Exhibit 99.1

ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

JUNE 30, 2008

(in
thousands)



|                                                            |  |   |           
|----------------------------------------------------------- |  | - | ----------
|ASSETS                                                      |  |   |           
|                                                            | 
|CURRENT ASSETS:                                             |  |   |           
|Cash and cash equivalents                                   |  | $ | 58,603    
|Marketable securities                                       |  |   | 16,831    
|Accounts receivable, net of allowance for doubtful accounts |  |   | 1,047,478 
|Accounts receivable from related companies                  |  |   | 19,385    
|Inventories                                                 |  |   | 179,235   
|Exchanges receivable                                        |  |   | 66,825    
|Deposits paid to vendors                                    |  |   | 60,383    
|Prepaid expenses and other current assets                   |  |   | 72,523    
|                                                            |  |   |           
|Total current assets                                        |  |   | 1,521,263 
|                                                            | 
|PROPERTY, PLANT AND EQUIPMENT, net                          |  |   | 7,457,490 
|ADVANCES TO AND INVESTMENT IN AFFILIATES                    |  |   | 1,281     
|GOODWILL                                                    |  |   | 775,965   
|INTANGIBLES AND OTHER LONG-TERM ASSETS, net                 |  |   | 369,526   
|                                                            |  |   |           
|Total assets                                                |  | $ | 10,125,525
|                                                            |  |   |           
|LIABILITIES AND PARTNERS CAPITAL                           |  |   |           
|                                                            | 
|CURRENT LIABILITIES:                                        |  |   |           
|Accounts payable                                            |  | $ | 1,006,824 
|Accounts payable to related companies                       |  |   | 26,035    
|Exchanges payable                                           |  |   | 68,863    
|Customer advances and deposits                              |  |   | 83,112    
|Accrued capital expenditures                                |  |   | 173,776   
|Accrued and other current liabilities                       |  |   | 176,653   
|Interest payable                                            |  |   | 77,023    
|Current maturities of long-term debt                        |  |   | 43,744    
|                                                            |  |   |           
|Total current liabilities                                   |  |   | 1,656,030 
|                                                            | 
|LONG-TERM DEBT, less current maturities                     |  |   | 4,870,276 
|DEFERRED INCOME TAXES                                       |  |   | 105,845   
|OTHER LONG-TERM LIABILITIES                                 |  |   | 15,282    
|MINORITY INTERESTS                                          |  |   | 3,302,727 
|COMMITMENTS AND CONTINGENCIES (Note 7)                      |  |   |           
|                                                            |  |   |           
|                                                            |  |   | 9,950,160 
|                                                            |  |   |           
|PARTNERS CAPITAL:                                          |  |   |           
|General partner                                             |  |   | 16        
|Limited partners -                                          |  |   |           
|Class A Limited Partner interests                           |  |   | 84,889    
|Class B Limited Partner interests                           |  |   | 90,277    
|Accumulated other comprehensive income                      |  |   | 183       
|                                                            |  |   |           
|Total partners capital                                     |  |   | 175,365   
|                                                            |  |   |           
|Total liabilities and partners capital                     |  | $ | 10,125,525
|                                                            |  |   |           

The accompanying notes are an integral part of this unaudited condensed consolidated balance sheet.



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ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

JUNE 30, 2008

(Tabular dollar amounts in thousands)



|1. | OPERATIONS AND ORGANIZATION:
|-- | ----------------------------

Energy
Transfer Partners GP, L.P. (ETP GP or the Partnership) was formed in August 2000 as a Delaware limited partnership. ETP GP is the General Partner and the owner of the 2% general partner interest of Energy Transfer Partners,
L.P. (ETP). ETP GP is owned 99.99% by its limited partners, and 0.01% by its general partner, Energy Transfer Partners, L.L.C. (ETP LLC). We and ETP LLC are wholly-owned by Energy Transfer Equity, L.P. (ETE).

Balance Sheet Presentation

This unaudited interim condensed consolidated balance sheet and notes thereto of ETP GP and subsidiaries as of June 30, 2008, have been prepared in accordance with accounting principles generally accepted in the United States of
America (GAAP) for interim consolidated financial information. Accordingly, this financial statement does not include all the information and footnotes required by GAAP for complete consolidated financial statements. However, management
believes that the disclosures made are adequate to make the information not misleading.

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 ETP GP and subsidiaries as of June 30, 2008. The unaudited interim condensed consolidated balance sheet should be read
in conjunction with the consolidated balance sheet and notes thereto of ETP GP and subsidiaries presented as Exhibit 99.1 to the Energy Transfer Partners, L.P. Annual Report on Form 10-K for the fiscal year ended August 31, 2007, as filed with
the Securities and Exchange Commission on October 30, 2007.

We consolidate all majority-owned and controlled subsidiaries, including
ETP and its subsidiaries, La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company (ETC OLP), Heritage Operating, L.P. (HOLP), Heritage Holdings, Inc. (HHI), Titan
Energy Partners, L.P. (Titan) and Energy Transfer Interstate Holdings, LLC (ET Interstate), the parent company of Transwestern Pipeline Company, LLC (Transwestern) and ETC Midcontinent Express Pipeline, LLC
(ETC MEP), collectively, the Operating Partnerships. We recognize a minority interest liability for all partially-owned consolidated subsidiaries. All significant intercompany accounts are eliminated in consolidation.

We also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an
undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other form of entity. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage
or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.

In
November 2007, ETP filed a Form 8-K indicating that its Limited Partnership Agreement had been amended to change its fiscal year end to the calendar year. Thus, ETPs, and our, current fiscal year began on January 1, 2008.

Business Operations

In order to
simplify the obligations of ETP under the laws of several jurisdictions in which we conduct business, our activities are primarily conducted through our Operating Partnerships, as follows:



| |  |  | ETC OLP - a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------



| |  |  | ET Interstate - the parent company of Transwestern and ETC MEP, all of which are Delaware limited liability companies engaged in interstate transportation of
natural gas;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | HOLP - a Delaware limited partnership primarily engaged in retail propane operations; and
| | - |  | -----------------------------------------------------------------------------------------



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| |  |  | Titan - a Delaware limited partnership engaged in retail propane operations.
| | - |  | ----------------------------------------------------------------------------

The Partnership, the Operating Partnerships, and their subsidiaries are collectively referred to in this report as we, us,
our, ETP GP, Energy Transfer Partners GP, L.P. or the Partnership.

ETC OLP owns and
operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and
marketing natural gas and natural gas liquids (NGLs) in the states of Texas, Louisiana, New Mexico, Utah and Colorado.

Our
interstate transportation operations principally focus on natural gas transportation of Transwestern and the joint venture activities of ETC MEP.

Our retail propane segment sells propane and propane-related products and services to residential, commercial, industrial and agricultural customers.



|2. | ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES, NEW ACCOUNTING STANDARDS AND BALANCE SHEET DETAIL:
|-- | ----------------------------------------------------------------------------------------------

Use of Estimates

The preparation of
financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and accruals for and disclosures of contingent assets and liabilities at the balance sheet
date.

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 and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results
are recognized in the following months financial statements. Management believes that the assets and liabilities as of June 30, 2008 represent the actual results in all material respects.

Some of the other more significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are
hedged, 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, estimates related to our
unit-based compensation plans, deferred taxes, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

Significant Accounting Policies

Financial Assets and Liabilities at Fair Value

We adopted Statement of Financial Accounting Standards No. 157, Fair
Value Measurements, (SFAS 157) effective January 1, 2008. SFAS 157 provides a definition of fair value, establishes a fair value framework and hierarchy under GAAP and provides for expanded disclosures of fair value
measurements. SFAS 157 does not require any new fair value measurements other than those established by other GAAP requirements. As noted below, under New Accounting Standards, the effective date of SFAS 157 has been deferred with
respect to certain non-financial assets and liabilities.

We have marketable securities, commodity derivatives and interest rate
derivatives that are accounted for as assets and liabilities at fair value in our condensed consolidated balance sheet. In accordance with SFAS 157, we determine the fair value of our assets and liabilities subject to fair value measurement by
using the highest possible Level as defined in SFAS 157. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives
transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for



3



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similar assets and liabilities. We consider over-the-counter commodity derivatives entered into directly with third parties Level 2 valuation since the
values of these derivatives are quoted on an exchange for similar transactions. We consider the valuation of our interest rate derivatives as Level 2 since we use a LIBOR curve based on quotes from an active exchange of Eurodollar futures for the
same period as the future interest swap settlements and discount the future cash flows accordingly, including the effects of our credit risk. Level 3 utilizes significant unobservable inputs. We currently do not have any fair value measurements
within the scope of SFAS 157 that require the use of significant unobservable inputs and therefore do not have any assets or liabilities considered as Level 3 valuations as defined by SFAS 157.

The following table summarizes the fair value of our financial assets and liabilities as of June 30, 2008 based on inputs used to derive their fair
values in accordance with SFAS 157:



|                          |  |                  |         |   |                                                                  |   |         |                                  |  |   |        |  
|------------------------- |  | ---------------- | ------- | - | ---------------------------------------------------------------- | - | ------- | -------------------------------- |  | - | ------ | -
|                          |  |                  |         |   | Fair Value Measurements atReporting Date Using                   |  
|                          |  | Fair MarketValue |         |   | Quoted prices inActive Marketsfor IdenticalAssets andLiabilities |   |         | SignificantOtherObservableInputs | 
|Description               |  | Total            |         |   | (Level 1)                                                        |   |         | (Level 2)                        | 
|Assets                    |  |                  |         |   |                                                                  |   |         |                                  |  |   |        |  
|Marketable Securities     |  | $                | 16,831  |   |                                                                  | $ | 16,831  |                                  |  | $ |       |  
|Commodity Derivatives     |  |                  | 10,553  |   |                                                                  |   | 2,611   |                                  |  |   | 7,942  |  
|                          |  |                  |        
|Liabilities               |  |                  |         |   |                                                                  |   |         |                                  |  |   |        |  
|Commodity Derivatives     |  |                  | (21,493 | ) |                                                                  |   | (13,845 | )                                |  |   | (7,648 | )
|Interest Rate Derivatives |  |                  | (2,086  | ) |                                                                  |   |        |                                  |  |   | (2,086 | )
|                          |  |                  |         |   |                                                                  |   |         |                                  |  |   |        |  
|                          |  | $                | 3,805   |   |                                                                  | $ | 5,597   |                                  |  | $ | (1,792 | )
|                          |  |                  |         |   |                                                                  |   |         |                                  |  |   |        |  

New Accounting Standards

FASB Statement No. 141 (Revised 2007), Business Combinations(SFAS 141R). On December 4, 2007, the FASB issued SFAS
141R. SFAS 141R will significantly change the accounting for business combinations. Under SFAS 141R, an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition-date
fair value with limited exceptions. Statement 141R will change the accounting treatment for certain specific items, including:



| |  |  | Acquisition costs will generally be expensed as incurred;
| | - |  | ---------------------------------------------------------



| |  |  | Non-controlling interests (currently referred to as "minority interests") will be valued at fair value at the acquisition date;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------



| |  |  | Acquired contingent liabilities will be recorded at fair value at the acquisition date and subsequently measured at either the higher of such amount or the amount
determined under existing guidance for non-acquired contingencies;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | In-process research and development will be recorded at fair value as an indefinite-lived intangible asset at the acquisition date;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------



| |  |  | Restructuring costs associated with a business combination will generally be expensed subsequent to the acquisition date; and
| | - |  | -----------------------------------------------------------------------------------------------------------------------------



| |  |  | Changes in deferred tax asset valuation allowances and income tax uncertainties after the acquisition date generally will affect income tax expense.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------

SFAS 141R also includes a substantial number of new disclosure requirements. SFAS 141R is to be applied prospectively to
business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Earlier adoption is prohibited. Accordingly, we are required to record and
disclose business combinations following existing GAAP until January 1, 2009.



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FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial StatementsAn
Amendment of ARB No. 51 (SFAS 160).On December 4, 2007, the FASB issued SFAS 160. SFAS 160 establishes new accounting and reporting standards for the non-controlling interest in a subsidiary and for the
deconsolidation of a subsidiary. Specifically, SFAS 160 requires the recognition of a non-controlling interest (minority interest) as equity in the consolidated financial statements and separate from the parent's equity. The amount of net income
attributable to the non-controlling interest will be included in consolidated net income on the face of the income statement. SFAS 160 clarifies that changes in a parent's ownership interest in a subsidiary that do not result in deconsolidation are
equity transactions if the parent retains its controlling financial interest. In addition, SFAS 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. Such gain or loss will be measured using the fair
value of the non-controlling equity investment on the deconsolidation date. SFAS 160 also includes expanded disclosure requirements regarding the interests of the parent and its non-controlling interest. SFAS 160 is effective for fiscal years, and
interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. We are currently evaluating the impact of SFAS 160 on our consolidated financial statements. While we do not anticipate a
significant financial impact, the impact of SFAS 160 on our financial statement presentation could be significant.

FASB Statement
No. 161, Disclosures about Derivative Instruments and Hedging ActivitiesAn Amendment of FASB Statement No. 133 (SFAS 161).Issued in March, 2008, SFAS 161 changes the disclosure requirements for derivative
instruments and hedging activities with the intent to provide users of financial statements with an enhanced understanding of (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items
are accounted for under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133) and its related interpretations, and (c) how derivative instruments and related hedged items affect
an entitys financial position, financial performance, and cash flows. SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on
derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. This statement has the same scope as SFAS 133, and accordingly applies to all entities. SFAS 161 is effective for financial statements
issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. SFAS 161 only
affects disclosure requirements; therefore, our adoption of this statement effective January 1, 2009 will not impact our financial position or results of operations.

FASB Statement No. 162, The Hierarchy of Generally Accepted Accounting Principles (SFAS 162). In May 2008, the FASB issued SFAS 162, which establishes a consistent framework, or hierarchy, for
selecting the accounting principles used to prepare financial statements of nongovernmental entities in conformity with GAAP. SFAS 162 is effective 60 days following the SECs approval of the Public Company Accounting Oversight Board (PCAOB)
amendments to its Interim Auditing Standards. We do not expect SFAS 162 to have a material impact on the preparation of our consolidated financial statements.

FASB Staff Position (FSP) SFAS 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2). FSP 157-2 defers the effective date of SFAS 157 to fiscal years beginning after
November 15, 2008, and interim periods within those fiscal years, for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at
least annually). As allowed under FSP 157-2, we have not applied the provisions of SFAS 157 to our nonfinancial assets and liabilities measured at fair value, which include impaired nonfinancial assets and certain assets and liabilities acquired in
business combinations. We are currently evaluating the impact of our adoption of FSP 157-2 effective January 1, 2009 on our consolidated financial statements.

Cash and Cash Equivalents

Cash and cash equivalents include all cash on hand, demand deposits, and
investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of
changes in value.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, such
balances may be in excess of the Federal Deposit Insurance Corporation (FDIC) insurance limit.



5



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Accounts Receivable

We exchanged a portion of our outstanding accounts receivable from Calpine Energy Services, L.P. for Calpine Corporation (Calpine) common stock during the first quarter of 2008 pursuant to a settlement
reached with Calpine related to their bankruptcy reorganization. The stock was included as marketable securities which are classified as available-for-sale securities and are reflected as a current asset on the condensed consolidated balance sheet
as of June 30, 2008 at a fair value of $14.9 million.

Accounts receivable consisted of the following at June 30, 2008:



|                                                                          |  |   |           |  
|------------------------------------------------------------------------- |  | - | --------- | -
|Accounts receivable - midstream and intrastate transportation and storage |  | $ | 904,043   |  
|Accounts receivable - interstate transportation                           |  |   | 24,993    |  
|Accounts receivable - propane                                             |  |   | 124,717   |  
|Less - allowance for doubtful accounts                                    |  |   | (6,275    | )
|                                                                          |  |   |           |  
|Total, net                                                                |  | $ | 1,047,478 |  
|                                                                          |  |   |           |  

Inventories

Inventories consist principally of natural gas held in storage valued at the lower of cost or market utilizing the weighted-average cost method. Propane inventories are valued at the lower of cost or market utilizing
the weighted-average cost of propane delivered to the customer service locations, including storage fees and inbound freight costs. The cost of appliances, parts, and fittings is determined by the first-in, first-out method. Inventories consisted of
the following at June 30, 2008:



|                                         |  |   |        
|---------------------------------------- |  | - | -------
|Natural gas, propane and other NGLs      |  | $ | 158,591
|Appliances, parts and fittings and other |  |   | 20,644 
|                                         |  |   |        
|Total inventories                        |  | $ | 179,235
|                                         |  |   |        



|3. | INTANGIBLES AND OTHER LONG-TERM ASSETS:
|-- | ---------------------------------------

Intangibles and other long-term assets are stated at cost net of amortization computed on the straight-line method. We eliminate from our balance sheet the gross carrying amount and the related accumulated amortization for any fully
amortized intangibles in the year they are fully amortized. Components and useful lives of intangibles and other long-term assets were as follows:



|                                             |  |                      |         |                         |   |         |  
|-------------------------------------------- |  | -------------------- | ------- | ----------------------- | - | ------- | -
|                                             |  | June 30, 2008        |        
|                                             |  | Gross CarryingAmount |         | AccumulatedAmortization |  
|Amortizable intangible assets:               |  |                      |         |                         |   |         |  
|Noncompete agreements (5 to 15 years)        |  | $                    | 39,173  |                         | $ | (21,878 | )
|Customer lists (3 to 15 years)               |  |                      | 143,420 |                         |   | (33,228 | )
|Contract rights (6 to 15 years)              |  |                      | 23,015  |                         |   | (2,796  | )
|Other (10 years)                             |  |                      | 2,677   |                         |   | (1,853  | )
|                                             |  |                      |         |                         |   |         |  
|Total amortizable intangible assets          |  |                      | 208,285 |                         |   | (59,755 | )
|                                             |  |                     
|Non-amortizable assets - Trademarks          |  |                      | 72,148  |                         |   |        |  
|                                             |  |                      |         |                         |   |         |  
|Total intangible assets                      |  |                      | 280,433 |                         |   | (59,755 | )
|                                             |  |                     
|Other long-term assets:                      |  |                      |         |                         |   |         |  
|Financing costs (3 to 15 years)              |  |                      | 55,161  |                         |   | (13,430 | )
|Regulatory assets                            |  |                      | 83,621  |                         |   | (4,244  | )
|Other                                        |  |                      | 27,740  |                         |   |        |  
|                                             |  |                      |         |                         |   |         |  
|Total intangibles and other long-term assets |  | $                    | 446,955 |                         | $ | (77,429 | )
|                                             |  |                      |         |                         |   |         |  



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We review amortizable intangible assets for impairment whenever events or changes in circumstances
indicate that the carrying amount of such assets may not be recoverable, in accordance with Statement of Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS 144). If such a
review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually at August 31,
or more frequently if circumstances dictate, in accordance with SFAS 144.



|4. | INCOME TAXES:
|-- | -------------

ETP GP is a limited
partnership. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes generally are included in the tax returns of the individual partners. Net earnings for financial
statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to
taxable income under the Partnership Agreement.

As a limited partnership we are generally not subject to income tax. We are, however,
subject to a statutory requirement that our non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of our total gross income, determined on a calendar year
basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation. Accordingly, certain activities that generate non-qualifying income are conducted through
taxable corporate subsidiaries (C corporations). These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the six months ended June 30, 2008 our
non-qualifying income did not, or was not expected to, exceed the statutory limit.

Those subsidiaries which are taxable corporations follow
the asset and liability method of accounting for income taxes in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). Under SFAS 109, deferred income taxes are recorded
based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets are received and liabilities settled.



|5. | DEBT OBLIGATIONS:
|-- | -----------------

Our debt obligations
consisted of the following:



|                                                    |  |              |         |            |                                                                               
|--------------------------------------------------- |  | ------------ | ------- | ---------- | ------------------------------------------------------------------------------
|                                                    |  | June 30,2008 |         | Maturities
|ETP Senior Notes:                                   |  |              |         |            |                                                                               
|2008 6.0% Senior Notes, net of discount of $635     |  | $            | 349,365 |            | One payment of $350,000 due July 13, 2013. Interest is paid semi-annually.    
|                                                    |  |             
|2008 6.7% Senior Notes, net of discount of $1,734   |  |              | 598,266 |            | One payment of $600,000 due July 2, 2018. Interest is paid semi-annually.     
|                                                    |  |             
|2008 7.5% Senior Notes, net of discount of $5,729   |  |              | 544,271 |            | One payment of $550,000 due July 1, 2038. Interest is paid semi-annually.     
|                                                    |  |             
|2006 6.125% Senior Notes, net of discount of $309   |  |              | 399,691 |            | One payment of $400,000 due February 15, 2017. Interest is paid semi-annually.
|                                                    |  |             
|2006 6.625% Senior Notes, net of discount of $2,218 |  |              | 397,782 |            | One payment of $400,000 due October 15, 2036. Interest is paid semi-annually. 
|                                                    |  |             
|2005 5.95% Senior Notes, net of discount of $1,633  |  |              | 748,367 |            | One payment of $750,000 due February 1, 2015. Interest is paid semi-annually. 
|                                                    |  |             
|2005 5.65% Senior Notes, net of discount of $260    |  |              | 399,740 |            | One payment of $400,000 due August 1, 2012. Interest is paid semi-annually.   



7



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|                                                                  |  |         |  |                                                                                                                                                                               
|----------------------------------------------------------------- |  | ------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Transwestern Senior Unsecured Notes:                              |  |         |  |                                                                                                                                                                               
|5.39% Senior Unsecured Series Notes, including premium of $3,788  |  | 91,788  |  | One payment of $88,000 due November 17, 2014. Interest is paid semi-annually.                                                                                                 
|                                                                  |  |        
|5.54% Senior Unsecured Series Notes, net of discount of $4,593    |  | 120,407 |  | One payment of $125,000 due November 17, 2016. Interest is paid semi-annually.                                                                                                
|                                                                  |  |        
|5.64% Senior Unsecured Series Notes                               |  | 82,000  |  | One payment due May 24, 2017. Interest is paid semi-annually.                                                                                                                 
|                                                                  |  |        
|5.89% Senior Unsecured Series Notes                               |  | 150,000 |  | One payment due May 24, 2022. Interest is paid semi-annually.                                                                                                                 
|                                                                  |  |        
|6.16% Senior Unsecured Series Notes                               |  | 75,000  |  | One payment due May 24, 2037. Interest is paid semi-annually.                                                                                                                 
|                                                                  |  |        
|HOLP Senior Secured Notes:                                        |  |         |  |                                                                                                                                                                               
|1996 8.55% Senior Secured Notes                                   |  | 36,000  |  | Annual payments of $12,000 due each June 30 through 2011. Interest is paid semi-annually.                                                                                     
|1997 Medium Term Note Program:                                    |  |         |  |                                                                                                                                                                               
|7.17% Series A Senior Secured Notes                               |  | 4,800   |  | Annual payments of $2,400 due each November 19 through 2009. Interest is paid semi-annually.                                                                                  
|                                                                  |  |        
|7.26% Series B Senior Secured Notes                               |  | 10,000  |  | Annual payments of $2,000 due each November 19 through 2012. Interest is paid semi-annually.                                                                                  
|2000 and 2001 Senior Secured Promissory Notes:                    |  |         |  |                                                                                                                                                                               
|8.55% Series B Senior Secured Notes                               |  | 13,714  |  | Annual payments of $4,571 due each August 15 through 2010. Interest is paid quarterly.                                                                                        
|                                                                  |  |        
|8.59% Series C Senior Secured Notes                               |  | 15,500  |  | Annual payments of $4,000 due August 15, 2008, and $5,750 due each August 15, 2009 and 2010. Interest is paid quarterly.                                                      
|                                                                  |  |        
|8.67% Series D Senior Secured Notes                               |  | 58,000  |  | Annual payments of $12,450 due August 15, 2008 and 2009, $7,700 due August 15, 2010, $12,450 due August 15, 2011, and $12,950 due August 15, 2012. Interest is paid quarterly.
|                                                                  |  |        
|8.75% Series E Senior Secured Notes                               |  | 7,000   |  | Annual payments of $1,000 due each August 15, 2009 through 2015. Interest is paid quarterly.                                                                                  
|                                                                  |  |        
|8.87% Series F Senior Secured Notes                               |  | 40,000  |  | Annual payments of $3,636 due each August 15, 2010 through 2020. Interest is paid quarterly.                                                                                  
|                                                                  |  |        
|7.89% Series H Senior Secured Notes                               |  | 5,818   |  | Annual payments of $727 due each May 15 through 2016. Interest is paid quarterly.                                                                                             
|                                                                  |  |        
|7.99% Series I Senior Secured Notes                               |  | 16,000  |  | One payment of $16,000 due May 15, 2013. Interest is paid quarterly.                                                                                                          
|                                                                  |  |        
|Revolving Credit Facilities:                                      |  |         |  |                                                                                                                                                                               
|ETP Revolving Credit Facility (including Swingline loan option)   |  | 734,177 |  | Available through June 2012 - see terms below under ETP Credit Facility.                                                                                                    
|                                                                  |  |        
|HOLP Fourth Amended and Restated Senior Revolving Credit Facility |  |        |  | Available through June 30, 2011 - see terms below under "HOLP Credit Facility."                                                                                               



8



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|                                                                                      |  |   |           |   |  |                                  
|------------------------------------------------------------------------------------- |  | - | --------- | - |  | ---------------------------------
|Other Long-Term Debt:                                                                 |  |   |           |   |  |                                  
|Notes payable on noncompete agreements with interest imputed at rates averaging 8.37% |  |   | 13,092    |   |  | Due in installments through 2014.
|                                                                                      |  |  
|Other                                                                                 |  |   | 3,242     |   |  | Due in installments through 2024.
|                                                                                      |  |   |           |   |  |                                  
|                                                                                      |  |   | 4,914,020 |   |  |                                  
|Current maturities                                                                    |  |   | (43,744   | ) |  |                                  
|                                                                                      |  |   |           |   |  |                                  
|                                                                                      |  | $ | 4,870,276 |   |  |                                  
|                                                                                      |  |   |           |   |  |                                  

Future maturities of long-term debt for each of the next five years and thereafter are as follows:



|                 |  |   |          
|---------------- |  | - | ---------
|2008 (remainder) |  | $ | 28,540   
|2009             |  |   | 45,364   
|2010             |  |   | 40,556   
|2011             |  |   | 34,229   
|2012             |  |   | 1,156,836
|Thereafter       |  |   | 3,608,495
|                 |  |   |          
|                 |  | $ | 4,914,020
|                 |  |   |          

ETP 2008 Senior Notes

On March 28, 2008, ETP issued a total of $1.5 billion aggregate principal amount of Senior Notes comprised of $350.0 million of 6.00% Senior Notes
due 2013, $600.0 million of 6.70% Senior Notes due 2018, and $550.0 million of 7.50% Senior Notes due 2038 (collectively, the ETP 2008 Senior Notes). The proceeds of approximately $1.48 billion (net of bond discounts of $8.2 million and
other offering costs of $10.8 million) from the issuance of the ETP 2008 Senior Notes were used to repay borrowings and accrued interest outstanding under ETPs $500.0 million, 364-day term loan credit facility (the 364-Day Credit
Facility) and to repay a portion of amounts outstanding under the ETP Credit Facility. ETP may redeem some or all of the ETP 2008 Senior Notes at any time, or from time to time, pursuant to the terms of the indenture. The ETP 2008 Senior Notes
were registered under the Securities Act of 1933 (as amended) pursuant to ETPs Registration Statement on Form S-3ASR, as supplemented by ETPs Prospectus Supplement dated March 25, 2008, filed with the SEC on March 26, 2008. The
364-Day Credit Facility was a single draw term loan for general corporate purposes, with an applicable Eurodollar rate plus 1.000% per annum based on the current rating by the rating agencies or at the Base Rate for a designated period. The
indebtedness under the 364-Day Credit Facility was unsecured and not guaranteed by us or any of our subsidiaries.

The ETP 2008 Senior Notes
were issued under an indenture containing covenants, which, among other things, restrict ETPs ability to, subject to certain exceptions, incur debt secured by liens, engage in sale and leaseback transactions or merge or consolidate with
another entity or sell substantially all of our assets. The ETP 2008 Senior Notes are unsecured obligations of us and ETP and our and ETPs obligation to repay the ETP Senior Notes is not guaranteed by any of our or ETPs subsidiaries. As
a result, the ETP 2008 Senior Notes effectively rank junior to any future indebtedness of ours or our or ETPs subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP
2008 Senior Notes effectively rank junior to all indebtedness and other liabilities of our or ETPs existing and future subsidiaries.

ETP Credit Facility

ETP has available a $2.0 billion revolving credit facility (the ETP Credit Facility)
that is expandable to $3.0 billion at its option (subject to the approval of the administrative agent under the Amended and Restated Credit Agreement, which approval is not to be unreasonably withheld) which matures on July 20, 2012, unless it
elects the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments under the ETP Credit Facility). Amounts borrowed under the ETP Credit Facility bear
interest at a rate based on either a Eurodollar rate or a prime rate. The ETP Credit Facility has a swingline loan option of which borrowings and aggregate principal amounts shall not exceed the lesser of (i) the aggregate commitments ($2.0
billion unless expanded to $3.0 billion) less the sum of all outstanding revolving credit loans and the letter of credit obligation and (ii) the swingline commitment.



9



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As of June 30, 2008, there was a balance of $734.2 million in revolving credit loans (including
$87.2 million in swingline loans) and $62.5 million in letters of credit. The weighted average interest rate on the total amount outstanding at June 30, 2008, was 3.078%. The total amount available under the ETP Credit Facility, as of
June 30, 2008, which is reduced by any amounts outstanding under the swingline loan and letters of credit, was $1.2 billion. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of our or ETPs subsidiaries
and has equal rights to holders of our or ETPs other current and future unsecured debt.

HOLP Credit Facility

A $75.0 million Senior Revolving Facility (the HOLP Credit Facility) is available to HOLP through June 30, 2011
which may be expanded to $150.0 million. The HOLP Credit Facility has a swingline loan option with a maximum borrowing of $10.0 million at a prime rate. Amounts borrowed under the HOLP Credit Facility bear interest at a rate based on either a
Eurodollar rate or a prime rate. As of June 30, 2008, there was no balance outstanding on the revolving credit loans. A letter of credit issuance is available to HOLP for up to 30 days prior to the maturity date of the HOLP Credit Facility.
There were outstanding letters of credit of $1.0 million at June 30, 2008. The sum of the loans made under the HOLP Credit Facility plus the letter of credit exposure and the aggregate amount of all swingline loans cannot exceed the $75.0
million maximum amount of the HOLP Credit Facility. The amount available at June 30, 2008 was $74.0 million.



|6. | PARTNERS CAPITAL AND UNIT-BASED COMPENSATION PLANS:
|-- | ----------------------------------------------------

Quarterly Distributions of Available Cash

Our distribution policy is consistent with the terms of
our Second Amended and Restated Agreement of Limited Partnership, which requires that we distribute all of our available cash quarterly. Our only cash-generating assets consist of partnership interests, including Incentive Distribution Rights
(IDR), from which we receive quarterly distributions from ETP. We have no independent operations outside of our interests in ETP. Under our Second Amended and Restated Agreement of Limited Partnership, our distributions are characterized
as the GP Distribution Amount and the IDR Distribution Amount. The GP Distribution Amount is all distributions we receive from ETP with respect to our 2% General Partner Interest and the IDR Distribution Amount is all distributions received from ETP
with respect to the Incentive Distribution Rights. Within 45 days following the end of each quarter, we will distribute all of our GP Available Cash and IDR Available Cash, as defined in the Second Amended and Restated Agreement of Limited
Partnership. GP Available Cash shall be distributed 99.99% to the Class A Limited Partners, pro rata and .01% to the General Partner. IDR Available Cash shall be distributed 99.99% to the Class B Limited Partners, pro rata and .01% to the
General Partner.

Subsidiary Equity Issuances

On January 8, 2008, ETP issued 750,000 additional ETP Common Units to underwriters pursuant to the exercise of a 30-day option to purchase Common Units to cover over-allotments in connection with a public
offering of 5,000,000 ETP Common Units, representing limited partner interests, in December 2007. The proceeds of $35.0 million, net of offering costs, were used to repay borrowings from the ETP Credit Facility.

On July 21, 2008, ETP issued 7,750,000 ETP Common Units representing limited partner interests at $39.45 per ETP Common Unit in connection with a
public offering. ETP also granted the underwriters a 30-day option to purchase up to an aggregate of 1,162,500 additional ETP Common Units, which was immediately exercised with the equity issuance. Net proceeds of approximately $338.0 million were
used by ETP to repay a portion of the amount outstanding under its ETP Revolving Credit Facility.

ETP Unit Based Compensation Plans

ETP follows the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004) Accounting for Stock-based
Compensation (SFAS 123R) for its unit-based compensation plans. Generally, the recipients of the ETP unit grants are not entitled to receive any unit distributions during the required service period for vesting. Accordingly, as provided
in SFAS 123R, ETP values the unit awards based on the per unit grant-date market value reduced by the present value of the distributions expected to be paid on the units during the requisite service period. The present value of expected service
period distributions is computed based on the risk-free interest rate, the expected life of the unit grants and the expected unit distributions.



10



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ETP has the following unit-based compensation plans as of June 30, 2008.

2004 Unit Plan

ETPs Amended
and Restated 2004 Unit Award Plan (the 2004 Unit Plan) provides for awards of up to 1,800,000 ETP Common Units and other rights to its employees, officers, and directors. 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 2004 Unit Plan. Units to be delivered upon the vesting of awards granted under the 2004 Unit Plan may be (i) units acquired by us in the open
market, (ii) units already owned by us, or (iii) units acquired by us from any other person. ETP may issue units under the 2004 Unit Plan without registration under the federal securities law, in which case holders of these units would be
subject to restrictions on their ability to sell these units, or it may issue units pursuant to a registration statement on Form S-8, in which case the holders of these units would not be subject to these restrictions. As of June 30, 2008,
458,115 ETP Common Units were available for future grants under ETPs 2004 Unit Plan.

The 2004 Unit Plan is administered by our Compensation Committee and may be amended from time to time by our Board of Directors; 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 than the 10thanniversary of its original effective date (June 23, 2014).

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. The issuance of Common Units 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 ETP Common Units.

Prior to the December 2007 unit awards, substantially all of the awards granted to employees under the 2004 Unit Plan required the achievement of performance objectives in order for the awards to become vested. The
expected life of each unit award subject to the achievement of performance objectives is assumed to be the minimum vesting period under the performance objectives of such unit award. Generally, each award has been structured to provide that, if the
performance objectives related to such award are achieved, one-third of the units subject to such award will vest each year over a three year period. The performance criteria are generally based upon the total return (unit price appreciation plus
cash distributions) to our Unitholders as compared to a group of publicly traded partnership peer companies. As circumstances change, cumulative adjustments of previously-recognized compensation expense are recorded.

Since December 2007, we have also granted unit awards to employees that vest 20% per year over a five year period with vesting based on continued
employment as of each applicable vesting date without regard to the satisfaction of any performance objectives.

Director Grants

Each ETP 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 ETP LLC, ETP, 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 ETP
Common 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 September 1st shall automatically
receive an award of ETP Common Units equal to $25 thousand ,divided by the fair market value of an ETP Common Unit on such date rounded to the nearest increment of ten Units (Annual Directors Grant). Each grant of an award to a
Director Participant will vest at the rate of one third per year, beginning on the first anniversary date of the Award; provided however, notwithstanding the foregoing, (i) all awards to a Director



11



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Participant shall become fully vested upon a change in control, as defined by the 2004 Unit 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.

At June 30, 2008, a total of 7,408 unit awards granted had not vested.

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 designates 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 June 30, 2008, there have been no Long-Term Incentive Grants made under the Plan.

Related Party
Awards

During 2007, a partnership (McReynolds Equity Partners, L.P.), the general partner of which is owned and controlled by the
President of our General Partner, awarded to certain new officers of ETP certain rights related to units of Energy Transfer Equity, L.P. (ETE) previously issued by ETE to such officer. These rights include the economic benefits of
ownership of these units based on a 5-year vesting schedule whereby the officer will vest in the units at a rate of 20% per year. None of the costs related to such awards are paid by ETP or ETE. Based on GAAP covering related party transactions
and unit-based compensation arrangements, we are recognizing non-cash compensation expense over the vesting period based on the grant date market value of the ETE units awarded the ETP employees assuming no forfeitures. Rights related to 55,000 of
the ETE units vested in December 2007 and 60,000 unit awards vested in March 2008. In June 2008, 240,000 unit awards were forfeited due to the resignation of an officer of ETP. As these units were outstanding prior to these awards, the awards do not
represent an increase in the number of outstanding units of either ETP or ETE and are not dilutive to cash distributions per unit with respect to either ETP or ETE. As of June 30, 2008, ETP expects to recognize non-cash compensation expense as
follows in future periods related to these awards:



|                          |  |   |      
|------------------------- |  | - | -----
|Years Ending December 31: |  |  
|2008 (remainder)          |  | $ | 1,708
|2009                      |  |   | 2,310
|2010                      |  |   | 1,342
|2011                      |  |   | 640  
|2012                      |  |   | 105  

On July 22, 2008, rights to 240,000 ETE units were awarded to ETPs current chief
financial officer. This award has similar terms to those discussed above, including vesting over five years at 20% per year. None of the costs related to this award will be paid by ETP or ETE. Non-cash compensation expense of approximately $7.0
million will be recognized by ETP ratably over the 5-year vesting period, beginning in July of 2008.



|7. | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL LIABILITIES:
|-- | ------------------------------------------------------------------------------

Regulatory Matters

On
September 29, 2006, Transwestern filed revised tariff sheets under Section 4(e) of the Natural Gas Act (NGA) proposing a general rate increase to be effective on November 1, 2006. In April 2007, the Federal Energy
Regulatory Commission (FERC) approved a Stipulation and Agreement of Settlement (Stipulation and Agreement) that resolved the primary components of the rate case. Transwesterns tariff rates and fuel charges are now
final for the period of the settlement. Transwestern is not required to file a new rate case until October 1, 2011.



12



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The Phoenix project, as filed with the FERC on September 15, 2006, includes the construction and
operation of approximately 260 miles of 36-inch or larger diameter pipeline extending from Transwesterns existing mainline in Yavapai County, Arizona to delivery points in the Phoenix, Arizona area and certain looping on Transwesterns
existing San Juan Lateral with approximately 25 miles of 36-inch diameter pipeline. On November 15, 2007, the FERC issued an order granting Transwestern its Certificate of Public Convenience and Necessity (Order). Pursuant to the
Order, Transwestern filed its initial Implementation Plan on November 14, 2007 and accepted the Order on November 19, 2007. On December 17, 2007, two parties filed requests for rehearing of the Order and on December 20, 2007, one
party filed a motion to stay the Order. On February 21, 2008, the FERC reaffirmed its decision in the Order; thus, Transwestern notified customers of the commencement of construction in January 2008. The San Juan Lateral portion of the project
was placed in service effective July 2008 and the pipeline to the Phoenix area is expected to be in service in phases during the third and fourth quarters of 2008. The total project cost estimate, including funds used during construction, is now
expected to be 10% to 20% higher than the initial estimate of $710.0 million. The expected increase is due to a variety of factors, including higher than expected costs of obtaining right-of-ways and permits, construction costs and environmental
inspector costs. A principal factor in the increased cost of right-of ways and construction costs was the adverse ruling Transwestern received from the Arizona Federal District Court with respect to our request for preliminary injunctive relief for
immediate possession of then outstanding rights-of-way. Although Transwestern has appealed this ruling to the Ninth Circuit Court of Appeals, Transwestern has also finalized the acquisition of substantially all of the remaining
right-of-way.

On December 13, 2006, we entered into an agreement with Kinder Morgan Energy Partners, L.P. (KMP) for a 50/50
joint development of Midcontinent Express Pipeline, an approximately 500-mile interstate natural gas pipeline that will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with
Transcos interstate natural gas pipeline in Butler, Alabama, is currently pending necessary regulatory approvals. On February 14, 2007, Midcontinent Express Pipeline LLC (MEP), the entity formed to own and operate this
pipeline, initiated public review of the project pursuant to the FERCs NEPA pre-filing review process. MEP filed its application with the FERC for a Certificate of Public Convenience and Necessity in October, 2007. In June 2008, the FERC
issued an order approving this application. Construction of this pipeline is expected to commence in September 2008, and the pipeline is expected to be in service by the second quarter of 2009. Total capital expenditures for the initial design of
this project are estimated to be $1.45 billion. In July 2008, MEP completed an open season with respect to a capacity expansion of MEP from the original planned capacity of 1.5 Bcf/d to a total capacity of 1.8 Bcf/d for the main segment of the
pipeline from north Texas to a planned interconnect location with the Columbia Gas Transmission Pipeline near Waverly, Louisiana. The additional 300,000 Mcf/d of capacity was fully subscribed as a result of this open season. The planned expansion of
capacity would be effectuated through the installation of additional compression on this segment of the pipeline. This expansion project is subject to MEPs filing of an application with, and approval from, the FERC.

On February 29, 2008, MEP entered into a credit agreement that provides for a $1.4 billion senior revolving credit facility (the MEP
Facility). We have guaranteed 50% of the obligations of MEP under the MEP Facility, with the remaining 50% of MEP Facility obligations guaranteed by KMP. Subject to certain exceptions, our guarantee may be proportionately increased or
decreased if our ownership percentage increases or decreases. The MEP Facility is available through February 28, 2011. Amounts borrowed under the MEP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The
commitment fee payable on the unused portion of the MEP Facility varies based on both our credit rating and that of KMP, with a maximum fee of 0.15%. The MEP Facility also has a swingline loan option with a maximum borrowing of $25.0 million at a
prime rate. The sum of the loans, swingline loans and letters of credit may not exceed the maximum amount of revolving credit available under the MEP Facility. The indebtedness under the MEP Facility is prepayable at any time at the option of MEP
without penalty. The MEP Facility contains covenants that limit (subject to certain exceptions) MEPs ability to grant liens, incur indebtedness, engage in transactions with affiliates, enter into restrictive agreements, enter into mergers, or
dispose of substantially all of its assets. As of June 30, 2008, MEP had $385.0 million of outstanding borrowings and $172.4 million of letters of credit issued under the MEP Facility. The weighted average interest rate on the total amount
outstanding as of June 30, 2008 was 3.167%. The total amount available under the MEP Facility was $842.6 million as of June 30, 2008.

MEP also has a $197.0 million reimbursement agreement, under which MEP may issue letters of credit. We have guaranteed 50% of the obligations of MEP under the reimbursement agreement, with the remaining 50% guaranteed by KMP. As of
June 30, 2008, MEP had $33.3 million of letters of credit issued under the reimbursement agreement.



13



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Commitments

In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and enter into long-term transportation and storage agreements. Such contracts contain terms that are
customary in the industry. We have also entered into several propane purchase and supply commitments which are typically one year agreements with varying terms as to quantities, prices and expiration dates. We believe that the terms of these
agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.

We
have certain non-cancelable leases for property and equipment which require fixed monthly rental payments and expire at various dates through 2020.

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations
in the normal course of business. Natural gas and propane are flammable, combustible gases. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of
business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with
coverages and deductibles 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.

FERC/CFTC and Related Matters. On July 26, 2007, the FERC issued to us an Order to Show Cause and Notice of Proposed Penalties (the
Order and Notice) that contains allegations that we violated FERC rules and regulations. The FERC has alleged that we engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the
fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight other occasions from December 2003 through August 2005, in order to benefit financially from our commodities derivatives positions and from certain of our
index-priced physical gas purchases in the Houston Ship Channel. The FERC has alleged that during these periods we violated the FERCs then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by the FERC under
authority of the Natural Gas Act (NGA). We allegedly violated this rule by artificially suppressing prices that were included in the Platts Inside FERC Houston Ship Channel index, published by McGraw-Hill Companies, on which the
pricing of many physical natural gas contracts and financial derivatives are based. Additionally, the FERC has alleged that we manipulated daily prices at the Waha and Permian Hubs in west Texas on two dates. Our Oasis pipeline transports interstate
natural gas pursuant to Natural Gas Policy Act (NGPA) Section 311 authority and is subject to the FERC-approved rates, terms and conditions of service. The allegations related to the Oasis pipeline include claims that the Oasis
pipeline violated NGPA regulations from January 26, 2004 through June 30, 2006 by granting undue preference to its affiliates for interstate NGPA Section 311 pipeline service to the detriment of similarly situated non-affiliated
shippers and by charging in excess of the FERC-approved maximum lawful rate for interstate NGPA Section 311 transportation. The FERC also seeks to revoke, for a period of 12 months, our blanket marketing authority for sales of natural gas in
interstate commerce at market-based prices, which activity is expected to account for approximately 1.0% of our operating income for our 2008 calendar year. If the FERC is successful in revoking our blanket marketing authority, our sales of natural
gas at market-based prices would be limited to sales to retail customers (such as utilities and other end users) and sales from our own production, if any, and any other sales of natural gas by us would be required to be made at contract prices that
would be subject to individual FERC approval.

In its Order and Notice, the FERC is seeking $70.1 million in disgorgement of profits, plus
interest, and $97.5 million in civil penalties relating to these matters. The FERC has taken the position that, once it receives ETPs response, it has several options as to how to proceed, including issuing an order on the merits, requesting
briefs, or setting specified issues for a trial-type hearing before an administrative law judge. On August 27, 2007, ETP filed a request for rehearing of the Order and Notice. On December 20, 2007, the FERC issued an order denying
rehearing and directed FERC Staff to file a brief recommending disposition of issues by order or by evidentiary hearing. ETP filed its response to the Order and Notice with the FERC on October 9, 2007, which response refuted the FERCs
claims and requested a dismissal of the FERC proceeding. On February 14, 2008, the Enforcement Staff of the



14



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FERC filed a brief recommending that the FERC refer various matters relating to its market manipulation allegations for an evidentiary hearing before a FERC
administrative law judge. The Enforcement Staff also recommended that FERC issue an order assessing the $15.5 million portion of the above-referenced penalty against ETP with respect to the allegations related to ETPs Oasis Pipeline and that
the Oasis-related penalty assessment, if not paid, then be referred by the FERC to a federal district court for de novo review. The Enforcement Staff also recommended that the FERC impose certain changes in Oasis business operations and
refunds to certain Oasis customers as previously proposed in the Order and Notice. Finally, the Enforcement Staff recommended that the FERC pursue market manipulation claims related to ETPs trading activities in October 2005, for November
2005 monthly deliveries, a period not previously covered by FERCs allegations in the Order and Notice, and that ETP be assessed an additional civil penalty of $25.0 million and be required to disgorge approximately $7.3 million of alleged
unjust profits related to this additional month. If the FERC pursues the claims related to this additional month, the total amount of civil penalties and disgorgement of profits sought by the FERC would be approximately $200.0 million. On
March 31, 2008, we responded to the Enforcement Staffs brief. On April 25, 2008, the Enforcement Staff filed an answer to our March 31, 2008 pleading. On May 15, 2008, the FERC ordered hearings to be conducted by FERC
administrative law judges with respect to the FERC's Oasis claims and market manipulation claims. The hearing related to the Oasis claims is scheduled to commence in December 2008 with the administrative law judges initial decision due by
April 27, 2009 and the hearing related to the market manipulation claims is scheduled to commence in April 2009 with the administrative law judges initial decision due by October 5, 2009. The FERC denied our request for dismissal of
the proceeding and has ordered that, following the completion of the hearings, the administrative law judges make recommendations with respect to whether we engaged in market manipulation in violation of the NGA and FERC regulations and whether
Oasis violated the NGPA and FERC regulations. The FERC reserved for itself the issues of possible civil penalties, revocation of our blanket market certificate, method by which we and Oasis would disgorge any unjust profits and whether any
conditions should be placed on Oasiss Section 311 authorization. Following the issuance of each of the administrative law judges initial decision, the FERC would then issue an order with respect to each of these matters. On
May 23, 2008, we requested rehearing and stay of the FERC's May 15, 2008 order establishing hearing, and we renewed those requests on June 26, 2008. On August 7, 2008, FERC denied rehearing of its May 15, 2008 order. On August 8,
2008, we filed a petition with the U.S. Court of Appeals for the Fifth Circuit to review and set aside FERCs May 15 and August 7, 2008 orders on the grounds that we are entitled to adjudicate FERCs claims in federal district court
pursuant to the NGA and the NGPA.

It is ETPs position that its trading and transportation activities during the periods at issue
complied in all material aspects with applicable law and regulations, and ETP intends to contest these cases vigorously. However, the laws and regulations related to alleged market manipulation are vague, subject to broad interpretation, and offer
little guiding precedent, while at the same time the FERC holds substantial enforcement authority. At this time, neither we nor ETP is able to predict the final outcome of these matters.

On July 26, 2007, the United States Commodity Futures Trading Commission (the CFTC) filed suit in United States District Court for the
Northern District of Texas alleging that we violated provisions of the Commodity Exchange Act (the CEA) by attempting to manipulate natural gas prices in the Houston Ship Channel. On March 17, 2008, ETP entered into a consent order
with the CFTC (the Consent Order). Pursuant to the Consent Order, ETP agreed to pay the CFTC $10.0 million and the CFTC agreed to release ETP and its affiliates, directors and employees from all claims or causes of action asserted by the
CFTC in this proceeding. The Consent Order provides that ETP is permanently enjoined from attempting to manipulate the price of any commodity in interstate commerce in violation of the CEA. By consenting to the entry of the Consent Order, ETP
neither admitted nor denied the allegations made by the CFTC in this proceeding. The settlement reduced our existing accrual and was paid from cash flow from operations in March 2008.

In addition to the FERC legal action, third parties have asserted claims and may assert additional claims against us and ETP for damages related to these
matters. In this regard, several natural gas producers and a natural gas marketing company have initiated legal proceedings in Texas state courts against us and ETP for claims related to the FERC claims. These suits contain contract and tort claims
relating to alleged manipulation of natural gas prices at the Houston Ship Channel and the Waha Hub in West Texas, as well as the natural gas price indices related to these markets and the Permian Basin natural gas price index during the period from
December 2003 through December 2006, and seek unspecified direct, indirect, consequential and exemplary damages. One of the suits against us and ETP contains an additional allegation that the defendants transported gas in a manner that favored their
affiliates and discriminated against the plaintiff, and otherwise artificially affected the market price of gas to other parties in the market. We have also been served with a complaint from an owner of royalty interests in natural gas producing
properties, individually and on behalf of a putative class of similarly situated royalty owners, working interest owners and producers/operators, seeking arbitration to recover damages based on alleged manipulation of natural gas prices at the
Houston Ship Channel. We have filed an original action in Harris County state court



15



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seeking a stay of the arbitration on the ground that the action is not arbitrable. The claimants have agreed to a stay of the arbitration pending briefing on
cross-motions for summary judgment in the state court proceeding. Briefing on these cross-motions is expected to be completed on August 11, 2008, and a hearing on the cross-motions is set for August 29, 2008.

A consolidated class action complaint has been filed against us in the United States District Court for the Southern District of Texas. This action
alleges that we engaged in intentional and unlawful manipulation of the price of natural gas futures and options contracts on the New York Mercantile Exchange, or NYMEX, in violation of the CEA. It is further alleged that during the class period
December 29, 2003 to December 31, 2005, we had the market power to manipulate index prices, and that we used this market power to artificially depress the index prices at major natural gas trading hubs, including the Houston Ship Channel,
in order to benefit our natural gas physical and financial trading positions and intentionally submitted price and volume trade information to trade publications. This complaint also alleges that we violated the CEA by knowingly aiding and abetting
violations of the CEA. The plaintiffs state that this allegedly unlawful depression of index prices by us manipulated the NYMEX prices for natural gas futures and options contracts to artificial levels during the class period, causing unspecified
damages to the plaintiffs and all other members of the putative class who sold natural gas futures or who purchased and/or sold natural gas options contracts on NYMEX during the class period. The plaintiffs have requested certification of their suit
as a class action, and seek unspecified damages, court costs and other appropriate relief. On January 14, 2008, ETP filed a motion to dismiss this suit on the grounds of failure to allege facts sufficient to state a claim. On March 20,
2008, the plaintiffs filed a second consolidated class action complaint. In response to this new pleading, on May 5, 2008 we filed a motion to dismiss the complaint. On June 19, 2008 the plaintiffs filed a response opposing ETPs
motion to dismiss.

On March 17, 2008, a second class action complaint was filed against us in the United States District Court for the
Southern District of Texas. This action alleges that we engaged in unlawful restraint of trade and intentional monopolization and attempted monopolization of the market for fixed-price natural gas baseload transactions at the Houston Ship Channel
from December 2003 through December 2005 in violation of federal antitrust law. The complaint further alleges that during this period we exerted monopoly power to suppress the price for these transactions to non-competitive levels in order to
benefit from our own physical natural gas positions. The plaintiff has, individually and on behalf of all other similarly situated sellers of physical natural gas, requested certification of its suit as a class action and seeks unspecified treble
damages, court costs and other appropriate relief. On May 19, 2008, ETP filed a motion to dismiss this complaint.

We are expensing the
legal fees, consultants fees and other expenses relating to these matters in the periods in which such expenses are incurred. In addition, our existing accruals for litigation and contingencies include an accrual related to these matters. At
this time, we are unable to predict the outcome of these matters; however, it is possible that the amount we become obliged to pay as a result of the final resolution of these matters, whether on a negotiated settlement basis or otherwise, will
exceed the amount of our accrual related to these matters. In accordance with applicable accounting standards, we will review the amount of our accrual related to these matters as developments related to these matters occur and we will adjust our
accrual if we determine that it is probable that the amount we may ultimately become obliged to pay as a result of the final resolution of these matters is greater than the amount of our existing accrual for these matters. As our accrual amounts are
non-cash, any cash payment of an amount in resolution of these matters would likely be made from cash from operations or borrowings, which payments would reduce our cash available for distributions either directly or as a result of increased
principal and interest payments necessary to service any borrowings incurred to finance such payments. If these payments are substantial, we may experience a material adverse impact on our results of operations, cash available for distribution and
our liquidity.

In re Natural Gas Royalties Qui Tam Litigation. MDL Docket No. 1293 (D. WY), Jack Grynberg, an individual, has
filed actions against a number of companies, including Transwestern, now transferred to the U.S. District Court for the District of Wyoming, for damages for mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral
interest owners. On October 20, 2006, the District Judge adopted in part the earlier recommendation of the Special Master in the case and ordered the dismissal of the case against Transwestern. Transwestern believes that its measurement
practices conformed to the terms of its FERC Gas Tariff, which were filed with and approved by the FERC. As a result, Transwestern believes that is has meritorious defenses to these lawsuits (including FERC-related affirmative defenses, such as the
filed rate/tariff doctrine, the primary/exclusive jurisdiction of the FERC, and the defense that Transwestern complied with the terms of its tariffs) and will continue to vigorously defend against them, including any appeal which may be taken from
the dismissal of the Grynberg



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case. Transwestern does not believe the outcome of this case will have a material adverse effect on its financial position, results of operations or cash
flows. A hearing was held on April 24, 2007 regarding Transwesterns Supplemental Brief for Attorneys fees which was filed on January 8, 2007 and the issues are submitted and are awaiting a decision. Grynberg moved to have the
cases he appealed remanded to the district court for consideration in light of a recently-issued Supreme Court case. The defendants/appellees opposed the motion. The Tenth Circuit motions panel referred the remand motion to the merits panel to be
carried with the appeals. Grynbergs opening brief was filed on or about July 31, 2007. Appellees opposition brief was filed on or about November 21, 2007. Appellee Transwestern filed its separate response brief on
January 11, 2008 and Grynbergs reply brief was filed in June 2008 and it is anticipated that the hearing on all briefs will be in September 2008.

Houston Pipeline Cushion Gas Litigation. At the time of the HPL System acquisition, AEP Energy Services Gas Holding Company II, L.L.C., HPL Consolidation LP and its subsidiaries (the HPL Entities),
their parent companies and American Electric Power Corporation (AEP), were engaged in ongoing litigation with Bank of America (B of A) that related to AEPs acquisition of HPL in the Enron bankruptcy and B of As
financing of cushion gas stored in the Bammel Storage Facility (Cushion Gas). This litigation is referred to as the Cushion Gas Litigation. Under the terms of the Purchase and Sale Agreement and the related Cushion Gas
Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation
and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory (approximately $1.0 billion in the aggregate). The Cushion Gas Litigation Agreement terminates upon final
resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or
indemnify ETC OLP and the HPL Entities for the costs related to such matters. On December 18, 2007, the United States District Court for the Southern District of New York held that B of A is entitled to receive monetary damages from AEP and the
HPL Entities of approximately $347.3 million less the monetary amount B of A would have incurred to remove 55 Bcf of natural gas from the Bammel Storage Facility. AEP filed a notice of motion for reconsideration questioning the courts damages
calculation. AEP will determine whether it will appeal the court decision once a final judgment is entered. Based on the indemnification provisions of the Cushion Gas Litigation Agreement, ETP does not expect that it will be liable for any portion
of this court award.

Other Matters. In addition to those matters described above, we or our subsidiaries are a party to various
legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable
outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable, can be estimated and is not covered by insurance, we make an accrual for the matter. For matters that are covered by
insurance, we accrue the related deductible. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty and it is possible that the outcome of a particular matter will result in the payment of
an amount in excess of the amount accrued for the matter. As our accrual amounts are non-cash, any cash payment of an amount in resolution of a particular matter would likely be made from cash from operations or borrowings. If cash payments to
resolve a particular matter substantially exceed our accrual for such matter, we may experience a material adverse impact on our results of operations, cash available for distribution and our liquidity.

As of June 30, 2008, an accrual of $20.4 million was recorded as accrued and other current liabilities and other non-current liabilities on our
condensed consolidated balance sheet for our contingencies and current litigation matters, excluding accruals related to environmental matters.

Environmental

Our 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 we believe our 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



17



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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, we have 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 entities engaged in similar businesses.

Transwestern conducts soil and groundwater remediation at
a number of its facilities. Some of the clean up activities include historical remediation obligations at several compressor sites on the Transwestern system for presence of polychlorinated biphenyls (PCBs) which are not eligible for
recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2018 is $10.1 million. Transwestern received FERC approval for rate recovery of the portion of soil and groundwater remediation not
related to PCBs effective April 1, 2007.

Environmental regulations were recently modified for United States Environmental Protection
Agencys Spill Prevention, Control and Countermeasures (SPCC) program. We are currently reviewing the impact to our operations and expect to expend resources on tank integrity testing and any associated corrective actions as well as
potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our
financial position, results of operations or cash flows.

In July 2001, HOLP 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 HOLP 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). We have not
received any follow-up correspondence from the EPA on the matter since our acquisition of the predecessor company in 2001. Based upon information currently available to us, it is believed that HOLPs liability if such action were to be taken by
the EPA would not have a material adverse effect on our financial condition or results of operations.

Petroleum-based contamination or
environmental wastes are known to be located on or adjacent to six sites on which HOLP 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, HOLP obtained indemnification rights for expenses associated with any remediation from the former owners or related entities. We have not been named as a potentially responsible party at
any of these sites, nor have our operations contributed to the environmental issues at these sites. Accordingly, no amount has been recorded in our June 30, 2008 condensed consolidated balance sheet. Based on information currently available to
us, such projects are not expected to have a material adverse effect on our financial condition.

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 our 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, we believe that such costs will not have
a material adverse effect on our financial position.

As of June 30, 2008, an accrual on an undiscounted basis of $14.2 million was
recorded in our condensed consolidated balance sheet as accrued and other current liabilities and other non-current liabilities to cover material environmental liabilities related to certain matters assumed in connection with the HPL acquisition,
the Transwestern acquisition, and the potential environmental liabilities for three sites that were formerly owned by Titan or its predecessors.



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Based on information available at this time and reviews undertaken to identify potential exposure, we
believe the amount reserved for all of the above environmental matters is adequate to cover the potential exposure for clean-up costs.

Our
pipeline operations are subject to regulation by the U.S Department of Transportation (DOT) under the Pipeline Hazardous Materials Safety Administration (PHMSA) pursuant to which the PHMSA has established regulations relating
to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity
management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as high consequence areas. Through June 30, 2008, Transwestern did not incur any
costs associated with the IMP Rule and has satisfied all of the requirements until 2010. Through June 30, 2008, a total of $4.0 million of capital costs and $10.4 million of operating and maintenance costs have been incurred for pipeline
integrity testing for our transportation assets other than Transwestern. Through June 30, 2008, a total of $1.5 million of capital costs and $0.3 million of operating and maintenance costs have been incurred for pipeline integrity costs for
Transwestern. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur even greater capital and operating expenditures for repairs or upgrades
deemed necessary to ensure the continued safe and reliable operation of its pipelines.



|8. | PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:
|-- | ---------------------------------------------

Accounting for Derivative Instruments and Hedging Activities

We have established a formal risk management policy in which
derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. We apply Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging
Activities (SFAS 133) as amended to account for our derivative financial instruments. This statement requires that all derivatives be 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.

At inception of a hedge, we formally document the relationship between the hedging
instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a
quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting
prospectively by including changes in the fair value of the derivative in current earnings.

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGL and propane prices. To reduce the impact of this price volatility, we
primarily utilize various exchange-traded and over-the-counter commodity financial instrument contracts to limit our exposure to margin fluctuations in natural gas, NGL and propane prices. These contracts consist primarily of futures and swaps and
are recorded at fair value on the condensed consolidated balance sheet. We have established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated
transaction. Furthermore, management reviews the creditworthiness of the derivative counterparties to manage against the risk of default on a bi-weekly basis.

We use a combination of financial instruments including, but not limited to, futures, price swaps, options and basis swaps to manage our exposure to market fluctuations in the prices of natural gas and NGLs. We enter
into these financial instruments with brokers who are clearing members with NYMEX and directly with counterparties in the over-the-counter (OTC) market. We are subject to margin deposit requirements under the OTC agreements and NYMEX
positions. NYMEX requires brokers to obtain an initial margin deposit based on an expected volume of the trade when the financial instrument is initiated. This amount is paid to the broker by both counterparties of the financial instrument to
protect the broker from default by one of the counterparties when the financial instrument settles. We also have maintenance margin deposits with certain counterparties in the OTC market. The payments



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on margin deposits occur when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on
the settlement date. We had net deposits with derivative counterparties of $60.4 million as of June 30, 2008 reflected as deposits paid to vendors on our condensed consolidated balance sheet.

The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily
available market information, broker quotes and appropriate valuation techniques.

Non-trading Activities

If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in
Accumulated Other Comprehensive Income (OCI) until the underlying hedged transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional
two-month period of time thereafter. For those financial derivative instruments that do not qualify for hedge accounting, the change in market value is recorded in earnings.

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

Trading Activities

Trading activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. Certain activities where limited market risk is assumed are considered trading for accounting
purposes and are executed with the use of a combination of financial instruments including, but not limited to, basis contracts and gas daily contracts. The derivative contracts that are entered into for trading purposes, subject to limits, are
recognized on the condensed consolidated balance sheet at fair value.

The following table details the outstanding commodity-related
derivatives as of June 30, 2008:



|                              |  |           |  |                     |   |  |           |  |                            |         |  
|----------------------------- |  | --------- |  | ------------------- | - |  | --------- |  | -------------------------- | ------- | -
|                              |  | Commodity |  | NotionalVolumeMMBTU |   |  | Maturity  |  | FairValueAsset (Liability) |        
|Mark to Market Derivatives    |  |           |  |                     |   |  |           |  |                            |         |  
|(Non-Trading)                 |  |           |  |                     |   |  |           |  |                            |         |  
|Basis Swaps IFERC/NYMEX       |  | Gas       |  | 16,110,000          |   |  | 2008-2011 |  | $                          | 97      |  
|Swing Swaps IFERC             |  | Gas       |  | (12,607,000         | ) |  | 2008-2009 |  |                            | (500    | )
|Fixed Swaps/Futures           |  | Gas       |  | (10,165,000         | ) |  | 2008-2009 |  |                            | (28,523 | )
|Forward Physical Contracts    |  | Gas       |  | (7,222,084          | ) |  | 2008      |  |                            | (449    | )
|Options                       |  | Gas       |  | (306,000            | ) |  | 2008      |  |                            | (1      | )
|Forwards/Swaps - in Gallons   |  | Propane   |  | 28,560,000          |   |  | 2008-2009 |  |                            | 6,649   |  
|                              |  |           |  |                    
|(Trading)                     |  |           |  |                     |   |  |           |  |                            |         |  
|Basis Swaps IFERC/NYMEX       |  | Gas       |  | (16,867,500         | ) |  | 2008-2009 |  | $                          | 5,177   |  
|                              |  |           |  |                    
|Cash Flow Hedging Derivatives |  |           |  |                     |   |  |           |  |                            |         |  
|(Non-Trading)                 |  |           |  |                     |   |  |           |  |                            |         |  
|Basis Swaps IFERC/NYMEX       |  | Gas       |  | 1,372,500           |   |  | 2008-2009 |  | $                          | (163    | )
|Fixed Swaps/Futures           |  | Gas       |  | 1,372,500           |   |  | 2008-2009 |  |                            | 6,773   |  

Estimates related to our gas marketing activities are sensitive to uncertainty and volatility
inherent in the energy commodities markets and actual results could differ from these estimates. We also attempt to maintain balanced positions in our non-trading activities to protect ourselves from the volatility in the energy commodities markets;
however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, is expected to 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



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contract. Financial contracts, which are not tied to physical delivery, are expected to be offset with financial contracts to balance our positions. To the
extent open commodity positions exist in our trading and non-trading activities, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably.

Interest Rate Risk

We are exposed to
market risk for changes in interest rates related to our bank credit facilities. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements which allow us to effectively convert a portion of variable
rate debt into fixed rate debt. Certain of our interest rate derivatives are accounted for as cash flow hedges. At June 30, 2008, we had $734.2 million of variable rate debt outstanding and a pay fixed receive float interest rate
swap with a notional amount of $125.0 million that is not designated as a hedge. Changes in fair value of the swap are recorded in earnings.

We are also subject to interest rate risk on our fixed rate debt if interest rates decrease. To manage this risk, 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.

The following table represents interest rate swap derivatives at June 30, 2008:



|           |  |                |         |      |                              |               |    |                     |   |      
|---------- |  | -------------- | ------- | ---- | ---------------------------- | ------------- | -- | ------------------- | - | -----
|Term       |  | NotionalAmount |         | Type |                              | SFAS 133Hedge |    | Fair ValueLiability
|March 2009 |  | $              | 125,000 |      | Pay Fixed 5.14%Receive Float |               | No |                     | $ | 2,086

Credit Risk

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties financial condition (including
credit ratings), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty.

Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of
counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and
other reserves, management does not anticipate a material adverse effect on financial position as a result of counterparty performance.



|9. | RELATED PARTY TRANSACTIONS:
|-- | ---------------------------

Accounts
receivable from and accounts payable to related companies as of June 30, 2008 relate primarily to activities in the normal course of business.

ETC OLP and Enterprise transport natural gas on each others pipelines, share operating expenses on jointly-owned pipelines, and ETC OLP sells natural gas to Enterprise. Our propane operations routinely buy and sell product with
Enterprise. The following table summarizes the related party balances with Enterprise at June 30, 2008:



|                        |  |   |       
|----------------------- |  | - | ------
|Natural Gas Operations: |  |   |       
|Accounts receivable     |  | $ | 10,554
|Accounts payable        |  |   | 11,003
|Imbalance payable       |  |   | 9,137 
|                        | 
|Propane Operations:     |  |   |       
|Accounts receivable     |  | $ | 858   
|Accounts payable        |  |   | 13,544



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Accounts receivable from related companies excluding Enterprise consist of the following at June 30,
2008:



|                                                                      |  |   |      
|--------------------------------------------------------------------- |  | - | -----
|ETE                                                                   |  | $ | 2,529
|MEP                                                                   |  |   | 4,914
|Others                                                                |  |   | 530  
|                                                                      |  |   |      
|Total accounts receivable from related companies excluding Enterprise |  | $ | 7,973
|                                                                      |  |   |      



|10. | SUPPLEMENTAL INFORMATION:
|--- | -------------------------

Following is the
balance sheet of the Partnership which is included to provide additional information with respect to ETP GPs financial position on a stand-alone basis as of June 30, 2008:



|                                        |  |   |        
|--------------------------------------- |  | - | -------
|ASSETS                                  |  |   |        
|                                        | 
|CURRENT ASSETS:                         |  |   |        
|Cash and cash equivalents               |  | $ | 57     
|Prepaid expenses and other              |  |   | 62     
|                                        |  |   |        
|Total current assets                    |  |   | 119    
|                                        | 
|INVESTMENT IN ENERGY TRANSFER PARTNERS  |  |   | 145,783
|GOODWILL                                |  |   | 29,588 
|OTHER LONG-TERM ASSETS                  |  |   | 250    
|                                        |  |   |        
|Total assets                            |  | $ | 175,740
|                                        |  |   |        
|LIABILITIES AND PARTNERS CAPITAL       |  |   |        
|                                        | 
|CURRENT LIABILITIES:                    |  |   |        
|Accounts payable to related company     |  | $ | 128    
|Accrued liabilities                     |  |   | 17     
|Current maturities of long-term debt    |  |   | 31     
|                                        |  |   |        
|Total current liabilities               |  |   | 176    
|                                        | 
|LONG-TERM DEBT, less current maturities |  |   | 199    
|                                        |  |   |        
|                                        |  |   | 375    
|                                        |  |   |        
|PARTNERS CAPITAL:                      |  |   |        
|General partner                         |  |   | 16     
|Limited partners -                      |  |   |        
|Class A Limited Partner interests       |  |   | 84,889 
|Class B Limited Partner interests       |  |   | 90,277 
|Accumulated other comprehensive income  |  |   | 183    
|                                        |  |   |        
|Total partners capital                 |  |   | 175,365
|                                        |  |   |        
|Total liabilities and partners capital |  | $ | 175,740
|                                        |  |   |        



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