Energy Transfer (ET) 8-K Report of Independent Registered Public Accounting Firm

EXHIBIT 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Partners

Energy Transfer Equity, L.P.

We have audited the accompanying consolidated balance sheet of Energy Transfer Equity, L.P. (a Delaware limited partnership) and subsidiaries as of December 31, 2007, and the related consolidated statements of operations, comprehensive income, partners’ capital (deficit), and cash flows for the four months then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting as of December 31, 2007. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy Transfer Equity, L.P. and subsidiaries as of December 31, 2007, and the results of their operations and their cash flows for the four months then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Dallas, Texas

March 18, 2008

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

December 31, 2007

(Dollars in thousands)

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	56,557
Marketable securities		3,002
Accounts receivable, net of allowance for doubtful accounts		822,027
Accounts receivable from related companies		18,070
Inventories		361,954
Deposits paid to vendors		42,273
Exchanges receivable		37,321
Price risk management assets		8,203
Prepaid expenses and other		54,389
Total current assets		1,403,796
PROPERTY, PLANT AND EQUIPMENT, net		6,852,458
LONG-TERM PRICE RISK MANAGEMENT ASSETS		36
ADVANCES TO AND INVESTMENT IN AFFILIATES		86,167
GOODWILL		757,698
INTANGIBLES AND OTHER LONG-TERM ASSETS, net		361,939
Total assets	$	9,462,094

The accompanying notes are an integral part of this consolidated financial statement.

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

December 31, 2007

(Dollars in thousands)

LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
CURRENT LIABILITIES:
Accounts payable	$	673,116
Accounts payable to related companies		48,012
Exchanges payable		40,382
Customer advances and deposits		75,831
Accrued and other current liabilities		335,784
Price risk management liabilities		13,547
Income taxes payable		7,264
Deferred income taxes		429
Current maturities of long-term debt		47,068
Total current liabilities		1,241,433
LONG-TERM DEBT, less current maturities		5,870,106
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		46,479
DEFERRED INCOME TAXES		199,934
OTHER NON-CURRENT LIABILITIES		12,986
MINORITY INTERESTS		2,106,819
COMMITMENTS AND CONTINGENCIES (Note 10)
Total liabilities		9,477,757
PARTNERS’ CAPITAL (DEFICIT):
General Partner		192
Limited Partners—Common Unitholders (222,829,956 units authorized, issued and outstanding)		(4,628	)
		(4,436	)
Accumulated other comprehensive loss, per accompanying statement		(11,227	)
Total partners’ deficit		(15,663	)
Total liabilities and partners’ capital (deficit)	$	9,462,094

The accompanying notes are an integral part of this consolidated financial statement.

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

For the Four Months Ended December 31, 2007

(Dollars in thousands, except per unit data)

REVENUES:
Natural gas operations	$	1,832,192
Retail propane		471,494
Other		45,656
Total revenues		2,349,342
COSTS AND EXPENSES:
Cost of products sold, natural gas operations		1,343,237
Cost of products sold, retail propane		315,698
Cost of products sold, other		14,719
Operating expenses		221,757
Depreciation and amortization		75,406
Selling, general and administrative		61,874
Total costs and expenses		2,032,691
OPERATING INCOME		316,651
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(103,375	)
Equity in losses of affiliates		(94	)
Gain on disposal of assets		14,310
Other expense, net		(34,734	)
INCOME BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS		192,758
Income tax expense		9,949
INCOME BEFORE MINORITY INTERESTS		182,809
Minority interests		(90,132	)
NET INCOME		92,677
GENERAL PARTNER’S INTEREST IN NET INCOME		287
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	92,390
BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.41
BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		222,829,916
DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.41
DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		222,829,916

The accompanying notes are an integral part of this consolidated financial statement.

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

For the Four Months Ended December 31, 2007

(Dollars in thousands)

Net income	$	92,677
Other comprehensive loss, net of tax:
Reclassification adjustment for gains and losses on derivative instruments accounted for as cash flow hedges included in net income		(17,970	)
Change in value of derivative instruments accounted for as cash flow hedges		(2,221	)
Change in value of available-for-sale securities		(98	)
Minority interests		(2,700	)
Comprehensive income	$	69,688
Reconciliation of Accumulated Other Comprehensive Income (Loss), net of tax
Balance, beginning of period	$	11,762
Current period reclassification to earnings		(17,970	)
Current period change in value		(2,319	)
Minority interests		(2,700	)
Balance, end of period	$	(11,227	)
Components of Accumulated Other Comprehensive Income (Loss), net of tax
Commodity related hedges	$	25,497
Interest rate hedges		(22,439	)
Available-for-sale securities		483
Minority interests		(14,768	)
Balance, end of period	$	(11,227	)

The accompanying notes are an integral part of this consolidated financial statement.

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL (DEFICIT)

For The Four Months Ended December 31, 2007

(Dollars in thousands)

	General Partner			Limited Partners - Common Unitholders
Balance, August 31, 2007	$	24		$	(58,918	)
Distribution to partners		(270	)		(86,904	)
Unit-based compensation		—			23
Subsidiary sale of common units		151			48,781
Net income		287			92,390
Balance, December 31, 2007	$	192		$	(4,628	)

The accompanying notes are an integral part of this consolidated financial statement.

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

For the Four Months Ended December 31, 2007

(Dollars in thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	92,677
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		75,406
Amortization of finance costs charged to interest		2,441
Provision for loss on accounts receivable		544
Non-cash compensation on unit grants		8,137
Non-cash executive compensation		442
Distributed earnings of affiliates, net		4,448
Deferred income taxes		37
Gain on disposal of assets		(14,310	)
Minority interests and other non-cash		88,063
Subsidiary distributions to minority unitholders		(61,517	)
Net change in operating assets and liabilities, net of acquisitions		(49,250	)
Net cash provided by operating activities		147,118
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		(337,092	)
Capital expenditures		(647,735	)
Advances to and investment in affiliates		(32,594	)
Proceeds from the sale of assets		21,478
Net cash used in investing activities		(995,943	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,742,802
Principal payments on debt		(1,062,272	)
Subsidiary equity offering net of issue costs		234,887
Distributions to Partners		(87,174	)
Debt issuance costs		(211	)
Net cash provided by financing activities		828,032
DECREASE IN CASH AND CASH EQUIVALENTS		(20,793	)
CASH AND CASH EQUIVALENTS, beginning of period		77,350
CASH AND CASH EQUIVALENTS, end of period	$	56,557

The accompanying notes are an integral part of this consolidated financial statement.

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2007

(Dollar amounts in thousands, except per unit data)

1. OPERATIONS AND ORGANIZATION:

The accompanying consolidated financial statements of Energy Transfer Equity, L.P. and subsidiaries (“the Partnership”, “ETE” or the “Parent Company”) presented herein as of December 31, 2007 and for the four-month transition period then ended, have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). We consolidate all majority-owned and controlled subsidiaries. We recognize a minority interest liability and minority interest expense for all partially-owned consolidated subsidiaries. All significant intercompany transactions and accounts are eliminated in consolidation.

The consolidated financial statements of the Partnership presented herein as of December 31, 2007 and for the four-month transition period then ended include the results of operations of ETE, ETE’s controlled subsidiary Energy Transfer Partners, L.P., a publicly-traded master limited partnership (“ETP”), and ETE’s wholly-owned subsidiaries: Energy Transfer Partners GP, L.P., the General Partner of ETP (“ETP GP”), and Energy Transfer Partners, L.L.C., the General Partner of ETP GP (“ETP LLC”). The results of operations for ETP in turn include the results of operations for ETP’s wholly-owned subsidiaries: La Grange Acquisition, L.P. dba Energy Transfer Company (“ETC OLP”), Heritage Operating, L.P. (“HOLP”), Titan Energy Partners, L.P. (“Titan”), Heritage Holdings, Inc. (“HHI”), Energy Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”) and ETC Midcontinent Express Pipeline, LLC (“ETC MEP”) for the entire period.

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 forms of entities. 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.

LE GP, LLC (“LE GP”), the general partner of ETE, is a Delaware limited liability company which is ultimately owned by the Chief Executive Officer of ETP, Ray Davis, a director of ETE, Natural Gas Partners VI, L.P., a venture capital investor, and Enterprise GP Holdings, L.P. (“Enterprise” or “EPE”).

Business Operations

Currently, the Parent Company’s business operations are conducted only though ETP’s subsidiary operating partnerships (collectively referred to as the “Operating Partnerships”). The Parent Company’s principal sources of cash flow are its direct and indirect investments in the limited and General Partner interests in ETP.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its general and limited partners. The Parent Company-only assets and liabilities of ETE are not available to satisfy the debts and other obligations of ETP and its consolidated subsidiaries. In order to fully understand the financial condition of the Partnership on a stand-alone basis, see Note 15 for stand-alone financial information apart from that of the consolidated partnership information included herein.

In order to simplify the obligations of the Partnership under the laws of several jurisdictions in which we conduct business, our activities consist of four reportable segments, which are conducted through ETP’s Operating Partnerships:

• ETC OLP—a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations;

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• ET Interstate—the parent company of Transwestern and ETC MEP, both Delaware limited liability companies engaged in interstate transportation of natural gas;

• HOLP—a Delaware limited partnership primarily engaged in retail propane operations; and

• 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”, “ETE”, “Energy Transfer” or the “Partnership.”

ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, natural gas intrastate 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.

ETC OLP owns an interest in and operates approximately 14,100 miles of in service natural gas gathering and intrastate transportation pipelines with an additional 500 miles of intrastate pipeline under construction, three natural gas processing plants, twelve natural gas treating facilities, ten natural gas conditioning facilities and three natural gas storage facilities located in Texas.

The midstream operations focus on the gathering, compression, treating, blending, processing, and marketing of natural gas, primarily on or through the Southeast Texas System, and marketing operations related to our producer services business. We also own approximately 27 miles of gathering pipelines in New Mexico and recently acquired 1,800 miles of gathering pipelines and six natural gas conditioning facilities in the Piceance-Uinta Basin of Colorado and Utah as further described below. Revenue is primarily generated by the volumes of natural gas gathered, compressed, treated, processed, transported, purchased and sold through our pipelines (excluding the transportation pipelines) and gathering systems as well as the level of natural gas and NGL prices.

The intrastate transportation and storage operations focus on transporting natural gas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. Revenue is typically generated from fees charged to customers to reserve firm capacity on or move gas through the pipeline on an interruptible basis. A monetary fee and/or fuel retention are also components of the fee structure. Excess fuel retained after consumption is typically valued at the first of the month published market prices and strategically sold when market prices are high. The intrastate transportation and storage operations also consist of the HPL System which generates revenue primarily from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies. The use of our Bammel storage reservoir allows us to purchase physical natural gas and then sell financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin. The HPL System also transports natural gas for a variety of third party customers.

Our interstate transportation operations principally focus on natural gas transportation of Transwestern, which owns and operates approximately 2,400 miles of interstate natural gas pipeline extending from Texas through the San Juan Basin to the California border. Transwestern is a major natural gas transporter to the California border and delivers natural gas from the east end of its system to Texas intrastate and Midwest markets. The Transwestern pipeline interconnects with our existing intrastate pipelines in West Texas. The revenues of this segment consist primarily of fees earned from natural gas transportation services and operational gas sales.

Our retail propane segment sells propane and propane-related products and services. The HOLP and Titan customer base includes residential, commercial, industrial and agricultural customers.

2. SIGNIFICANT ACQUISITIONS:

On October 5, 2007, ETP acquired the Canyon Gathering System midstream business of Canyon Gas Resources, LLC from Cantera Resources Holdings, LLC (the “Canyon acquisition”) for $305,152 in cash, subject to working capital adjustments as defined in the purchase and sale agreement. The Canyon Gathering System has over 400,000 dedicated acres under long-term contracts. The Canyon assets include a gathering system in the Piceance-Uinta Basin which consists of over 1,800 miles of 2-inch to 16-inch pipe with a projected capacity of over 300 MMcf/d, as well as six conditioning plants for NGL extraction and gas treatment with a processing capacity of 90 MMcf/d. Some of the largest U.S. producers are active in the area and are major customers of the system. The results of the Canyon Gathering System are included in our midstream segment since the acquisition date. The cash paid for this acquisition was financed with borrowings under a $310,000 ETP term loan facility, as discussed further in Note 6.

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The Canyon acquisition was accounted for under the purchase method of accounting in accordance with SFAS 141, and the purchase price was preliminarily allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition, as follows:

Accounts receivable	$	4,303
Inventory		183
Prepaid and other current assets		1,612
Property, plant, and equipment		284,910
Contract rights and customer lists (6 to 15 year life)		6,351
Goodwill		10,959
Total assets acquired		308,318
Accounts payable		(2,299	)
Customer advances and deposits		(867	)
Total liabilities assumed		(3,166	)
Net assets acquired	$	305,152

Goodwill was warranted because this acquisition enhances our current operations. We expect to finalize the purchase price allocation in the third calendar quarter of 2008.

3. SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Revenue Recognition

Revenues for sales of natural gas, natural gas liquids (“NGLs”) including propane, and propane appliances, parts, and fittings are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenue from service labor, transportation, treating, compression, and gas processing, is recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available. Tank rent is recognized ratably over the period it is earned.

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

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

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

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We have a risk management policy that provides for our marketing and trading operations to execute limited strategies. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. Certain strategies are considered trading activities for accounting purposes and are accounted for on a net basis in revenues on the consolidated statements of operations. Our trading activities include purchasing and selling natural gas and the use of financial instruments, including basis contracts and gas daily contracts.

We account for our trading activities under the provisions of EITF Issue No. 02-3,Accounting for Contracts Involved in Energy Trading and Risk Management Activities (“EITF 02-3”), which requires revenue and costs related to energy trading contracts to be presented on a net basis in the statement of operations. As a result of our trading activities, discussed in Note 11, and the use of derivative financial instruments that may not qualify for hedge accounting in our midstream and transportation and storage segments, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to the risk management committee which includes members of senior management, and predefined limits and authorizations set forth by our risk management policy.

Our intrastate transportation and storage and interstate transportation segments results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) a fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Our intrastate transportation and storage segment also generates its revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities, primarily on the ET Fuel system, and to a lesser extent, on the HPL System.

Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from the midstream segment’s producer services, and from producers at the wellhead. To the extent the natural gas is obtained from producers, it is purchased at a discount to a specified price and is typically resold to customers at a price based on a published index.

We engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir on its HPL System. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. Since the acquisition of the HPL System, we have continually managed our positions to enhance the future profitability of our storage position. We expect margins from the HPL System to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.

Regulatory Accounting

Regulatory Assets and Liabilities—Transwestern is subject to regulation by certain state and federal authorities, is part of our interstate transportation segment and has accounting policies that conform to Statement of Financial Accounting Standards No. 71 (As Amended),Accounting for the Effects of Certain Types of Regulation (“SFAS 71”), which is in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory

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assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

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 the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream and transportation and storage segments 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 operating results estimated for the four months ended December 31, 2007 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.

Cash, Cash Equivalents and Supplemental Cash Flow Information

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 change 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.

The net change in cash due to changes in operating assets and liabilities (net of acquisitions) for the four months ended December 31, 2007 is comprised as follows:

Accounts receivable	$	(169,263	)
Accounts receivable from related companies		(12,091	)
Inventories		(168,430	)
Deposits paid to vendors		3,243
Exchanges receivable		(4,216	)
Prepaid expenses and other		(7,702	)
Intangibles and other long-term assets		2,523
Regulatory assets		(1,918	)
Accounts payable		195,574
Accounts payable to related companies		28,876
Customer advances and deposits		(6,775	)
Exchanges payable		6,117
Accrued and other current liabilities		48,664
Other long-term liabilities		(680	)
Income taxes payable		777
Price risk management liabilities, net		36,051
Net change in assets and liabilities, net of effect of acquisitions	$	(49,250	)

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Non-cash financing activities and supplemental cash flow information for the four months ended December 31, 2007 are as follows:

NON-CASH FINANCING ACTIVITIES:
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$	3,896
Subsidiary issuance of Common Units in connection with certain acquisitions	$	1,400
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest, net of $12,657 capitalized	$	79,084
Cash paid during the period for income taxes	$	9,135

Marketable Securities

Marketable securities we own are classified as available-for-sale securities and are reflected as a current asset on the consolidated balance sheet at fair value.

Accounts Receivable

Our midstream and intrastate transportation and storage operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty prepayment, or master set off agreement). Management reviews midstream and intrastate transportation and storage accounts receivable balances bi-weekly. Credit limits are assigned and monitored for all counterparties of the midstream and transportation and storage operations. Management believes that the occurrence of bad debt in our midstream and intrastate transportation and storage segments was not significant at the end of 2007; therefore, an allowance for doubtful accounts for the midstream and intrastate transportation and storage segments was not deemed necessary. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. There was no bad debt expense for the four months ended December 31, 2007.

Transwestern has a concentration of customers in the electric and gas utility industries as well as natural gas producers. This concentration of customers may impact Transwestern’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments or other forms of collateral to Transwestern. Transwestern sought additional assurances from customers due to credit concerns, and held aggregate prepayments of $598 at December 31, 2007, which are recorded in customer advances and deposits in the consolidated balance sheets. Transwestern’s management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to minimal credit risk. Transwestern considers many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectibility. Management believes that the occurrence of bad debt in our interstate transportation segment was not significant at the end of 2007; therefore, an allowance for doubtful accounts for interstate transportation segment was not deemed necessary. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. There was no bad debt expense for the four months ended December 31, 2007.

HOLP and Titan grant credit to their customers for the purchase of propane and propane-related products. Included in accounts receivable are trade accounts receivable arising from HOLP’s retail and wholesale propane and Titan’s retail propane operations and receivables arising from liquids marketing activities. Accounts receivable for retail and wholesale propane operations are recorded as amounts are billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts for the retail and wholesale propane segments is based on management’s assessment of the realizability of customer accounts, based on the overall creditworthiness of our customers and any specific disputes.

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

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Accounts receivable at December 31, 2007 consisted of the following:

Accounts receivable—midstream and intrastate transportation and storage	$	612,533
Accounts receivable—interstate transportation		31,676
Accounts receivable—propane		183,516
Less—allowance for doubtful accounts		(5,698	)
Total, net	$	822,027

The activity in the allowance for doubtful accounts for the propane operations for the four months ended December 31, 2007 consisted of the following:

Balance, beginning of period	$	5,601
Provision for loss on accounts receivable		544
Accounts receivable written off, net of recoveries		(447	)
Balance, end of period	$	5,698

Inventories

Inventories consist principally of natural gas held in storage which is valued at the lower of cost or market utilizing the weighted average cost method. Propane inventories are also 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 at December 31, 2007 consisted of the following:

Natural gas, propane and other NGLs	$	342,457
Appliances, parts and fittings and other		19,497
Total inventories	$	361,954

Exchanges

The midstream and intrastate transportation and storage segments’ exchanges consist of natural gas and NGL delivery imbalances with others. These amounts, which are valued at market prices, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheet. Management believes market value approximates cost at December 31, 2007.

The interstate segment’s natural gas imbalances occur as a result of differences in volumes of gas received and delivered. Transwestern records natural gas imbalance, in-kind receivables and payables at the dollar weighted composite average of all current month gas transactions and dollar valued imbalances are recorded at contractual prices.

Property, Plant and Equipment

Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated economic or Federal Energy Regulatory Commission (“FERC”) mandated lives of the assets. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the installation of company-owned propane tanks and construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our results of operations.

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We review property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. No impairment of long-lived assets was required during the period presented.

An accrual of allowance for funds used during construction (“AFUDC”) is a utility accounting practice calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC has been segregated into two component parts – borrowed funds and equity funds. The allowance for borrowed and equity funds used during construction totaled $5,095 for the four-month period ended December 31, 2007.

Components and useful lives of property, plant and equipment at December 31, 2007 were as follows:

Land and improvements	$	65,348
Buildings and improvements (10 to 30 years)		118,438
Pipelines and equipment (10 to 80 years)		4,113,026
Natural gas storage (40 years)		91,656
Bulk storage, equipment and facilities (3 to 30 years)		463,807
Tanks and other equipment (5 to 30 years)		528,777
Vehicles (5 to 10 years)		161,920
Right of way (20 to 80 years)		271,412
Furniture and fixtures (3 to 10 years)		24,928
Linepack		41,099
Pad Gas		53,242
Other (5 to 10 years)		86,602
		6,020,255
Less – Accumulated depreciation		(514,169	)
		5,506,086
Plus – Construction work-in-process		1,346,372
Property, plant and equipment, net	$	6,852,458

Capitalized interest is included for pipeline construction projects. Interest is capitalized based on the borrowing rate of ETP’s revolving credit facility when the related costs are incurred. A total of $12,657 of interest was capitalized for pipeline construction projects for the four months ended December 31, 2007 (excluding AFUDC as discussed above).

Depreciation expense for the four-month period ended December 31, 2007 was $68,642.

Asset Retirement Obligation

We account for our asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations,(“SFAS 143”) and FASB Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations(“FIN 47”). SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period a legal obligation for the retirement of tangible long-lived assets is incurred, typically at the time the assets are placed into service. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement, an entity would recognize changes in the amount of the liability resulting from the passage of time and revisions to either the timing or amount of estimated cash flows. FIN 47 clarified that the term “conditional asset retirement obligation”, as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement of the obligation are uncertain. These conditional obligations were not previously addressed by SFAS 143. FIN 47 requires us to accrue the fair value of a liability for the conditional asset retirement obligation when incurred – generally upon acquisition, construction or development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement of a conditional asset retirement should be factored into the measurement of the liability when a range of scenarios can be determined. FIN 47 clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

We have determined that we are obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain assets. Determination of the amounts to be recognized is based upon

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numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates, and the credit-adjusted risk-free interest rates. However, management is not able to reasonably determine the fair value of the asset retirement obligations as of December 31, 2007 because the settlement dates were indeterminable. An asset retirement obligation will be recorded in the periods management can reasonably determine the settlement dates.

Advances to and Investment in Affiliates

We own interests in a number of related businesses that are accounted for using the equity method. In general, we use the equity method of accounting for an investment in which we have a 20% to 50% ownership and exercise significant influences over, but do not control, the investee’s operating and financial policies.

In December 2006, we entered into an agreement with Kinder Morgan Energy Partners, L.P. for a 50/50 joint development of the Midcontinent Express Pipeline (“MEP”). MEP, 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, will have an initial capacity of 1.4 Bcf per day and is expected to cost approximately $1,322,000 to construct. Pending necessary regulatory approvals, the pipeline project is expected to be in service by the first calendar quarter 2009. MEP has prearranged binding commitments from multiple shippers for 1,195,000 dekatherms per day which includes a binding commitment from Chesapeake Energy Marketing, Inc., an affiliate of Chesapeake Energy Corporation, for 500,000 dekatherms per day. MEP has executed a firm capacity lease agreement for up to 500,000 dekatherms per day of capacity on the Oklahoma intrastate pipeline system of Enogex, a subsidiary of OGE Energy, to provide transportation capacity from various locations in Oklahoma into and through MEP. The new pipeline will also interconnect with Natural Gas Pipeline Company of America, a wholly-owned subsidiary of Knight, Inc. (formerly known as Kinder Morgan, Inc.), and with our Texoma pipeline near Paris, Texas. We account for our investment in MEP using the equity method of accounting.

Goodwill

Goodwill is associated with acquisitions made for our midstream, intrastate transportation and storage, interstate transportation and retail propane segments. In accordance with Statement of Accounting Standards No. 142,Goodwill and Other Intangible Assets,(“SFAS 142”), we have historically performed our annual test of goodwill impairment at August 31^st. With our change in year end, we will continue to perform this annual test at August 31.

The changes in the carrying amount of goodwill during the four-month period ended December 31, 2007 were as follows:

	Midstream		Intrastate Transportation and Storage		Interstate Transportation			Retail Propane			Other		Total
Balance, August 31, 2007	$	13,409	$	10,327	$	107,550		$	587,143		$	29,589	$	748,018
Purchase accounting adjustments		—		—		(8,937	)		190			—		(8,747	)
Goodwill acquired		10,959		—		—			7,742			—		18,701
Sale of operations		—		—		—			(274	)		—		(274	)
Balance, December 31, 2007	$	24,368	$	10,327	$	98,613		$	594,801		$	29,589	$	757,698

The purchase price allocations for the Canyon acquisition (see Note 2) and other acquisitions during the period are preliminary based on estimated fair values. There is no guarantee that the preliminary allocations will not change as a result of the completion of the evaluation of the fair values of the assets acquired and liabilities assumed. We expect to finalize the purchase price allocations in the third calendar quarter of 2008.

Intangibles and Other 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 as of December 31, 2007 were as follows:

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	Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Noncompete agreements (5 to 15 years)	$	34,855	$	(19,438	)
Customer lists (3 to 15 years)		139,097		(26,821	)
Contract rights (6 to 15 years)		23,015		(1,849	)
Other (10 years)		2,677		(1,463	)
Total amortizable intangible assets		199,644		(49,571	)
Non-amortizable assets—Trademarks		70,339		—
Total intangible assets		269,983		(49,571	)
Other long-term assets:
Financing costs (3 to 15 years)		57,934		(14,493	)
Regulatory assets		71,064		—
Other long-term assets		27,022		—
Total intangibles and other long-term assets	$	426,003	$	(64,064	)

Aggregate amortization expense of intangible assets for the four months ended December 31, 2007 is as follows:

Reported in depreciation and amortization	$	6,764
Reported in interest expense	$	2,716

The estimated aggregate amortization expense for the next five years is $24,348 for 2008; $23,621 for 2009; $21,983 for 2010; $20,380 for 2011; and $17,100 for 2012.

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^st, or more frequently if circumstances dictate, in accordance with SFAS 144.

Customer Advances and Deposits

Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month and from our propane customers as security or prepayments for future propane deliveries. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit. Advances and deposits received from customers were $75,831 as of December 31, 2007.

Accrued and Other Current Liabilities

Accrued and other current liabilities at December 31, 2007 consist of the following:

Accrued wages and benefits	$	35,729
Capital expenditures		87,622
Operating expenses		19,773
Litigation, environmental and other contingencies		35,707
Interest		78,933
Taxes other than income taxes		48,437
Other		29,583
Total accrued and other current liabilities	$	335,784

Fair Value of Financial Instruments

The carrying amounts of accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value. Based on the estimated borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at December 31, 2007 was $5,868,796 and $5,917,174, respectively.

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Shipping and Handling Costs

In accordance with EITF No. 00-10,Accounting for Shipping and Handling Fees and Costs,we have classified $48,635 from producer payments for natural gas, compression and treating, which can be considered handling costs, as revenue for the four-month period ended December 31, 2007. Shipping and handling costs related to fuel sold are included in cost of sales. The remaining costs of approximately $30,682 included in operating expenses reflect the cost of fuel consumed for compression and treating for the four-month period ended December 31, 2007. We do not separately charge propane shipping and handling costs to customers.

Costs and Expenses

Costs of products sold include actual cost of fuel sold adjusted for the effects of our hedging and other commodity derivative activities, storage fees and inbound freight on propane, and the cost of appliances, parts, and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, shipping and handling costs related to propane, purchasing costs, and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.

We record the collection of taxes to be remitted to governmental authorities on a net basis in cost of sales. The net amount of such taxes is not significant.

Issuances of Subsidiary Units

The Parent Company accounts for the difference between the carrying amount of its investment in ETP and the underlying book value arising from issuance of units by ETP (excluding unit issuances to the Parent Company) as capital transactions rather than electing the income recognition method as permitted by SEC Staff Accounting Bulletin No. 51 (“SAB 51”). If ETP issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment in ETP has been impaired, in which case a provision would be reflected in the statement of operations. The Parent Company did not recognize any impairment related to the issuance of ETP Units during the four-month period ended December 31, 2007 (see Note 7).

Income Taxes

Energy Transfer Equity, L.P. 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 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-qualified 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 four-month period ended December 31, 2007, our non-qualifying income did not 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.

On May 18, 2006, the State of Texas enacted House Bill 3 which replaced the existing state franchise tax with a “margin tax”. In general, legal entities that conduct business in Texas are subject to the Texas margin tax,

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including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the margin tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Therefore, we have accounted for Texas margin tax as income tax expense in the period subsequent to the law’s effective date of January 1, 2007. For the four months ended December 31, 2007, we recognized current state income tax expense related to the Texas margin tax of $3,905.

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. For further discussion and detail of our derivative instruments and/or hedging activities see Note 11 – “Price Risk Management Assets and Liabilities”.

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.

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. We report the realized gain or loss and ineffectiveness portions of those hedges in interest expense. Gains and losses on interest rate derivatives that are not cash flow hedges are classified in other income or expense. See Note 11 for additional information related to interest rate derivatives.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flow from operating activities, in the same category as the cash flows from the items being hedged.

Allocation of Income (Loss)

For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests (see Note 7).

New Accounting Standards

FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. We adopted FIN 48 on September 1, 2007, which adoption did not have a significant impact on our consolidated financial statements.

FASB Staff Position No. EITF 00-19-2,Accounting for Registration Payment Arrangements (“FSP 00-19-2”). FSP 00-19-2, issued in December 2006, provides guidance related to the accounting for registration payment arrangements. FSP 00-19-2 specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate arrangement or included as a provision of a financial instrument or arrangement, should be separately recognized and measured in accordance with FASB No. 5,Accounting for Contingencies (“SFAS 5”). FSP 00-19-2 requires that if the transfer of consideration under a registration payment arrangement is probable and can be reasonably estimated at inception,

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the contingent liability under such arrangement shall be included in the allocation of proceeds from the related financing transaction using the measurement guidance in SFAS 5. We adopted this Staff Position on September 1, 2007 and the impact was not significant (see Note 7).

FASB Statement No. 157,Fair Value Measurement, (“SFAS 157”). This standard provides guidance for using fair value to measure assets and liabilities and applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including any financial statements for an interim period within that fiscal year. We are currently evaluating the impact of our adoption of this statement effective January 1, 2008 on our consolidated financial statements.

FASB Statement No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of SFAS Statements No. 87, 88, 106 and 132(R), (“SFAS 158”). Issued in September 2006, this statement requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multi-employer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. SFAS 158 also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. We adopted the recognition and disclosure provisions of SFAS 158 on December 1, 2006 in connection with our acquisition of Transwestern, the effect of which was not material. The measurement provisions of the statement are effective for fiscal years ending after December 15, 2008. The adoption of the measurement provisions of this statement on January 1, 2008 did not have a material impact on our consolidated financial statements.

FASB Statement No. 159,The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115, (“SFAS 159”). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. Most of the provisions in SFAS 159 are elective; however, the amendment applies to all entities with available-for-sale and trading securities. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. We are currently evaluating the impact of our adoption of this statement effective January 1, 2008 on our consolidated financial statements.

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 be generally 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. 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.

4. NET INCOME PER LIMITED PARTNER UNIT:

Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP that would have resulted assuming the incremental units related to ETP’s unit-based compensation plans had been issued during the respective periods. Such units have been determined based on the treasury stock method.

A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit for the four months ended December 31, 2007 is as follows:

Basic Net Income per Limited Partner Unit:
Limited Partner’s interest in net income	$	92,390
Weighted average limited partner units		222,829,916
Basic net income per limited partner unit	$	0.41
Diluted Net Income per Limited Partner Unit:
Limited Partner’s interest in net income	$	92,390
Dilutive effect of Unit Grants		(218	)
Diluted net income available to limited partners	$	92,172
Weighted average limited partner units		222,829,916
Diluted net income per limited partner unit	$	0.41

5. MINORITY INTERESTS:

The following table summarizes the changes in minority interest liability during the four months ended December 31, 2007:

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Balance, beginning of the period	$	1,882,432
Minority interest in net income of subsidiaries		90,132
Distributions and other		(63,756	)
Gain on sale of subsidary Common Units (see Note 7)		(48,932	)
Compensation under employee unit awards by subsidiary		8,114
Non-cash executive compensation		1,167
ETP Units tendered by employees to pay taxes		(164	)
Change in accumulated other comprehensive income allocable to minority interests		2,700
Subsidiary units issued in connection with public offering		234,887
Subsidiary units issued in connection with certain acquisitions		1,400
Impact of remedial tax allocation		(1,161	)
Balance, end of the period	$	2,106,819

6. DEBT OBLIGATIONS:

Our debt obligation as of December 31, 2007 consists of the following:

			Maturities
ETP Senior Notes:
2006 6.125% Senior Notes, net of discount of $322	$	399,678	One payment of $400,000 due February 15, 2017. Interest is paid semi-annually.
2006 6.625% Senior Notes, net of discount of $2,231		397,769	One payment of $400,000 due October 15, 2036. Interest is paid semi-annually.
2005 5.95% Senior Notes, net of discount of $1,733		748,267	One payment of $750,000 due February 1, 2015. Interest is paid semi-annually.
2005 5.65% Senior Notes, net of discount of $288		399,712	One payment of $400,000 due August 1, 2012. Interest is paid semi-annually.
Transwestern Senior Unsecured Notes:
5.39% Senior Unsecured Notes, including premium of $4,077		92,077	One payment due November 17, 2014. Interest is paid semi-annually.
5.54% Senior Unsecured Notes, net of discount of $4,855		120,145	One payment 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.

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HOLP Senior Secured Notes:
1996 8.55% Senior Secured Notes	48,000	Annual payments of $12,000 due each June 30th 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 19th through 2009. Interest is paid semi-annually.
7.26% Series B Senior Secured Notes	10,000	Annual payments of $2,000 due each November 19th 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 15th 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.
7.21% Series G Senior Secured Notes	3,800	Annual payments of $3,800 due each May 15ththrough 2008. Interest is paid quarterly.
7.89% Series H Senior Secured Notes	6,545	Annual payments of $727 due each May 15th 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.

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Revolving Credit Facilities and Term Loans:
ETE Senior Secured Revolving Credit Facility (including Swingline loan option)		122,643		Available through February 8, 2011. See terms below under “Term Loans and Revolving Credit Facilities”.
ETE Senior Secured Term Loan		1,450,000		Due November 1, 2012. See terms below under “Term Loans and Revolving Credit Facilities”.
ETP Revolving Credit Facility (including Swingline loan option)		1,626,948		Available through June 2012 – see terms below under “Term Loans and Revolving Credit Facilities”.
HOLP Fourth Amended and Restated Senior Revolving Credit Facility		15,000		Available through June 30, 2011, see terms below under “Term Loans and Revolving Credit Facilities”.
Other Long-Term Debt:
Notes Payable on noncompete agreements with interest imputed at rates averaging 5.51% for the four months ended December 31, 2007		11,171		Due in installments through 2014.
Other		3,405		Due in installments through 2024.
		5,917,174
Current maturities of long-term debt		(47,068	)
	$	5,870,106

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

Calendar 2008	$	47,068
Calendar 2009		44,679
Calendar 2010		39,777
Calendar 2011		171,113
Calendar 2012		3,498,778
Thereafter		2,115,759
	$	5,917,174

HOLP Senior Secured Notes

All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure the HOLP Senior Secured, Medium Term, and Senior Secured Promissory Notes (collectively, the “HOLP Notes”). In addition to the stated interest rate for the HOLP Notes, we are required to pay an additional 1% per annum on the outstanding balance of the HOLP Notes at such time as the HOLP Notes are not rated investment grade status or higher. As of December 31, 2007 the HOLP Notes were rated investment grade or better thereby alleviating the requirement that we pay the additional 1% interest.

Term Loans and Revolving Credit Facilities

Parent Company Credit Facilities

The Parent Company has a $1,450,000 Term Loan Facility with a Term Loan Maturity Date of November 1, 2012 (the “Parent Company Credit Agreement”). The Parent Company Credit Agreement also includes a $500,000 Secured Revolving Credit Facility (the “Parent Company Revolving Credit Facility”) available through February 8, 2011. The Parent Company Revolving Credit Facility also offers a swingline loan option with a maximum borrowing of $10,000 and a daily rate based on LIBOR.

The total outstanding amount borrowed under the Parent Company Credit Agreement and the Parent Company Revolving Credit Facility as of December 31, 2007 was $1,572,643 (including $1,143 in swingline loans). The total amount available under the Parent Company’s debt facilities as of December 31, 2007 was $377,357. The Parent Company Revolving Credit Facility also contains an accordion feature which will allow the Parent Company, subject to lender approval, to expand the facility’s capacity up to an additional $100,000.

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Loans under the Parent Company Revolving Credit Facility bear interest at Parent Company’s option at either (a) the Eurodollar rate plus the applicable margin or (b) base rate plus the applicable margin. The applicable margins are a function of the Parent Company’s leverage ratio that corresponds to levels set-forth in the agreement. The applicable Term Loan bears interest at (a) the Eurodollar rate plus 1.75% per annum and (b) with respect to any Base Rate Loan, at Prime Rate plus 0.25% per annum. The weighted average interest rate was 6.6475% for the amounts outstanding on the Parent Company Senior Secured Revolving Credit Facility and the Parent Company $1,450,000 Senior Secured Term Loan Facility. The weighted average interest rate was 5.8780% for the amounts outstanding on the Parent Company swingline loans. The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is based on the applicable Leverage Ratio which is currently at Level III or 0.375%.

The Parent Company Credit Agreement is secured by a lien on all tangible and intangible assets of the Parent Company and its subsidiaries, including its ownership of 62,500,797 ETP Common Units, the Parent Company’s 100% interest in ETP LLC and ETP GP with indirect recourse to ETP GP’s 2% General Partner interest in ETP and 100% of ETP GP’s outstanding incentive distribution rights in ETP, which the Parent Company holds through its ownership of ETP GP.

ETP Term Loan Facility

On December 18, 2007, ETP used proceeds received from an equity offering (see Note 7) and funds from the ETP Credit Facility to fully repay the ETP Term Loan Facility, a $310,000, 364-day term loan credit facility ETP executed on October 5, 2007 primarily to finance the Canyon acquisition. The ETP Term Loan Facility was a single draw term loan with an applicable Eurodollar rate plus 0.600% per annum based on our current rating by the rating agencies or at the Base Rate for a designated period.

ETP Credit Facility

ETP has available a $2,000,000 revolving credit facility (the “ETP Credit Facility”) that is expandable to $3,000,000 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 ETP 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 ($2,000,000 unless expanded to $3,000,000) less the sum of all outstanding revolving credit loans and the letter of credit obligation and (ii) the swingline commitment. The aggregate amount of swingline loans in any borrowing is not subject to a minimum amount or increment. The indebtedness under the ETP Credit Facility is prepayable at any time at ETP’s option without penalty. The commitment fee payable on the unused portion of the ETP Credit Facility varies based on ETP’s credit rating (0.11% based on ETP’s current rating) with a maximum fee of 0.125%.

The credit agreement relating to the ETP Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries ability to, among other things:

• incur indebtedness;

• grant liens;

• enter into mergers;

• dispose of assets;

• make certain investments;

• make Distributions during certain Defaults and during any Event of Default;

• engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

• engage in transactions with affiliates;

• enter into restrictive agreements; and

• enter into speculative hedging contracts.

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This credit agreement also contains a financial covenant that provides that on each date the Partnership makes a Distribution, the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1, with a permitted increase to 5.5 to 1 during a Specified Acquisition Period (as such terms are used in the credit agreement).

As of December 31, 2007, there was a balance of $1,626,948 in revolving credit loans (including $273,948 in swingline loans) and $61,336 in letters of credit. The weighted average interest rate on the total amount outstanding at December 31, 2007, was 5.746%. The total amount available under the ETP Credit Facility, as of December 31, 2007, which is reduced by any amounts outstanding under the swingline loan and letters of credit, was $311,716. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of ETP’s other current and future unsecured debt.

ETP 364-Day Credit Facility

On February 5, 2008, ETP entered into a credit agreement providing for a $500,000, 364-day term loan credit facility (the “364-Day Credit Facility”). Borrowings under the 364-Day Credit Facility will be used for general corporate purposes. The 364-Day Credit Facility is a single draw term loan with an applicable Eurodollar rate plus 1.000% per annum based on our current rating by the rating agencies or at the Base Rate for a designated period. We borrowed the entire amount available under this facility on February 12, 2008. The indebtedness under the 364-Day Credit Facility is unsecured and is not guaranteed by any of our or ETP’s subsidiaries. Borrowings under the 364-Day Credit Facility, upon proper notice to the administrative agent, may be prepaid in whole or in part without premium or penalty. The loan agreement related to the 364-Day Credit Facility requires any proceeds received from debt or equity issuance, assets sales, or accordion increases be used to make a mandatory prepayment on the outstanding loan balance. This loan agreement contains covenants that are similar to the covenants of the ETP Credit Facility.

HOLP Credit Facility

A $75,000 Senior Revolving Facility (the “HOLP Facility”) is available to HOLP through June 30, 2011 which may be expanded to $150,000. The HOLP Facility has a swingline loan option with a maximum borrowing of $10,000 at a prime rate. Amounts borrowed under the HOLP 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 facility varies based on the Leverage Ratio, as defined in the HOLP Facility credit agreement, with a maximum fee of 0.50%. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets, merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secure the HOLP Facility. As of December 31, 2007, there was $15,000 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 Facility. There were outstanding letters of credit of $1,002 at December 31, 2007. The weighted average interest rate on the total amount outstanding at December 31, 2007, was 5.97%. The sum of the loans made under the HOLP Facility plus the letter of credit exposure and the aggregate amount of all swingline loans cannot exceed the $75,000 maximum amount of the HOLP Facility. The amount available at December 31, 2007 was $58,998.

Debt Covenants

The agreements for the Parent Company Revolving Credit Facility and Senior Secured Term Loan Facility and ETP’s and the Operating Partnerships’ Senior Notes, Senior Unsecured Notes, Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and the revolving credit facilities contain customary restrictive covenants applicable to the Parent Company, ETP and the Operating Partnerships, including the achievement of various financial and leverage covenants, limitations on substantial disposition of assets, changes in ownership, the level of additional indebtedness and creation of liens.

The Parent Company Revolving Credit Facility and Senior Secured Term Loan Facility contain financial covenants as follows:

• Maximum Leverage Ratio – Consolidated Funded Debt of the Parent Company (as defined) to Consolidated EBITDA (as defined in the agreements) of the Parent Company of not more than 4.50 to 1.00, with a permitted increase to 5.00 to 1.00 during a specified acquisition period extending for two fiscal quarters following the close of a specified acquisition

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• Maximum Consolidated Leverage Ratio – Consolidated Funded Debt of the Parent Company and ETP to Consolidated EBITDA of ETP of not more than 5.50 to 1.00

• Interest Coverage Ratio may not be less than 3.00 to 1.00

• Value to Loan Ratio may not be less than 2.00 to 1.00

The most restrictive of the ETP and Operating Partnerships’ covenants require us to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA, as defined in the agreements, for the specified four fiscal quarter period of not greater than 5.0 to 1.0, with a permitted increase to 5.5 to 1.0 during a specified Acquisition Period (these terms are defined in the credit agreement related to the ETP Credit Facility), Adjusted Consolidated Funded Indebtedness to Adjusted Consolidated EBITDA (as these terms are similarly defined in the credit agreement related to the ETP Credit Facility and the note agreements related to the HOLP Notes) of not more than 4.75 to 1 and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the credit agreement related to the ETP Credit Facility and the note agreements related to the HOLP Notes) of not less than 2.25 to 1. The Consolidated EBITDA used to determine these ratios is calculated in accordance with these debt agreements. These debt agreements also provide that the Operating Partnerships may not declare, make, or incur a liability to make, restricted payments during each fiscal quarter, unless: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed Available Cash with respect to the immediately preceding quarter; (b) no default or event of default exists before such restricted payments; and (c) each Operating Partnership’s restricted payment is not greater than the product of each Operating Partnership’s Percentage of Aggregate Available Cash multiplied by the Aggregate Partner Obligations (as these terms are similarly defined in the bank credit facilities and the Note Agreements). The note agreements related to the HOLP Notes further provide that HOLP’s Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the notes and in addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the notes, a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.

For purposes of calculating these ratios, Consolidated EBITDA is based upon our EBITDA, as adjusted for the most recent four quarterly periods, and modified to give pro forma effect for acquisitions and divestitures made during the test period and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months.

Failure to comply with the various restrictive and affirmative covenants of our bank credit facilities and the Note Agreements could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Partnerships’ ability to incur additional debt and/or our ability to pay distributions. We are required to measure these financial tests and covenants quarterly. We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of November 30, 2007 (the last quarterly date we were required to provide verification of compliance to our lenders). Beginning with the quarter ending March 31, 2008, financial tests and covenant calculations will be performed on a calendar quarter basis.

7. PARTNERS’ CAPITAL AND UNIT-BASED COMPENSATION PLANS:

Under the terms of ETE’s partnership agreement, the limited partners’ potential liability is limited to their investment in the Partnership. The general partner of ETE manages and controls the business and affairs of the Partnership. The limited partners of ETE are not involved in the management and control of ETE.

On November 7, 2007, the Board of Directors of our General Partner approved an amendment to the Amended and Restated Agreement of Limited Partnership of the Partnership, and this amendment became effective on November 9, 2007. This amendment changes the fiscal year of the Partnership from a year ending on August 31 to a year ending on December 31. In order to transition to the new fiscal year, the amendment also provides that, in lieu of making a cash distribution to the Partnership’s unitholders and the General Partner with respect to the three-month period ended November 30, 2007, the Partnership will make a cash distribution for the four-month period ended December 31, 2007, which distribution will be made within 50 days following the end of such four-month period (such distribution was paid on February 19, 2008). Finally, the amendment provides that, following this one-time four-month distribution period, the Partnership will make cash distributions with respect to each calendar quarter within 50 days following the end of each calendar quarter.

In connection with the March 2007 private placement of 5,006,261 units, the Parent Company executed a registration rights agreement under which it agreed to file a shelf registration statement under the Securities Act within 120 days of closing of the private placement (the “closing”). If the shelf registration statement was not

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declared effective within 180 days after closing or after becoming effective, or ceased to be effective during the Effectiveness Period (defined as the period during which there are registerable units outstanding) for any period of time in excess of 30 days, each purchaser of the units would be entitled to the payment of liquidated damages. The payment would be equal to 1.0% of the unit purchase price per 30-day period following the 180 day effectiveness period. In certain circumstances, the payment could be made using additional ETE common units. For the four months ended December 31, 2007, an expense of $7,800 has been recorded in other income (expense), net in our consolidated statements of operations for liquidated damages under this registration rights agreement and the registration rights agreement entered into in connection with the November 2006 private placement because the shelf registration was not declared effective within the required timeframe. The liquidated damages were paid to entitled purchasers in December 2007. The S-3 registration statement became effective in October 2007.

Limited Partner Units

Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement, as amended. The Partnership’s Common Units are registered under the Securities Act of 1934 and are listed for trading on the New York Stock Exchange. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.”

As of December 31, 2007, we had limited partner interests represented by 222,829,956 Common Units issued and outstanding that are entitled to receive distributions in accordance with their terms, an aggregated 99.69% Limited Partner interest.

Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.

Common Units

The change in Common Units during the four-month period ended December 31, 2007 is as follows:

Balance, beginning of period	222,828,332
Issuance of restricted Common Units under long-term incentive plan	1,624
Balance, end of period	222,829,956

Issuances of Subsidiary Units

The Parent Company accounts for the difference between the carrying amount of its investment in ETP and the underlying book value arising from issuance of units by ETP (excluding unit issuances to the Parent Company) as capital transactions rather than electing the income recognition method as permitted by SEC Staff Accounting Bulletin No. 51 (“SAB 51”). If ETP issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment in ETP has been impaired, in which case a provision would be reflected in the statement of operations. The Parent Company did not recognize any impairment related to the issuance of ETP Units during the four-month period ended December 31, 2007.

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On December 18, 2007, ETP sold in a public offering 5,000,000 common units representing limited partner interests at $48.81 per ETP common unit. ETP used the offering proceeds of $234,887, net of issuance costs, to repay a portion of the outstanding debt under the ETP Term Loan Facility. The remainder of the outstanding balance of the ETP Term Loan Facility was repaid with borrowings from the ETP Credit Facility. ETP also granted the underwriters a 30-day option to purchase up to an aggregate of 750,000 additional common units to cover over-allotments, if any. The underwriters exercised their option in full and ETP issued 750,000 additional common units at $48.81 per common unit on January 8, 2008. The proceeds of $35,235, net of offering costs, were used to repay borrowings from the ETP Credit Facility.

The Partnership recorded the difference of $48,932 between the carrying amount of the Partnership’s investment in ETP and its share of the underlying book value after giving effect to the above transaction as a capital transaction based on the Partnership’s ownership in ETP being diluted from 45.61% to 43.99% during the four months ended December 31, 2007. The capital transaction is reflected in the Partnership’s consolidated balance sheet as an increase in limited partners’ capital in accordance with the guidance in SAB 51. No deferred taxes were recorded and the transaction had no effect on the Partnership’s income.

Contributions to Subsidiary

The Parent Company indirectly owns the entire 2% general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. ETP GP is required to make contributions to ETP each time ETP issues limited partner interests for cash or in connection with acquisitions in order to maintain its 2% general partner interest in ETP. These contributions are generally paid by offsetting the required contributions against the funds ETP GP receives from ETP distributions on the general partner and limited partner interests owned by ETP GP. ETP GP was required to contribute $5,009 for the four months ended December 31, 2007. ETE advanced the funds for ETP GP to pay a $24,489 contribution during the four months ended December 31, 2006 and at December 31, 2007 there was $10,814 remaining as a receivable from affiliates in the Parent Company stand alone balance sheet.

Parent Company Quarterly Distributions of Available Cash

Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. We currently have no independent operations outside of our interests in ETP.

Our only cash-generating assets currently consist of distributions from ETP related to the following limited and general partner interests, including incentive distribution rights in ETP:

• ETE’s ownership of the 2% general partner interest in ETP, which it holds through its ownership interests in ETP GP.

• 62,500,797 ETP Units representing approximately 44% of the total outstanding ETP Units, which ETE holds directly; and

• 100% of the incentive distribution rights in ETP, which ETE holds through its ownership interests in ETP GP and which entitle it to receive specified percentages of the cash distributed by ETP as ETP’s per unit distribution increases. The Parent Company’s incentive distribution rights entitle it to receive incentive distributions to the extent that quarterly distributions to ETP’s Unitholders exceed $0.275 per unit ($1.10 per unit on an annualized basis). These incentive distributions entitle the Parent Company to increasing percentages of ETP’s cash distributions based upon exceeding incentive distribution thresholds specified in ETP’s Partnership Agreement, which incentive distribution rights entitle the Parent Company to receive 50% of ETP’s cash distributions in excess of $0.4125 per unit. At ETP’s current distribution levels, the Parent Company is entitled to receive cash distributions at the highest incentive distribution level of 50% with respect to ETP’s distributions in excess of $0.4125 per unit.

On October 19, 2007 the Parent Company paid a cash distribution for the fourth quarter ended August 31, 2007 of $0.39 per Common Unit, or $1.56 annually, an increase of $0.07 per Common Unit on an annualized basis to Unitholders of record at the close of business on October 5, 2007.

With the previously announced change in year-end reporting to December 31, ETE has a “transition period” consisting of the four months ended December 2007. Based on this change in timing, on January 18, 2008, the Board of Directors approved the previously announced management recommendation for a one-time four-month distribution, rather than a normal three-month period, to complete the conversion to a calendar year end from the previous August 31 fiscal year end. ETE’s four-month distribution amount was $0.55 per unit, ($1.64 per unit

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annualized), representing a distribution of $0.41 per unit for the three-month period and $0.14 per unit for the additional month. This represents an increase of $0.08 per unit on an annualized basis. The following ETE distribution was paid on February 19, 2008 to Unitholders of record as of the close of business on February 1, 2008:

Limited Partners	$	122,556
General Partner		381
Total distributions paid	$	122,937

After this distribution payment, the Parent Company will continue to make quarterly distributions on a three-month basis as we have done in the past. Going forward, the next quarterly distribution payments are scheduled to be mid May, mid August, and mid November.

ETP’s Quarterly Distributions of Available Cash

ETP is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of its general partner.

On October 15, 2007, ETP paid a cash distribution for the fourth fiscal quarter ended August 31, 2007 of $0.825 per Common Unit, or $3.30 annually, an increase of $0.075 increase per Common Unit on an annualized basis to Unitholders of record at the close of business on October 5, 2007. The Parent Company also received distributions relating to its ownership of general partner interest in ETP and incentive distributions to the extent the quarterly distribution exceeded $0.275 per unit.

The total amount of distributions the Parent Company received from ETP relating to its ownership of limited partner interests, general partner interests and incentive distribution rights of ETP during the four-month transition period ended December 31, 2007 is as follows:

Limited Partners Interest	$	51,563
General Partner Interest		3,553
Incentive Distribution Rights		59,315
Total distributions received from ETP	$	114,431

ETP also changed its year end from August 31 to December 31 and, in connection with this change, amended its partnership agreement to provide that, in lieu of making a cash distribution for the three-month period ended November 30, 2007, ETP will make a cash distribution for the four-month period ended December 31, 2007. On January 18, 2008 ETP’s Board of Directors approved the management recommended payment of a four-month distribution to ETP Unitholders of $1.125 per unit, representing a distribution of $0.84375 per unit for the three-month period and $0.28125 per unit for the additional month. This represents an increase of $0.075 per unit on an annualized basis. The four-month distribution was paid on February 14, 2008 to ETP Unitholders of record as of the close of business on February 1, 2008. Based on the number of ETP’s Common Units outstanding at December 31, 2007, the Parent Company received a cash distribution for this four-month period of $161,198 (or $644,792 on an annualized basis), which consists of $5,110 from the Parent Company’s indirect ownership of the 2% general partner interest in ETP, $85,775 from the Parent Company’s indirect ownership of 100% of the incentive distribution rights in ETP, and $70,313 from the Parent Company’s ownership of 62,500,797 Common Units of ETP.

After this distribution payment, ETP will continue to make quarterly distributions on a three-month basis as it has done in the past with the next scheduled quarterly distribution payments occurring in mid May, mid August, and mid November.

Unit Based Compensation Plans

We follow the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004)Accounting for Stock-based Compensation (“SFAS 123R”) for the unit-based compensation plans of the Parent Company and ETP. Generally, the recipients of the stock grants are not entitled to receive any unit distributions during the required service period for vesting. Accordingly, as provided in SFAS 123R, the Partnership 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.

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We recognized compensation expense of $8,137 for the four months ended December 31, 2007 for ETP’s and the Parent Company’s unit-based compensation plans.

ETE Long-Term Incentive Plan

The ETE Long-Term Incentive Plan provides for the following five types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 3,000,000 units. In addition, the Board of Directors or the Compensation Committee of the board of directors of the Partnership’s general partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE.

Each ETE 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 then in office and, automatically on each September 1st thereafter, will receive an award of Units equal to $15 divided by the fair market value of ETE Common Units on such date (“Annual Director’s Grant”). Each 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, all awards to a Director Participant shall become fully vested upon a change in control, as defined by the 2004 Unit Plan. On December 22, 2006 a total of 1,948 restricted units were granted to ETE Directors and on September 4, 2007 a total of 1,624 restricted units were granted to ETE Directors, which are the only units outstanding under the ETE Long-Term Incentive Plan as of December 31, 2007.

ETP Unit-Based Compensation Plans

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 ETP in the open market, (ii) units already owned by ETP or ETP’s General Partner, or (iii) units acquired by ETP or its General Partner directly from ETP, or 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 may issue units pursuant to an S-8 registration statement filed in September 2007, in which case the holders of these units would not be subject to these restrictions. As of December 31, 2007, 433,751 ETP Common Units were available for future grants under the 2004 Unit Plan.

The 2004 Unit Plan is administered by the Compensation Committee of the Board of Directors of ETP’s general partner (“ETP’s Compensation Committee”) and may be amended from time to time by ETP’s Board; provided however, that no amendment will be made without the approval of a majority of ETP’s 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 ETP; 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 10^th anniversary of its original effective date (June 23, 2014).

Employee Grants. ETP’s Compensation Committee, at 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 ETP 2004 Unit Plan. All outstanding awards shall fully vest into units upon any Change in Control, as defined by the 2004 Unit Plan, or upon such terms as the ETP Compensation Committee may require at the time the award is granted. The issuance of ETP 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 the ETP Common Units.

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Prior to December 2007, 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 the ETP Unitholders as compared to a group of publicly traded partnership peer companies. Compensation expense is recorded based upon the total awards granted over the required service period that are expected to vest based on the estimated level of achievement of performance objectives. As circumstances change, cumulative adjustments of previously-recognized compensation expense are recorded. ETP has 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, including the grant on December 5, 2007 of unit awards to employees relating to an aggregate of 558,750 common units.

On October 2, 2007 the Compensation Committee of ETP’s General Partner determined that based on ETP’s performance for the year ended August 31, 2007, of the 225,887 employee awards scheduled to vest on September 1, 2007, 25%, or 56,482 employee awards vested and 75%, or 169,405 awards were forfeited. The Compensation Committee of ETP’s General Partner also approved a special one-time grant of 158,080 employee awards to vest on October 2, 2008, which are not subject to performance objectives but are subject only to continued employment with us through the first anniversary of the grant date of October 2, 2007.

ETP assumed a weighted average risk-free interest rate of 3.70% for the four months ended December 31, 2007 in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each employee grant. For the employee awards outstanding as of the period ended December 31, 2007, the grant-date average per unit cash distributions were estimated to be $7.56. Upon vesting, ETP Common Units are issued.

The following table shows the activity of the employee grants during the four months ended December 31, 2007:

	Number of Units		Weighted Average Fair Value Per Unit
Unvested awards as of August 31, 2007	557,437		$	39.08
Awards granted	716,830			42.45
Awards vested	(56,482	)		35.14
Awards forfeited	(178,256	)		35.31
Unvested awards as of December 31, 2007	1,039,529		$	42.27

The total expected compensation expense to be recognized related to the unvested employee awards as of December 31, 2007 is $20,547 for calendar year 2008, $7,228 for calendar year 2009, $3,580 for calendar year 2010, $1,936 for calendar year 2011, and $782 for calendar year 2012.

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 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 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 ETP Compensation Committee.

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We assumed a weighted average risk-free interest rate of 4.48% for the four months ended December 31, 2007 in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each Director Grant. For the unvested Director Awards as of December 31, 2007, the grant-date average per unit cash distributions were estimated to be $6.15.

The following table shows the activity of the Director awards granted during the four months ended December 31, 2007:

	Number of Units		Weighted Average Fair Value Per Unit
Unvested awards as of August 31, 2007	12,166		$	27.63
Annual Director Grants	2,880			45.87
Awards vested	(8,118	)		23.14
Unvested awards as of December 31, 2007	6,928		$	40.47

The total expected compensation expense to be recognized related to the unvested Director Awards as of December 31, 2007 is $110 for calendar year 2008, $38 for calendar year 2009, and $9 for calendar year 2010.

Long-Term Incentive Grants.The Compensation Committee of ETP may, from time to time, grant awards under the Plan to any ETP executive officer or any ETP employee it may designate as a participant in accordance with general guidelines under the Plan. These guidelines include (i) options to purchase a specified number of ETP Common 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 December 31, 2007, there have been no Long-Term Incentive Grants made under the Plan.

Related Party Awards

Through December 31, 2007, a partnership (McReynolds Equity Partners, L.P., formerly FEM Group, L.P.), the general partner of which is owned and controlled by our President has awarded to certain new officers of ETP certain rights related to units of ETE previously issued by ETE to our President and held by such partnership. 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, the Parent Company and ETP are recognizing non-cash compensation expense over the vesting period based on the grant date market value of ETE units awarded the ETP employees assuming no forfeitures. Rights related to 55,000 of the ETE units vested in December 2007. Awards granted for the four months ended December 31, 2007 result in a total non-cash compensation expense of approximately $23,523 to be recognized over the related vesting period. For the four-month period ended December 31, 2007, we recognized non-cash compensation expense of $3,551, as a result of these awards. 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. ETP expects to recognize non-cash compensation expense as follows in future periods related to these awards:

Calendar 2008	$	6,939
Calendar 2009		4,122
Calendar 2010		2,399
Calendar 2011		1,146
Calendar 2012		175

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8. INCOME TAXES:

The components of our federal and state income tax provision for the four months ended December 31, 2007 are summarized as follows:

Current provision:
Federal	$	2,990
State		5,831
Total		8,821
Deferred provision:
Federal		516
State		612
Total		1,128
Total tax provision	$	9,949
Effective tax rate		5.16	%

The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are not subject to federal and state income taxes at the Partnership level. The difference between the statutory rate and the effective rate for the four months ended December 31, 2007 is summarized as follows:

Federal statutory tax rate	35.00	%
State income tax rate net of federal benefit	2.57	%
Earnings not subject to tax at the Partnership level	(32.41	)%
Effective tax rate	5.16	%

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the deferred tax liability for the four months ended December 31, 2007 were as follows:

Property, plant and equipment	$	199,809
Other, net		554
Total deferred tax liability	$	200,363

9. MAJOR CUSTOMERS AND SUPPLIERS:

Our major customers are in the natural gas operations segments. Our natural gas operations have a concentration of customers in natural gas transmission, distribution and marketing, as well as industrial end-users while our NGL operations have a concentration of customers in the refining and petrochemical industries. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively. Management believes that our portfolio of accounts receivable is sufficiently diversified to minimize any potential credit risk. No single customer accounts for 10% or more of our consolidated revenue.

We had gross segment purchases as a percentage of total purchases from major suppliers for the four months ended December 31, 2007 as follows:

Propane segments:
Unaffiliated
Targa Liquids	15.9	%
M.P. Oils, Ltd.	14.2	%
Affiliated
Enterprise	50.6	%

ETP sold its investment in M-P Energy in October 2007. M-P Energy is a Canadian partnership in which our wholly-owned subsidiary, M.P. Oils, Ltd. (until October 2007) owned a 60% interest. Prior to the sale, M.P. Oils, Ltd. had been one of our major affiliated propane suppliers. In connection with the sale of M-P Energy, ETP executed a seven year propane purchase agreement for approximately 90 million gallons per year at market prices plus a nominal fee.

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This concentration of suppliers may impact our overall operations either positively or negatively. However, management believes that the diversification of suppliers is sufficient to enable us to purchase all of our supply needs at market prices without a material disruption of operations if supplies are interrupted from any of our existing sources. Although no assurances can be given that supplies of natural gas, propane and NGLs will be readily available in the future, we expect a sufficient supply to continue to be available.

10. 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. On March 9, 2007, Transwestern filed with the Federal Energy Regulatory Commission (the “FERC”) its Stipulation and Agreement of Settlement (“Stipulation and Agreement”) which provides for (i) revised base tariff rates, (ii) the amortization of certain costs, including the Enron Cash Balance Plan, regulatory commission expense, post retirement benefits, the accumulated reserve adjustment regulatory asset, deferred income taxes, and certain non-PCB environmental costs, and (iii) a depreciation rate of 1.20 percent for all transmission plant facilities. On April 27, 2007, the FERC approved the Stipulation and Agreement with an effective date of April 1, 2007. 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.

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. Total project costs are estimated to be approximately $710,000 including AFUDC with projected phased-in service dates in the third and fourth calendar quarter of 2008. 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 issued an order denying the motion for stay and the requests for rehearing. As a result, the FERC certificate issued on November 15, 2007 remains effective and binding. Transwestern has incurred expenditures of $260,489 through December 31, 2007 for the Phoenix project.

On December 13, 2006, we entered into an agreement with Kinder Morgan Energy Partners, L.P. (“KMEP”) for a 50/50 joint development of Midcontinent Express Pipeline (“MEP”). MEP, 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, MEP 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 Natural Gas Act Section 7 Certificate of Public Convenience and Necessity in October, 2007. The Section 7 Certificate must be granted before construction may commence. The approximately $1,322,000 pipeline project is expected to be in service by the first calendar quarter of 2009.

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 also have a long-term purchase contract for approximately 79 million gallons of propane per year that contains a two-year cancellation provision and a seven year contract to purchase not less than 90 million gallons per year. 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.

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We have certain non-cancelable leases for property and equipment which require fixed monthly rental payments and expire at various dates through 2020. Rental expense under these operating leases totaled approximately $9,424 for the four-month period ended December 31, 2007 and has been included in operating expenses in the accompanying statements of operations. Future minimum lease commitments for such leases are:

Calendar 2008	$	13,379
Calendar 2009		11,672
Calendar 2010		17,058
Calendar 2011		15,970
Calendar 2012		14,577
Thereafter		27,699

Titan has a long-term purchase contract with Enterprise to purchase substantially all of Titan’s propane requirements. The contract continues until March 31, 2010 and contains renewal and extension options. The contract contains various service level agreements between the parties.

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 ETP an Order to Show Cause and Notice of Proposed Penalties (the “Order and Notice”) that contains allegations that ETP violated FERC rules and regulations. The FERC has alleged that ETP 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 dates from December 2003 through August 2005, in order to benefit financially from ETP’s commodities derivatives positions and from certain of its index-priced physical gas purchases in the Houston Ship Channel. The FERC has alleged that during these periods ETP violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by FERC under authority of the Natural Gas Act (“NGA”). ETP allegedly violated this rule by artificially suppressing prices that were included in the PlattsInside 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 ETP manipulated daily prices at the Waha Hub and the Katy Hub near Houston, Texas. ETP’s 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, ETP’s blanket marketing authority for sales of natural gas in interstate commerce at negotiated rates, which activity is expected to account for approximately 1.0% of ETP’s operating income for its 2008 calendar year. If the FERC is successful in revoking ETP’s blanket marketing authority, ETP’s sales of natural gas at market-based rates would be limited to sales of natural gas to retail customers (such as utilities and other end users) and sales from its own production, and any other sales of natural gas by ETP would be required to be made at prices that would be subject to FERC approval.

In its Order and Notice, the FERC is seeking $70,134 in disgorgement of profits, plus interest, and $97,500 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

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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 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 $15,500 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 forde novo review. The Enforcement Staff also recommended that the FERC impose certain changes in Oasis’ business operations and refunds to certain Oasis customers, 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 $25,000 and be required to disgorge approximately $7,300 of alleged unjust profits related to this additional month. If the claims related to this additional month are pursued by the FERC, the total amount of civil penalties and disgorgement of profits sought by the FERC would be approximately $200,000. ETP will respond to the Enforcement Staff’s brief by March 31, 2008. The FERC has not taken any action related to these recommendations of the Enforcement Staff.

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 by attempting to manipulate natural gas prices in the Houston Ship Channel. On March 17, 2008, this suit was dismissed after ETP entered into a consent order with the CFTC. Pursuant to the consent order, ETP agreed to pay the CFTC $10,000 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 will be permanently enjoined from attempting to manipulate the price of any commodity in interstate commerce in violation of the Commodity Exchange Act. 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 will reduce our existing accrual and be paid from cash flow from operations.

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, 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. One of the producers also seeks to intervene in the FERC proceeding, alleging that it is entitled to a FERC-ordered refund of $5,900, plus interest and costs. This producer has also filed a complaint at FERC against us and ETP requesting an agency hearing and claiming that we and ETP violated the NGA by failing to make sales for resale at negotiated rates; intentionally engaged in market manipulation; knowingly submitted misleading information to Platts; and caused damages to the producer group in the amount of $5,900. This producer has requested refunds and other remedies. On December 20, 2007, the FERC denied this producer’s request to intervene in the FERC proceeding and on February 6, 2008 the FERC dismissed this producer’s complaint. We have also been served with a complaint from an owner of royalty interests in natural gas producing properties, on behalf of a putative class of royalty owners, pursuant to which such royalty owner seeks arbitration to recover damages based on alleged manipulation of natural gas prices at the Houston Ship Channel. This complaint seeks certification on behalf of a class of similarly situated parties, unspecified monetary damages and other relief.

In addition, 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 Commodity Exchange Act (“CEA”). It is further alleged that during the class period December 29, 2003 to

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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 also violated the CEA because we knowingly aided and abetted violations of the CEA. This action alleges that this 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 plaintiff and all other members of the putative class who purchased and/or sold natural gas futures and options contracts on NYMEX during the class period. The class action complaint consolidated two class actions which were pending against us. Following the consolidation order, the plaintiffs who had filed these two earlier class actions filed the consolidated complaint. They have requested certification of their suit as a class action, 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. The response to ETP’s motion to dismiss is due March 20, 2008.

We are expensing the legal fees, consultants’ fees and related 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, and taking into consideration the settlement with the CFTC, we are still unable to predict the outcome of these unresolved 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 existing accrual related to these matters. In accordance with applicable accounting standards, we will review the amount of our existing 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 Tariffs, 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 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.

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 $1,000,000 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

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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 $347,300 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 December 31, 2007, an accrual of $30,504 was recorded as accrued and other current liabilities and other non-current liabilities on our 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 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 remediation of 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 $11,687. 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

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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.

We also assumed certain environmental remediation matters related to eleven sites in connection with our acquisition of the HPL System.

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 December 31, 2007 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 or results of operations.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of 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 December 31, 2007, an accrual on an undiscounted basis of $15,732 was recorded in our 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.

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 December 31, 2007, Transwestern did not incur any costs associated with the IMP Rule and has satisfied all of the requirements until 2010. Through December 31, 2007, a total of $4,996 of capital costs and $4,495 of operating and maintenance costs have been incurred for pipeline integrity testing for our transportation assets other than Transwestern. Through December 31, 2007, a total of $4,211 of capital costs and $551 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.

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11. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

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 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 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 $42,248 as of December 31, 2007 reflected as deposits paid to vendors on our 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. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as cash flow hedges are included in cost of products sold in the period the hedged transactions occur. Gains and losses deferred in OCI related to cash flow hedges remain in OCI until the underlying physical 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 cost of products sold in the condensed consolidated statement of operations. We reclassified into earnings gains of $17,145 for the four months ended December 31, 2007 related to commodity financial instruments that were previously reported in OCI.

We expect gains of $25,113 to be reclassified into earnings over the next twelve months related to income currently reported in OCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs. The majority of our commodity-related derivatives are expected to settle within the next year.

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 a 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, and changes in the fair value of these derivative instruments are recognized in midstream and intrastate transportation and storage revenue in the condensed consolidated statement of operations on a net basis.

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The following table details the outstanding commodity-related derivatives as of December 31, 2007:

	Commodity	Notional Volume MMBTU		Maturity	Fair Value Asset (Liability)
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	2,732,500		2008-2009	$	(2,767	)
Swing Swaps IFERC	Gas	(4,640,000	)	2008		(1,515	)
Fixed Swaps/Futures	Gas	(26,987,500	)	2008-2009		14,230
Forward Physical Contracts	Gas	(17,847,140	)	2008		(1,063	)
Options	Gas	(670,000	)	2008		(161	)
Forward/Swaps—in Gallons	Propane	9,282,000		2008		3,319
(Trading)
Basis Swaps IFERC/NYMEX	Gas	(18,362,500	)	2008	$	2,298
Cash Flow Hedging Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(11,255,000	)	2008-2009	$	(1,262	)
Fixed Swaps/Futures	Gas	(13,120,000	)	2008-2009		26,913

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 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.

During the four months ended December 31, 2007, the Partnership discontinued application of hedge accounting in connection with certain derivative financial instruments that were qualified for and designated as cash flow hedges related to forecasted sales of natural gas stored in the Partnership’s Bammel storage facilities. The discontinuation resulted from management’s determination that the originally forecasted sales of natural gas from the storage facilities were no longer probable of occurring by the end of the originally specified time period, or within an additional two-month period of time thereafter. The determination was made principally due to the unseasonably warm weather that occurred during December 2007. One of the key criteria to achieve hedge accounting under SFAS 133 is that the forecasted transaction be probable of occurring as originally set forth in the hedge documentation. As a result, during the four months ended December 31, 2007, the Partnership recognized previously deferred unrealized gains of $9,186 from the discontinued application of hedge accounting, which is included in the reclassification into earnings from OCI. The Partnership classified the unrealized gains as costs of products sold in its consolidated statement of operations.

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. We report the realized gain or loss and ineffectiveness portions of those hedges in interest expense. Gains and losses on interest rate derivatives that are not cash flow hedges are classified in other income (expense), net in the four-month period ended December 31, 2007.

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The following table represents interest rate swap derivatives at December 31, 2007:

Term	Notional Amount		Type	SFAS 133 Hedge	Fair Value Liability
March 2009	$	125,000	Pay Fixed 5.14%	No	$	1,530
			Receive Float
May 2016		300,000	Pay Fixed 5.2%	No		15,870
			Receive Float
November 2012		700,000	Pay Fixed 4.84%	Yes		23,281
			Receive Float
November 2012		500,000	Pay Fixed 4.57%	No		16,020
			Receive Float

We reclassified into earnings gains of $650 for the four months ended December 31, 2007 related to interest rate swaps that were previously reported in OCI. We expect losses of $4,917 to be reclassified into earnings over the next twelve months related to income on interest rate financial instruments currently reported in OCI. The amount ultimately realized, however, could differ as interest rates and the timing of debt issuances change.

The following table represents pre-tax balances in Accumulated OCI related to interest rate swaps accounted for as hedges as of December 31, 2007:

Date Settled	Term	Notional Amount		Type	Accumulated Other Comprehensive Income (Loss)
Quarterly through maturity	2012	$	700,000	Pay Fixed 4.84%	$	(23,365	)
				Receive Float
April 2007	2014		400,000	LIBOR		(11,135	)
				Forward Starting
June 2006	2016		200,000	Treasury Lock		12,210
January 2005	2017		100,000	Treasury Lock		(269	)
					$	(22,559	)

Summary of Derivative Gains and Losses

The following represents gains (losses) on derivative activity for the four months ended December 31, 2007:

Commodity-related
Unrealized non-trading gains recognized in cost of products sold related to commodity-related derivative activity, excluding ineffectiveness	$	4,934
Ineffective portion of derivatives qualifying for hedge accounting recognized in cost of products sold		8,472
Realized non-trading gains related to commodity-related derivatives included in cost of products sold		13,625
Trading unrealized losses recognized in revenues		(205	)
Trading realized losses recognized in revenues		(2,094	)
Interest rate swaps
Unrealized losses on interest rate swap included in other income, excluding ineffectiveness	$	(30,059	)
Ineffective portion of derivatives qualifying for hedge accounting included in interest expense		(2	)
Realized gains on interest rate swap included in interest expense and other income, net		2,097

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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 or results of operations as a result of counterparty performance.

12. RETIREMENT BENEFITS:

ETP sponsors a defined contribution profit sharing and 401(k) savings plan, which covers virtually all employees subject to service period requirements. Profit sharing contributions are made to the plan at the discretion of ETP’s Board of Directors and are allocated to eligible employees as of the last day of the plan year. Employer matching contributions are calculated using a discretionary formula based on employee contributions. We made matching contributions of $2,596 to the 401(k) savings plan for the four months ended December 31, 2007.

13. RELATED PARTY TRANSACTIONS:

Accounts receivable from and payable to related companies as of December 31, 2007 relate primarily to activities in the normal course of business.

During the four months ended December 31, 2007, the Operating Partnerships made the following sales to and purchases from Enterprise:

Enterprise Transactions	Product	Volumes (in thousands)	Dollars
Propane Operations—Purchases	Propane—gallons	112,961	$	175,839
Natural Gas Operations—Sales	NGLs—gallons	3,240		4,726
	Natural Gas—MMBtu	2,036		11,452
	Fees	—		610
Purchases	Natural Gas Imbalances—MMBtu	313		(911	)
	Natural Gas—MMBtu	3,577		23,341
	Fees	—		311

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. The following table summarizes the related party balances with Enterprise on our condensed consolidated balance sheet related to our natural gas operations:

Accounts receivable	$	9,770
Accounts payable	$	6,840
Imbalance payable	$	6,218

Our propane operations have accounts receivable from Enterprise of $3,396 as of December 31, 2007. Accounts payable to Enterprise for our propane operations were $41,939 as of December 31, 2007. Titan has a long-term purchase contract to purchase substantially all of its propane requirements, and as of December 31, 2007 had forward mark to market derivatives for approximately 9.3 million gallons of propane at a fair value of $3,139 with Enterprise. Additionally, HOLP has a monthly storage contract with TEPPCO Partners, L.P. (an affiliate of Enterprise) for approximately $600 per year.

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Accounts receivable from related companies excluding Enterprise as of December 31, 2007 consist of the following:

LE GP	$	174
MEP		743
Energy Transfer Technologies, Ltd.		922
Others		3,065
Total accounts receivable from related companies excluding Enterprise	$	4,904

The Chief Executive Officer (“CEO”) of ETP’s General Partner, Mr. Kelcy Warren, voluntarily determined that effective October 19, 2007, his salary would be reduced to one dollar plus an amount sufficient to cover his allocated payroll deductions for health and welfare benefits. Mr. Warren also declined the cash bonus of $750 for our fiscal year 2007 that had been accrued for him as of August 31, 2007, and decided that he would not accept any future equity awards under the 2004 Unit Plan. In accordance with GAAP, we recorded compensation expense and an offsetting capital contribution of $417 for the four months ended December 31, 2007 as an estimate of the reasonable compensation level for the CEO position, and transferred the $750 accumulated fiscal year 2007 bonus from accrued liabilities to ETP’s partners’ capital.

As of December 31, 2007, we had advances due from a propane joint venture of $18,185 which are included in advances to and investment in affiliates on our condensed consolidated balance sheet.

Our natural gas midstream and intrastate transportation and storage operations secure compression services from third parties including Energy Transfer Technologies, Ltd., of which Energy Transfer Group, LLC is the General Partner. These entities are collectively referred to as the “ETG Entities”. Our Chief Executive Officer has an indirect ownership in the ETG Entities. In addition, two of the General Partner’s directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of independent directors of the General Partner, no less favorable than those available from other providers of compression services. During the four months ended December 31, 2007, we made payments totaling $785 to the ETG Entities for compression services provided to and utilized in our natural gas midstream and intrastate transportation and storage operations. As of December 31, 2007, accounts receivable from ETG related to compressor leases totaled $922.

14. REPORTABLE SEGMENTS:

Our financial statements reflect four reportable segments which conduct business exclusively in the United States of America, as follows:

• natural gas operations -

• midstream

• intrastate transportation and storage

• interstate transportation

• retail propane operations

Segments below the quantitative thresholds are classified as “other”. The components of the “other” classification have not met any of the quantitative thresholds for determining reportable segments. Management has included the wholesale propane operations in “other” because such operations are not material.

Midstream and intrastate transportation and storage segment revenues and expenses include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

See Note 1, “Business Operations” for a detailed description of the operations of each of our reportable segments.

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We evaluate the performance of our operating segments based on operating income exclusive of general partnership selling, general, administrative expenses, gain (loss) on disposal of assets, minority interests, interest expense, earnings (losses) from equity investments and income tax expense (benefit). Certain overhead costs relating to a reportable segment have been allocated for purposes of calculating operating income. Effective with the Transwestern acquisition on December 1, 2006, we began allocating administration expenses from the Partnership to our Operating Partnerships using the Modified Massachusetts Formula Calculation (“MMFC”) which is based on factors such as respective segments’ gross margins, employee costs, and property and equipment. The expenses subject to allocation are based on estimated amounts and take into consideration actual expenses from previous months and known trends. The difference between the allocation and actual costs is adjusted in the following month. The amounts allocated for the four months ended December 31, 2007 were approximately $6,761 to the midstream and intrastate transportation segments, $2,613 to the interstate transportation segment and $5,992 to the propane segment, for a total of approximately $15,366. These amounts were offset by costs allocated to the Partnership from the Operating Partnerships for support services. The amounts allocated to the Partnership, using the MMFC, from the midstream and intrastate transportation and propane segments for the four months ended December 31, 2007 were $2,440 and $850, respectively. No such amounts were allocated to the Partnership from the interstate transportation segment for the four months ended December 31, 2007.

The following table presents the financial information by segment for four months ended December 31, 2007:

Volumes (unaudited):
Midstream
Natural gas MMBtu/d—sold		1,090,090
NGLs bbls/d—sold		25,389
Transportation and storage
Natural gas MMBtu/d—transported		8,787,387
Natural gas MMBtu/d—sold		1,259,566
Interstate transportation
Natural gas MMBtu/d—transported		1,708,477
Retail propane gallons (in thousands)		205,311
Revenues:
Midstream	$	1,166,313
Eliminations		(664,522	)
Intrastate transportation and storage		1,254,401
Interstate transportation		76,000
Retail propane and other retail propane related		511,258
All other		5,892
Total revenues	$	2,349,342
Cost of Sales:
Midstream	$	1,043,191
Eliminations		(664,522	)
Intrastate transportation and storage		964,568
Retail propane and other retail propane related		325,158
All other		5,259
Total cost of sales	$	1,673,654
Depreciation and Amortization:
Midstream	$	14,943
Intrastate transportation and storage		23,429
Interstate transportation		12,305
Retail propane and other retail propane related		24,537
All other		192
Total depreciation and amortization	$	75,406

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Operating Income (Loss):
Midstream	$	71,853
Intrastate transportation and storage		169,361
Interstate transportation		29,657
Retail propane and other retail propane related		46,747
All other		(796	)
Selling general and administrative expenses not allocated to segments		(171	)
Total operating income	$	316,651
Other items not allocated by segment:
Interest expense	$	(103,375	)
Equity in losses of affiliates		(94	)
Gain on disposal of assets		14,310
Other expense, net		(34,734	)
Income tax expense		(9,949	)
Minority interests		(90,132	)
		(223,974	)
Net income	$	92,677
Total Assets:
Midstream	$	1,444,446
Intrastate transportation and storage		4,254,514
Interstate transportation		1,834,941
Retail propane and other retail propane related		1,778,426
All other		149,767
Total	$	9,462,094
Additions to Property, Plant and Equipment Including Acquisitions (accrual basis):
Midstream	$	414,722
Intrastate transportation and storage		320,965
Interstate transportation		167,343
Retail propane and other retail propane related		47,553
All other		953
Total	$	951,536

15. SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

Following are the financial statements of the Parent Company which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:

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BALANCE SHEET

December 31, 2007

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	42
Accounts receivable from related companies		11,586
Prepaid expenses and other		66
Total current assets		11,694
ADVANCES TO AND INVESTMENT IN AFFILIATES		1,607,658
INTANGIBLES AND OTHER LONG-TERM ASSETS, net		11,588
Total assets	$	1,630,940
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
CURRENT LIABILITIES:
Accounts payable	$	728
Accounts payable to affiliates		1,574
Accrued interest		15,671
Accrued and other current liabilities		564
Income taxes payable		252
Price risk management liabilities		9,189
Total current liabilities		27,978
LONG-TERM DEBT, less current maturities		1,572,643
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		45,982
COMMITMENTS AND CONTINGENCIES
		1,646,603
PARTNERS’ CAPITAL (DEFICIT):
General Partner		192
Limited Partner—Common Unitholders (222,829,956 units authorized, issued and outstanding)		(4,628	)
		(4,436	)
Accumulated other comprehensive loss		(11,227	)
Total partners’ deficit		(15,663	)
Total liabilities and partners’ capital (deficit)	$	1,630,940

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STATEMENT OF OPERATIONS

For The Four Months Ended December 31, 2007

SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(2,875	)
OTHER INCOME (EXPENSE):
Interest expense		(37,071	)
Equity in earnings of affiliates		168,547
Other expense, net		(35,798	)
INCOME BEFORE INCOME TAX EXPENSE		92,803
Income tax expense		(126	)
NET INCOME		92,677
GENERAL PARTNER'S INTEREST IN NET INCOME		287
LIMITED PARTNERS' INTEREST IN NET INCOME	$	92,390

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STATEMENT OF CASH FLOWS

For The Four Months Ended December 31, 2007

NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	77,360
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,255
Cash distributions to Partners		(87,174	)
Net cash used for financing activities		(85,919	)
DECREASE IN CASH AND CASH EQUIVALENTS		(8,559	)
CASH AND CASH EQUIVALENTS, beginning of period		8,601
CASH AND CASH EQUIVALENTS, end of period	$	42

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16. SUBSEQUENT EVENTS:

On February 29, 2008, MEP, our joint venture with KMEP, entered into a credit agreement that provides for a $1,400,000 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 KMEP. 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 debt rating and that of KMEP, with a maximum fee of 0.15%. The MEP Facility also has a swingline loan option with a maximum borrowing of $25,000 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 March 7, 2008, MEP had $210,000 outstanding borrowings under the MEP Facility. The weighted average interest rate on the total amount outstanding at March 7, 2008 was 3.488%. The total amount available under the MEP Facility was $1,190,000 as of March 7, 2008.

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