Exhibit 99.1

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Equity, L.P. and Subsidiaries

	Page
Consolidated Balance Sheets – December 31, 2010 and 2009	F-3
Consolidated Statements of Operations – Years Ended December 31, 2010, 2009 and 2008	F-5
Consolidated Statements of Comprehensive Income – Years Ended December 31, 2010, 2009 and 2008	F-6
Consolidated Statements of Equity – Years Ended December 31, 2010, 2009 and 2008	F-7
Consolidated Statements of Cash Flows – Years Ended December 31, 2010, 2009 and 2008	F-8
Notes to Consolidated Financial Statements	F-9

F-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, 2009, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the two years in the period ended December 31, 2009. 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 audits.

We conducted our audits 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide 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, 2009, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2, the Partnership retrospectively adopted a new accounting pronouncement on January 1, 2009 related to the accounting for noncontrolling interests in consolidated financial statements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Energy Transfer Equity, L.P.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 24, 2010 (not separately included herein), expressed an unqualified opinion on the effectiveness of internal control over financial reporting.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 24, 2010

F-2

 ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	December 31,
	2010			2009
ASSETS	(not included in attached audit opinion)
CURRENT ASSETS:
Cash and cash equivalents	$	86,264		$	68,315
Marketable securities		2,032			6,055
Accounts receivable, net of allowance for doubtful accounts of $6,706 and    $6,338 as of December 31, 2010 and 2009, respectively		612,357			566,522
Accounts receivable from related companies		76,331			51,894
Inventories		366,384			389,954
Exchanges receivable		21,926			23,136
Price risk management assets		16,357			12,371
Other current assets		109,359			149,712
Total current assets		1,291,010			1,267,959
PROPERTY, PLANT AND EQUIPMENT		13,284,430			10,117,041
ACCUMULATED DEPRECIATION		(1,431,698	)		(1,052,566	)
		11,852,732			9,064,475
ADVANCES TO AND INVESTMENTS IN AFFILIATES		1,359,979			663,298
LONG-TERM PRICE RISK MANAGEMENT ASSETS		13,971			—
GOODWILL		1,600,611			775,094
INTANGIBLES AND OTHER ASSETS, net		1,260,427			389,683
Total assets	$	17,378,730		$	12,160,509

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

F-3

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	December 31,
	2010		2009
LIABILITIES AND EQUITY	(not included in attached audit opinion)
CURRENT LIABILITIES:
Accounts payable	$	421,556	$	359,176
Accounts payable to related companies		27,351		38,515
Exchanges payable		16,003		19,203
Price risk management liabilities		13,172		65,146
Accrued and other current liabilities		567,688		366,781
Current maturities of long-term debt		35,305		40,924
Total current liabilities		1,081,075		889,745
LONG-TERM DEBT, less current maturities		9,346,067		7,750,998
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		79,465		73,332
SERIES A CONVERTIBLE PREFERRED UNITS (Note 7)		317,600		—
OTHER NON-CURRENT LIABILITIES		235,848		226,183
COMMITMENTS AND CONTINGENCIES (Note 10)
PREFERRED UNITS OF SUBSIDIARY (Note 7)		70,943		—
EQUITY:
PARTNERS’ CAPITAL:
General Partner		520		368
Limited Partners:
Common Unitholders (222,941,172 and 222,898,248 units authorized, issued and outstanding as of December 31, 2010 and 2009, respectively)		115,350		53,412
Accumulated other comprehensive income (loss)		4,798		(53,628	)
Total partners’ capital		120,668		152
Noncontrolling interest		6,127,064		3,220,099
Total equity		6,247,732		3,220,251
Total liabilities and equity	$	17,378,730	$	12,160,509

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

F-4

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

	Years Ended December 31,
	2010			2009			2008
REVENUES:	(not included in attached audit opinion)
Natural gas operations	$	5,167,945		$	4,115,806		$	7,653,156
Retail propane		1,314,973			1,190,524			1,514,599
Other		115,214			110,965			125,612
Total revenues		6,598,132			5,417,295			9,293,367
COSTS AND EXPENSES:
Cost of products sold ─ natural gas operations		3,328,754			2,519,575			5,885,982
Cost of products sold ─ retail propane		752,926			574,854			1,014,068
Cost of products sold ─ other		29,657			27,627			38,030
Operating expenses		784,546			680,893			781,831
Depreciation and amortization		431,199			325,024			274,372
Selling, general and administrative		234,321			178,924			200,181
Total costs and expenses		5,561,403			4,306,897			8,194,464
OPERATING INCOME		1,036,729			1,110,398			1,098,903
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(624,887	)		(468,420	)		(357,541	)
Equity in earnings (losses) of affiliates		65,220			20,597			(165	)
Losses on disposal of assets		(5,255	)		(1,564	)		(1,303	)
Gains (losses) on non-hedged interest rate derivatives		(52,357	)		33,619			(128,423	)
Allowance for equity funds used during construction		28,942			10,557			63,976
Impairment of investment in affiliate		(52,620	)		—			—
Other, net		(44,210	)		1,913			8,115
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		351,562			707,100			683,562
Income tax expense		13,738			9,229			3,808
INCOME FROM CONTINUING OPERATIONS		337,824			697,871			679,754
Loss from discontinued operations		(1,244	)		—			—
NET INCOME		336,580			697,871			679,754
Less: Net income attributable to noncontrolling interest		143,822			255,398			304,710
NET INCOME ATTRIBUTABLE TO PARTNERS		192,758			442,473			375,044
GENERAL PARTNER’S INTEREST IN NET INCOME		597			1,370			1,161
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	192,161		$	441,103		$	373,883
BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.86		$	1.98		$	1.68
BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		222,941,156			222,898,203			222,829,956
DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.86		$	1.98		$	1.68
DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		222,941,156			222,898,203			222,829,956

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

F-5

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

	Years Ended December 31,
	2010			2009			2008
	(not included in attached audit opinion)
Net income	$	336,580		$	697,871		$	679,754
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on    derivative instruments accounted for as cash flow    hedges		49,353			16,958			(22,916	)
Change in value of derivative instruments accounted    for as cash flow hedges		19,012			(11,017	)		(40,350	)
Change in value of available-for-sale securities		(4,023	)		10,924			(6,418	)
		64,342			16,865			(69,684	)
Comprehensive income		400,922			714,736			610,070
Less: Comprehensive income attributable to noncontrolling interest		149,738			258,066			291,624
Comprehensive income attributable to partners	$	251,184		$	456,670		$	318,446

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

F-6

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Dollars in thousands)

	General Partner			Common Unitholders			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Balance, December 31, 2007 (not included in attached audit opinion)	$	192		$	(4,628	)	$	(11,227	)	$	2,106,819		$	2,091,156
Distributions to ETE partners		(1,349	)		(434,519	)		—			—			(435,868	)
Subsidiary distributions		—			—			—			(319,963	)		(319,963	)
Subsidiary units issued for cash		151			48,631			—			326,505			375,287
Non-cash unit-based compensation    expense, net of units tendered by    employees for tax withholdings		—			823			—			19,968			20,791
Non-cash executive compensation		—			48			—			1,202			1,250
Other, net		—			—			—			(3,407	)		(3,407	)
Other comprehensive loss, net of tax		—			—			(56,598	)		(13,086	)		(69,684	)
Net income		1,161			373,883			—			304,710			679,754
Balance, December 31, 2008		155			(15,762	)		(67,825	)		2,422,748			2,339,316
Distributions to ETE partners		(1,457	)		(469,201	)		—			—			(470,658	)
Subsidiary distributions		—			—			—			(381,471	)		(381,471	)
Subsidiary units issued for cash		300			96,696			—			902,680			999,676
Non-cash unit-based compensation    expense, net of units tendered by    employees for tax withholdings		—			551			—			20,613			21,164
Non-cash executive compensation		—			25			—			1,225			1,250
Other, net		—			—			—			(3,762	)		(3,762	)
Other comprehensive income, net of tax		—			—			14,197			2,668			16,865
Net income		1,370			441,103			—			255,398			697,871
Balance, December 31, 2009		368			53,412			(53,628	)		3,220,099			3,220,251
Regency Transactions (See Notes 1 and 3)		648			209,065			—			1,895,268			2,104,981
Distributions to ETE partners		(1,495	)		(481,553	)		—			—			(483,048	)
Subsidiary distributions		—			—			—			(567,593	)		(567,593	)
Subsidiary units issued for cash		441			142,154			—			1,409,215			1,551,810
Non-cash unit-based compensation    expense, net of units tendered by    employees for tax withholdings		—			911			—			23,770			24,681
Non-cash executive compensation		—			25			—			1,225			1,250
Other, net		(39	)		(825	)		—			(4,658	)		(5,522	)
Other comprehensive income, net of tax		—			—			58,426			5,916			64,342
Net income		597			192,161			—			143,822			336,580
Balance, December 31, 2010 (not included in attached audit opinion)	$	520		$	115,350		$	4,798		$	6,127,064		$	6,247,732

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

F-7

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

	December 31,
	2010			2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:	(not included in attached audit opinion)
Net income	$	336,580		$	697,871		$	679,754
Reconciliation of net income to net cash provided by operating activities:
Impairment of investment in affiliate		52,620			—			—
Impairment of goodwill		—			—			11,359
Payment for termination of Parent Company interest rate derivatives (See Note 11)		(168,550	)		—			—
Proceeds from termination of ETP interest rate derivatives (See Note 11)		26,495			—			—
Depreciation and amortization		431,199			325,024			274,372
Amortization of finance costs charged to interest		18,111			14,954			10,962
Non-cash unit-based compensation expense		29,918			24,583			24,304
Non-cash executive compensation expense		1,250			1,250			1,250
Losses on disposal of assets		5,255			1,564			1,303
Distribution in excess of earnings of affiliates, net		79,975			3,224			5,621
Other non-cash		14,483			3,627			(21,652	)
Net change in operating assets and liabilities, net of effects of acquisitions (see Note 2)		259,543			(348,636	)		156,447
Net cash provided by operating activities		1,086,879			723,461			1,143,720
CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash (paid for) received from acquisitions		(345,237	)		30,367			(84,783	)
Capital expenditures		(1,509,977	)		(748,621	)		(2,054,806	)
Contributions in aid of construction costs		13,720			6,453			50,050
(Advances to) repayments from affiliates, net		(92,603	)		(655,500	)		54,534
Proceeds from the sale of assets		104,118			21,545			19,420
Net cash used in investing activities		(1,829,979	)		(1,345,756	)		(2,015,585	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		4,388,531			3,542,612			6,205,994
Principal payments on debt		(4,078,171	)		(3,020,587	)		(4,890,619	)
Subsidiary equity offerings, net of issue costs		1,551,810			936,337			373,059
Distributions to partners		(483,048	)		(470,658	)		(435,868	)
Distributions to noncontrolling interests		(567,593	)		(381,471	)		(319,963	)
Debt issuance costs		(48,613	)		(7,646	)		(25,272	)
Other		(1,867	)		—			—
Net cash provided by financing activities		761,049			598,587			907,331
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		17,949			(23,708	)		35,466
CASH AND CASH EQUIVALENTS, beginning of period		68,315			92,023			56,557
CASH AND CASH EQUIVALENTS, end of period	$	86,264		$	68,315		$	92,023

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

F-8

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts in thousands, except per unit data)

1.   OPERATIONS AND ORGANIZATION:

Financial Statement Presentation

The consolidated financial statements of Energy Transfer Equity, L.P. (the “Partnership,” “we” or “ETE”) presented herein for the years ended December 31, 2010, 2009 and 2008, 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 subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner.  All significant intercompany transactions and accounts are eliminated in consolidation.  Management has evaluated subsequent events through the date the financial statements were issued.

The consolidated financial statements of ETE presented herein for the years ended December 31, 2010, 2009 and 2008 include the results of operations of:

·   the Parent Company;

·   our controlled subsidiaries, ETP and Regency (see description of their respective operations below under “Business Operations”);

·   ETP’s and Regency’s wholly-owned subsidiaries; and our wholly-owned subsidiaries that own the general partner and Incentive Distribution Right (“IDR”) interest in ETP and Regency.

The consolidated financial statements include the results of Regency from May 26, 2010, the date ETE obtained control of Regency, through December 31, 2010.

At December 31, 2010, our equity interests consisted of:

	General Partner Interest (as a % of total partnership interest)	IDRs	Limited Partner Units
ETP	1.8%	100%		50,226,967
Regency	2.0%	100%		26,266,791

Our subsidiaries 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.

Certain prior period amounts have been reclassified to conform to the 2010 presentation.  These reclassifications had no impact on net income or total equity.

Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, Energy Transfer Partners GP, L.P. (“ETP GP”), the General Partner of ETP, ETP GP’s General Partner, Energy Transfer Partners, L.L.C. (“ETP LLC”), Regency, Regency GP LP (“Regency GP”), the General Partner of Regency, and Regency GP’s General Partner, Regency GP LLC (“Regency LLC”).  References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

F-9

Business Operations

The Parent Company’s principal sources of cash flow are its direct and indirect investments in the Limited Partner and General Partner interests in ETP and Regency.  The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners and holders of its Series A Convertible Preferred Units (“Preferred Units”).  Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries.  In order to fully understand the financial condition of the Parent Company on a stand-alone basis, see Note 16 for stand-alone financial information apart from that of the consolidated partnership information included herein.

The following is a brief description of ETP’s and Regency’s operations:

·   ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets.  ETP has pipeline operations in Arkansas, Arizona, Colorado, Louisiana, Mississippi, New Mexico, Utah, and West Virginia and owns the largest intrastate pipeline system in Texas.  ETP currently has natural gas operations that include more than 17,500 miles of gathering and transportation pipelines, treating and processing assets, and three storage facilities located in Texas.  ETP is also one of the three largest retail marketers of propane in the United States, serving more than one million customers across the country.

·   Regency is a publicly traded Delaware limited partnership formed in 2005 engaged in the gathering, treating, processing, compressing and transportation of natural gas and NGLs.  Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville and Marcellus shales as well as the Permian Delaware basin.  Its assets are primarily located in Louisiana, Texas, Arkansas, Pennsylvania, Mississippi, Alabama and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma.

2.   ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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 intrastate transportation and storage operations are estimated using volume estimates and market prices.  Any differences between estimated results and actual results are recognized in the following month’s financial statements.  Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves.  Actual results could differ from those estimates.

Revenue Recognition

Our segments are engaged in multiple revenue-generating activities.  To the extent that those activities are similar among our segments, revenue recognition policies are similar.  Following is a description of revenue recognition policies for significant revenue-generating activities within each segment.

F-10

Investment in ETP

Revenues for ETP’s sales of natural gas, 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.  Revenues from service labor, transportation, treating, compression and gas processing, are 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.

ETP’s intrastate transportation and storage and interstate transportation operations’ results are determined primarily by the amount of capacity its customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines.  Under transportation contracts, ETP’s 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) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly.  Excess fuel retained after consumption is typically valued at market prices.

ETP’s intrastate transportation and storage operations also generate 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, ETP purchases natural gas from the market, including purchases from ETP’s midstream marketing operations, and from producers at the wellhead.

In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in its storage facilities.  ETP also engages in natural gas storage transactions in which it seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir.  ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover its carrying costs and provide for a gross profit margin.  ETP expects margins from natural gas storage transactions 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, ETP 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 it operates, competitive factors in the energy industry, and other issues.

Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through its pipeline and gathering systems and the level of natural gas and NGL prices.  ETP generates midstream revenues and gross margins principally under fee-based or other arrangements in which it receives 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 ETP’s systems and is not directly dependent on commodity prices.

ETP also utilizes other types of arrangements in its midstream operations, 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 ETP gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price, and (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices.  In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above.  The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements.  ETP’s 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.

F-11

ETP conducts marketing activities in which it markets the natural gas that flows through its assets, referred to as on-system gas.  ETP also attracts other customers by marketing volumes of natural gas that do not move through its assets, referred to as off-system gas.  For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells 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.

ETP’s retail propane operations sell propane and propane-related products and services.  The Heritage Operating, L.P. (“HOLP”) and Titan Energy Partners, L.P. (“Titan”) customer base includes residential, commercial, industrial and agricultural customers.

In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job.  Costs incurred on a job are deducted at the time revenue is recognized.

Investment in Regency

Regency earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas gathering, processing and transportation, (iii) contract compression services and (iv) contract treating services.  Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs.  Revenue associated with transportation and processing fees are recognized when the service is provided.  For contract compression services, revenue is recognized when the service is performed.  For gathering and processing services, Regency receives either fees or commodities from natural gas producers depending on the type of contract.  Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above.  Under the percentage-of-proceeds contract type, Regency is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas.  Under the percentage-of-index contract type, Regency earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas at a price approximating the index price and NGLs to third parties.  Regency generally reports revenue gross when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership.  Revenue for fee-based arrangements is presented net, because Regency takes the role of an agent for the producers.  Allowance for doubtful accounts is determined based on historical write-off experience and specific identification.

Regulatory Accounting - Regulatory Assets and Liabilities

Certain of our subsidiaries are subject to regulation by certain state and federal authorities and has accounting policies that conform to 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 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 sheets for the period in which the discontinuance of regulatory accounting treatment occurs.

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 changes in value.

We place our cash deposits and temporary cash investments with high credit quality financial institutions.  At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

F-12

As a result of ETP’s acquisition of a natural gas compression equipment business in exchange for ETP Common Units, cash acquired in connection with acquisitions during 2009 exceeded the cash we paid during the period.

The net change in operating assets and liabilities (net of acquisitions) included in cash flows from operating activities is comprised as follows:

	Years Ended December 31,
	2010			2009			2008
Accounts receivable	$	92,085		$	28,431		$	220,635
Accounts receivable from related companies		(26,265	)		(26,321	)		3,234
Inventories		14,750			(101,592	)		96,145
Exchanges receivable		1,064			22,074			(7,888	)
Other current assets		33,233			8,195			(57,150	)
Intangibles and other assets		5,843			(1,467	)		(15,881	)
Accounts payable		(66,936	)		(16,024	)		(296,185	)
Accounts payable to related companies		(9,939	)		4,184			(13,538	)
Exchanges payable		(3,841	)		(35,433	)		14,254
Accrued and other current liabilities		72,669			(101,927	)		68,975
Other non-current liabilities		442			1,401			1,741
Price risk management assets and liabilities, net		146,438			(130,157	)		142,105
Net change in operating assets and liabilities, net of effects of acquisitions	$	259,543		$	(348,636	)	$	156,447

Non-cash investing and financing activities and supplemental cash flow information are as follows:

	Years Ended December 31,
	2010		2009		2008
NON-CASH INVESTING ACTIVITIES:
Marketable securities received in exchange for accounts receivable	$	—	$	—	$	10,816
Accrued capital expenditures	$	108,076	$	46,134	$	153,230
Gain from subsidiary issuance of Common Units (recorded in partners’ capital)	$	352,307	$	96,996	$	48,782
NON-CASH FINANCING ACTIVITIES:
Long-term debt assumed and non-compete agreement notes payable issued from acquisitions	$	1,242,604	$	26,237	$	5,077
Subsidiary issuance of Common Units in connection with certain acquisitions	$	584,436	$	63,339	$	2,228
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	547,286	$	440,492	$	330,816
Cash paid for income taxes	$	9,188	$	15,447	$	5,191

Marketable Securities

Marketable securities are classified as available-for-sale securities and are reflected as current assets on the consolidated balance sheets at fair value.

Accounts Receivable

Our subsidiaries assess the credit risk of their customers.  Certain of our subsidiaries deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guarantee prepayment, master setoff agreement or collateral).  Management reviews

F-13

accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and specific identification.

Inventories

Inventories consist principally of natural gas held in storage valued at the lower of cost or market utilizing the weighted-average cost method.  Propane inventories are 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 consisted of the following:

	December 31,
	2010		2009
Natural gas and NGLs, excluding propane	$	170,179	$	157,103
Propane		76,341		66,686
Appliances, parts and fittings and other		119,864		166,165
Total inventories	$	366,384	$	389,954

ETP utilizes commodity derivatives to manage price volatility associated with its natural gas inventory.  In April 2009, it began designating certain of these derivatives as fair value hedges for accounting purposes.  Subsequent to the designation of those fair value hedging relationships, changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.

During 2009, ETP recorded lower of cost or market adjustments of $54.0 million and fair value adjustments related to its application of fair value hedging of $66.1 million.

Exchanges

Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others.  These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets.  These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms.

Other Current Assets

Other current assets consisted of the following:

	December 31,
	2010		2009
Deposits paid to vendors	$	52,192	$	79,694
Prepaid and other		57,167		70,018
Total other current assets	$	109,359	$	149,712

Property, Plant and Equipment

Property, plant and equipment are stated at cost less accumulated depreciation.  Depreciation is computed using the straight-line method over the estimated useful 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.  Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment.  Additionally, our subsidiaries 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,

F-14

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 consolidated statements of operations.

We and our subsidiaries 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 periods presented.

Capitalized interest is included for pipeline construction projects, except for interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued.  Interest is capitalized based on the current borrowing rate of ETP’s revolving credit facility when the related costs are incurred.  AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects.  It represents the cost of servicing the capital invested in construction work-in-process.  AFUDC is segregated into two component parts – borrowed funds and equity funds.

Components and useful lives of property, plant and equipment were as follows:

	December 31,
	2010			2009
Land and improvements	$	103,325		$	87,388
Buildings and improvements (10 to 83 years)		383,274			160,912
Pipelines and equipment (10 to 83 years)		9,709,568			7,388,889
Natural gas storage (40 years)		100,909			100,746
Bulk storage, equipment and facilities (5 to 83 years)		736,520			591,908
Tanks and other equipment (10 to 30 years)		623,126			602,915
Vehicles (3 to 33 years)		200,702			176,946
Right of way (20 to 83 years)		637,930			516,709
Furniture and fixtures (3 to 33 years)		41,205			32,810
Linepack		55,744			53,404
Pad gas		57,907			47,363
Other (5 to 33 years)		189,103			117,896
		12,839,313			9,877,886
Less ─ Accumulated depreciation		(1,431,698	)		(1,052,566	)
		11,407,615			8,825,320
Plus ─ Construction work-in-process		445,117			239,155
Property, plant and equipment, net	$	11,852,732		$	9,064,475

We recognized the following amounts of depreciation expense and capitalized interest expense for the periods presented:

	Years Ended December 31,
	2010		2009		2008
Depreciation expense	$	394,698	$	304,129	$	256,910
Capitalized interest, excluding AFUDC	$	4,071	$	11,791	$	21,595

Advances to and Investment in Affiliates

Certain of our subsidiaries 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 influence over, but do not control the investee’s operating and financial policies.

See Note 4 for a discussion of these joint ventures.

F-15

Goodwill

Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired.  Our annual impairment test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage, midstream and retail propane operations and as of December 31 for all others, including all of Regency’s reporting units.  No goodwill impairments were recorded for the periods presented in these consolidated financial statements.

Changes in the carrying amount of goodwill were as follows:

	Investment in ETP			Investment in Regency		Corporate and Other		Total
Balance, December 31, 2008	$	743,694		$	—	$	29,589	$	773,283
Purchase accounting adjustments		(8,662	)		—		—		(8,662	)
Goodwill acquired		10,473			—		—		10,473
Balance, December 31, 2009		745,505			—		29,589		775,094
Goodwill acquired		36,460			789,789		—		826,249
Other		(732	)		—		—		(732	)
Balance, December 31, 2010	$	781,233		$	789,789	$	29,589	$	1,600,611

Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.  A net increase in goodwill of $825.5 million was recorded during the year ended December 31, 2010, primarily due to $789.8 million from the Regency Transactions discussed in Note 3.  This additional goodwill is not expected to be deductible for tax purposes.  ETP also recorded goodwill of $27.3 million from its acquisition of the natural gas gathering company referenced in Note 3, which is expected to be deductible for tax purposes.

Intangibles and Other Assets

Intangibles and other assets are stated at cost, net of amortization computed on the straight-line method.  We eliminate from our consolidated balance sheets 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 assets were as follows:

	December 31, 2010					December 31, 2009
	Gross Carrying		Accumulated			Gross Carrying		Accumulated
	Amount		Amortization			Amount		Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	971,657	$	(88,583	)	$	176,858	$	(58,761	)
Trade names (20 years)		65,500		(1,910	)		—		—
Noncompete agreements (3 to 15 years)		21,165		(11,888	)		24,139		(12,415	)
Patents (9 years)		750		(118	)		750		(35	)
Other (10 to 15 years)		1,320		(492	)		478		(397	)
Total amortizable intangible assets		1,060,392		(102,991	)		202,225		(71,608	)
Non-amortizable intangible assets ─ Trademarks		77,445		—			75,825		—
Total intangible assets		1,137,837		(102,991	)		278,050		(71,608	)
Other assets:
Financing costs (3 to 30 years)		137,012		(38,945	)		84,099		(34,702	)
Regulatory assets		107,384		(14,445	)		101,879		(9,501	)
Other		35,001		(426	)		41,466		—
Total intangibles and other assets	$	1,417,234	$	(156,807	)	$	505,494	$	(115,811	)

F-16

We recorded the following intangible assets in conjunction with the Regency Transactions:

Amortizable intangible assets:
Customer relationships, contracts and agreements (30 years)	$	600,860
Trade names (20 years)		65,500
Total intangible and other assets acquired	$	666,360

In connection with the acquisition of a natural gas gathering company, ETP also recorded customer contracts of $68.2 million with useful lives of 46 years during 2010.  In connection with the Zephyr Gas Services, LLC (“Zephyr”) acquisition, Regency recorded intangibles related to customer relationships of $119.4 million with useful lives of 20 years.  See discussion of amounts recorded in the Regency Transactions at Note 3.

Aggregate amortization expense of intangibles and other assets was as follows:

	Years Ended December 31,
	2010		2009		2008
Reported in depreciation and amortization	$	33,913	$	20,895	$	17,462
Reported in interest expense	$	18,016	$	11,195	$	9,015

Estimated aggregate amortization expense for the next five years is as follows:

Years Ending December 31:
2011	$	60,364
2012		56,776
2013		51,342
2014		50,332
2015		47,874

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.  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, or more frequently if circumstances dictate.  Our annual impairment test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage, midstream, and retail propane operations and as of December 31 for all others, including Regency’s reporting units.  No impairment of intangible assets was required during the periods presented in these consolidated financial statements.

Asset Retirement Obligation

Our subsidiaries have determined that they are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets.  Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates.  However, ETP’s and Regency’s management were not able to reasonably measure the fair value of the asset retirement obligations as of December 31, 2010 or 2009 because the settlement dates were indeterminable.  ETP and Regency will record an asset retirement obligation in the periods in which management can reasonably determine the settlement dates.

F-17

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	December 31,
	2010		2009
Interest payable	$	191,466	$	137,708
Customer advances and deposits		111,448		88,430
Accrued capital expenditures		87,260		46,134
Accrued wages and benefits		76,592		25,577
Taxes other than income taxes		36,204		23,294
Income taxes payable		8,344		3,154
Other		56,374		42,484
Total accrued and other current liabilities	$	567,688	$	366,781

Deposits or advances are received from ETP and Regency’s customers as prepayments for natural gas deliveries in the following month and from ETP’s 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.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, 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 loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of December 31, 2010 was $10.23 billion and $9.38 billion, respectively.  As of December 31, 2009, the aggregate fair value and carrying amount of our consolidated debt obligations was $8.25 billion and $7.79 billion, respectively.

We have marketable securities, commodity derivatives, interest rate derivatives, Series A Convertible Preferred Units and embedded derivatives in the Regency Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets.  We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs.  Level 1 inputs are observable quotes in an active market for identical assets and liabilities.  We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation.  Level 2 inputs are inputs observable for similar assets and liabilities.  We consider over-the-counter (“OTC”) commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions.  Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade.  We consider the valuation of our interest rate derivatives as Level 2 since we use a LIBOR curve based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements and discount the future cash flows accordingly, including the effects of our credit risk.  Level 3 inputs are unobservable.  Derivatives related to the Regency Preferred Units are valued using a binomial lattice model.  The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected volatility and are considered Level 3.  The fair value of the Series A Convertible Preferred Units was based predominantly on an income approach model and is also considered Level 3.

F-18

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2010 and 2009 based on inputs used to derive their fair values:

	Fair Value Measurements at
	December 31, 2010 Using
				Quoted Prices
				in Active
				Markets for			Significant			Significant
				Identical Assets			Observable			Unobservable
	Fair Value			and Liabilities			Inputs			Inputs
	Total			(Level 1)			(Level 2)			(Level 3)
Assets:
Marketable securities	$	2,032		$	2,032		$	—		$	—
Interest rate derivatives		20,790			—			20,790			—
Commodity derivatives:
Natural Gas:
Fixed Swaps/Futures		3,130			649			2,481			—
Options — Puts		26,234			—			26,234			—
NGLs — Forward Swaps		7,056			—			7,056			—
Total commodity derivatives		36,420			649			35,771			—
Total Assets	$	59,242		$	2,681		$	56,561		$	—
Liabilities:
Interest rate derivatives	$	(20,922	)	$	—		$	(20,922	)	$	—
Series A Convertible Preferred Units		(317,600	)		—			—			(317,600	)
Embedded Derivative in Preferred Units of Subsidiary		(57,023	)		—			—			(57,023	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX		(1,617	)		(1,617	)		—			—
Swing Swaps IFERC		(2,086	)		(1,958	)		(128	)		—
Fixed Swaps/Futures		(427	)		—			(427	)		—
Options — Calls		(2,569	)		—			(2,569	)		—
NGLs – Forward Swaps		(10,684	)		—			(10,684	)		—
WTI Crude Oil		(3,581	)		—			(3,581	)		—
Total commodity derivatives		(20,964	)		(3,575	)		(17,389	)		—
Total Liabilities	$	(416,509	)	$	(3,575	)	$	(38,311	)	$	(374,623	)

	Fair Value Measurements at
	December 31, 2009 Using
				Quoted Prices
				in Active
				Markets for			Significant
				Identical Assets			Observable
	Fair Value			and Liabilities			Inputs
	Total			(Level 1)			(Level 2)
Assets:
Marketable securities	$	6,055		$	6,055		$	—
Commodity derivatives		32,479			20,090			12,389
Liabilities:
Commodity derivatives		(8,016	)		(7,574	)		(442	)
Interest rate derivatives		(138,036	)		—			(138,036	)
	$	(107,518	)	$	18,571		$	(126,089	)

F-19

The following table presents the changes in Level 3 derivatives measured on a recurring basis for the year ended December 31, 2010.  There were no transfers between Level 2 and Level 3 for the year ended December 31, 2010 and there were no Level 3 assets or liabilities for the year ended December 31, 2009.

Balance, December 31, 2009	$	—
Issuance of Series A Convertible Preferred Units		(304,950	)
Acquisition date fair value of Preferred Units of Subsidiary		(48,633	)
Net unrealized losses included in other income (expense)		(21,040	)
Balance, December 31, 2010	$	(374,623	)

Prior to the Regency Transactions, ETP adjusted the investment in MEP to fair value based on the present value of expected future cash flows (Level 3), resulting in a nonrecurring fair value adjustment of $52.6 million.  See Note 4.

Shipping and Handling Costs

Shipping and handling costs related to fuel sold are included in cost of products sold.  ETP’s shipping and handling costs related to fuel consumed for compression and treating are included in operating expenses and totaled $43.3 million, $55.9 million and $112.0 million for the years ended December 31, 2010, 2009 and 2008, respectively.  ETP does 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 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.

Issuances of Subsidiary Units

We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income.  For example, upon ETP’s or Regency’s issuance of respective ETP or Regency Common Units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.

Income Taxes

ETE 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 our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).

As a limited partnership, we are generally not subject to income tax.  We are, however, subject to a statutory requirement that our non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of our total gross income, determined on a calendar year basis under the applicable income tax provisions.  If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation.  Accordingly, certain activities that generate non-qualifying income are conducted through taxable corporate subsidiaries (“C corporations”).  These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations.  For the years ended December 31, 2010, 2009 and 2008, our non-qualifying income did not exceed the statutory limit.

F-20

Those subsidiaries which are taxable corporations follow the asset and liability method of accounting for income taxes, under which deferred income taxes are recorded based upon differences between the financial reporting and tax basis 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.

The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are generally not subject to federal and state income taxes at the Partnership level.

The components of the federal and state income tax expense (benefit) or our taxable subsidiaries are summarized as follows:

	Years Ended December 31,
	2010		2009			2008
Current expense (benefit):
Federal	$	1,602	$	(8,850	)	$	(180	)
State		8,594		9,657			12,241
Total		10,196		807			12,061
Deferred expense (benefit):
Federal		2,788		8,643			(8,531	)
State		754		(221	)		278
Total		3,542		8,422			(8,253	)
Total income tax expense	$	13,738	$	9,229		$	3,808

As of December 31, 2010 and 2009, we had deferred income tax liabilities of $213.9 million and $204.4 million, respectively, recorded in other non-current liabilities in our consolidated balance sheets.  Substantially all of our deferred tax liability relates to property, plant and equipment, including $143.9 million and $136.6 million as of December 31, 2010 and 2009, respectively, and basis differences associated with ETP’s Class E Units of $70.2 million and $67.5 million as of December 31, 2010 and 2009, respectively.  As of December 31, 2010, we had deferred income tax liabilities of $0.4 million recorded in accrued and other liabilities in our consolidated balance sheets.

Accounting for Derivative Instruments and Hedging Activities

For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations.  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.

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 net income for the period.

If we designate a hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations.  This amount is offset by the changes in fair value of the related hedging instrument.  Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.

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

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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 (“AOCI”) 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.  Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI 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 financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments.  Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges.  For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense.  For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on non-hedged interest rate derivatives” in the consolidated statements of operations.  See Note 11 for additional information related to interest rate derivatives.

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 8).

3.   ACQUISITIONS AND DISPOSITIONS:

2010

Regency Transactions

On May 26, 2010, we acquired our equity interests in Regency in a series of transactions, which we refer to as the Regency Transactions.  In the Regency Transactions, we:

• acquired the general partner interest and IDRs in Regency in exchange for 3,000,000 Preferred Units having an aggregate liquidation preference of $300.0 million;

• acquired from ETP an indirect 49.9% interest in Midcontinent Express Pipeline LLC (“MEP”), ETP’s joint venture with Kinder Morgan Energy Partners, L.P. (“KMP”) to operate the Midcontinent Express Pipeline, and an option to acquire an additional 0.1% interest in MEP in exchange for the redemption by ETP of approximately 12.3 million ETP Common Units we previously owned; and

• acquired 26.3 million Regency Common Units in exchange for our contribution of all of our interests in MEP, including the option to acquire an additional 0.1% interest, to Regency.

As of December 31, 2010, we owned approximately 19% of Regency’s outstanding Common Units.

We accounted for the Regency Transactions using the purchase method of accounting.  The purchase price was $305.0 million, which was the fair value of the 3,000,000 Preferred Units exchanged in connection with the Regency Transactions.

F-22

The following summarizes the assets acquired and liabilities assumed in the Regency Transactions, as well as the fair value of the noncontrolling interest in Regency:

Total current assets	$	189,502
Property, plant and equipment		1,548,384
Advances to and investments in affiliates		739,164
Goodwill		789,789
Intangible assets		666,360
Other assets		37,693
		3,970,892
Total current liabilities		192,788
Long-term debt		1,239,863
Other long-term liabilities		57,517
Regency convertible preferred units		70,793
Noncontrolling interest		2,104,981
		3,665,942
Total consideration		304,950
Cash received		23,995
Total consideration, net of cash received	$	280,955

See disclosure of the amount of Regency’s revenues and earnings included in the consolidated statement of operations from the close of the acquisition through December 31, 2010 in Note 14.

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the years ended December 31, 2010 and 2009 are presented as if the Regency Transactions had been completed on January 1, 2009.

	Years Ended December 31,
	2010		2009
Revenues	$	7,101,793	$	6,420,462
Net income		375,300		791,890
Net income attributable to partners		235,569		414,528
Basic net income per Limited Partner unit		1.05		1.85
Diluted net income per Limited Partner unit		1.05		1.85

The pro forma consolidated results of operations include adjustments to:

·   include the results of Regency for all periods presented;

·   include the incremental expenses associated with the fair value adjustments recorded as a result of applying the purchase method of accounting;

·   adjust for one-time expenses related to the Regency Transactions; and

·   adjust for the relative change in ownership of ETP as a result of the transfer of MEP.

The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

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Other Acquisitions

In March 2010, ETP purchased a natural gas gathering company, which provides dehydration, treating, redelivery and compression services on a 120-mile pipeline system in the Haynesville Shale for approximately $150.0 million in cash, excluding certain adjustments as defined in the purchase agreement.  In connection with this transaction, ETP recorded customer contracts of $68.2 million and goodwill of $27.3 million.

In September 2010, Regency completed its acquisition of Zephyr, a Texas based field services company for approximately $193.3 million in cash.  In connection with this transaction, Regency recorded intangible assets of $119.4 million and no goodwill.

Dispositions

In July 2010, Regency sold its East Texas gathering and processing assets to an affiliate of Tristream Energy LLC for approximately $70.2 million in cash.  The net income from these assets is classified as discontinued operations in the consolidated statements of operations from the date of the Regency Transactions to the date of the sale.

2009

In November 2009, ETP acquired all of the outstanding equity interests of a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas, in exchange for the issuance of 1,450,076 ETP Common Units having an aggregate market value of approximately $63.3 million on the closing date.  In connection with this transaction, ETP received cash of $41.1 million, assumed total liabilities of $30.5 million, which includes $8.4 million in notes payable and recorded goodwill of $8.7 million.

In August 2009, ETP acquired Energy Transfer Group, L.L.C. (“ETG”), as described in Note 13.  In connection with this transaction, we assumed liabilities of $33.5 million and recorded goodwill of $1.7 million.

2008

During the year ended December 31, 2008, subsidiaries of ETP, collectively acquired substantially all of the assets of 20 propane businesses.  The aggregate purchase price for these acquisitions totaled $96.4 million, which included $76.2 million of cash paid, net of cash acquired, liabilities assumed of $8.2 million, 53,893 Common Units issued valued at $2.2 million and debt forgiveness of $9.8 million.  The cash paid for acquisitions was financed primarily with ETP’s and HOLP’s revolving credit facilities.  We recorded $15.3 million of goodwill in connection with these acquisitions.

4.   INVESTMENTS IN AFFILIATES:

Midcontinent Express Pipeline LLC

Certain of our subsidiaries are party to an agreement with Kinder Morgan Energy Partners, L.P. (“KMP”) for a joint development of the Midcontinent Express pipeline.  Construction of the approximately 500-mile pipeline was completed and natural gas transportation service commenced August 1, 2009 on the pipeline from Delhi, Louisiana, to an interconnect with the Transco interstate natural gas pipeline in Butler, Alabama.  Interim service began on the pipeline from Bennington, Oklahoma, to Delhi in April 2009.

On January 9, 2009, MEP filed an amended application to revise its initial transportation rates to reflect an increase in projected costs for the project; the amended application was approved by the FERC on March 25, 2009.  In May 2010, MEP, the entity formed to construct, own and operate this pipeline, placed into service certain expansion facilities to increase the total capacity for the main segment of the pipeline from Bennington to an interconnect location with the Columbia Gas Transmission, LLC near Waverly, Louisiana from 1.4 Bcf/d to 1.5 Bcf/d.  In June 2010, MEP placed additional expansion facilities into service, further increasing capacity for the main segment of the pipeline from Bennington to the interconnect with the Columbia Gas Transmission pipeline from 1.5 Bcf/d to 1.8 Bcf/d, and increasing the total capacity of the main segment of the pipeline from the interconnect with Columbia Gas Transmission’s pipeline to the Transco interstate natural gas pipeline near Butler, Alabama, from 1.0 Bcf/d to 1.2 Bcf/d.

F-24

In conjunction with the Regency Transactions, the Parent Company acquired from ETP a 49.9% interest in MEP, in exchange for ETP’s redemption of approximately 12.3 million ETP Common Units that were previously held by the Parent Company.  The Parent Company immediately contributed this 49.9% interest in MEP to Regency in exchange for approximately 26.3 million Regency Common Units.  In addition to the 49.9% interest in MEP, the Parent Company also acquired an option to purchase ETP’s remaining 0.1% interest in MEP in May 2011, which the Parent Company also transferred to Regency.

In conjunction with this transfer, ETP recorded a non-cash charge of approximately $52.6 million during the year ended December 31, 2010 to reduce the carrying value of its interest in MEP to its estimated fair value.

RIGS Haynesville Partnership Co.

Regency owns a 49.99% interest in the RIGS Haynesville Partnership Co. joint venture (“HPC”), which, through its ownership of the Regency Intrastate Gas System (“RIGS”), delivers natural gas from northwest Louisiana to markets as well as downstream pipelines in northeast Louisiana through a 450-mile intrastate pipeline system.

Fayetteville Express Pipeline LLC

ETP is party to an agreement with KMP for a 50/50 joint development of the Fayetteville Express pipeline, an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi.  In December 2009, Fayetteville Express Pipeline LLC (“FEP”), the entity formed to construct, own and operate this pipeline, received FERC approval of its application for authority to construct and operate this pipeline.  ETP is the operator of the pipeline which has an initial capacity of 2.0 Bcf/d.  As of December 31, 2010, FEP has secured binding commitments for a minimum of 10 years for transportation of approximately 1.85 Bcf/d.  The new pipeline will interconnect with Natural Gas Pipeline Company of America (“NGPL”) in White County, Arkansas, Texas Gas Transmission in Coahoma County, Mississippi and ANR Pipeline Company in Quitman County, Mississippi.  NGPL is operated and partially owned by Kinder Morgan, Inc.  Kinder Morgan, Inc. owns the general partner of KMP.

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Summarized Financial Information

The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, MEP, HPC and FEP (on a 100% basis for all periods presented).

	December 31,
	2010		2009
Current assets	$	83,735	$	74,737
Restricted cash, non-current		—		33,595
Property, plant and equipment, net		4,052,396		3,439,779
Other assets		160,655		171,469
Total assets	$	4,296,786	$	3,719,580
Current liabilities	$	91,860	$	187,945
Non-current liabilities		1,772,686		1,153,835
Equity		2,432,240		2,377,800
Total liabilities and equity	$	4,296,786	$	3,719,580

	Years Ended December 31,
	2010		2009		2008
Revenue	$	406,346	$	142,076	$	—
Operating income		221,623		66,333		—
Net income		166,910		56,247		1,057

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5.   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 and the assumed conversion of Series A Convertible Preferred Units, see Note 7.  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 or Regency that would have resulted assuming the incremental units related to ETP’s or Regency’s equity incentive plans, as applicable, had been issued during the respective periods.  Such units have been determined based on the treasury stock method.

The calculation below for diluted net income per limited partner unit excludes the impact of any ETE Common Units that would be issued upon conversion of the Series A Convertible Preferred Units, because inclusion would have been antidilutive.  The Series A Convertible Preferred Units have a liquidation preference of $300.0 million and are subject to mandatory conversion as discussed in Note 7.

A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:

	Years Ended December 31,
	2010			2009			2008
Basic Net Income per Limited Partner Unit:
Limited Partners’ interest in net income	$	192,161		$	441,103		$	373,883
Weighted average limited partner units		222,941,156			222,898,203			222,829,956
Basic net income per limited partner unit	$	0.86		$	1.98		$	1.68
Diluted Net Income per Limited Partner Unit:
Limited Partners’ interest in net income	$	192,161		$	441,103		$	373,883
Dilutive effect of Unit Grants		(228	)		(410	)		(349	)
Diluted net income available to limited partners	$	191,933		$	440,693		$	373,534
Weighted average limited partner units		222,941,156			222,898,203			222,829,956
Diluted net income per limited partner unit	$	0.86		$	1.98		$	1.68

Discontinued operations per unit has been omitted as the impact rounds to $0.00 for all periods presented.

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6.   DEBT OBLIGATIONS:

Our debt obligations consist of the following:

	December 31,
	2010			2009
Parent Company Indebtedness:
ETE Senior Notes, due October 15, 2020	$	1,800,000		$	—
ETE senior secured revolving credit facilities		—			123,951
ETE Senior Secured Term Loan		—			1,450,000
Subsidiary Indebtedness:
ETP Senior Notes:
5.65% Senior Notes due August 1, 2012		400,000			400,000
6.0% Senior Notes due July 1, 2013		350,000			350,000
8.5% Senior Notes due April 15, 2014		350,000			350,000
5.95% Senior Notes due February 1, 2015		750,000			750,000
6.125% Senior Notes due February 15, 2017		400,000			400,000
6.7% Senior Notes due July 1, 2018		600,000			600,000
9.7% Senior Notes due March 15, 2019		600,000			600,000
9.0% Senior Notes due April 15, 2019		650,000			650,000
6.625% Senior Notes due October 15, 2036		400,000			400,000
7.5% Senior Notes due July 1, 2038		550,000			550,000
Regency Senior Notes:
9.375% Senior Notes due June 1, 2016		250,000			—
6.875% Senior Notes due December 1, 2018		600,000			—
Transwestern Senior Unsecured Notes:
5.39% Senior Unsecured Notes due November 17, 2014		88,000			88,000
5.54% Senior Unsecured Notes due November 17, 2016		125,000			125,000
5.64% Senior Unsecured Notes due May 24, 2017		82,000			82,000
5.36% Senior Unsecured Notes due December 9, 2020		175,000			175,000
5.89% Senior Unsecured Notes due May 24, 2022		150,000			150,000
5.66% Senior Unsecured Notes due December 9, 2024		175,000			175,000
6.16% Senior Unsecured Notes due May 24, 2037		75,000			75,000
HOLP Senior Secured Notes:
Senior Secured Notes with interest rates ranging from 7.26% to 8.87%		103,127			140,512
Revolving Credit Facilities:
ETP Revolving Credit Facility		402,327			150,000
Regency Revolving Credit Facility		285,000			—
HOLP Revolving Credit Facility		—			10,000
Other Long-Term Debt		9,671			10,288
Unamortized discounts, net		(6,013	)		(12,829	)
Fair value adjustments related to interest rate swaps		17,260			—
		9,381,372			7,791,922
Current maturities		(35,305	)		(40,924	)
	$	9,346,067		$	7,750,998

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Future maturities of long-term debt, excluding $11.2 million in unamortized discounts and fair value adjustments related to interest rate swaps, for each of the next five years and thereafter are as follows:

2011	$	35,305
2012		825,748
2013		373,098
2014		729,108
2015		755,931
Thereafter		6,650,935
Total	$	9,370,125

Senior Notes

ETE Senior Notes

In September 2010, the Parent Company completed a public offering of $1.8 billion aggregate principal amount of 7.5% Senior Notes due October 15, 2020.  We used net proceeds of approximately $1.77 billion to repay all of the outstanding indebtedness under our then existing revolving credit facility and term loan facility, to fund the cost to terminate the interest rate swap agreements related to those borrowings, and for general partnership purposes.  We may redeem some or all of the notes at any time pursuant to the terms of the indenture subject to the payment of a “make-whole” premium.  Interest is payable semi-annually.

The ETE Senior Notes are unsecured obligations of ETE and the obligation to repay the ETE Senior Notes is not guaranteed by any of ETE’s subsidiaries, including ETP, Regency, and their respective subsidiaries.  The indebtedness of ETP and Regency and their respective subsidiaries effectively ranks senior to the ETE Senior Notes.

ETP Senior Notes

ETP may redeem some or all of the ETP Senior Notes at any time pursuant to the terms of the indenture and related indenture supplements subject to the payment of a “make-whole” premium.  Interest is payable semi-annually.  The 9.7% ETP Senior Notes contain a put option at par exercisable on March 15, 2012.

The ETP Senior Notes are unsecured obligations of ETP and the obligation of ETP to repay the ETP Senior Notes is not guaranteed by us, ETP or any of ETP’s subsidiaries.  The ETP Senior Notes effectively rank junior to all indebtedness and other liabilities of ETP’s existing and future subsidiaries.

Transwestern Senior Unsecured Notes

The Transwestern Pipeline Company, LLC (“Transwestern”) notes are payable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined.  The balance is payable upon maturity.  Interest is payable semi-annually.

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 Notes.  Interest is payable quarterly or semiannually and principal payments are made in annual installments through 2020 except for a one time payment of $16.0 million due in 2013.

Regency Senior Notes

Regency Senior Notes due 2013.  During the fourth quarter of 2010, in connection with the issuance of $600.0 million senior notes due 2018 described below, Regency redeemed all of its $357.5 million senior notes due 2013.  Accordingly, a redemption premium of $17.2 million was recorded in the consolidated statement of operations.  In addition, Regency wrote off unamortized loan fees of $5.0 million and unamortized bond premiums of $6.4 million.  A net loss on debt refinancing of $15.7 million related to these transactions is included in net other expenses of our consolidated statement of operations.

F-29

Regency Senior Notes due 2016.  Regency has $250.0 million of Regency Senior Notes due 2016 that mature on June 1, 2016.  The senior notes bear interest at 9.375% with interest payable semi-annually.  

At any time before June 1, 2012, up to 35% of the Regency Senior Notes due 2016 can be redeemed with the proceeds of an equity offering at a price of 109.375% plus accrued interest.  Beginning June 1, 2013, Regency may redeem all or part of these notes for the principal amount plus a declining premium until June 1, 2015, and thereafter at par, plus accrued and unpaid interest.  At any time prior to June 1, 2013, Regency may also redeem all or part of the Regency Senior Notes due 2016 at a price equal to 100% of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at June 1, 2013 plus (ii) all required interest payments due on the note through June 1, 2013, computed using a discount rate equal to the treasury rate (as defined in the indenture governing the senior notes) as of such redemption date plus 0.50% over the principal amount of the note.

Regency Senior Notes due 2018.  In October 2010, Regency completed a public offering of $600.0 million aggregate principal amount of 6.875% senior notes due 2018.  Interest will be paid semi-annually in arrears on June 1 and December 1, commencing June 1, 2011.  Regency capitalized $12.2 million in debt issuance costs which will amortize over the term of the senior notes.  The proceeds were used to redeem Regency’s senior notes due 2013 and to partially repay outstanding borrowings under the Regency Credit Facility.

At any time before December 1, 2013, up to 35% of the Regency Senior Notes due 2018 can be redeemed at a price of 106.875% plus accrued interest.  Beginning December 1, 2014, Regency may redeem all or part of the Regency Senior Notes due 2018 for the principal amount plus a declining premium until December 31, 2016, and thereafter at par, plus accrued and unpaid interest.  At any time prior to December 1, 2014, Regency may also redeem all or part of the Regency Senior Notes due 2018 at a price equal to 100% of the principal amount redeemed plus accrued interest and the applicable premium, which equals to the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at December 1, 2014 plus (ii) all required interest payments due on the note through December 1, 2014, computed using a discount rate equal to the treasury rate (as defined) as of such redemption date plus 50 basis points over the principal amount of the note.

Upon a change of control followed by a rating decline within 90 days, each noteholder of Regency’s senior notes will be entitled to require Regency to purchase all or a portion of its notes at a purchase price of 101% plus accrued interest and liquidated damages, if any.  Subsequent to the Regency Transactions, no noteholder has exercised this option.

Revolving Credit Facilities

ETE Senior Secured Credit Facility

Concurrent with the closing of its senior notes offering in September 2010, the Parent Company terminated its $500 million senior secured revolving credit facility and entered into a $200 million five-year senior secured revolving credit facility (the “Parent Company Credit Agreement”) available through September 20, 2015.  As of December 31, 2010, there were no outstanding borrowings under the Parent Company Credit Agreement.

Under the Parent Company Credit Agreement, the obligations of ETE are secured by all tangible and intangible assets of ETE and certain of its subsidiaries, including (i) its ownership of 50,226,967 ETP Common Units; (ii) ETE’s 100% equity interest in ETP LLC and ETP GP, through which ETE holds the IDRs in ETP; (iii) the 26,266,791 Common Units of Regency; and (iv) ETE’s 100% equity interest in Regency GP LLC and Regency GP LP, through which ETE holds the IDRs in Regency.

F-30

Borrowings bear interest, at ETE’s option, at either the Eurodollar rate plus an applicable margin or the alternative base rate.  The alternative base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate, a federal funds effective rate plus 0.50%, and an adjusted one-month LIBOR rate plus 1.00%.  The applicable margins are based upon ETE’s leverage ratio and range from 2.75% to 3.75% for Eurodollar loans and from 1.75% to 2.75% for base rate loans.  The commitment fee payable on the unused portion of the Parent Company Credit Agreement is based on ETE’s leverage ratio and ranges from 0.50% to 0.75%.

In connection with the Parent Company Credit Agreement, ETE and certain of its subsidiaries entered into a Pledge and Security Agreement (the “Security Agreement”) with Credit Suisse AG, Cayman Islands Branch, as collateral agent (the “Collateral Agent”).  The Security Agreement secures all of ETE’s obligations under the Parent Company Credit Agreement and grants to the Collateral Agent a continuing first priority lien on, and security interest in, all of ETE’s and the other grantors’ tangible and intangible assets.

ETP Credit Facility

ETP maintains a revolving credit facility (the “ETP Credit Facility”) that provides for $2.0 billion of revolving credit capacity that is expandable to $3.0 billion (subject to obtaining the approval of the administrative agent and securing lender commitments for the increased borrowing capacity).  The ETP Credit Facility 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).  Amounts borrowed under the ETP Credit Facility bear interest, at ETP’s option, at a Eurodollar rate plus an applicable margin or a base rate.  The base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate or a federal funds effective rate plus 0.50%.  The applicable margin for Eurodollar loans ranges from 0.30% to 0.70% based upon ETP’s credit rating and is currently 0.55% (0.60% if facility usage exceeds 50%).  The commitment fee payable on the unused portion of the ETP Credit Facility varies based on ETP’s credit rating with a maximum fee of 0.125%.  The fee is 0.11% based on ETP’s current rating.

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 our current and future unsecured debt.  The indebtedness under the ETP Credit Facility has the same priority of payment as ETP’s other current and future unsecured debt.

As of December 31, 2010, ETP had a balance of $402.3 million outstanding under the ETP Credit Facility and, taking into account letters of credit of approximately $25.5 million, $1.57 billion available for future borrowings.  The weighted average interest rate on the total amount outstanding as of December 31, 2010 was 0.84%.

HOLP Credit Facility

HOLP previously had a $75.0 million Senior Revolving Facility (the “HOLP Credit Facility”) available to HOLP through June 30, 2011.  As of December 31, 2010, there was no outstanding balance in revolving credit loans and outstanding letters of credit of $0.5 million.  The amount available for borrowing as of December 31, 2010 was $74.5 million.  The HOLP Credit Facility was terminated in February 2011, and HOLP will meet its future liquidity needs through intercompany loans from ETP.

Regency Credit Facility

The Regency Credit Facility has aggregate revolving commitments of $900 million, with $100 million of availability for letters of credit.  Regency also has the option to request an additional $250 million in revolving commitments with ten business days written notice provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the credit facility have been met.  The maturity date of the Regency Credit Facility is June 15, 2014.

The outstanding balance of revolving loans under the Regency Credit Facility bears interest at LIBOR plus a margin or an alternate base rate.  The alternate base rate used to calculate interest on base rate loans will be calculated using the greater of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.00%.  The applicable margin shall range from 1.50% to 2.25% for base rate loans, 2.50% to 3.25% for Eurodollar loans, and a commitment fee will range from 0.375% to 0.500%.  Regency must also pay a participation fee for each revolving lender participating in letters of credit based upon the applicable margin,

F-31

which is currently 2.5% of the average daily amount of such lender’s letter of credit exposure, and a fronting fee to the issuing bank of letters of credit equal to 0.125% per annum of the average daily amount of the letter of credit exposure.

As of December 31, 2010, there was a balance outstanding in the Regency Credit Facility of $285.0 million in revolving credit loans and approximately $16.0 million in letters of credit.  The total amount available under the Regency Credit Facility, as of December 31, 2010, which is reduced by any letters of credit, was approximately $599.0 million.  The weighted average interest rate on the total amount outstanding as of December 31, 2010 was 2.9%.

Covenants Related to Our Credit Agreements

Covenants Related to the Parent Company

The Parent Company Credit Agreement contains customary representations, warranties and covenants, including financial covenants regarding a maximum leverage ratio, a maximum consolidated leverage ratio, a minimum fixed charge coverage ratio and a minimum loan to value ratio.  In addition, the Parent Company Credit Agreement contains customary events of default, including, but not limited to, (i) default for failure to pay the principal on any loan or any reimbursement obligation with respect to any letter of credit when due and payable, (ii) failure to duly observe, perform or comply with certain specified covenants, (iii) a representation or warranty made in connection with any loan document proves to have been false or incorrect in any material respect on any date on or as of which made, and (iv) the occurrence of a change of control.

The Parent Company Senior Secured Revolving Credit Facility contains 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;

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

·   Fixed Charge Coverage Ratio of not less than 3.00 to 1.00; and

·   Value to Loan Ratio of not less than 2.00 to 1.00.

Covenants Related to ETP

The agreements related to the ETP Senior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.

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

·   incur indebtedness;

·   grant liens;

·   enter into mergers;

·   dispose of assets;

·   make certain investments;

·   make Distributions (as defined in such credit agreement) during certain Defaults (as defined in such credit agreement) and during any Event of Default (as defined in such credit agreement);

·   engage in business substantially different in nature than the business currently conducted by ETP and its subsidiaries;

·   engage in transactions with affiliates;

·   enter into restrictive agreements; and

·   enter into speculative hedging contracts.

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The credit agreement related to the ETP Credit Facility also contains a financial covenant that provides that on each date ETP 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 defined in the ETP Credit Facility.  This financial covenant could therefore restrict ETP’s ability to make cash distributions to its Unitholders, its general partner and the holder of its IDRs.

The agreements related to the HOLP Senior Secured Notes contain customary restrictive covenants, including the maintenance of financial covenants and limitations on substantial disposition of assets, changes in ownership, the level of additional indebtedness and creation of liens.

The agreements related to the Transwestern senior unsecured notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.

Covenants Related to Regency

The Regency Senior Notes contain various covenants that limit, among other things, Regency’s ability, and the ability of certain of its subsidiaries, to:

·   incur additional indebtedness;

·   pay distributions on, or repurchase or redeem equity interests;

·   make certain investments;

·   incur liens;

·   enter into certain types of transactions with affiliates; and

·   sell assets, consolidate or merge with or into other companies.

If the Regency Senior Notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, Regency will no longer be subject to many of the foregoing covenants.  The Regency Credit Facility contains the following financial covenants:

·   Regency’s consolidated EBITDA ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 5.25 to 1.

·   Regency’s consolidated senior secured leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 3.00 to 1.

The Regency Credit Facility also contains various covenants that limit, among other things, the ability of Regency and RGS to:

·   incur indebtedness;

·   grant liens;

·   enter into sale and leaseback transactions;

·   make certain investments, loans and advances;

·   dissolve or enter into a merger or consolidation;

·   enter into asset sales or make acquisitions;

·   enter into transactions with affiliates;

·   prepay other indebtedness or amend organizational documents or transaction documents (as defined in the credit agreement governing the Regency Credit Facility);

·   issue capital stock or create subsidiaries; or

·   engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Regency Credit Facility or reasonable extensions thereof.

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Compliance With Our Covenants

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions.

We, ETP and Regency are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2010.

7.   REDEEMABLE PREFERRED UNITS:

ETE Preferred Units

In connection with the Regency Transactions as discussed in Note 3, ETE issued 3,000,000 Preferred Units to an affiliate of GE Energy Financial Services, Inc. (“GE EFS”) having an aggregate liquidation preference of $300.0 million and are reflected as a long-term liability in our consolidated balance sheets as of December 31, 2010.  The Preferred Units were issued in a private placement at a stated price of $100 per unit and are entitled to a preferential quarterly cash distribution of $2.00 per Preferred Unit.  The Preferred Units will automatically convert on the fourth anniversary of the date of issuance into an amount of ETE Common Units equal in value to the issue price plus any accrued but unpaid distributions plus a specified premium equal to the lesser of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE Common Units subsequent to the date of issuance of the Preferred Units.  ETE may choose, at its sole option, to pay 50% of the conversion consideration based on the issue price plus any accrued but unpaid distributions in cash.  ETE may elect to redeem all, but not less than all, of the Preferred Units beginning on the third anniversary of the date of issuance for ETE Common Units or cash equal to the issue price plus a premium paid out in common units, equal to the greater of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE Common Units subsequent to the date of issuance.  GE EFS also has certain rights to force ETE to redeem or convert the outstanding Preferred Units for specified consideration upon the occurrence of certain extraordinary events involving ETE or ETP.  Holders of the Preferred Units have no voting rights, except that approval of a majority of the Preferred Units is needed to approve any amendment to ETE’s Partnership Agreement that would result in (i) any increase in the size of the class of Preferred Units, (ii) any alteration or change to the rights, preferences, privileges, duties, or obligations of the Preferred Units or (iii) any other matter that would adversely affect the rights or preferences of the Preferred Units, including in relation to other classes of ETE partnership interests.  During 2010 we recorded a non-cash charge of approximately $12.7 million to increase the carrying value of the Preferred Units to its estimated fair value of $317.6 million.

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Preferred Units of Subsidiary

Regency had 4,371,586 Regency Preferred Units outstanding at December 31, 2010, which were convertible into 4,584,192 Regency Common Units.  If outstanding on September 2, 2029 the Regency Preferred Units are mandatorily redeemable for $80.0 million plus all accrued but unpaid distributions thereon.  Holders of the Regency Preferred Units receive fixed Regency quarterly cash distributions of $0.445 per unit.  Holders can elect to convert Regency Preferred Units to Regency Common Units at any time in accordance with Regency’s partnership agreement.

The following table provides a reconciliation of the beginning and ending balances of the Regency Preferred Units:

	Regency Preferred Units		Amount (1)
Balance at acquisition date		4,371,586	$	70,793
Accretion to redemption value		—		150
Ending balance as of December 31, 2010		4,371,586	$	70,943

(1) This amount will be accreted to $80.0 million plus any accrued and unpaid distributions at September 2, 2029.

8.   PARTNERS’ CAPITAL:

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.  The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the New York Stock Exchange (“NYSE”).  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 “Parent Company Quarterly Distributions of Available Cash.”

As of December 31, 2010, there were issued and outstanding 222,941,172 Common Units representing an aggregate 99.69% limited partner interest in the Partnership.

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.

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Common Units

The change in ETE Common Units during the years ended December 31, 2010, 2009 and 2008 was as follows:

	Years Ended December 31,
	2010		2009		2008
Number of Common Units, beginning of period		222,898,248		222,829,956		222,829,956
Issuance of restricted Common Units under long-term incentive plan		42,924		68,292		—
Number of Common Units, end of period		222,941,172		222,898,248		222,829,956

Sale of Common Units by Subsidiaries

The Parent Company accounts for the difference between the carrying amount of its investment in ETP and Regency and the underlying book value arising from issuance of units by ETP or Regency (excluding unit issuances to the Parent Company) as a capital transaction.  If ETP or Regency issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations.  The Parent Company did not recognize any impairment related to the issuance of ETP or Regency Common Units during the periods presented.

As a result of ETP’s and Regency’s issuances and redemptions of Common Units, we have recognized increases in partner’s capital of $352.3 million, $97.0 million and $48.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Sale of Common Units by ETP

The following table summarizes ETP’s public offerings of ETP Common Units during the periods presented:

Date	Number of ETP Common Units (1)		Price per ETP Unit		Net Proceeds		Use of Proceeds
July 2008		8,912,500	$	39.45	$	337,531	(2)
January 2009		6,900,000		34.05		225,354	(2)
April 2009		9,775,000		37.55		352,369	(3)
October 2009		6,900,000		41.27		275,979	(2)
January 2010		9,775,000		44.72		423,551	(2)(3)
August 2010		10,925,000		46.22		489,418	(2)(3)

(1)   Number of Common Units includes the exercise of the overallotment options by the underwriters.

(2)   Proceeds were used to repay amounts outstanding under the ETP Credit Facility.

(3)   Proceeds were used to fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.

ETP’s Equity Distribution Program

In December 2010, ETP entered into an Equity Distribution Agreement with Credit Suisse Securities (USA) LLC (“Credit Suisse”).  According to the provisions of this agreement, ETP may offer and sell from time to time through Credit Suisse, as its sales agent, Common Units having an aggregate offering price of up to $200.0 million.  Sales of the units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between ETP and Credit Suisse.  Under the terms of this agreement, ETP may also sell Common Units to Credit Suisse as principal for its own account at a price agreed upon at the time of sale.  Any sale of Common Units to Credit Suisse as principal would be pursuant to the terms of a separate agreement between us and Credit Suisse.

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Previously, ETP had an Equity Distribution Agreement with UBS Securities LLC (“UBS”), which was similar to its existing agreement with Credit Suisse, as described above, and allowed for sales of up to $300.0 million.

The following table summarizes ETP’s Common Unit issuances under its Equity Distribution Agreements, the net proceeds from which were used to repay amounts outstanding under ETP’s revolving credit facility:

	Year Ended December 31, 2010				Year Ended December 31, 2009
Agreement	Number of ETP Common Units Issued		Net Proceeds		Number of  ETP Common Units Issued		Net Proceeds
UBS		4,638,687	$	214,267		1,891,691	$	81,456
Credit Suisse		555,600		25,051		—		—
		5,194,287	$	239,318		1,891,691	$	81,456

Approximately $168.1 million of ETP Common Units remain available to be issued under the agreement based on trades initiated through December 31, 2010.

On May 26, 2010, in conjunction with the Regency Transactions, the Parent Company acquired from ETP a 49.9% interest in MEP, in exchange for ETP’s redemption of 12,273,830 ETP Common Units that were previously held by the Parent Company (see Note 4).

Sale of Common Units by Regency

In August 2010, Regency issued 17,537,500 Regency Common Units through a public offering.  The proceeds of $400.2 million, net of commissions, from the offering were used primarily to repay borrowings under the RGS Credit Facility.

Contributions to Subsidiaries

The Parent Company indirectly owns the entire general partner interest in ETP through its ownership of ETP GP, the general partner of ETP.  In order to maintain its general partner interest in ETP, ETP GP was previously required to make contributions to ETP each time ETP issued limited partner interests for cash or in connection with acquisitions.  These contributions were 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.  In July 2009, ETP amended and restated its partnership agreement, and as a result, ETP GP is no longer required to make corresponding contributions to maintain its general partner interest in ETP.  ETP GP was required to contribute approximately $12.3 million and $8.0 million for the years ended December 31, 2009 and 2008, respectively.  As of December 31, 2009, ETP GP had a contribution payable to ETP of $8.9 million, which was paid in full in 2010.

The Parent Company owns the entire general partner interest in Regency through its ownership of Regency GP.  Regency GP has the right, but not the obligation, to contribute a proportionate amount of capital to Regency to maintain its current general partner interest.  Regency GP’s initial 2% interest in Regency’s distributions will be reduced if Regency issues additional units in the future and Regency GP does not contribute a proportionate amount of capital to Regency to maintain its 2% General Partner interest.

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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.  The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Regency related to limited and general partner interests, including IDRs.  We currently have no independent operations outside of our direct and indirect interests in ETP and Regency.

Our distributions declared during the years ended December 31, 2010, 2009 and 2008 are summarized as follows:

Quarter Ended	Record Date	Payment Date	Distribution per ETE Common Unit
September 30, 2010	November 8, 2010	November 19, 2010	$	0.5400
June 30, 2010	August 9, 2010	August 19, 2010		0.5400
March 31, 2010	May 7, 2010	May 19, 2010		0.5400
December 31, 2009	February 8, 2010	February 19, 2010		0.5400
September 30, 2009	November 9, 2009	November 19, 2009		0.5350
June 30, 2009	August 7, 2009	August 19, 2009		0.5350
March 31, 2009	May 8, 2009	May 19, 2009		0.5250
December 31, 2008	February 6, 2009	February 19, 2009		0.5100
September 30, 2008	November 10, 2008	November 19, 2008		0.4800
June 30, 2008	August 7, 2008	August 19, 2008		0.4800
March 31, 2008	May 5, 2008	May 19, 2008		0.4400
December 31, 2007	February 1, 2008 (1)	February 19, 2008		0.5500

(1)   One-time four month distribution related to the conversion to a calendar year end from the previous August 31 fiscal year end.

On January 27, 2011, the Parent Company declared a cash distribution for the three months ended December 31, 2010 of $0.54 per Common Unit, or $2.16 annualized.  We paid this distribution on February 18, 2011 to Unitholders of record at the close of business on February 7, 2011.

The total amount of distributions we have declared is as follows (all from Available Cash from our operating surplus and are shown in the period to which they relate):

	Years Ended December 31,
	2010		2009		2008
Limited Partners	$	481,554	$	475,911	$	425,640
General Partner interest		1,495		1,478		1,322
Total distributions declared	$	483,049	$	477,389	$	426,962

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ETP’s Quarterly Distribution of Available Cash

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

ETP’s distributions declared during the periods presented below are summarized as follows:

Quarter Ended	Record Date	Payment Date	Distribution per ETP Common Unit
September 30, 2010	November 8, 2010	November 15, 2010	$	0.89375
June 30, 2010	August 9, 2010	August 16, 2010		0.89375
March 31, 2010	May 7, 2010	May 17, 2010		0.89375
December 31, 2009	February 8, 2010	February 15, 2010		0.89375
September 30, 2009	November 9, 2009	November 16, 2009	$	0.89375
June 30, 2009	August 7, 2009	August 14, 2009		0.89375
March 31, 2009	May 8, 2009	May 15, 2009		0.89375
December 31, 2008	February 6, 2009	February 13, 2009		0.89375
September 30, 2008	November 10, 2008	November 14, 2008	$	0.89375
June 30, 2008	August 7, 2008	August 14, 2008		0.89375
March 31, 2008	May 5, 2008	May 15, 2008		0.86875
December 31, 2007	February 1, 2008 (1)	February 14, 2008		1.12500

(1) One-time four month distribution related to the conversion to a calendar year end from the previous August 31 fiscal year end.

On January 27, 2011, ETP declared a cash distribution for the three months ended December 31, 2010 of $0.89375 per ETP Common Unit, or $3.575 annualized.  ETP paid this distribution on February 14, 2011 to ETP Unitholders of record at the close of business on February 7, 2011.

The total amounts of ETP distributions declared during the periods presented in the consolidated financial statements are as follows (all from Available Cash from ETP’s operating surplus and are shown in the period to which they relate):

	Years Ended December 31,
	2010		2009		2008
Limited Partners:
Common Units	$	676,798	$	629,263	$	537,731
Class E Units		12,484		12,484		12,484
General Partner interest		19,524		19,505		17,322
Incentive Distribution Rights		375,979		350,486		298,575
Total distributions declared by ETP	$	1,084,785	$	1,011,738	$	866,112

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Regency’s Quarterly Distribution of Available Cash

Regency’s Partnership Agreement requires that Regency distribute all of its Available Cash to its Unitholders and its General Partner within 45 days after the end of each quarter to unitholders of record on the applicable record date, as determined by the general partner.  The term Available Cash generally consists of all cash and cash equivalents on hand at the end of that quarter less the amount of cash reserves established by the general partner to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to the unitholders and to the General Partner for any one or more of the next four quarters and plus, all cash on hand on that date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.

Distributions paid by Regency since the date of acquisition are summarized as follows:

Quarter Ended	Record Date	Payment Date	Distribution per Regency Common Unit
September 30, 2010	November 5, 2010	November 12, 2010	$	0.445
June 30, 2010	August 6, 2010	August 13, 2010		0.445

On January 27, 2011, Regency declared a cash distribution for the three months ended December 31, 2010 of $0.445 per Regency Common Unit, or $1.78 annualized.  This distribution will be paid on February 14, 2011 to Regency Unitholders of record at the close of business on February 7, 2011

The total amounts of Regency distributions declared since the date of acquisition were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):

	Year Ended December 31,
	2010
Limited Partners	$	175,360
General Partner Interest		3,640
Incentive Distribution Rights		3,016
Total distributions declared by Regency	$	182,016

Accumulated Other Comprehensive Income

The following table presents the components of AOCI, net of tax:

	December 31,
	2010			2009
Net gains on commodity related hedges	$	14,146		$	1,991
Net losses on interest rate hedges		—			(56,210	)
Unrealized gains on available-for-sale securities		918			4,941
Noncontrolling interest		(10,266	)		(4,350	)
Total AOCI, net of tax	$	4,798		$	(53,628	)

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9.   UNIT-BASED COMPENSATION PLANS:

We, ETP, and Regency have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards.

ETE Long-Term Incentive Plan

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.  The 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, excluding the Class B Units.  As of December 31, 2010, 2,885,212 units remain available to be awarded under the plan.

During 2010, the Compensation Committee did not grant any ETE units.  During 2009, the Compensation Committee granted a total of 41,000 ETE units with grant date fair values of $30.76 per unit to employees with vesting over a five-year period at 20% per year.  These awards include rights to distributions paid on unvested units.

During 2010, a total of 22,841 ETE units vested, with a total fair value of $0.5 million as of the vesting date.  As of December 31, 2010, a total of 75,919 restricted units granted to ETE employees and directors remain outstanding, for which we expect to recognize a total of $1.0 million in compensation over a weighted average period of 2.2 years.

ETP Unit-Based Compensation Plans

Unit Grants

ETP has granted restricted unit awards to employees that vest over a specified time period, typically a five-year period at 20% per year, with vesting based on continued employment as of each applicable vesting date.  Upon vesting, ETP Common Units are issued.  These unit awards entitle the recipients of the unit awards to receive, with respect to each ETP Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per ETP Common Unit made by ETP on its Common Units promptly following each such distribution by ETP to its Unitholders.  We refer to these rights as “distribution equivalent rights.”

Under ETP’s equity incentive plans, its non-employee directors each receive grants that vest ratably over three years and do not entitle the holders to receive distributions during the vesting period.

Award Activity

The following table shows the activity of the ETP awards granted to employees and non-employee directors:

	Number of ETP Units			Weighted Average Grant-Date Fair Value Per ETP Unit
Unvested awards as of December 31, 2009		1,690,592		$	39.88
Awards granted		761,428			49.82
Awards vested		(417,328	)		39.60
Awards forfeited		(98,114	)		37.84
Unvested awards as of December 31, 2010		1,936,578			43.95

During the years ended December 31, 2010, 2009 and 2008, the weighted average grant-date fair value per unit award granted was $49.82, $43.56 and $33.86, respectively.  The total fair value of awards vested was $16.5 million, $14.7 million and $14.6 million, respectively based on the market price of ETP Common Units as of

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the vesting date.  As of December 31, 2010, a total of 1,936,578 unit awards remain unvested, for which ETP expects to recognize a total of $61.8 million in compensation expense over a weighted average period of 1.9 years.

Related Party Awards

McReynolds Energy Partners, L.P., the general partner of which is owned and controlled by an ETE officer, awarded to certain officers of ETP certain rights related to units of ETE previously issued by ETE to such ETE officer.  These rights include the economic benefits of ownership of these ETE units based on a five year vesting schedule whereby the officer will vest in the ETE units at a rate of 20% per year.  As these ETE units are conveyed to the recipients of these awards upon vesting from a partnership that is not owned or managed by ETE or ETP, none of the costs related to such awards are paid by ETP or ETE unless this partnership defaults under its obligations pursuant to these unit awards.  As these units were outstanding prior to these awards, these 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 is recognizing non-cash compensation expense over the vesting period based on the grant-date fair value of the ETE units awarded to the ETP employees assuming no forfeitures.  For the years ended December 31, 2010, 2009 and 2008, ETP recognized non-cash compensation expense, net of forfeitures, of $3.7 million, $6.4 million and $3.5 million, respectively, as a result of these awards.  As of December 31, 2010, rights related to 365,000 ETE common units remain outstanding, for which ETP expects to recognize a total of $3.2 million in compensation expense over a weighted average period of 1.5 years

Regency Unit-Based Compensation Plans

Regency has the following awards outstanding as of December 31, 2010:

·   201,950 Regency Common Unit options, all of which are exercisable, with a weighted average exercise price of $21.93 per unit option;

·   No Regency restricted (non-vested) Common Units; and

·   742,517 Regency Phantom Units, with a weighted average grant date fair value of $23.61 per Phantom Unit.

In conjunction with the Regency Transactions, certain of Regency’s then-outstanding Phantom Units converted to 252,630 Regency Common Units as a result of change-in-control provisions associated with the awards.  Each of Regency’s outstanding Phantom Units as of December 31, 2010 is the economic equivalent of one Regency Common Unit and is accompanied by a Distribution Equivalent Right, entitling the holder to an amount equal to any cash distributions paid on Regency Common Units.  The outstanding Regency Phantom Units will vest one-third on each March 15th through 2013.

Regency expects to recognize $14.3 million of compensation expense related to the Regency Phantom Units over a weighted average period of 4.3 years.

10.   REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL LIABILITIES:

Regulatory Matters

In April 2010, the application to construct and operate the Tiger pipeline was approved by the FERC and field construction began on the pipeline in June 2010.  The Tiger pipeline was placed in service in December 2010.  In June 2010, ETP filed an application for authority to construct and operate an expansion of the Tiger pipeline.  In February 2011, ETP accepted the FERC’s order authorizing the construction of this expansion.

On September 29, 2006, Transwestern filed revised tariff sheets under Section 4(e) of the Natural Gas Act (“NGA”) proposing a general rate increase to be effective on November 1, 2006.  In April 2007, the FERC approved a Stipulation and Agreement of Settlement that resolved the primary components of the rate case.  Transwestern’s tariff rates and fuel rates are now final for the period of the settlement.  Transwestern is required to file a new rate case no later than October 1, 2011.

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Guarantees

MEP Guarantee

Previously ETP guaranteed 50% of the obligations of MEP under its senior revolving credit facility (the “MEP Facility”).  The MEP Facility matured on February 28, 2011.

FEP Guarantee

On November 13, 2009, FEP entered into a credit agreement that provides for a $1.1 billion senior revolving credit facility (the “FEP Facility”).  ETP has guaranteed 50% of the obligations of FEP under the FEP Facility, with the remainder of FEP Facility obligations guaranteed by KMP.  Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if ETP’s ownership percentage in FEP increases or decreases.  The FEP Facility is available through May 11, 2012 and amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or prime rate.

As of December 31, 2010, FEP had $940.0 million of outstanding borrowings issued under the FEP Facility and ETP’s contingent obligation with respect to its guaranteed portion of FEP’s outstanding borrowings was $470.0 million, which is not reflected in our consolidated balance sheets.  The weighted average interest rate on the total amount outstanding as of December 31, 2010 was 3.2%.

Commitments

In the normal course of business, ETP and Regency 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.  ETP has 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.  ETP believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034.  Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $23.8 million, $19.8 million and $17.2 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Future minimum lease commitments for such leases are:

Years Ending December 31:
2011	$	27,841
2012		24,297
2013		22,114
2014		19,593
2015		19,073
Thereafter		173,118

ETP’s propane operations have an agreement with Enterprise Products Partners L.P. (together with its subsidiaries “Enterprise”) (see Note 13) to supply a portion of its propane requirements.  The agreement will continue until March 2015 and includes an option to extend the agreement for an additional year.

In connection with the sale of ETP’s investment in M-P Energy in October 2007, ETP executed a propane purchase agreement for approximately 90.0 million gallons per year through 2015 at market prices plus a nominal fee.

ETP and Regency have commitments to make capital contributions to its joint ventures and ETP expects capital contributions for 2011 will be between $200 million and $230 million.

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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 coverage 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 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 contained allegations that ETP violated FERC rules and regulations.  The FERC 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 occasions from December 2003 through August 2005, in order to benefit financially from ETP’s commodities derivatives positions and from certain of ETP’s index-priced physical gas purchases in the Houston Ship Channel.  The FERC alleged that during these periods ETP violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by the FERC under authority of the NGA.  The FERC alleged that ETP violated this rule by artificially suppressing prices that were included in the Platts Inside FERC Houston Ship Channel index, published by McGraw-Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based.  The FERC also alleged that one of our intrastate pipelines violated various FERC regulations by, among other things, granting undue preferences in favor of an affiliate.  In its Order and Notice, the FERC specified that it was seeking $69.9 million in disgorgement of profits, plus interest, and $82.0 million in civil penalties relating to these market manipulation claims.  In February 2008, the FERC’s Enforcement Staff also 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 the FERC’s allegations in the Order and Notice, and that ETP be assessed an additional civil penalty of $25.0 million and be required to disgorge approximately $7.3 million of alleged unjust profits related to this additional month.

On August 26, 2009, ETP entered into a settlement agreement with the FERC’s Enforcement Staff with respect to the pending FERC claims against ETP and, on September 21, 2009, the FERC approved the settlement agreement without modification.  The agreement resolves all outstanding FERC claims against ETP and required that ETP make a $5.0 million payment to the federal government and establish a $25.0 million fund for the purpose of settling related third-party claims based on or arising out of the market manipulation allegation against ETP by those third parties that elect to make a claim against this fund, including existing litigation claims as well as any new claims that may be asserted against this fund.  Pursuant to the settlement agreement, the FERC made no findings of fact or conclusions of law.  In addition, the settlement agreement specifies that by executing the settlement agreement ETP does not admit or concede to the FERC or any third party any actual or potential fault, wrongdoing or liability in connection with ETP’s alleged conduct related to the FERC claims.  The settlement agreement also requires ETP to maintain specified compliance programs and to conduct independent annual audits of such programs for a two-year period.

In September 2009, the FERC appointed an administrative law judge, or ALJ, to establish a process of potential claimants to make claims against the $25.0 million fund, to determine the validity of any such claims and to make a recommendation to the FERC relating to the application of this fund to any potential claimants.  Pursuant to the process established by the ALJ, a number of parties submitted claims against this fund and, subsequent thereto, the ALJ made various determinations with respect to the validity of these claims, solely for purposes of participation in this fund allocation process, and the methodology for making payments from the fund to claimants.  In June 2010, each claimant that had been allocated a payment amount from the fund by the ALJ was required to make a determination as to whether to accept the ALJ’s recommended payment amount from the fund, and all such claimants accepted their allocated payment amounts.  In connection with accepting the allocated payment amount, each such claimant was required to waive and release all claims against ETP related to this matter.

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In addition to the claims that were settled pursuant to the ALJ fund allocation process discussed above, ETP was a party in three legal proceedings that asserted 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 indices during the period from December 2003 through December 2006.  In all three of these legal proceedings, ETP has received favorable rulings at the lower court and appellate court levels that have resulted in the dismissal of all claims made in these proceedings, and no further appeals or motions for rehearing may be pursued by the plaintiffs in these proceedings except with respect to one proceeding as to which the plaintiffs may seek review at the U.S. Supreme Court, which action we believe is unlikely to occur.

ETP is expensing the legal fees, consultants’ fees and other expenses relating to these matters in the periods in which such costs are incurred.  ETP records accruals for litigation and other contingencies whenever required by applicable accounting standards.  Based on the terms of the settlement agreement with the FERC described above, ETP made the $5.0 million payment and established the $25.0 million fund in October 2009.  The after-tax impact of the settlement was less than $30.0 million due to tax benefits resulting from the portion of the payment that is used to satisfy third party claims.

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 defendants in 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.”  In 2004, a subsidiary of ETP, La Grange Acquisition, L.P. (“ETC OLP”) acquired the HPL Entities from AEP, at which time AEP agreed, pursuant to a Cushion Gas Litigation Agreement, 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 $1.00 billion in the aggregate).  The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation.  In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters.  On December 18, 2007, the United States District Court for the Southern District of New York held that B of A is entitled to receive monetary damages from AEP and the HPL Entities of approximately $347.3 million less the monetary amount B of A would have incurred to remove 55 Bcf of natural gas from the Bammel storage facility.  Following an attempted appeal of this decision by AEP, the parties to this litigation entered into a settlement agreement in February 2011 that, among other matters, recognized AEP’s ownership rights to the cushion gas and recognized HPL’s continued right to use this cushion gas through 2013 pursuant to a right to use agreement entered into between predecessors of AEP and HPL in 2001.  The settlement agreement also reaffirms the indemnification obligations of AEP in the Cushion Gas Litigation Agreement.  As a result of the settlement agreement and the indemnification provisions in the Cushion Gas Litigation Agreement, ETP does not expect that it will have any liability to either AEP or B of A with respect to the matters subject to this litigation.

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 of December 31, 2010 and 2009, accruals of approximately $10.2 million and $11.1 million, respectively, were recorded related to deductibles.  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.

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No amounts have been recorded in our December 31, 2010 or 2009 consolidated balance sheets for contingencies and current litigation matters, other than accruals related to environmental matters and deductibles.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that can require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as 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, gathering, treating, compressing, blending and processing business.  As a result, there can be no assurance that significant costs and liabilities will not be incurred.  Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits.  Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies there under, 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 safety and health, and the handling, storage, use, and disposal of hazardous materials to prevent and minimize material environmental or other damage, and to limit the financial liability, which could result from such events.  However, the risk of environmental or other damage is inherent in transporting, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products, as it is with other entities engaged in similar businesses.

Our operations are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees.  In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.  We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we operate.  In some states, these laws are administered by state agencies, and in others, they are administered on a municipal level.  With respect to the transportation of propane by truck, we are subject to regulations governing the transportation of hazardous materials under the Federal Motor Carrier Safety Act, administered by the DOT.  We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations.  We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in substantial compliance with applicable laws and regulations.

ETP Environmental Matters

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, 2010 and 2009, accruals on an undiscounted basis of $13.8 million and $12.6 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities related to environmental matters.

Based on information available at this time and reviews undertaken to identify potential exposure, ETP believes the amount reserved for environmental matters is adequate to cover the potential exposure for clean-up

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costs.

Transwestern conducts soil and groundwater remediation at a number of its facilities.  Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by polychlorinated biphenyls (“PCBs”).  The costs of this work are not eligible for recovery in rates.  The total accrued future estimated cost of remediation activities expected to continue through 2025 is $8.2 million, which is included in the aggregate environmental accruals discussed above.  Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007.

Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCBs.  Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers.  However, such future costs are not expected to have a material impact on our financial position, results of operations or cash flows.

Environmental regulations were recently modified for the U.S. Environmental Protection Agency’s (the “EPA”) Spill Prevention, Control and Countermeasures program.  ETP is currently reviewing the impact to its operations and expects 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 ETP believes such costs will not have a material adverse effect on its financial position, results of operations or cash flows.

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.  ETP has not been named as a potentially responsible party at any of these sites, nor have its operations contributed to the environmental issues at these sites.  Accordingly, no amounts have been recorded in our December 31, 2010 or 2009 consolidated balance sheets.  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.

By March 2013, the Texas Commission on Environmental Quality is required to develop another plan to address the recent change in the ozone standard from 0.08 parts per million (“ppm”) to 0.075 ppm and the EPA recently proposed lowering the standard even further, to somewhere in between 0.06 and 0.07 ppm.  These efforts may result in the adoption of new regulations that may require additional nitrogen oxide emissions reductions.

ETP’s 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 requirements 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.”  Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing, or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis.  For the years ended December 31, 2010, 2009 and 2008, $13.3 million, $31.4 million and $23.3 million, respectively, of capital costs and $15.4 million, $18.5 million and $13.1 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing.  Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP 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.

Regency Environmental Matters

Regency Field Services LLC (“RFS”), one of Regency’s operating subsidiaries, currently owns the Dubach and Calhoun gas processing plants in north Louisiana (the “Plants”).  The Plants each have groundwater

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contamination as a result of historical operations.  At the time that RFS acquired the Plants from El Paso Field Services LP (“El Paso”), Kerr-McGee Corporation (“Kerr-McGee”) was performing remediation of the groundwater contamination, because the Plants were once owned by Kerr-McGee and when Kerr-McGee sold the Plants to a predecessor of El Paso in 1988, Kerr-McGee retained liability for any environmental contamination at the Plants.  In 2005, Kerr-McGee created and spun off Tronox and Tronox allegedly assumed certain of Kerr-McGee’s environmental remediation obligations (including its obligation to perform remediation at the Plants) prior to the acquisition of Kerr-McGee by Anadarko Petroleum Corporation.  In January 2009, Tronox filed for Chapter 11 bankruptcy protection.  RFS filed a claim in the bankruptcy proceeding relating to the environmental remediation work at the Plants.  Tronox has thus far continued its remediation efforts at the Plants.  Tronox filed a reorganization plan on July 7, 2010.  The plan calls for the creation of a trust to fund environmental clean-up at the various sites where Tronox has an obligation.  Regency anticipates that the amount of the trust allocated for clean-up of the Dubach and Calhoun plants will cover the remaining costs if the method of pace of clean-up remains consistent with historical prices.  Regency will not report further on this matter absent further adverse developments.

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 manage the impact of volatility from these prices, our subsidiaries utilize various exchange-traded and OTC commodity financial instrument contracts.  These contracts consist primarily of futures, swaps and options and are recorded at fair value in the consolidated balance sheets.  Following is a description of price risk management activities by segment.

Investment in ETP

ETP injects and holds natural gas in its Bammel storage facility to take advantage of contango markets, when the price of natural gas is higher in the future than the current spot price.  ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities.  At the inception of the hedge, ETP will lock in a margin by purchasing gas in the spot market or off peak season and entering a financial contract to lock in the sale price.  If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP will value the hedged natural gas inventory at current spot market prices along with the financial derivative it uses to hedge it.  Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled.  Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.  Unrealized margins represent the unrealized gains or losses from ETP’s derivative instruments using mark-to-market accounting, with changes in the fair value of its derivatives being recorded directly in earnings.  These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices.  If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses.  If the spread widens, ETP will record unrealized losses or lower unrealized gains.  Typically, as ETP enters the winter months, the spread converges so that it recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdrawal of natural gas.

ETP is also exposed to market risk on natural gas it retains for fees in its intrastate transportation and storage operations and operational gas sales in its interstate transportation operations.  ETP uses financial derivatives to hedge the sales price of this gas, including futures, swaps and options.  Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas.  The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs.  When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

Derivatives are utilized in ETP’s midstream operations in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations.  ETP attempts to maintain balanced positions in its marketing activities to protect itself 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 most of the gas required by its 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

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the contract.  Financial contracts, which are not tied to physical delivery, are expected to be offset with financial contracts to balance ETP’s positions.  To the extent open commodity positions exist, fluctuating commodity prices can impact its financial position and results of operations, either favorably or unfavorably.

ETP’s propane operations permit customers to guarantee the propane delivery price for the next heating season.  As ETP executes fixed sales price contracts with its customers, it may enter into propane futures contracts to fix the purchase price related to these sales contracts, thereby locking in a gross profit margin.  Additionally, ETP may use propane futures contracts to secure the purchase price of its propane inventory for a percentage of its anticipated propane sales.

Investment in Regency

Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations.  The prices of these commodities are impacted by changes in the supply and demand as well as market focus.  Regency’s profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders.  Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts.  In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk.  Speculative positions are prohibited under Regency’s policy.

Regency is exposed to market risks associated with commodity prices, counterparty credit, and interest rates.  Regency’s management and the board of directors of Regency’s General Partner have established comprehensive risk management policies and procedures to monitor and manage these market risks.  Regency’s General Partner is responsible for delegation of transaction authority levels, and the Risk Management Committee of Regency’s General Partner is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.  Regency’s Risk Management Committee receives regular briefings on positions and exposures, credit exposures, and overall risk management in the context of market activities.

Regency’s Preferred Units (see Note 7) contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and Regency’s call option.  These embedded derivatives are accounted for using mark-to-market accounting.  Regency does not expect the embedded derivatives to affect its cash flows.

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Consolidated Summary of Commodity-Related Derivatives

The following table details the outstanding commodity-related derivatives as of December 31, 2010 and 2009:

	2010				2009
	Notional				Notional
	Volume			Maturity	Volume			Maturity
Mark-to-Market Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu)		(38,897,500	)	2011		72,325,000		2010-2011
Swing Swaps IFERC (MMBtu)		(19,720,000	)	2011		(38,935,000	)	2010
Fixed Swaps/Futures (MMBtu)		(2,570,000	)	2011		4,852,500		2010-2011
Options ─ Puts (MMBtu)		—		—		2,640,000		2010
Options ─ Calls (MMBtu)		(3,000,000	)	2011		(2,640,000	)	2010
Propane:
Forwards/Swaps (Gallons)		1,974,000		2011		6,090,000		2010
Fair Value Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu)		(28,050,000	)	2011		(22,625,000	)	2010
Fixed Swaps/Futures (MMBtu)		(39,105,000	)	2011		(27,300,000	)	2010
Hedged Item – Inventory (MMBtu)		39,105,000		2011		27,300,000		2010
Cash Flow Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu)		—		—		(13,225,000	)	2010
Fixed Swaps/Futures (MMBtu)		3,620,000		2011-2012		(22,800,000	)	2010
Options – Puts (MMBtu)		26,760,000		2011-2012		—		—
Options – Calls (MMBtu)		(26,760,000	)	2011-2012		—		—
Propane:
Forwards/Swaps (Gallons)		51,114,000		2011-2012		20,538,000		2010
Natural Gas Liquids:
Forwards/Swaps (Barrels)		1,212,110		2011-2012		—		—
WTI Crude Oil:
Forwards/Swaps (Barrels)		373,655		2011-2012		—		—

We expect gains of $15.6 million related to commodity derivatives to be reclassified into earnings over the next twelve months related to amounts currently reported in AOCI.  The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

As of July 2008, ETP no longer engages in the trading of commodity derivative instruments that are not substantially offset by physical or other commodity derivative positions.  As a result, we no longer have any material exposure to market risk from such activities.  The derivative contracts that were previously entered into for trading purposes were recognized in the consolidated balance sheets at fair value, and changes in the fair value of these derivative instruments are recognized in revenue in the consolidated statements of operations on a net basis.  Trading activities, including trading of physical gas and financial derivative instruments, resulted in net losses of approximately $26.2 million for the year ended December 31, 2008.

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Interest Rate Risk

We are exposed to market risk for changes in interest rates.  In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt.  We manage a portion of our current and future interest rate exposures by utilizing interest rate swaps in order to achieve our desired mix of fixed and variable rate debt.  We also utilize forward starting interest rate swaps to lock in the rate on a portion of anticipated debt issuances.  The following is a summary of interest rate swaps outstanding as of December 31, 2010, none of which are designated as hedges for accounting purposes:

Entity	Term	Notional Amount		Type (1)
ETP	August 2012 (2)	$	400,000	Forward starting to pay a fixed rate of 3.64% and receive a floating rate
ETP	July 2018		500,000	Pay a floating rate and receive a fixed rate of 6.70%
Regency	April 2012		250,000	Pay a fixed rate of 1.325% and receive a floating rate

(1)Floating rates are based on LIBOR.

(2)These forward starting swaps have an effective date of August 2012 and a term of 10 years; however, the swaps have a mandatory termination provision and will be settled in August 2012.

In May and August 2010, ETP terminated interest rate swaps with total notional amounts of $750.0 million and $350.0 million, respectively, for proceeds of $15.4 million and $11.1 million, respectively.  These swaps were designated as fair value hedges.  In connection with the swap terminations, $9.7 million and $10.4 million of previously recorded fair value adjustments to hedged long-term debt will be amortized as a reduction of interest expense through February 2015 and July 2013, respectively.

In addition to interest rate swaps, ETP also periodically enters into interest rate swaptions that enable counterparties to exercise options to enter into interest rate swaps with ETP.  Swaptions may be utilized when ETP’s targeted benchmark interest rate for anticipated debt issuance is not attainable at the time in the interest rate swap market.  Upon issuance of a swaption, ETP receives a premium, which ETP recognizes over the term of the swaption to "Gains (losses) on non-hedged interest rate derivatives" in the consolidated statements of operations.  No swaptions were outstanding as of December 31, 2010.

In connection with ETE’s offering of senior notes in September 2010, ETE terminated interest rate swaps with an aggregate notional amount of $1.5 billion and recognized in interest expense $66.4 million of realized losses on terminated interest rate swaps that had been accounted for as cash flow hedges.  In addition to the $66.4 million of realized losses on hedged interest rate swaps, ETE also paid $102.2 million to terminate non-hedged interest rate swaps.  The $102.2 million of realized losses on non-hedged interest rate swaps had previously been recognized in net income and therefore the termination of the non-hedged swaps did not impact earnings.  The total cash paid to terminate interest rate swaps was $168.6 million, including realized losses on hedged and non-hedged swaps.

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 petrochemical companies and other industrial, mid-size to major oil and gas companies and power 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.  Currently, management does not anticipate a material adverse effect on financial position or results of operations as a result of counterparty performance.

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ETP utilizes master-netting agreements and have maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers.  Payments on margin deposits are required 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 for non-exchange traded derivatives.  We exchange margin calls on a daily basis for exchange traded transactions.  Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.  ETP had net deposits with counterparties of $52.2 million and $79.7 million as of December 31, 2010 and 2009, respectively.

Regency is exposed to credit risk from its derivative counterparties.  Although Regency does not require collateral from these counterparties, Regency deals primarily with financial institutions when entering into financial derivatives, and enters into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract receivables and payables in the event of default by either party.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary

The following table provides a balance sheet overview of the Partnership’s derivative assets and liabilities as of December 31, 2010 and 2009:

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	2010		2009		2010			2009
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	35,031	$	669	$	(6,631	)	$	(24,035	)
Commodity derivatives		9,263		8,443		(14,692	)		(201	)
Interest rate derivatives		—		—		—			(61,879	)
		44,294		9,112		(21,323	)		(86,115	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	64,940	$	72,851	$	(72,729	)	$	(36,950	)
Commodity derivatives		275		3,928		—			(241	)
Interest rate derivatives		20,790		—		(20,922	)		(76,157	)
Embedded derivatives in Regency Preferred Units		—		—		(57,023	)		—
		86,005		76,779		(150,674	)		(113,348	)
Total derivatives	$	130,299	$	85,891	$	(171,997	)	$	(199,463	)

The commodity derivatives (margin deposits) are recorded in “Other current assets” on our consolidated balance sheets.  The remainder of the derivatives are recorded in “Price risk management assets/liabilities.”

We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

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The following tables summarize the amounts recognized with respect to our derivative financial instruments for the periods presented:

	Change in Value Recognized in OCI on Derivatives
	(Effective Portion)
	Years Ended December 31,
	2010			2009			2008
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	49,665		$	3,143		$	17,461
Interest rate derivatives		(29,980	)		(14,705	)		(57,676	)
Total	$	19,685		$	(11,562	)	$	(40,215	)

	Location of Gain/(Loss)	Amount of Gain/(Loss)
	Reclassified from	Reclassified from AOCI into Income
	AOCI into Income	(Effective Portion)
	(Effective Portion)	Years Ended December 31,
		2010			2009			2008
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	37,325		$	9,924		$	42,874
Interest rate derivatives	Interest expense		(86,697	)		(26,882	)		(11,339	)
Total		$	(49,372	)	$	(16,958	)	$	31,535

	Location of Gain/(Loss)
	Reclassified from	Amount of Gain/(Loss) Recognized
	AOCI into Income	in Income on Ineffective Portion
	(Ineffective Portion)	Years Ended December 31,
		2010			2009		2008
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	(70	)	$	—	$	(8,347	)
Total		$	(70	)	$	—	$	(8,347	)

	Location of	Amount of Gain/(Loss) Recognized in Income
	Gain/(Loss)	representing hedge ineffectiveness and amount
	Recognized in	excluded from the assessment of effectiveness
	Income on Derivatives	Years Ended December 31,
		2010		2009		2008
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	16,210	$	60,045	$	—
Total		$	16,210	$	60,045	$	—

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	Location of
	Gain/(Loss)	Amount of Gain/(Loss) Recognized
	Recognized in	in Income on Derivatives
	Income on Derivatives	Years Ended December 31,
		2010			2009		2008
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	3,806		$	99,807	$	12,478
Trading commodity derivatives	Revenue		—			—		(28,283	)
Interest rate derivatives	Gains (losses) on non-    hedged interest rate    derivatives		(52,357	)		33,619		(128,423	)
Embedded derivatives	Other income (expense)		(8,390	)		—		—
Total		$	(56,941	)	$	133,426	$	(144,228	)

We recognized $70.5 million of unrealized losses, $18.6 million of unrealized losses and $35.5 million of unrealized gains on commodity derivatives not in fair value hedging relationships (including the ineffective portion of commodity derivatives in cash flow hedging relationships and amounts classified as trading activity) for the years ended December 31, 2010, 2009 and 2008, respectively.  In addition, for the years ended December 31, 2010 and 2009, we recognized unrealized gains of $17.4 million and $48.6 million, respectively, on commodity derivatives and related hedged inventory accounted for as fair value hedges.

12.   RETIREMENT BENEFITS:

ETP sponsors a 401(k) savings plan which covers virtually all employees.  Employer matching contributions are calculated using a formula based on employee contributions.  Prior to 2009, employer-matching contributions were discretionary.  ETP made matching contributions of $9.8 million, $9.8 million and $9.7 million to the 401(k) savings plan for the years ended December 31, 2010, 2009 and 2008, respectively.

Regency also provides matching contributions for its employee contributions to their 401(k) savings accounts, which vests ratably over 3 years.  Effective January 1, 2011, Regency’s 401(k) plan merged with and into that of ETP.  As a results of the Regency Transactions, Regency’s matching contributions that had not yet fully vested became fully vested effective immediately.  All future matching contributions from Regency to its employee 401(k) accounts will vest immediately.  Regency made matching contributions of $2.0 million during the period from May 26, 2010 to December 31, 2010.

13.   RELATED PARTY TRANSACTIONS:

The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services.  For the year ended December 31, 2010 the Parent Company received $5.8 million from Regency related to these services.  For the years ended December 31, 2010, 2009 and 2008 the Parent Company paid $6.3 million, $0.5 million and $0.5 million, respectively, to ETP related to these services.  The increase recorded in the current year was the result of increased service fees related to the provision of various general and administrative services for Regency.

Enterprise and its subsidiaries currently hold a portion of our limited partner interest.  As a result, Enterprise and its affiliates are considered related parties for financial reporting purposes.

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ETP and Enterprise transport natural gas on each other’s pipelines, share operating expenses on jointly-owned pipelines and ETP sells natural gas and compression equipment to Enterprise.  ETP’s propane operations routinely buy and sell product with Enterprise.  Regency sells natural gas and NGLs to, and incurs NGL processing fees with Enterprise.  The following table presents sales to and purchase from Enterprise, including Regency transactions subsequent to May 26, 2010:

	Years Ended December 31,
	2010		2009		2008
ETP’s Natural Gas Operations:
Sales	$	538,657	$	414,333	$	154,272
Purchases		23,592		48,528		115,228
Regency’s Natural Gas Operations:
Sales		142,631		—		—
Purchases		4,606		—		—
ETP’s Propane Operations:
Sales		15,527		19,961		22,211
Purchases		415,897		343,540		493,809

ETP’s propane operations purchase a portion of its propane requirements from Enterprise pursuant to an agreement that was extended until March 2015, and includes an option to extend the agreement for an additional year.  As of December 31, 2010 and 2009, Titan, had forward mark-to-market derivatives for approximately 1.7 million and 6.1 million gallons of propane at a fair value asset of $0.2 million and $3.3 million, respectively, with Enterprise.  In addition, as of December 31, 2010 and 2009, Titan had forward derivatives accounted for as cash flow hedges of 32.5 million and 20.5 million gallons of propane at a fair value assets of $6.6 million and $8.4 million, respectively, with Enterprise.

Sales of $26.0 million and cost of products sold of $20.5 million are included in our consolidated statements of operations related to transactions with FEP, ETP’s unconsolidated affiliate.

Under a master services agreement with HPC, Regency operates and provides all employees and services for the operation and management of HPC.  The related party general administrative expenses reimbursed to Regency were $9.8 million for the period from May 26, 2010 to December 31, 2010.

Regency’s contract compression operations provide contract compression services to HPC.  HPC also provides transportation service to Regency.  Regency had revenue of $13.2 million for the period from May 26, 2010 to December 31, 2010 and cost of sales of $8.1 million for the period from May 26, 2010 to December 31, 2010 with HPC.

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The following table summarizes the related party balances on our consolidated balance sheets:

	As of December 31,
	2010		2009
Accounts receivable from related parties:
Enterprise:
ETP’s Natural Gas Operations	$	36,736	$	47,005
Regency’s Natural Gas Operations		25,539		—
ETP’s Propane Operations		2,327		3,386
Other		11,729		1,503
Total accounts receivable from related parties	$	76,331	$	51,894
Accounts payable to related parties:
Enterprise:
ETP’s Natural Gas Operations	$	2,687	$	3,518
Regency’s Natural Gas Operations		1,323		—
ETP’s Propane Operations		22,985		31,642
Other		356		3,355
Total accounts payable to related parties	$	27,351	$	38,515
ETP’s net imbalance receivable from Enterprise	$	1,360	$	694
Regency’s net imbalance receivable from Enterprise	$	753	$	—

Effective August 17, 2009, ETP acquired 100% of the membership interests of ETG, which owns all of the partnership interests of Energy Transfer Technologies, Ltd. (“ETT”).  ETT provides compression services to customers engaged in the transportation of natural gas, including ETP.  The membership interests of ETG were contributed to ETP by Mr. Warren and by two entities, one of which is controlled by a director of the General Partner of ETP’s general partner and the other of which is controlled by a member of ETP’s management.  In exchange, the former members acquired the right to receive (in cash or Common Units) future amounts to be determined based on the terms of the contribution arrangement.  These contingent amounts are to be determined in 2014 and 2017, and the former members of ETG may receive payments contingent on the acquired operations performing at a level above the average return required by ETP for approval of its own growth projects during the period since acquisition.  In addition, the former members may be required to make cash payments to us under certain circumstances.  ETP has not accrued any contingent payments related to this agreement.

Prior to ETP’s acquisition of ETG in August 2009, its natural gas midstream and intrastate transportation and storage operations secured compression services from ETT.  The terms of each arrangement to provide compression services were, in the opinion of independent directors of the General Partner, no more or less favorable than those available from other providers of compression services.  During the years ended December 31, 2009 (through the ETG acquisition date) and 2008, ETP made payments totaling $3.4 million and $9.4 million, respectively, to ETG for compression services provided to and utilized in ETP's natural gas midstream and intrastate transportation and storage operations.

Subsequent to the acquisition of ETG, ETP pays $4.7 million in operating lease payments per year to the former owners for the use of compressor equipment through 2017.

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14.   REPORTABLE SEGMENTS:

As a result of the Regency Transactions in May 2010, our reportable segments were re-evaluated and now reflect two reportable segments, both of which conduct their business exclusively in the United States of America, as follows:

·   Investment in ETP ─ Reflects the consolidated operations of ETP.

·   Investment in Regency ─ Reflects the consolidated operations of Regency.

Each of the respective general partners of ETP and Regency has separate operating management and boards of directors.  We control ETP and Regency through our ownership of their respective general partners.  See further discussion of ETP and Regency’s operations in Note 1.

We evaluate the performance of our operating segments based on net income.  The following tables present the financial information by segment.  The amounts reflected as “Corporate and Other” include the Parent Company activity and the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

ETP and Regency related party transactions are generally based on transactions made at market-related rates.  Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

The following tables present the financial information by segment for the following periods:

	Investment in ETP			Investment in Regency			Corporate and Other			Adjustments  and Eliminations			Total
Year Ended December 31, 2010:
Revenues from external customers	$	5,884,786		$	715,324		$	—		$	(1,978	)	$	6,598,132
Intersegment revenues		41			1,289			—			(1,330	)		—
Depreciation and amortization		343,011			75,967			12,221			—			431,199
Interest expense, net of interest capitalized		412,553			48,251			167,669			(3,586	)		624,887
Equity in earnings of affiliates		11,727			53,493			—			—			65,220
Income tax expense (benefit)		15,536			552			(2,350	)		—			13,738
Net income (loss)		617,222			(5,972	)		(274,670	)		—			336,580
Year Ended December 31, 2009:
Revenues from external customers	$	5,417,295		$	—		$	—		$	—		$	5,417,295
Intersegment revenues		—			—			—			—			—
Depreciation and amortization		312,803			—			12,221			—			325,024
Interest expense, net of interest capitalized		394,274			—			74,146			—			468,420
Equity in earnings of affiliates		20,597			—			—			—			20,597
Income tax expense (benefit)		12,777			—			(3,548	)		—			9,229
Net income (loss)		791,542			—			(93,671	)		—			697,871
Year Ended December 31, 2008:
Revenues from external customers	$	9,293,868		$	—		$	—		$	(501	)	$	9,293,367
Intersegment revenues		—			—			—			—			—
Depreciation and amortization		262,151			—			12,221			—			274,372
Interest expense, net of interest capitalized		265,701			—			91,840			—			357,541
Equity in earnings (losses) of affiliates		(165	)		—			—			—			(165	)
Income tax expense (benefit)		6,680			—			(2,872	)		—			3,808
Net income (loss)		866,023			—			(186,269	)		—			679,754

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	As of December 31,
	2010			2009			2008
Total assets:
Investment in ETP	$	12,149,992		$	11,734,972		$	10,627,490
Investment in Regency		4,770,204			—			—
Corporate and Other		469,221			431,109			445,571
Adjustments and Eliminations		(10,687	)		(5,572	)		(3,159	)
Total	$	17,378,730		$	12,160,509		$	11,069,902
	Years Ended December 31,
	2010			2009			2008
Additions to property, plant and equipment including     acquisitions, net of contributions in aid of     construction costs (accrual basis):
Investment in ETP	$	1,470,001		$	680,780		$	2,115,402
Investment in Regency (including $1.5 billion acquired in the Regency Transactions)		2,068,328			—			—
Total	$	3,538,329		$	680,780		$	2,115,402

	As of December 31,
	2010		2009		2008
Advances to and investments in affiliates:
Investment in ETP	$	8,723	$	663,298	$	10,110
Investment in Regency		1,351,256		—		—
Total	$	1,359,979	$	663,298	$	10,110

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15.   QUARTERLY FINANCIAL DATA (UNAUDITED):

Summarized unaudited quarterly financial data is presented below.  Earnings per unit are computed on a stand-alone basis for each quarter and total year.  ETP’s propane operations are seasonal due to weather conditions in their service areas.  Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year.  Sales to commercial and industrial customers are less weather sensitive.  ETC OLP’s business is also seasonal due to the operations of ET Fuel System and the HPL System.  We expect margin related to the HPL System operations to be higher during the periods from November through March of each year and lower during the periods from April through October of each year due to the increased demand for natural gas during the cold 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.

	Quarter Ended
	March 31		June 30			September 30			December 31		Total Year
2010:
Revenues	$	1,871,981	$	1,362,529		$	1,587,807		$	1,775,815	$	6,598,132
Gross profit		647,116		522,075			592,702			724,902		2,486,795
Operating income		338,928		179,257			202,052			316,492		1,036,729
Net income (loss)		204,082		(20,479	)		(4,826	)		157,803		336,580
Limited Partners’ interest in net income (loss)		112,428		19,208			(15,289	)		75,814		192,161
Basic net income (loss) per limited partner unit	$	0.50	$	0.09		$	(0.07	)	$	0.34	$	0.86
Diluted net income (loss) per limited partner unit	$	0.50	$	0.09		$	(0.07	)	$	0.34	$	0.86
2009:
Revenues	$	1,629,974	$	1,151,690		$	1,129,849		$	1,505,782	$	5,417,295
Gross profit		670,835		525,697			451,701			647,006		2,295,239
Operating income		356,098		215,031			173,501			365,768		1,110,398
Net income		279,750		141,758			34,267			242,096		697,871
Limited Partners’ interest in net income		151,067		104,053			46,824			139,159		441,103
Basic net income per limited partner unit	$	0.68	$	0.47		$	0.21		$	0.62	$	1.98
Diluted net income per limited partner unit	$	0.68	$	0.47		$	0.21		$	0.62	$	1.98

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16.   SUPPLEMENTAL 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:

BALANCE SHEETS

	December 31,
	2010		2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	27,247	$	62
Accounts receivable from related companies		171		97
Other current assets		864		1,287
Total current assets		28,282		1,446
ADVANCES TO AND INVESTMENTS IN AFFILIATES		2,231,722		1,711,928
INTANGIBLES AND OTHER ASSETS, net		29,118		5,574
Total assets	$	2,289,122	$	1,718,948
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	—	$	178
Accounts payable to related companies		6,654		5,024
Price risk management liabilities		—		64,704
Accrued and other current liabilities		44,200		1,607
Total current liabilities		50,854		71,513
LONG-TERM DEBT, less current maturities		1,800,000		1,573,951
SERIES A CONVERTIBLE PREFERRED UNITS		317,600		—
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		—		73,332
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner		520		368
Limited Partners – Common Unitholders (222,941,172 and    222,898,248 units authorized, issued and outstanding at December    31, 2010 and 2009, respectively)		115,350		53,412
Accumulated other comprehensive income (loss)		4,798		(53,628	)
Total partners’ capital		120,668		152
Total liabilities and partners’ capital	$	2,289,122	$	1,718,948

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STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2010			2009			2008
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(21,829	)	$	(4,970	)	$	(6,453	)
OTHER INCOME (EXPENSE):
Interest expense		(167,658	)		(74,049	)		(91,822	)
Equity in earnings of affiliates		455,901			526,383			551,835
Losses on non-hedged interest rate derivatives		(53,388	)		(5,620	)		(77,435	)
Other, net		(19,721	)		79			(1,056	)
INCOME BEFORE INCOME TAXES		193,305			441,823			375,069
Income tax expense (benefit)		547			(650	)		25
NET INCOME		192,758			442,473			375,044
GENERAL PARTNER’S INTEREST IN NET INCOME		597			1,370			1,161
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	192,161		$	441,103		$	373,883

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STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2010			2009			2008
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	317,328		$	468,969		$	436,819
CASH FLOWS FROM INVESTING ACTIVITIES:
MEP Transaction		3,258			—			—
Net cash provided by investing activities		3,258			—			—
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,858,245			67,505			190,533
Principal payments on debt		(1,632,374	)		(65,816	)		(191,464	)
Distributions to Partners		(483,048	)		(470,658	)		(435,868	)
Debt issuance costs		(36,224	)		—			—
Net cash used in financing activities		(293,401	)		(468,969	)		(436,799	)
INCREASE IN CASH AND CASH EQUIVALENTS		27,185			—			20
CASH AND CASH EQUIVALENTS, beginning of period		62			62			42
CASH AND CASH EQUIVALENTS, end of period	$	27,247		$	62		$	62

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