additional insight to our operating results.
 
    EBITDA, as adjusted, is used by management to determine our operating performance, and along with other data as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. We have a large number of business locations located in different regions of the United States. EBITDA, as adjusted, can be a meaningful measure of financial performance because it excludes factors which are outside the control of the employees responsible for operating and managing the business locations, and provides information management can use to evaluate the performance of the business locations, or the region where they are located, and the employees responsible for operating them. To present EBITDA, as adjusted, on a full Partnership basis, we add back the minority interest of the general partner because net income is reported net of the general partner’s minority interest. Our EBITDA, as adjusted, includes non-cash compensation expense which is a non-cash expense item resulting from our unit based compensation plans that does not require cash settlement and is not considered during management’s assessment of the operating results of the our business. By adding these non-cash compensation expenses in EBITDA, as adjusted, allows management to compare our operating results to those of other companies in the same industry who may have compensation plans with levels and values of annual grants that are different than ours. Other expenses include other finance charges and other asset non-cash impairment charges that are reflected in our operating results but are not classified in interest, depreciation and amortization. We do not include gain or loss on the sale of assets when determining EBITDA, as adjusted, since including non-cash income or loss resulting from the sale of assets increases/decreases the performance measure in a manner that is not related to the true operating results of our business. In addition, our debt agreements contain financial covenants based on EBITDA, as adjusted. For a description of these covenants, please read — Financing and Sources of Liquidity in this Form 10-Q.
 
    There are material limitations to using a measure such as EBITDA, as adjusted, including the difficulty associated with using it as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss. In addition, our calculation of EBITDA, as adjusted, may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP. EBITDA, as adjusted, for the periods described herein is calculated in the same manner as presented by us and Heritage in the past. Management compensates for these limitations by considering EBITDA, as adjusted in conjunction with its analysis of other GAAP financial measures, such as gross profit, net income (loss), and cash flow from operating activities.

34


Table of Contents

(b)   The following reconciliation of Aggregate EBITDA, as adjusted to net income is presented for comparability purposes only, and is comprised of the aggregate of Energy Transfer Company and Heritage’s historical results for the period from September 1, 2003 to November 30, 2003.

         
    Three Months  
    Ended  
    November 30,  
    2003  
    (Aggregate)  
Net income reconciliation
       
 
       
Net income
  $ 14,398  
Depreciation and amortization
    13,562  
Interest expense
    12,000  
Income taxes
    1,759  
Non-cash compensation expense
    90  
Interest (income) and other
    (40 )
Depreciation, amortization, and interest of investee
    343  
Minority interests in Operating Partnership
    (27 )
Gain on disposal of assets
    (173 )
 
     
Aggregate EBITDA, as adjusted (a)
  $ 41,912  
 
     

Liquidity and Capital Resources

Our ability to satisfy our obligations will depend on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.

     Future capital requirements of our business will generally consist of:

  •   maintenance capital expenditures which includes capital expenditures made to connect additional wells to our natural gas systems in order to maintain or increase throughput on existing assets, and capital expenditures to extend the useful lives of our propane assets in order to sustain our operations, including vehicle replacements on our propane vehicle fleet;
 
  •   growth capital expenditures, mainly for customer propane tanks and for constructing new pipelines, processing plants and treating plants; and
 
  •   acquisition capital expenditures including acquisition of new pipeline systems and propane operations.

We believe that cash generated from the operations of our businesses will be sufficient to meet anticipated maintenance capital expenditures. We will initially finance all capital requirements by cash flows from operating activities. To the extent that our future capital requirements exceed cash flows from operating activities:

  •   maintenance capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities described below, which will be repaid by subsequent season reductions in inventory and accounts receivable:
 
  •   growth capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities; and
 
  •   acquisition capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities, other lines of credit, long-term debt, the issuance of additional Common Units or a combination thereof.

35


Table of Contents

The assets utilized in our propane operations do not typically require lengthy manufacturing process time or complicated, high technology components. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our propane business. In addition, we do not experience any significant increases attributable to inflation in the cost of these assets or in our propane operations. The assets used in our midstream and transportation segments, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures other than new well connects.

Operating Activities. Cash provided by operating activities during the three months ended November 30, 2004, was $56.6 million as compared to cash used in operating activities of $9.8 million for the three months ended November 30, 2003. The net cash provided by operations for the three months ended November 30, 2004 consisted of net income of $30.6 million, adjusted for non-cash charges of $20.5 million, principally depreciation and amortization, and an increase in working capital of $5.5 million. Various components of working capital changed significantly from the prior period due to factors such as the variance in the timing of accounts receivable collections, payments on accounts payable, deposits paid and received, and purchase of inventories related to the propane operations.

Investing Activities. Cash used in investing activities during the three months ended November 30, 2004 of $109.4 million is comprised of cash paid for acquisitions of $67.3 million and $43.4 million invested for maintenance and growth capital expenditures needed to sustain operations at current levels and to support growth of operations. Cash used in investing activities also includes proceeds from the sale of idle property of $1.3 million. The cash paid for acquisitions included $2.6 million expended for retail propane acquisitions, and $64.7 million expended for certain assets from Devon. In addition to cash paid for acquisitions, we issued Common Units valued at $2.5 million, incurred debt of $0.9 million for non-compete agreements and other long term debt, and assumed $0.4 of liabilities in connection with the retail propane acquisitions.

Financing Activities. Cash received from financing activities during the three months ended November 30, 2004 was $30.2 million. ETC OLP borrowed $60.0 million under its Revolving Credit Facility in November 2004 to partially fund the acquisition of the assets acquired from Devon. The net increase in HOLP’s Bank Facility was $11.4 million. This increase is normal and was used to fund inventory purchases and increased operating expenses related to the beginning of heating season. Cash received from financing activities is reduced by the distributions we paid to our Common Unitholders and the General Partner’s 2% interest of $41.0 million, and other financing costs of $0.2 million.

Financing and Sources of Liquidity

We maintain separate credit facilities for each of ETC OLP and HOLP. Each credit facility is secured only by the assets of the Operating Partnership that it finances, and neither Operating Partnership nor its subsidiaries will guarantee the debt of the other Operating Partnership.

Energy Transfer Facilities

ETC OLP has a $725.0 million Term Loan Facility that matures on January 18, 2008. Amounts borrowed under the ETC OLP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The Term Loan Facility is secured by substantially all of the ETC OLP’s assets. As of November 30, 2004, the Term Loan Facility had a balance of $725.0 million with a weighted average interest rate of 5.20%.

A $225.0 million Revolving Credit Facility is available through January 18, 2008. Amounts borrowed under the ETC OLP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The maximum commitment fee payable on the unused portion of the facility is 0.50%. The facility is fully secured by substantially all of ETC OLP’s assets. As of November 30, 2004, there was $60.0 million outstanding under the Revolving Credit Facility, and $1.1 million in letters of credit outstanding, which reduce the amount available for borrowing under the Revolving Credit Facility. The weighted average interest rate was 4.99% as of November 30, 2004. Letters of Credit under the Revolving Credit Facility may not exceed $40.0 million.

During the second quarter of our 2005 fiscal year, we expect to refinance our existing ETC OLP Credit Facility. We are currently in discussions with various financing sources with respect to the availability and terms of any such refinancing. We would expect any refinancing to increase our available credit, extend maturities and be on terms generally more favorable to us than the current ETC OLP Credit Facility. There can, however, be no assurance that we can successfully complete such refinancing on terms acceptable to us.

36


Table of Contents

HOLP Facilities

Effective March 31, 2004, HOLP entered into the Third Amended and Restated Credit Agreement, which includes a $75.0 million Senior Revolving Working Capital Facility available through December 31, 2006. Amounts borrowed under the Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 3.7119% for the amount outstanding at November 30, 2004. The maximum commitment fee payable on the unused portion of the facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10.0 million for a period of not less than 30 consecutive days at least one time during each fiscal year. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Working Capital Facility. As of November 30, 2004, the Senior Revolving Working Capital Facility had a balance outstanding of $43.1 million and $1.0 in outstanding letters of credit.

The Third Amended and Restated Credit Agreement also includes a $75.0 million Senior Revolving Acquisition Facility is available through December 31, 2006. Amounts borrowed under the Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 3.7119% for the amount outstanding at November 30, 2004. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Acquisition Facility. As of November 30, 2004, the Senior Revolving Acquisition Facility had a balance outstanding of $19.0 million.

Cash Distributions

We will use our cash provided by operating and financing activities from the Operating Partnerships to provide distributions to our Unitholders. Under the Partnership Agreement, we will distribute to our partners within 45 days after the end of each fiscal quarter, an amount equal to all of our Available Cash for such quarter. Available Cash generally means, with respect to any quarter of the Partnership, all cash on hand at the end of such quarter less the amount of cash reserves established by the General Partner in its reasonable discretion that is necessary or appropriate to provide for future cash requirements. Our commitment to our Unitholders is to distribute the increase in our cash flow while maintaining prudent reserves for the Partnership’s operations. On October 15, 2004, we paid a quarterly distribution of $0.825 per unit, or $3.30 per unit annually to Unitholders of record as of the close of business on October 7, 2004. This distribution represented an increase of $0.075 per unit (an annualized increase of $0.30 per unit) over the distribution paid for the third quarter of fiscal 2004. The current distribution includes incentive distributions payable to the General Partner to the extent the quarterly distribution exceeds $0.55 per unit (an annualized rate of $2.20).

New Accounting Standards

In October 2004, the Emerging Issues Task Force (EITF) reached a consensus on EITF No. 04-10, Determining Whether to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds (EITF 40-10). Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information (SFAS 131), requires that a public business enterprise report financial and descriptive information about its reportable operating segments. Operating segments are components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments. The issue addressed how an enterprise should evaluate the aggregation criteria in paragraph 17 of Statement 131 when determining whether operating segments that do not meet the quantitative thresholds may be aggregated in accordance with paragraph 19 of Statement 131. EITF 04-10 was effective for fiscal years ending after October 13, 2004, and the guidance in this issue has been considered in our disclosure of reportable segments included in Note 15 accompanying the unaudited consolidated financial statements.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123(R), Accounting for Stock-Based Compensation (SFAS 123R). SFAS 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. This statement focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS 123R requires that the fair value of such equity instruments be recognized as expense in the historical

37


Table of Contents

financial statements as services are performed. SFAS 123R shall be effective for interim or annual periods beginning after June 15, 2005. We do not expect the adoption of SFAS 123R to have a material effect on our financial statements as we currently follow the fair value recognition provisions of SFAS 123.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 153, Exchanges of Nonmonetary Assets – an amendment of APB Opinion No 29 (SFAS 153). This statement amends Opinion No. 29, Accounting for Nonmonetary Transactions, to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 shall be effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. We do not expect the adoption of SFAS 153 to have a material effect on our financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity variations, risks related to interest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our exposure to such risks.

Commodity Price Risk

We are exposed to commodity price risk from the risk of price changes in the natural gas and NGLs that we buy and sell and in our midstream, processing and marketing activities. Derivative instruments are used to protect margins on natural gas purchases, sales, transportation, and natural gas liquid sales. Pursuant to our risk management policy, we do not engage in speculative trading in our midstream, processing and marketing activities. In our retail propane business, the market price of propane is often subject to volatile changes as a result of supply or other market conditions over which we have no control. In the past, price changes have generally been passed along to our propane customers to maintain gross margins, mitigating the commodity price risk. In order to help ensure adequate supply sources are available to us during periods of high demand, we will at times purchase significant volumes of propane during periods of low demand, which generally occur during the summer months, at the then current market price, for storage both at our customer service locations and in major storage facilities and for future resale.

We use a combination of financial instruments including, but not limited to, futures, price swaps and basis trades to manage our exposure to market fluctuations in the prices of natural gas, NGLs and propane. Swaps and futures allow us to protect our margins because corresponding losses or gains in the value of financial instruments are generally offset by gains or losses in the physical market.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected, or (2) our counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that we engage in hedging activities we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly protected against decreases in such prices.

We manage our price risk related to future physical purchase or sale commitments for our producer services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in prices. However, we are subject to counterparty risk for both the physical and financial contracts. We account for such physical contracts under the “normal purchases and sales exception” in accordance with SFAS No. 133.

In our midstream and transportation segments, we account for certain of our derivatives as cash flow hedges under SFAS 133. All derivatives are recognized in the balance sheet as price risk management assets and liabilities measured at fair value. For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated statement of operations in cost of products sold. The fair value of price risk management assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income. The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income and when the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in earnings in the consolidated statement of operations. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the consolidated statement of operations.

38


Table of Contents

The following summarizes our open commodity derivative positions as of November 30, 2004 Our counterparties to financial contracts include ABN Amro, BP Corporation, Sempra Energy Trading Corp., and Entergy-Koch Trading, LP.

                             
        Notional                
        Volume             Fair  
November 30, 2004:   Commodity   MMBTU     Maturity     Value  
Basis Swaps IFERC/Nymex
  Gas     37,756,000       2004-2005     $ (9,900 )
Basis Swaps IFERC/Nymex
  Gas     72,789,500       2004-2005       39,906  
 
                         
 
                      $ 30,006  
 
                           
Swing Swaps IFERC
  Gas     89,816,487       2004-2005     $ (767 )
Swing Swaps IFERC
  Gas     50,828,000       2004-2005     $ 1,122  
Swing Swaps IFERC
  Gas     76,720,000       2006-2008        
 
                         
 
                      $ 355  
 
                           
Futures Nymex
  Gas     4,732,500       2004-2005     $ (1,666 )
Futures Nymex
  Gas     40,940,000       2004-2005       (32,925 )
 
                         
 
                        (34,591 )
                             
        Barrels                  
NGL Swaps
  Condensate     105,000       2004-2005     $ (915 )

We also enter into energy trading contracts, which are not derivatives, and therefore are not within the scope of SFAS 133. The types of contracts we utilize in our liquids marketing segment include energy commodity forward contracts, options, and swaps traded on the over-the-counter financial markets. In accordance with the provisions of SFAS 133, derivative financial instruments utilized in connection with our liquids marketing activity are accounted for using the mark-to-market method. Under the mark-to-market method of accounting, forwards, swaps, options, and storage contracts are reflected at fair value, and are shown in the consolidated balance sheet as assets and liabilities from liquids marketing activities. We follow the applicable provisions of EITF Issue No. 02-3, Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 02-3), which requires that gains and losses on derivative instruments be shown net in the statement of operations if the derivative instruments are held for trading purposes. Net realized and unrealized gains and losses from the financial contracts and the impact of price movements are recognized in the statement of operations as other revenue. Changes in the assets and liabilities from the liquids marketing activities result primarily from changes in the market prices, newly originated transactions, and the timing and settlement of contracts. We do not apply mark-to-market accounting for any contracts that are not within the scope of SFAS 133. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist.

The notional amounts and terms of these financial instruments as of November 30, 2004 include fixed price payor for 7,350,000 barrels of propane and fixed price receiver of 6,972,000 barrels of propane. Notional amounts reflect the volume of the transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure Heritage’s exposure to market or credit risks.The fair value of the financial instruments related to liquids marketing activities, as of November 30, 2004 was assets of $0.6 million and liabilities of $0.5 million.

On all transactions in which we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis.

Sensitivity analysis

At November 30, 2004, the fair value of Nymex futures was a liability of $34.6 million on a net short position of 36,207,500 MMBtu. A hypothetical change of 10% in the underlying commodity value would change the fair value of the futures by $28.7 million.

At November 30, 2004 the fair value of basis trades was an asset of $30.0 million on a net short of position of 35,033,500 MMBtu. A hypothetical change of 10% in basis prices would change the fair value by $3.5 million.

39


Table of Contents

The fair value of condensate hedges at November 30, 2004 was an asset of $0.9 million on a short position of 105,000 Bbls. A hypothetical price change of 10% on the liquid hedges would have an effect of $0.5 million on the fair value of derivatives.

Estimates related to our liquids marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. A theoretical change of 10% in the underlying commodity value of the liquids marketing contracts would result in an approximate $32 thousand change in the market value of the contracts as there were approximately 378 thousand gallons of net unbalanced positions at November 30, 2004.

Interest Rate Risk

We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. An interest rate swap agreement is used to manage a portion of the exposure related to ETC OLP’s Term Loan Facility to changing interest rates by converting floating rate debt to fixed rate debt. As of November 30, 2004, this interest rate swap had a notional amount of $75 million that matures on October 9, 2005. The fair value of the interest rate swap is marked to market and the changes in the fair value are recorded in interest expense. The fair value of the interest rate swap was a liability of $0.4 million as of November 30, 2004. We also have long-term debt instruments which are typically issued at fixed interest rates. Prior to or when these debt obligations mature, we may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.

As of November 30, 2004, we had $847.1 million of variable rate debt of which $75.0 million is covered by the interest rate swap discussed above. A change of one percent in the LIBOR rates effective as of November 30, 2004 would have changed interest expense by $7.7 million. This amount has been determined by considering the impact of the hypothetical interest rates on our variable rate borrowings outstanding as of November 30, 2004.

Credit risk

We are diligent in attempting to ensure that we issue credit to only credit-worthy customers. However, our purchase and resale of gas exposes us to significant credit risk, as the margin on any sale is generally a small percentage of the total sales price. Therefore, a credit loss can be very large relative to our overall profitability.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officers and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a–15(e) and 15d–15(e) of the Exchange Act). Based upon that evaluation, management, including the Chief Executive Officers and Chief Financial Officer of our General Partner, concluded that our disclosure controls and procedures were adequate and effective as of November 30, 2004.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)–15 or Rule 15d–15(f) of the Exchange Act) during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We are currently undergoing a comprehensive effort in preparation for compliance with Section 404 of the Sarbanes-Oxley Act of 2002. This effort includes the documentation, testing and review of our internal controls under the direction of senior management. During the course of these activities, we have identified certain internal control issues which senior management believes need to be improved. As a result, we are evaluating and implementing improvements to our internal controls over financial reporting and will continue to do so. These improvements include further formalization of policies and procedures, improved segregation of duties, and improved information technology system controls. To date, we have not identified any material internal control weaknesses.

PART II OTHER INFORMATION

ITEM 6. EXHIBITS

(a) Exhibits

The exhibits listed on the following Exhibit Index are filed as part of this Report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.

40


Table of Contents

             
    Exhibit    
    Number   Description
 
           
(1)
    3.1     Agreement of Limited Partnership of Heritage Propane Partners, L.P.
 
           
(10)
    3.1.1     Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
 
           
(16)
    3.1.2     Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
 
           
(19)
    3.1.3     Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
 
           
(19)
    3.1.4     Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
 
           
(27)
    3.1.5     Amendment No. 5 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
 
           
(27)
    3.1.6     Amendment No. 6 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
 
           
(1)
    3.2     Agreement of Limited Partnership of Heritage Operating, L.P.
 
           
(12)
    3.2.1     Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
 
           
(19)
    3.2.2     Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
 
           
(27)
    3.2.3     Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
 
           
(27)
    3.3     Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P.
 
           
(18)
    3.4     Amended Certificate of Limited Partnership of Heritage Operating, L.P.
 
           
(20)
    4.1     Registration Rights Agreement for Limited Partner Interests of Heritage Propane Partners, L.P.
 
           
(27)
    4.2     Unitholder Rights Agreement dated January 20, 2004 among Heritage Propane Partners, L.P., Heritage Holdings, Inc., TAAP LP and La Grange Energy, L.P.
 
           
(1)
    10.2     Form of Note Purchase Agreement (June 25, 1996).
 
           
(3)
    10.2.1     Amendment of Note Purchase Agreement (June 25, 1996) dated as of July 25, 1996.
 
           
(4)
    10.2.2     Amendment of Note Purchase Agreement (June 25, 1996) dated as of March 11, 1997.
 
           
(6)
    10.2.3     Amendment of Note Purchase Agreement (June 25, 1996) dated as of October 15, 1998.
 
           
(8)
    10.2.4     Second Amendment Agreement dated September 1, 1999 to June 25, 1996 Note Purchase Agreement.
 
           
(11)
    10.2.5     Third Amendment Agreement dated May 31, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.
 
           
(10)
    10.2.6     Fourth Amendment Agreement dated August 10, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.
 
           
(13)
    10.2.7     Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.
 
           
(27)
    10.2.8     Sixth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.
 
           
(1)
    10.3     Form of Contribution, Conveyance and Assumption Agreement among Heritage Holdings, Inc., Heritage Propane Partners, L.P. and Heritage Operating, L.P.
 
           
(1)
    10.6     Restricted Unit Plan.

41


Table of Contents

             
    Exhibit    
    Number   Description
 
           
(4)
    10.6.1     Amendment of Restricted Unit Plan dated as of October 17, 1996.
 
           
(12)
    10.6.2     Amended and Restated Restricted Unit Plan dated as of August 10, 2000.
 
           
(18)
    10.6.3     Second Amended and Restated Restricted Unit Plan dated as of February 4, 2002.
 
           
(30)
    10.6.4     2004 Unit Plan.
 
           
(32)
    10.6.5     Form of Grant Agreement.
 
           
(5)
    10.16     Note Purchase Agreement dated as of November 19, 1997.
 
           
(6)
    10.16.1     Amendment dated October 15, 1998 to November 19, 1997 Note Purchase Agreement.
 
           
(8)
    10.16.2     Second Amendment Agreement dated September 1, 1999 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.
 
           
(9)
    10.16.3     Third Amendment Agreement dated May 31, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.
 
           
(10)
    10.16.4     Fourth Amendment Agreement dated August 10, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.
 
           
(13)
    10.16.5     Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.
 
           
(26)
    10.16.6     Sixth Amendment Agreement dated as of November 18, 2003 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.
 
           
(10)
    10.17     Contribution Agreement dated June 15, 2000 among U.S. Propane, L.P., Heritage Operating, L.P. and Heritage Propane Partners, L.P.
 
           
(10)
    10.17.1     Amendment dated August 10, 2000 to June 15, 2000 Contribution Agreement.
 
           
(10)
    10.18     Subscription Agreement dated June 15, 2000 between Heritage Propane Partners, L.P. and individual investors.
 
           
(10)
    10.18.1     Amendment dated August 10, 2000 to June 15, 2000 Subscription Agreement.
 
           
(16)
    10.18.2     Amendment Agreement dated January 3, 2001 to the June 15, 2000 Subscription Agreement.
 
           
(17)
    10.18.3     Amendment Agreement dated October 5, 2001 to the June 15, 2000 Subscription Agreement.
 
           
(10)
    10.19     Note Purchase Agreement dated as of August 10, 2000.
 
           
(13)
    10.19.1     Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.
 
           
(14)
    10.19.2     First Supplemental Note Purchase Agreement dated as of May 24, 2001 to the August 10, 2000 Note Purchase Agreement.
 
           
(26)
    10.19.3     Sixth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.
 
           
(15)
    10.20     Stock Purchase Agreement dated as of July 5, 2001 among the shareholders of ProFlame, Inc. and Heritage Holdings, Inc.
 
           
(15)
    10.21     Stock Purchase Agreement dated as of July 5, 2001 among the shareholders of Coast Liquid Gas, Inc. and Heritage Holdings, Inc.
 
           
(15)
    10.22     Agreement and Plan of Merger dated as of July 5, 2001 among California Western Gas Company, the Majority Stockholders of California Western Gas Company signatories thereto, Heritage Holdings, Inc. and California Western Merger Corp.
 
           
(15)
    10.23     Agreement and Plan of Merger dated as of July 5, 2001 among Growth Properties, the Majority Shareholders signatories thereto, Heritage Holdings, Inc. and Growth Properties Merger Corp.

42


Table of Contents

             
    Exhibit    
    Number   Description
 
           
(15)
    10.24     Asset Purchase Agreement dated as of July 5, 2001 among L.P.G. Associates, the Shareholders of L.P.G. Associates and Heritage Operating, L.P.
 
           
(15)
    10.25     Asset Purchase Agreement dated as of July 5, 2001 among WMJB, Inc., the Shareholders of WMJB, Inc. and Heritage Operating, L.P.
 
           
(15)
    10.25.1     Amendment to Asset Purchase Agreement dated as of July 5, 2001 among WMJB, Inc., the Shareholders of WMJB, Inc. and Heritage Operating, L.P.
 
           
(18)
    10.26     Assignment, Conveyance and Assumption Agreement between U.S. Propane, L.P. and Heritage Holdings, Inc., as the former General Partner of Heritage Propane Partners, L.P. dated as of February 4, 2002.
 
           
(18)
    10.27     Assignment, Conveyance and Assumption Agreement between U.S. Propane, L.P. and Heritage Holdings, Inc., as the former General Partner of Heritage Operating, L.P., dated as of February 4, 2002.
 
           
(22)
    10.28     Assignment for Contribution of Assets in Exchange for Partnership Interest dated December 9, 2002 amount V-1 Oil Co., the shareholders of V-1 Oil Co., Heritage Propane Partners, L.P. and Heritage Operating, L.P.
 
           
(24)
    10.30     Acquisition Agreement dated November 6, 2003 among the owners of U.S. Propane, L.P. and U.S. Propane, L.L.C. and La Grange Energy, L.P.
 
           
(24)
    10.31     Contribution Agreement dated November 6, 2003 among La Grange Energy, L.P. and Heritage Propane Partners, L.P. and U.S. Propane, L.P.
 
           
(25)
    10.31.1     Amendment No. 1 dated December 7, 2003 to Contribution Agreement dated November 6, 2003 among La Grange Energy, L.P. and Heritage Propane Partners, L.P. and U.S. Propane, L.P.
 
           
(24)
    10.32     Stock Purchase Agreement dated November 6, 2003 among the owners of Heritage Holdings, Inc. and Heritage Propane Partners, L.P.
 
           
(27)
    10.34     Second Amended and Restated Credit Agreement among La Grange Acquisition, L.P. and Banks dated January 20, 2004.
 
           
(28)
    10.34.1     First Amendment effective June 1, 2004, to Second Amended and Restated Credit Agreement among La Grange Acquisition, L.P. and Banks dated January 20, 2004.
 
           
(28)
    10.34.2     Second Amendment effective June 1, 2004, to Second Amended and Restated Credit Agreement among La Grange Acquisition, L.P. and Banks dated January 20, 2004.
 
           
(31)
    10.34.3     Third Amendment effective August 31, 2004 to Second Amended and Restated Credit Agreement among La Grange Acquisition, L.P. and Banks dated January 20, 2004.
 
           
(28)
    10.35     Purchase and Sale Agreement between TXU Fuel Company and Energy Transfer Partners, L.P. dated April 25, 2004.
 
           
(28)
    10.35.1     First Amendment to Purchase and Sale Agreement and Closing Agreement between TXU Fuel Company and Energy Transfer Partners, L.P. dated June 1, 2004.
 
           
(29)
    10.36     Third Amended and Restated Credit Agreement amount Heritage Operating L.P. and the Banks dated March 31, 2004.
 
           
(32)
    21.1     List of Subsidiaries.
 
           
(*)
    31.1     Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
           
(*)
    31.2     Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
           
(*)
    32.1     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
 
           
(*)
    32.2     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

43


Table of Contents


     • Filed herewith.

(1)   Incorporated by reference to the same numbered Exhibit to Registrant’s Registration Statement of Form S-1, File No. 333-04018, filed with the Commission on June 21, 1996.

(2)   Incorporated by reference to Exhibit 10.11 to Registrant’s Registration Statement on Form S-1, File No. 333-04018, filed with the Commission on June 21, 1996.

(3)   Incorporated by reference to the same numbered Exhibit to Registrant’s Form 10-Q for the quarter ended November 30, 1996.

(4)   Incorporated by reference to the same numbered Exhibit to Registrant’s Form 10-Q for the quarter ended February 28, 1997.

(5)   Incorporated by reference to the same numbered Exhibit to Registrant’s Form 10-Q for the quarter ended May 31, 1998.

(6)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K for the year ended August 31, 1998.

(7)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 1999.

(8)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K for the year ended August 31, 1999.

(9)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2000.

(10)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 8-K dated August 23, 2000.

(11)   File as Exhibit 10.16.3.

(12)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K for the year ended August 31, 2000.

(13)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended February 28, 2001.

(14)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2001.

(15)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 8-K dated August 15, 2001.

(16)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K for the year ended August 31, 2001.

(17)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended November 30, 2001.

(18)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended February 28, 2002.

(19)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2002.

(20)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 8-K dated February 4, 2002.

(21)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K for the year ended August 31, 2002.

(22)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 8-K dated January 6, 2003.

(23)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended November 30, 2002.

(24)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2003.

(25)   Incorporated by reference to the same numbered Exhibit to Registrant’s Form 10-Q for the quarter ended November 30, 2003).

(26)   Incorporated by reference as the same numbered exhibit to the Registrant’s Form 10-Q for the quarter ended February 29, 2004.

(27)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended February 29, 2004.

(28)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 8-K filed June 14, 2004.

(29)   Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2004.

44


Table of Contents

(30)   Incorporated by reference to Annex A of the Registrant’s Schedule 14A Proxy Statement filed May 18, 2004.

(31) Incorporated by reference to the same numbered Exhibit to

(32)   Incorporated by reference to the same numbered Exhibit to Registrant’s Form 10-K for the year ended August 31, 2003

45


Table of Contents

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

         
    ENERGY TRANSFER PARTNERS, L.P.
 
       
    By: U.S. Propane, L.P.., General Partner
 
       
    By: U.S. Propane, L.L.C., General Partner
 
       
Date: January 10, 2005
  By:   /s/ H. Michael Krimbill
     
           H. Michael Krimbill
     (President and officer duly authorized to sign on
           behalf of the registrant)

46