Edgar Filing: Energy Transfer Partners, L.P.

Form 10-Q

FORM 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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

For the Quarterly Period Ended February 28, 2006

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from to

Commission file number 1-11727

ENERGY TRANSFER PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware

73-1493906

(state or other jurisdiction or

incorporation or organization)

(I.R.S. Employer

Identification No.)

2838 Woodside Street

Dallas, Texas 75204

(Address of principal executive offices and zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer ¨ Non accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

At April 7, 2006, the registrant had units outstanding as follows:


Energy Transfer Partners, L.P.	108,055,561	Common Units
	2,570,150	Class F Units

FORM 10-Q

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Partners, L.P. and Subsidiaries


		Page
PART I	FINANCIAL INFORMATION

ITEM 1.	Financial Statements (Unaudited)

Condensed Consolidated Balance Sheets – February 28, 2006 and August 31, 2005		1

Condensed Consolidated Statements of Operations – Three and Six Months Ended February 28, 2006 and 2005		3

Consolidated Statements of Comprehensive Income – Three and Six Months Ended February 28, 2006 and 2005		4

Consolidated Statement of Partners’ Capital – Six Months Ended February 28, 2006		5

Condensed Consolidated Statements of Cash Flows – Six Months Ended February 28, 2006 and 2005		6

Notes to Condensed Consolidated Financial Statements		7

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	31

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	47

ITEM 4.	CONTROLS AND PROCEDURES	49

PART II	OTHER INFORMATION

ITEM 6.	EXHIBITS	50

SIGNATURES

Forward-Looking Statements

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

Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see the Partnership’s Annual Report on Form 10-K as amended on 10-K/A for the fiscal year ended August 31, 2005 filed with the Securities and Exchange Commission on November 14, 2005 and December 12, 2005, respectively.

Definitions

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


/d		per day
Bbls		barrels
Btu		British thermal unit, an energy measurement
Mcf		thousand cubic feet
MMBtu		million British thermal unit
MMcf		million cubic feet
Bcf		billion cubic feet
NGL		natural gas liquid, such as propane, butane and natural gasoline
LIBOR		London Interbank Offered Rate
NYMEX		New York Mercantile Exchange
Reservoir		A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

(unaudited)


	February 28, 2006		August 31, 2005
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	33,843	$	24,914
Marketable securities		3,575		3,452
Accounts receivable, net of allowance for doubtful accounts		821,763		847,028
Accounts receivable from related parties		724		4,479
Inventories		238,787		302,893
Exchanges receivable		18,892		35,623
Price risk management assets		65,907		138,961
Prepaid expenses and other assets		79,254		100,670

Total current assets		1,262,745		1,458,020

PROPERTY, PLANT AND EQUIPMENT, net		2,666,479		2,440,565
LONG-TERM PRICE RISK MANAGEMENT ASSETS		9,043		41,687
INVESTMENT IN AFFILIATES		37,135		37,353
GOODWILL		325,093		324,019
INTANGIBLES AND OTHER ASSETS, net		112,933		125,262

Total assets	$	4,413,428	$	4,426,906

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

(unaudited)


	February 28, 2006		August 31, 2005
LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Working capital facility	$	21,198	$	17,026
Accounts payable		674,639		818,775
Accounts payable to related parties		410		1,073
Customer deposits		8,464		88,038
Price risk management liabilities		41,374		104,772
Accrued and other current liabilities		147,815		179,778
Income taxes payable		23,590		2,063
Deferred income taxes		2,157		—
Current maturities of long-term debt		39,673		39,349

Total current liabilities		959,320		1,250,874

LONG-TERM DEBT, less current maturities		1,517,724		1,675,705
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		1,021		30,517
LONG-TERM AFFILIATED PAYABLE		—		2,005
NONCURRENT DEFERRED INCOME TAXES		108,985		111,185
OTHER NONCURRENT LIABILITIES		10,356		13,284
MINORITY INTERESTS		2,074		17,144

		2,599,480		3,100,714

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
General Partner		66,185		49,384
Common Unitholders (108,055,561 and 106,889,904 units authorized, issued and outstanding at February 28, 2006 and August 31, 2005, respectively)		1,615,778		1,362,125
Class C Unitholders (1,000,000 units authorized, issued and outstanding at February 28, 2006 and August 31, 2005)		—		—
Class E Unitholders (8,853,832 units authorized, issued and outstanding at February 28, 2006 and August 31, 2005 – held by subsidiary and reported as treasury units)		—		—
Class F Unitholders (2,570,150 and 0 units authorized, issued and oustanding at February 28, 2006 and August 31, 2005, respectively)		94,686		—
Accumulated other comprehensive income (loss)		37,299		(85,317	)

Total partners’ capital		1,813,948		1,326,192

Total liabilities and partners’ capital	$	4,413,428	$	4,426,906

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit and unit data)

(unaudited)


	Three Months Ended February 28, 2006			Three Months Ended February 28, 2005			Six Months Ended February 28, 2006			Six Months Ended February 28, 2005
REVENUES:
Midstream and transportation and storage	$	2,083,303		$	1,130,526		$	4,291,837		$	1,824,213
Propane and other		366,513			309,318			574,599			479,829

Total revenues		2,449,816			1,439,844			4,866,436			2,304,042

COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage		1,785,053			1,028,558			3,744,422			1,650,473
Cost of products sold, propane and other		223,778			182,617			355,036			288,606
Operating expenses		99,696			73,551			202,367			133,751
Depreciation and amortization		29,014			22,232			55,927			41,893
Selling, general and administrative		31,455			11,913			56,254			22,637

Total costs and expenses		2,168,996			1,318,871			4,414,006			2,137,360

OPERATING INCOME		280,820			120,973			452,430			166,682

OTHER INCOME (EXPENSE):
Interest expense		(28,542	)		(23,024	)		(56,935	)		(40,355	)
Equity in earnings (losses) of affiliates		106			109			(168	)		145
Gain (loss) on disposal of assets		662			(436	)		534			(527	)
Loss on extinguishment of debt		—			(7,996	)		—			(7,996	)
Interest income and other, net		2,302			235			3,261			369

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS		255,348			89,861			399,122			118,318

Income tax expense		4,014			3,127			26,425			4,159

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS		251,334			86,734			372,697			114,159

Minority interests		(549	)		(358	)		(2,104	)		(516	)

INCOME FROM CONTINUING OPERATIONS		250,785			86,376			370,593			113,643

INCOME FROM DISCONTINUED OPERATIONS		—			1,225			—			4,568

NET INCOME		250,785			87,601			370,593			118,211

GENERAL PARTNER’S INTEREST IN NET INCOME		27,695			10,456			48,179			16,545

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	223,090		$	77,145		$	322,414		$	101,666

BASIC NET INCOME PER LIMITED PARTNER UNIT
Limited Partners’ income from continuing operations	$	1.37		$	0.67		$	2.13		$	1.02
Limited Partners’ income from discontinued operations		—			0.01			—			0.04

NET INCOME PER LIMITED PARTNER UNIT (see Note 7)	$	1.37		$	0.68		$	2.13		$	1.06

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		107,815,792			94,177,730			107,352,608			91,697,190

DILUTED NET INCOME PER LIMITED PARTNER UNIT
Limited Partners’ income from continuing operations	$	1.36		$	0.67		$	2.12		$	1.02
Limited Partners’ income from discontinued operations		—			0.01			—			0.04

NET INCOME PER LIMITED PARTNER UNIT (see Note 7)	$	1.36		$	0.68		$	2.12		$	1.06

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		108,017,060			94,331,506			107,551,712			91,837,451

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

(unaudited)


	Three Months Ended February 28, 2006			Three Months Ended February 28, 2005			Six Months Ended February 28, 2006			Six Months Ended February 28, 2005
Net income	$	250,785		$	87,601		$	370,593		$	118,211

Other comprehensive income before tax:
Reclassification adjustment for (gains) and losses on derivative instruments included in net income accounted for as hedges, before tax expense of $979, and tax benefit of $281 for the three and six months ended February 28, 2006, respectively.		(142,981	)		(4,053	)		(42,431	)		10,735
Change in value of derivative instruments accounted for as hedges, before tax benefit of $913, and tax expense of $1,098 for the three and six months ended February 28, 2006, respectively.		139,010			17,900			165,741			2,378
Change in value of available-for-sale securities, before tax benefit of $2, and tax expense of $1 for the three and six months ended February 28, 2006, respectively.		256			1,817			124			1,226
Income tax benefit (expense) related to items of other comprehensive income		64			—			(818	)		—

Comprehensive income	$	247,134		$	103,265		$	493,209		$	132,550

Reconciliation of Accumulated Other Comprehensive Income:

Balance, beginning of period	$	40,950		$	(1,293	)	$	(85,317	)	$	32

Current period reclassification to earnings		(142,002	)		(4,053	)		(42,150	)		10,735
Current period change		138,351			19,717			164,766			3,604

Balance, end of period	$	37,299		$	14,371		$	37,299		$	14,371

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

For the six months ended February 28, 2006

(in thousands, except unit data)

(unaudited)


	Number of Common Units	Number of Class F Units	General Partner			Common			Class C		Class E		Class F		Accumulated Other Comprehensive Income (Loss)			Total
Balance, August 31, 2005	106,889,904	—	$	49,384		$	1,362,125		$	—	$	—	$	—	$	(85,317	)	$	1,326,192
Unit distribution	—	—		(34,080	)		(112,289	)		—		—		—		—			(146,369	)
Issuance of restricted Common Units	95,807	—		—			—			—		—		—		—			—
Issuance of Common and Class F units to Energy Transfer Equity, L.P.	1,069,850	2,570,150		—			38,911			—		—		93,476		—			132,387
General Partner capital contribution	—	—		2,702			—			—		—		—		—			2,702
Net change in accumulated other comprehensive income per accompanying statement	—	—		—			—			—		—		—		122,616			122,616
Deferred compensation on restricted units and long- term incentive plan	—	—		—			5,827			—		—		—		—			5,827
Net income	—	—		48,179			321,204			—		—		1,210		—			370,593

Balance, February 28, 2006	108,055,561	2,570,150	$	66,185		$	1,615,778		$	—	$	—	$	94,686	$	37,299		$	1,813,948

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)


	Six Months Ended
	February 28, 2006			February 28, 2005
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	438,058		$	156,576

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		(29,946	)		(1,113,070	)
Working capital settlement on prior year acquisitions		19,653			—
Capital expenditures		(255,101	)		(75,227	)
Proceeds from the sale of assets		3,875			2,654
Cash invested in subsidiaries		—			(51	)

Net cash used in investing activities		(261,519	)		(1,185,694	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,013,188			1,581,530
Principal payments on debt		(1,168,322	)		(1,032,610	)
Proceeds from borrowing from affiliates		—			174,624
Subscribed stock		—			180,000
Debt issuance costs		(1,196	)		(15,655	)
Capital contribution from General Partner		2,702			3,520
Equity offering		132,387			169,807
Unit distributions		(146,369	)		(86,533	)

Net cash (used in) provided by financing activities		(167,610	)		974,683

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		8,929			(54,435	)

CASH AND CASH EQUIVALENTS, beginning of period		24,914			81,745

CASH AND CASH EQUIVALENTS, end of period	$	33,843		$	27,310

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Dollar amounts in thousands, except per unit data)

(unaudited)

1. OPERATIONS AND ORGANIZATION:

The accompanying condensed consolidated balance sheet as of August 31, 2005, which has been derived from audited financial statements, and the unaudited interim financial statements and notes thereto of Energy Transfer Partners, L.P., and subsidiaries have been prepared in accordance with accounting principles generally accepted in the United States of America for interim consolidated financial information and pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete consolidated financial statements. However, the Partnership believes that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the Partnership’s operations, maintenance activities and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting.

In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of Energy Transfer Partners and subsidiaries as of February 28, 2006, and the results of operations for the three-month and six-month periods ended February 28, 2006 and 2005, and cash flows for the six-month periods ended February 28, 2006 and 2005. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of Energy Transfer Partners presented in the Partnership’s Annual Report on Form 10-K for the fiscal year ended August 31, 2005, as amended on Form 10-K/A as filed with the Securities and Exchange Commission on November 14, 2005, and December 12, 2005, respectively.

Certain prior period amounts have been reclassified to conform to the classification presentation in the 2006 condensed financial statements. These reclassifications have no impact on net income or total partners’ capital. Prior periods have also been adjusted to reflect the sale of certain assets in the midstream segment as discontinued operations (see Note 2).

Business Operations

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

2. DISCONTINUED OPERATIONS:

In April 2005, the Partnership sold its assets in Oklahoma, referred to as the Elk City System, for $191,606 in cash and recorded a gain on the sale during fiscal year 2005 of $142,469, net of income taxes. Accordingly, the Elk City System was accounted for as discontinued operations in accordance with Statement of Financial Accounting Standards, No. 144, Accounting for the Impairment or Disposal of Long-lived Assets, for all periods presented in the condensed consolidated statements of operations, as follows:


	Three Months Ended February 28, 2005			Six Months Ended February 28, 2005
Revenues	$	40,731		$	84,195
Cost and expenses		(39,506	)		(79,627	)

Income from discontinued operations	$	1,225		$	4,568

3. USE OF ESTIMATES:

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream and transportation and storage segments are estimated using volume estimates and market prices. Any difference between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the three and six months ended February 28, 2006 represent the actual results in all material respects.

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

4. ACCOUNTS RECEIVABLE:

ETC OLP’s midstream and transportation and storage operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other forms of security (corporate guaranty or prepayment). Management reviews midstream and transportation and storage accounts receivable balances each week. Credit limits are assigned and monitored for all counterparties of the midstream and transportation and storage operations. Management believes that the occurrence of bad debts in the midstream and transportation and storage segments is not significant; therefore, an allowance for doubtful accounts for the midstream and transportation and storage segments was not deemed necessary at February 28, 2006 or August 31, 2005. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. There was no bad debt expense recognized for the three or six months ended February 28, 2006 and 2005 in the midstream and transportation and storage segments.

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

HOLP grants credit to its customers for the purchase of propane and propane-related products. Included in accounts receivable are trade accounts receivable arising from HOLP’s retail and wholesale propane operations. Accounts receivable for retail and wholesale propane operations are recorded as amounts billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts for the retail and wholesale propane segments is based on management’s assessment of the realizability of customer accounts. Management considers the overall creditworthiness of the Partnership’s customers, historical trends in collectability, and any specific disputes in determining the amount of allowance for doubtful accounts. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. For the three months ended February 28, 2006 and 2005, bad debt expense, net of recoveries, was $362 and $244, respectively. Bad debt expense, net of recoveries, of $549 and $430 was recognized for the six months ended February 28, 2006 and 2005, respectively.

Accounts receivable consisted of the following:


	February 28, 2006			August 31, 2005
Accounts receivable - midstream and transportation and storage	$	696,099		$	782,090
Accounts receivable - propane		129,664			69,014
Less – allowance for doubtful accounts		(4,000	)		(4,076	)

Total, net	$	821,763		$	847,028

5. INVENTORIES:

ETC OLP’s inventories consist principally of natural gas held in storage which is valued at the lower of cost or market utilizing the weighted average cost method. Propane inventories are also valued at the lower of cost or market. The cost of propane inventories is determined using the weighted-average cost of propane delivered to the customer service locations, and includes storage fees and inbound freight costs, while the cost of appliances, parts, and fittings is determined by the first-in, first-out method. Inventories consisted of the following:


	February 28, 2006		August 31, 2005
Natural gas, propane and other NGLs	$	224,991	$	288,657
Appliances, parts and fittings and other		13,796		14,236

Total inventories	$	238,787	$	302,893

6. CUSTOMER DEPOSITS:

The August 31, 2005 balance of customer deposits of $88,038 included $51,400 related to a prepayment made by a customer for natural gas that was physically delivered during the first quarter of fiscal year 2006. Other customer deposits as of August 31, 2005 have either been returned or applied against amounts owed to the Partnership during the six months ended February 28, 2006.

7. INCOME PER LIMITED PARTNER UNIT:

Basic net income per limited partner unit is computed in accordance with EITF Issue No. 03-6 (“EITF 03-6”) Participating Securities and the Two-Class method under FASB Statement No. 128, by dividing limited partners’ interest in net income by the weighted average number of Common and Class F Units outstanding. In periods when the Partnership’s aggregate net income exceeds the aggregate distributions, EITF 03-6 requires the Partnership to present earnings per unit as if all of the earnings for the periods were distributed (see table below). Diluted net income per limited partner unit is computed by dividing limited partners’ interest in net income, after considering the General Partner’s interest, by the weighted average number of Common and Class F Units outstanding and the effect of non-vested restricted units (“Unit Grants”) granted under the 2004 Unit Plan and predecessor plan computed using the treasury stock method. A reconciliation of net income and weighted average units used in computing basic and diluted earnings per unit is as follows:


	Three Months Ended February 28, 2006			Three Months Ended February 28, 2005			Six Months Ended February 28, 2006			Six Months Ended February 28, 2005
Net income	$	250,785		$	87,601		$	370,593		$	118,211
Adjustments:
General Partner’s incentive distributions		(22,679	)		(8,704	)		(40,767	)		(14,181	)
General Partner’s equity ownership		(5,016	)		(1,752	)		(7,412	)		(2,364	)

Limited Partners’ interest in net income	$	223,090		$	77,145		$	322,414		$	101,666
Additional earnings allocation to General Partner (a)		(75,907	)		(13,095	)		(94,206	)		(4,445	)

Net income available to limited partners (a)	$	147,183		$	64,050		$	228,208		$	97,221

Weighted average limited partner units – basic		107,815,792			94,177,730			107,352,608			91,697,190

Limited Partners’ basic income per unit from continuing operations	$	1.37		$	0.67		$	2.13		$	1.02
Limited Partners’ basic income per unit from discontinued operations		—			0.01			—			0.04

Basic net income per limited partner unit (a)	$	1.37		$	0.68		$	2.13		$	1.06

Weighted average limited partner units		107,815,792			94,177,730			107,352,608			91,697,190
Dilutive effect of Unit grants		201,268			153,776			199,014			140,261

Weighted average limited partner units, assuming dilutive effect of Unit grants		108,017,060			94,331,506			107,551,712			91,837,451

Limited Partners’ diluted income per unit from continuing operations	$	1.36		$	0.67		$	2.12		$	1.02
Limited Partners’ diluted income per unit from discontinued operations		—			0.01			—			0.04

Diluted net income per limited partner unit (a)	$	1.36		$	0.68		$	2.12		$	1.06

(a)

Basic and diluted net income per limited partner unit for the three and six months ended February 28, 2005, have been restated to reflect the application of EITF 03-6. The Partnership’s net income for partners’ capital and income statement presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions, if any, to the Partnership’s General Partner, the holder of the incentive distribution rights pursuant to the Partnership Agreement, which are declared and paid following the close of each quarter. However, for purposes of computing basic and diluted net income per limited partner unit, in periods when the Partnership’s aggregate net income exceeds the aggregate distributions for such periods, an increased amount of net income is allocated to the General Partner for the additional pro forma priority income attributable to the application of EITF 03-6. The General Partner is entitled to receive incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds levels specified in the Partnership Agreement.

8. CASH FLOW FROM OPERATING ACTIVITIES:

Cash flow provided by operating activities in the condensed consolidated statements of cash flows is comprised of the following principal components:


	Six Months Ended February 28, 2006			Six Months Ended February 28, 2005
Net income	$	370,593		$	118,211

Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		57,297			44,707
Non-cash compensation on unit grants		5,827			804
Minority interests not distributed		1,597			562
Other non-cash items		(755	)		14,248
Changes in assets and liabilities:
Accounts receivable		44,160			(52,894	)
Inventories		64,218			68,509
Price risk management assets and liabilities, net		136,100			(5,595	)
Accounts payable		(151,053	)		10,294
(Utilization) collection of customer deposits		(79,620	)		116
Income taxes		21,527			(572	)
Other		(31,833	)		(41,814	)

Net cash provided by operating activities	$	438,058		$	156,576

9. UNIT BASED COMPENSATION PLANS:

On September 1, 2005, the Partnership adopted the modified prospective provisions of Statement of Financial Accounting Standards No. 123 (revised 2004) Accounting for Stock-based Compensation (“SFAS 123R”). As provided in SFAS 123R, the Partnership values the unit awards based on the per unit grant-date market value reduced by the present value of the distributions expected to be paid on the units during the requisite service period. The present value is computed based on the risk-free interest rate, the expected life of the unit grants and the expected unit distributions. The Partnership assumed a weighted average risk-free interest rate of 4.32% for the three and six months ended February 28, 2006, in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each grant. The weighted average fair value at the grant date of the awards outstanding for the three and six months ended February 28, 2006 and 2005 was $30.61. Annual average cash distributions at the grant date were estimated to be $2.16 for the three and six months ended February 28, 2006. The expected life of each grant is assumed to be the minimum vesting period under certain

performance criteria of each grant. The Partnership recognized compensation expense of $5,380 and $5,827, respectively, for the three and six months ended February 28, 2006 related to unit based compensation plans. For the three and six months ended February 28, 2005, the Partnership recognized compensation expense of $402 and $804, respectively. Adoption of SFAS 123R did not have a material effect on the Partnership’s income from continuing operations.

2004 Unit Plan

Employee Grants. The Compensation Committee, at its discretion, may from time to time grant awards to any employee, upon such terms and conditions as it may determine appropriate and in accordance with specific general guidelines as defined by the Plan. On December 20, 2005, the Compensation Committee modified the terms of the grants awarded during fiscal year 2005, by issuing 88,183 Common Units on the grants which vested September 1, 2005, forfeiting 800 grants and granting 168,200 additional awards. Management has determined that the change due to the modification of the grants awarded in fiscal 2005, in accordance with SFAS 123R, was immaterial. As of February 28, 2006, 356,350 awards to employees were outstanding under the 2004 Unit Plan and 2,867 were forfeited. These awards vest at a rate of one-third per year for three years based upon the achievement of certain performance criteria. The issuance of Common Units pursuant to the 2004 Unit Plan is intended to serve as a means of incentive compensation, therefore, no consideration will be payable by the plan participants upon vesting and issuance of the Common Units.

Director Grants. Each director who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of Energy Transfer Partners, L.L.C., the Partnership, or a subsidiary (“Director Participant”), who is elected or appointed to the Board for the first time shall automatically receive, on the date of his or her election or appointment, an award of up to 2,000 Units (the “Initial Director’s Grant”). Each Director Participant who is in office on September 1st shall automatically receive an award of Units equal to $15 divided by the fair market value of Common Units on such date (“Annual Director’s Grant”). On September 1, 2005, 3,000 Directors Grants vested, and Common Units were issued under the predecessor plan. On December 20, 2005, an additional 3,014 units were vested, and 730 units were forfeited under the 2004 Unit Plan and predecessor plan. As of February 28, 2006, Initial Director’s Grants and annual Director’s Grants totaling 23,210 units were outstanding under the 2004 Unit Plan and the predecessor plan.

Long-Term Incentive Grants. The Compensation Committee may, from time to time, grant awards under the Plan to any executive officer or any employee it may designate as a participant in accordance with general guidelines under the Plan. As of February 28, 2006, there have been no Long-Term Incentive Grants made under the Plan.

10. ACQUISITIONS:

In January 2005, the Partnership acquired the controlling interests in HPL Consolidation LP (“HPL”) from American Electric Power Corporation (“AEP”) for approximately $825,000 subject to working capital adjustments. In addition the Partnership acquired working inventory of natural gas stored in the Bammel storage facilities and financed the purchase through a short-term borrowing from an affiliate, which was repaid in full in April 2005. Under the terms of the transaction, the Partnership acquired all but a 2% limited partner interest in HPL. On November 10, 2005, the Partnership acquired the remaining 2% limited partnership interests in HPL for $16,560 in cash. The purchase price was allocated to property, plant and equipment and the minority interest liability associated with the 2% limited partner interests was eliminated. As a result, HPL become a wholly-owned subsidiary of ETC OLP. The Partnership also reached a settlement agreement with AEP in November 2005 related to certain inventory and working capital matters associated with the acquisition. The terms of the agreement were not material in relation to the Partnership’s financial position or results of operations.

The Partnership obtained the final independent valuation and has made the final allocations of the purchase price to the acquired assets during the three months ended February 28, 2006, and the final adjustments resulted in a reduction of $45,820 to the amount allocated to pad gas and an increase of an equal amount to acquired depreciable assets. The final adjustment did not have a material impact on the Partnership’s financial position or results of operation.

The unaudited pro forma consolidated results of operations for the three and six months ended February 28, 2005 are presented as if the acquisition of the 98% controlling interests in HPL had occurred at the beginning of the period presented. The proforma consolidated net income and earnings per unit include the income from discontinued operations as presented on the condensed consolidated income statement for the three and six months ended February 28, 2005. The results do not necessarily reflect the results that would have been obtained if the acquisition had actually occurred on the dates indicated or results that may be expected in the future.


	Three Months Ended February 28, 2005		Six Months Ended February 28, 2005
Revenues	$	2,222,893	$	3,970,159
Net income	$	111,066	$	146,631
Basic earnings per Limited Partner Unit	$	0.74	$	1.11

Diluted earnings per Limited Partner Unit	$	0.74	$	1.11

11. WORKING CAPITAL FACILITY AND LONG-TERM DEBT:

On November 23, 2005, the Partnership filed a registered exchange offer to exchange newly issued 5.65% Senior Notes due 2012 (the “2012 Notes”) which will be registered under the Securities Act of 1933 (the “New Notes”), for a like amount of outstanding 5.65% Senior Notes due 2012, which have not been registered under the Securities Act (the “Old Notes”). The sole purpose of the exchange offer is to fulfill the obligations of the Partnership under the registration rights agreement entered into in connection with the sale by the Partnership of the Old Notes on July 29, 2005. The 2012 Notes issued pursuant to the exchange offer will have substantially identical terms to the Old Notes. The 2012 Notes initially will be fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP that guarantee the Partnership’s obligations under its revolving credit facility. On February 23, 2006 the Partnership commenced the exchange offer which closed on March 31, 2006. All $400,000 of the unregistered 2012 Notes were tendered pursuant to the exchange offer and will be replaced with a like amount of registered notes.

On December 13, 2005 the Partnership entered into the ETP Revolving Credit Facility, a $900,000 five-year revolving credit facility available through December 10, 2010 which replaced its previous revolving credit facility. Amounts borrowed under the ETP Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The ETP Revolving Credit Facility also offers a Swingline loan option with a maximum borrowing of $50,000 at a daily rate based on LIBOR. The maximum commitment fee payable on the unused portion of the facility is 0.25%. The weighted average interest rate was 5.320% for the amount outstanding as of February 28, 2006 ($100,000). There was no amount outstanding under the Swingline option. The Partnership also had outstanding letters of credit of $9,935 under the ETP Revolving Credit Facility. Total amount available under the Credit Agreement as of February 28, 2006 was $790,065. The ETP Revolving Credit Facility, which is expandable to $1,000,000, is fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP that guarantee the Partnership’s obligations. The ETP Revolving Credit Facility is unsecured and has equal rights to holders of the Partnership’s other current and future unsecured debt.

A $75,000 Senior Revolving Working Capital Facility is available through December 31, 2006. Amounts borrowed under this Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 6.270% for the amount outstanding at February 28, 2006. The maximum commitment fee payable on the unused portion of the facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10,000 for a period of not less than 30 consecutive days at least one time during each fiscal year. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Working Capital Facility. As of February 28, 2006, the Senior Revolving Working Capital Facility had a balance outstanding of $21,198, all short-term. There were outstanding Letters of Credit for the Senior Revolving Working Capital Facility of $6,052 at February 28, 2006. Effective September 1, 2005, HOLP entered into the Second Amendment to the Third Amended and Restated Credit Agreement. The amendment states that in no event shall the Letter of Credit Exposure exceed $15,000 at any time. All of the remaining terms, provisions and conditions of the existing Credit Agreement continue in full force and effect as within the March 31, 2004 Third Amended and Restated Credit Amendment. Letter of Credit exposure plus the Working Capital Loan cannot exceed the $75,000 maximum Working Capital Facility.

Prior to February 28, 2006, HOLP also maintained a $75,000 Senior Revolving Acquisition Facility for acquisitions of propane-related businesses. Amounts borrowed under the Acquisition Credit Facility bore interest at a rate based on either a Eurodollar rate or a prime rate. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP and the capital stock of HOLP’s subsidiaries secured the Senior Revolving Acquisition Facility. As of February 28, 2006, HOLP paid in full the outstanding indebtedness under this facility and cancelled this facility.

12. COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL LIABILITIES:

Commitments

The Partnership has forward commodity contracts which will be settled by physical delivery. Short-term contracts, which expire in less than one year, require delivery of up to 600,687 MMBtu/d. Long-term contracts require delivery of up to 313,387 MMBtu/d and extend through July 2018.

The Partnership, in the normal course of business, purchases, processes, and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. The Partnership believes that such terms are commercially reasonable and will not have a material adverse effect on the Partnership’s financial position or results of operations. The Partnership has also entered into several propane purchase and supply commitments which are typically one-year agreements with varying terms as to quantities, prices, and expiration dates. The Partnership also has a long-term purchase contract for 100 million gallons of propane per year that contains a two-year cancellation provision.

Litigation

The Operating Partnerships may, from time to time, be involved in litigation and claims arising out of their respective operations in the normal course of business. Management is not aware of any material legal or governmental proceedings against ETC OLP or contemplated to be brought against ETC OLP, under the various environmental protection statutes to which it is subject. Propane is a flammable, combustible gas. Serious personal injury and significant property damage can arise in connection with its storage, transportation or use. In the ordinary course of business, HOLP is sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. The Partnership maintains liability insurance with insurers in amounts and with coverages and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect the Partnership and its Operating Partnerships from material expenses related to product liability, personal injury or property damage in the future. Although any litigation is inherently uncertain, based on past experience, the information currently available and the availability of insurance coverage, the Partnership does not believe that pending or threatened litigation matters will have a material adverse effect on its financial condition or results of operations.

At the time of the HPL acquisition, the HPL Entities, their parent companies and AEP, were engaged in ongoing litigation with Bank of America (“B of A”) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel Storage facility (“Cushion Gas”). This litigation is referred to as the “Cushion Gas Litigation”. Under the terms of the Purchase and Sale Agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory. 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.

The Partnership or its subsidiaries is a party to various legal proceedings and/or regulatory proceedings incidental to its business. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against the Partnership. In the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to

management’s estimate of the likely exposure. For matters that are covered by insurance, the Partnership accrues the related deductible. As of February 28, 2006 and August 31, 2005, an accrual of $2,823 and $1,120, respectively, was recorded as accrued and other current liabilities on the Partnership’s condensed consolidated balance sheet.

Environmental

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

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of the Partnership’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, the Partnership believes that such costs will not have a material adverse effect on its financial position. As of February 28, 2006 and August 31, 2005, an accrual on an undiscounted basis of $1,992 and $2,036, respectively, was recorded as accrued and other current liabilities and other non-current liabilities in the Partnership’s condensed consolidated balance sheets to cover environmental liabilities including certain matters assumed in connection with the HPL acquisition. A receivable of $392 and $404 was recorded on the Partnership’s condensed consolidated balance sheets as of February 28, 2006 and August 31, 2005, respectively, to account for a predecessor’s share of certain environmental liabilities.

13. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Accounting for Derivative Instruments and Hedging Activities

The Partnership applies Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) as amended. This statement requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at fair value. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.

The Partnership has established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability or anticipated transaction. At inception of a hedge, the Partnership formally documents the relationship between the hedging instrument and the hedged item, the risk management objectives, the methods used for assessing and testing effectiveness, and how any ineffectiveness will be measured and recorded. The Partnership also assesses, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in its hedging transactions are highly effective in offsetting changes in cash flows. Furthermore, management meets on a weekly basis to assess the creditworthiness of the derivative counterparties to manage against the risk of default. If the Partnership determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.

The market prices used to value the Partnership’s financial derivative transactions reflect management’s estimates considering various factors including closing exchange and over-the-counter quotations.

Non-trading Activities

The Partnership utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit its exposure to margin fluctuations in natural gas and NGL prices. These contracts consist primarily of futures and swaps and are recorded at fair value on the condensed consolidated balance sheet. If the Partnership designates a financial derivative instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in Accumulated Other Comprehensive Income (“OCI”) until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as cash flow hedges are included in cost of products sold in the period the hedged transactions occurs. Gains and losses deferred in OCI related to cash flow hedges remain in OCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For those financial derivative instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the condensed consolidated statement of operations. The Partnership reclassified into earnings gains of $142,989 and $41,675 for the three and six months ended February 28, 2006, respectively, and gains of $4,056 and losses of $10,731 for the three and six months ended February 28, 2005, respectively, related to commodity financial instruments that were previously reported in OCI.

In the course of normal operations, the Partnership routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs that qualify for and are designated as a normal purchase and sales contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for using accrual accounting. In connection with the HPL acquisition, the Partnership acquired certain physical forward contracts that contain embedded options. These contracts have not been designated as normal purchases and sales contracts, and therefore, are marked to market in addition to the financial options that offset them. The Black Scholes valuation model was used to estimate the value of these embedded derivatives.

Trading Activities

The Partnership has a risk management policy that governs its marketing and trading operations. These activities are monitored independently by the Partnership’s risk management function and must take place within predefined limits and authorizations. Certain strategies are considered trading for accounting purposes and are executed with the use of a combination of financial instruments including, but not limited to, basis contracts and gas daily contracts. The Partnership accounts for its trading activities under the provisions of EITF Issue No. 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (“EITF 02-3”), which requires revenue and costs related to energy trading contracts to be presented on a net basis in the income statement. The derivative contracts that are entered into for trading purposes, subject to limits, are recognized on the condensed consolidated balance sheet at fair value, and changes in the fair value of these derivative instruments are recognized in midstream and transportation and storage revenue in the condensed consolidated statement of operations. Gains and losses associated with trading activities for the three and six months ended February 28, 2006 were losses of $2,743 and gains of $49,837, respectively, including unrealized losses of $25,530 and $19,117, respectively. There were no trading activities during the three or six months ended February 28, 2005.

The following table details the outstanding commodity-related derivatives as of February 28, 2006 and August 31, 2005, respectively:


February 28, 2006:	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Mark to Market Derivatives

(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(10,194,105	)	2006-2009	$	(10,038	)

Swing Swaps IFERC	Gas	(66,692,579	)	2006-2008	$	3,391

Fixed Swaps/Futures	Gas	750,000		2006-2007	$	50,391

Options	Gas	(1,392,000	)	2006-2008	$	27,324

Forward Physical Contracts	Gas	(12,632,000	)	2006-2008	$	(27,324	)

(Trading)
Basis Swaps IFERC/NYMEX	Gas	4,657,500		2006-2007	$	28,650

Swing Swaps IFERC	Gas	775,000		2006	$	(425	)

Forward Physical Contracts	Gas	(678,900	)	2006	$	(191	)

Cash Flow Hedging Derivatives

(Non-Trading)
Fixed Swaps/Futures	Gas	(17,552,500	)	2006-2007	$	23,237

Fixed Index Swaps	Gas	1,090,000		2006	$	2,092

Basis Swaps IFERC/NYMEX	Gas	(14,155,000	)	2006-2007	$	2,665

August 31, 2005:
Mark to Market Derivatives

(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(34,196,114	)	2005-2007	$	646

Swing Swaps IFERC	Gas	(25,636,504	)	2005-2006	$	(6,400	)

Fixed Swaps/Futures	Gas	(1,960,000	)	2005-2006	$	(7,423	)

Options	Gas	(1,776,000	)	2005-2008	$	78,941

Forward Physical Contracts	Gas	(21,340,000	)	2005-2008	$	(78,941	)

(Trading)
Basis Swaps IFERC/NYMEX	Gas	(55,772,500	)	2005-2007	$	49,833

Swing Swaps IFERC	Gas	(42,204,999	)	2005-2008	$	(3,686	)

Fixed Swaps/Futures	Gas	(150,000	)	2005	$	559

Forward Physical Contracts	Gas	—		2005	$	441

Cash Flow Hedging Derivatives

Fixed Swaps/Futures	Gas	(41,827,500	)	2005-2007	$	(141,142	)

Fixed Index Swaps	Gas	5,910,000		2005-2006	$	36,455

Basis Swaps IFERC/NYMEX	Gas	(6,877,500	)	2005-2006	$	3,361

The Partnership expects gains of $26,951 to be reclassified into earnings over the next twelve months related to income currently reported in OCI. The amount ultimately realized, however, will differ as commodity prices change. The majority of the Partnership’s derivatives are expected to settle within the next two years.

Estimates related to the Partnership’s gas marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. The Partnership also attempts to maintain balanced positions in its non-trading 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, will provide the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, will be offset with financial contracts to balance the Partnership’s positions. To the extent open commodity positions exist, fluctuating commodity prices can impact the Partnership’s financial results and financial position, either favorably or unfavorably.

During the three months ended February 28, 2006 the Partnership discontinued application of hedge accounting in connection with certain derivative financial instruments that were qualified for and designated as cash flow hedges related to forecasted sales of natural gas stored in the Partnership’s Bammel storage facilities. The discontinuation resulted from management’s determination that the originally forecasted sales of natural gas from the storage facilities were no longer probable of occurring by the end of the originally specified time period, or within an additional two-month period of time thereafter. The determination was made principally due to the unseasonably warm weather that occurred during February 2006 through March 2006 and the Partnership’s flexibility to make changes to the underlying injection and withdrawal schedule for its storage assets, given changes in market conditions. One of the key criteria to achieve hedge accounting under SFAS 133 is that the forecasted transaction be probable of occurring as originally set forth in the hedge documentation. As a result, during the three months ended February 28, 2006, the Partnership recognized previously deferred unrealized gains related to February 2006 and March 2006 of $84,680 from the discontinued application of hedge accounting, which is included in the $142,989 and $41,675 reclassified into earnings from OCI during the three and six months ended February 28, 2006, respectively. The Partnership classified the $84,680 as costs of products sold in its consolidated statements of operations.

Interest Rate Risk

The Partnership is exposed to market risk for changes in interest rates related to its bank credit facilities. The Partnership manages a portion of its interest rate exposures by utilizing interest rate swaps and similar arrangements which allow the Partnership to effectively convert a portion of variable rate debt into fixed rate debt.

Treasury locks with a notional amount of $200,000 were entered into and outstanding as of February 28, 2006 and had a fair value of $4,812 which was recorded as unrealized gains in OCI and a component of price risk management assets in the condensed consolidated balance sheet. The outstanding treasury locks as of February 28, 2006 were entered into in anticipation of a bond offering to occur in fiscal year 2006. Nominal gains and losses were reclassified into earnings previously reported in OCI during the three and six months ended February 28, 2006 and the three and six months ended February 28, 2005 related to treasury locks. Gains of $756 were reclassified into earnings previously reported in OCI during the six months ended February 28, 2006.

ETC OLP also had a treasury lock with a notional amount of $75,000 that matured in October 2005. As of August 31, 2005, the treasury lock had a fair value of $151. Under the terms of the lock agreement, the Partnership paid a fixed rate of 2.76% and received three-month LIBOR with a quarterly settlement. The treasury lock was not accounted for as a hedge but received mark to market accounting. Accordingly, changes in the fair value are recorded as a component of interest expense in the condensed consolidated statement of operations.

The following represents gains (losses) on derivative activity for the periods presented:


	Three Months Ended						Six Months Ended
	February 28, 2006			February 28, 2005			February 28, 2006			February 28, 2005
*Commodity-related*
Unrealized gains (losses) recognized in revenues and cost of products sold related to Partnership’s derivative activity, excluding ineffectiveness	$	(35,744	)	$	4,608		$	37,809		$	11,647
Ineffective portion of derivatives qualifying for hedge accounting	$	35,645		$	440		$	17,323		$	(14,902	)
Realized gains included in revenues and cost of products sold	$	109,748		$	19,124		$	100,455		$	31,660
*Interest rate swaps*
Unrealized gains (losses) on interest rate swap included in interest expense	$	—		$	359		$	(151	)	$	861
Ineffective portion of derivatives qualifying for hedge accounting	$	—		$	—		$	771		$	—
Realized gains (losses) on interest rate swap included in interest expense	$	(8	)	$	(131	)	$	135		$	(364	)

14. QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH:

On October 14, 2005, the Partnership paid a quarterly distribution of $0.50 per unit, or $2.00 per unit annually, to the Unitholders of record at the close of business on September 30, 2005. On January 13, 2006, the Partnership paid a quarterly distribution of $0.55 per unit, or $2.20 per unit annually to Unitholders of record at the close of business on January 4, 2006. On March 7, 2006, the Partnership declared a cash distribution for the second quarter ended February 28, 2006 of $0.5875 per Common Unit, or $2.35 per unit annually, an increase of $0.15 per Common Unit on an annualized basis. The distribution is payable on April 14, 2006 to Unitholders of record at the close of business on March 24, 2006. In addition to these quarterly distributions, the General Partner, Energy Transfer Partners, GP, L.P. (“ETP GP”), received quarterly distributions for its general partner interest in the Partnership and incentive distributions to the extent the quarterly distribution exceeded $0.275 per unit. The total amount of distributions declared relating to the six months ended February 28, 2006 on Common Units, the Class F Units, the Class E Units, the General Partner interests and the Incentive Distribution Rights totaled $122,325, $1,510, $6,242, $3,486, and $40,767, respectively. All such distributions were made from Available Cash from Operating Surplus.

15. PARTNERS’ CAPITAL:

Pursuant to its general partner authority, the Partnership’s General Partner amended the Amended and Restated Agreement of Limited Partnership of ETP on February 6, 2006, to create a new class of limited partner interests titled Class F Units. The terms and provisions of the Class F Units provide that they may be converted to Common Units upon the approval of a majority of the votes cast by the holders of the Partnership’s Common Units provided that the total votes cast by such holders represent a majority of the Common Units entitled to vote. Prior to conversion of the Class F Units, the Class F Units will share in Partnership distributions and will be entitled to all items of Partnership income, gain, loss, deduction and credit as if the Class F Units were Subordinated Units. Upon receiving the requisite approval by the Partnership’s common unitholders under a proposal to convert the Class F Units to Common Units, all Class F Units shall convert to Common Units on a one-for-one basis. In the event the Class F Units are not converted to Common Units within six months of their issuance, the Class F Units will be entitled to share in Partnership distributions based on 115% of the amount of any Partnership distribution to each Common Unit, and the right to receive distributions shall have the same order of priority relative to distributions on the Common Units.

On February 8, 2006, the Partnership sold and issued 1,069,850 Common Units and 2,570,150 Class F Units representing limited partnership interests in the Partnership, to Energy Transfer Equity, L.P., (“ETE”). ETE owns 100% of the 2% general partner interests in ETP GP and 50% of the incentive distribution rights in the Partnership (which it holds through its ownership interests in ETP GP). The price paid for each of the Common Units and Class F Units was equal to $36.37 per unit, the New York Stock Exchange closing price of the Partnership’s Common Units on February 8, 2006. The Common Units and Class F Units were issued to ETE in a private placement that is exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended. Of the aggregate proceeds of $132,387 from the sale, $75,000 was used to extinguish the HOLP Senior Revolving Acquisition Facility, to pay down the HOLP Senior Revolving Working Capital Facility, and for HOLP general operating purposes. The remaining balance of $57,387 from the proceeds was used to pay down existing debt on the ETP Revolving Credit Facility and for general Partnership operating purposes.

16. INCOME TAXES:

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

The Partnership is generally not subject to income tax. It is, however, subject to a statutory requirement that its non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of its total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of the Partnership’s non-qualifying income exceeds this statutory limit, the Partnership would be taxed as a corporation. Accordingly, certain activities that generate non-qualified income are conducted through taxable corporate subsidiaries (“C corporations”). These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the periods ended February 28, 2006 and 2005, the Partnership’s non-qualifying income did not exceed the statutory limit.

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

The difference between the statutory rate and the effective rate is summarized as follows:


	Three Months Ended				Six Months Ended
	February 28, 2006		February 28, 2005		February 28, 2006		February 28, 2005
Federal statutory tax rate	35.0	%	35.0	%	35.0	%	35.0	%
State income tax rate net of federal benefit	3.4	%	3.6	%	3.4	%	3.7	%
Partnership earnings not subject to tax at the Partnership level	(36.8	)%	(35.1	)%	(31.8	)%	(35.2	)%

Effective tax rate	1.6	%	3.5	%	6.6	%	3.5	%

Income tax expense consists of the following current and deferred amounts:


	Three Months Ended						Six Months Ended
	February 28, 2006			February 28, 2005			February 28, 2006			February 28, 2005
Current income tax expense (benefit):
Federal	$	12,853		$	(25	)	$	28,117		$	2,134
State		950			(42	)		1,288			342
Deferred income tax expense (benefit):
Federal		(9,288	)		2,713			(2,625	)		1,379
State		(501	)		481			(355	)		304

Total	$	4,014		$	3,127		$	26,425		$	4,159

17. RELATED PARTY TRANSACTIONS:

Accounts receivable from related parties consisted of the following for the periods presented:


	February 28, 2006		August 31, 2005
ETP GP – capital contribution	$	—	$	2,098
Joint venture propane operation		481		689
Other		243		1,692

Total	$	724	$	4,479

Accounts payable to related parties consisted of the following for the periods presented:


	February 28, 2006		August 31, 2005
ETE	$	393	$	746
Other		17		327

Total	$	410	$	1,073

As of February 28, 2006 and August 31, 2005, the Partnership had a note payable of $0 and $2,062, respectively, related to its contribution in a propane joint venture entered into July 2005 in which it owns a 50% interest. The note bears interest at an annual rate equal to the one month LIBOR rate plus 150 basis points, compounded monthly.

On February 2, 2006 the Partnership entered into a shared services agreement in conjunction with the initial public offering of ETE. Under the terms of the shared services agreement, ETE will pay the Partnership an annual administrative fee of $500 for the provision of various general and administrative services for ETE’s benefit. The administrative fee may increase in the second and third years by the greater of 5% or the percentage increase in the consumer price index and may also increase if ETE makes an acquisition that requires an increase in the level of general and administrative services that ETE receives from its general partner or its affiliates. Fees recognized during the three months ended February 28, 2006 were nominal.

The Partnership’s natural gas midstream and transportation and storage operations secure compression services from various third parties including Energy Transfer Technologies, Ltd. Energy Transfer Group, LLC is the general partner of Energy Transfer Technologies, Ltd. These entities are collectively referred to as the “ETG Entities”. The Partnership’s Co-Chief Executive Officers have an indirect ownership in the ETG Entities. In addition, two of the General Partner’s directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of independent directors of the General Partner, no less favorable than those available from other providers of compression services. For the six months ended February 28, 2006 and 2005, payments totaling $2,485 and $596, respectively, were made to the ETG Entities for compression services provided to and utilized in the Partnership’s natural gas midstream and transportation and storage operations.

18. SUMMARIZED CONDENSED CONSOLIDATING FINANCIAL STATEMENTS:

The Partnership’s ETP Revolving Credit Facility and Senior Notes are fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP (the “Subsidiary Guarantors”). HOLP and its direct and indirect subsidiaries and Heritage Holdings, Inc. do not guarantee the Partnership’s Revolving Credit Facility and Senior Notes. The Subsidiary Guarantors jointly and severally guarantee, on an unsecured senior basis, the Partnership’s obligations under the Partnership’s Revolving Credit Facility and Senior Notes. Following are unaudited condensed consolidating financial information of the Partnership, the Subsidiary Guarantors, the Non-Guarantor Subsidiaries and the Partnership on a consolidated basis. The condensed consolidating financial information presented herein complies with Rule 3-10 of Regulation S-X, is prepared on the equity method, and does not contain related financial statement disclosures that would be required with a complete set of financial statements presented in conformity with accounting principles generally accepted in the United States of America.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

As of February 28, 2006

(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,213	$	—	$	31,630	$	—		$	33,843
Marketable securities		—		—		3,575		—			3,575
Accounts receivable, net of allowance for doubtful accounts		—		696,099		125,664		—			821,763
Accounts receivable from related parties		65		63,486		2,076		(64,903	)		724
Inventories		—		179,302		59,485		—			238,787
Price risk management assets		4,812		61,095		—		—			65,907
Exchanges receivable		—		18,892		—		—			18,892
Prepaid expenses and other assets		791		70,405		8,058		—			79,254

Total current assets		7,881		1,089,279		230,488		(64,903	)		1,262,745

PROPERTY, PLANT AND EQUIPMENT, net		9		2,153,881		512,589		—			2,666,479
LONG-TERM PRICE RISK MANAGEMENT ASSETS		—		9,043		—		—			9,043
INVESTMENT IN AFFILIATES		3,242,852		32,534		137,890		(3,376,141	)		37,135
GOODWILL		—		23,736		301,357		—			325,093
INTANGIBLES AND OTHER ASSETS, net		13,289		2,861		96,783		—			112,933

Total assets	$	3,264,031	$	3,311,334	$	1,279,107	$	(3,441,044	)	$	4,413,428

LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Working capital facility	$	—	$	—	$	21,198	$	—		$	21,198
Accounts payable		246		595,248		79,145		—			674,639
Accounts payable to related parties		60,263		4,640		410		(64,903	)		410
Customer deposits		—		5,947		2,517		—			8,464
Price risk management liabilities		—		41,374		—		—			41,374
Accrued and other current liabilities		8,742		81,686		57,387		—			147,815
Income taxes payable		—		18,525		5,065		—			23,590
Deferred income taxes		—		2,157		—		—			2,157
Current maturities of long-term debt		—		—		39,673		—			39,673

Total current liabilities		69,251		749,577		205,395		(64,903	)		959,320

LONG-TERM DEBT, less current maturities		1,247,543		—		270,181		—			1,517,724
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		—		1,021		—		—			1,021
NON-CURRENT DEFERRED INCOME TAXES		—		52,378		56,607		—			108,985
OTHER NONCURRENT LIABILITIES		—		10,356		—		—			10,356
MINORITY INTERESTS		—		—		2,074		—			2,074

Total liabilities		1,316,794		813,332		534,257		(64,903	)		2,599,480

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL		1,947,237		2,498,002		744,850		(3,376,141	)		1,813,948

Total liabilities and partners’ capital	$	3,264,031	$	3,311,334	$	1,279,107	$	(3,441,044	)	$	4,413,428

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

As of August 31, 2005

(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	3,810	$	38	$	21,066		$	—		$	24,914
Marketable securities		—		—		3,452			—			3,452
Accounts receivable, net of allowance for doubtful accounts		—		782,090		64,938			—			847,028
Accounts receivable from related parties		99,833		12,515		1,858			(109,727	)		4,479
Inventories		—		225,325		77,568			—			302,893
Exchanges receivable		—		35,623		—			—			35,623
Price risk management assets		—		138,961		—			—			138,961
Prepaid expenses and other assets		917		91,925		7,828			—			100,670

Total current assets		104,560		1,286,477		176,710			(109,727	)		1,458,020

PROPERTY, PLANT AND EQUIPMENT, net		9		1,938,160		502,396			—			2,440,565
LONG-TERM PRICE RISK MANAGEMENT ASSETS		—		41,687		—			—			41,687
INVESTMENT IN AFFILIATES		2,718,945		32,601		144,283			(2,858,476	)		37,353
GOODWILL		—		23,736		300,283			—			324,019
INTANGIBLES AND OTHER ASSETS, net		13,057		14,412		97,793			—			125,262

Total assets	$	2,836,571	$	3,337,073	$	1,221,465		$	(2,968,203	)	$	4,426,906

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Working capital facility	$	—	$	—	$	17,026		$	—		$	17,026
Accounts payable		2,181		764,590		52,004			—			818,775
Accounts payable to related parties		9,461		100,865		474			(109,727	)		1,073
Customer deposits		—		85,527		2,511			—			88,038
Price risk management liabilities		2,156		102,616		—			—			104,772
Income taxes payable		—		2,148		(85	)		—			2,063
Accrued and other current liabilities		8,618		80,174		90,986			—			179,778
Current maturities of long-term debt		—		—		39,349			—			39,349

Total current liabilities		22,416		1,135,920		202,265			(109,727	)		1,250,874

LONG-TERM DEBT, less current maturities		1,348,432		—		327,273			—			1,675,705
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		—		30,517		—			—			30,517
LONG-TERM AFFILIATED PAYABLE		—		—		2,005			—			2,005
NONCURRENT DEFERRED INCOME TAXES		—		52,854		58,331			—			111,185
MINORITY INTERESTS		—		15,319		1,825			—			17,144
OTHER NONCURRENT LIABILITIES		—		13,284		—			—			13,284

Total liabilities		1,370,848		1,247,894		591,699			(109,727	)		3,100,714

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL		1,465,723		2,089,179		629,766			(2,858,476	)		1,326,192

Total liabilities and partners’ capital	$	2,836,571	$	3,337,073	$	1,221,465		$	(2,968,203	)	$	4,426,906

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended February 28, 2006

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES:
Midstream and transportation and storage	$	—		$	2,083,303		$	—		$	—		$	2,083,303
Propane and other		—			—			366,513			—			366,513

Total revenue		—			2,083,303			366,513			—			2,449,816

COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage		—			1,785,053			—			—			1,785,053
Cost of products sold, propane and other		—			—			223,778			—			223,778
Operating expenses		—			48,913			50,783			—			99,696
Depreciation and amortization		—			14,942			14,072			—			29,014
Selling, general and administrative		6,200			19,382			5,873			—			31,455

Total costs and expenses		6,200			1,868,290			294,506			—			2,168,996

OPERATING INCOME (LOSS)		(6,200	)		215,013			72,007			—			280,820

OTHER INCOME (EXPENSE):
Interest expense		(22,464	)		(1,872	)		(8,052	)		3,846			(28,542	)
Equity in earnings (losses) of affiliates		275,770			234			(128	)		(275,770	)		106
Gain on disposal of assets		—			584			78			—			662
Interest income and other, net		3,679			2,536			(67	)		(3,846	)		2,302

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS		250,785			216,495			63,838			(275,770	)		255,348

Income tax expense		—			1,101			2,913			—			4,014

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS		250,785			215,394			60,925			(275,770	)		251,334

Minority interests		—			—			(549	)		—			(549	)

NET INCOME	$	250,785		$	215,394		$	60,376		$	(275,770	)	$	250,785

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended February 28, 2005

(see Note 2)

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES:
Midstream and transportation and storage	$	—		$	1,130,526		$	—		$	—		$	1,130,526
Propane and other		39			—			309,279			—			309,318

Total revenue		39			1,130,526			309,279			—			1,439,844

COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage		—			1,028,558			—			—			1,028,558
Cost of products sold, propane and other		—			—			182,617			—			182,617
Operating expenses		—			26,200			47,351			—			73,551
Depreciation and amortization		—			8,718			13,514			—			22,232
Selling, general and administrative		1,503			6,858			3,552			—			11,913

Total costs and expenses		1,503			1,070,334			247,034			—			1,318,871

OPERATING INCOME (LOSS)		(1,464	)		60,192			62,245			—			120,973

OTHER INCOME (EXPENSE):
Interest expense		(8,537	)		(7,077	)		(7,916	)		506			(23,024	)
Equity in earnings of affiliates		97,624			34			75			(97,624	)		109
Loss on disposal of assets		—			(5	)		(431	)		—			(436	)
Loss on extinguishment of debt		—			(7,996	)		—			—			(7,996	)
Interest income and other, net		(22	)		854			(91	)		(506	)		235

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS		87,601			46,002			53,882			(97,624	)		89,861

Income tax expense		—			249			2,878			—			3,127

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS		87,601			45,753			51,004			(97,624	)		86,734

Minority interests		—			(113	)		(245	)		—			(358	)

INCOME FROM CONTINUING OPERATIONS		87,601			45,640			50,759			(97,624	)		86,376

INCOME FROM DISCONTINUED OPERATIONS		—			1,225			—			—			1,225

NET INCOME	$	87,601		$	46,865		$	50,759		$	(97,624	)	$	87,601

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the six months ended February 28, 2006

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES:
Midstream and transportation and storage	$	—		$	4,291,837		$	—		$	—		$	4,291,837
Propane and other		—			—			574,599			—			574,599

Total revenue		—			4,291,837			574,599			—			4,866,436

COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage		—			3,744,422			—			—			3,744,422
Cost of products sold, propane and other		—			—			355,036			—			355,036
Operating expenses		—			102,590			99,777			—			202,367
Depreciation and amortization		—			28,361			27,566			—			55,927
Selling, general and administrative		9,020			38,169			9,065			—			56,254

Total costs and expenses		9,020			3,913,542			491,444			—			4,414,006

OPERATING INCOME (LOSS)		(9,020	)		378,295			83,155			—			452,430

OTHER INCOME (EXPENSE):
Interest expense		(43,068	)		(4,192	)		(15,782	)		6,107			(56,935	)
Equity in earnings (losses) of affiliates		417,091			(17	)		(151	)		(417,091	)		(168	)
Gain (loss) on disposal of assets		—			594			(60	)		—			534
Interest income and other, net		5,590			3,938			(160	)		(6,107	)		3,261

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS		370,593			378,618			67,002			(417,091	)		399,122

Income tax expense		—			20,106			6,319			—			26,425

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS		370,593			358,512			60,683			(417,091	)		372,697

Minority interests		—			(1,349	)		(755	)		—			(2,104	)

NET INCOME	$	370,593		$	357,163		$	59,928		$	(417,091	)	$	370,593

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the six months ended February 28, 2005

(see Note 2)

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES:
Midstream and transportation and storage	$	—		$	1,824,213		$	—		$	—		$	1,824,213
Propane and other		39			—			479,790			—			479,829

Total revenue		39			1,824,213			479,790			—			2,304,042

COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage		—			1,650,473			—			—			1,650,473
Cost of products sold, propane and other		—			—			288,606			—			288,606
Operating expenses		—			42,293			91,458			—			133,751
Depreciation and amortization		—			15,054			26,839			—			41,893
Selling, general and administrative		2,617			13,437			6,583			—			22,637

Total costs and expenses		2,617			1,721,257			413,486			—			2,137,360

OPERATING INCOME (LOSS)		(2,578	)		102,956			66,304			—			166,682

OTHER INCOME (EXPENSE):
Interest expense		(9,498	)		(16,780	)		(15,544	)		1,467			(40,355	)
Equity in earnings of affiliates		130,287			48			97			(130,287	)		145
Loss on disposal of assets		—			(22	)		(505	)		—			(527	)
Loss on extinguishment of debt		—			(7,996	)		—			—			(7,996	)
Interest income and other, net		—			2,048			(212	)		(1,467	)		369

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSES AND MINORITY INTERESTS		118,211			80,254			50,140			(130,287	)		118,318

Income tax expense		—			192			3,967			—			4,159

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS		118,211			80,062			46,173			(130,287	)		114,159

Minority interests		—			(113	)		(403	)		—			(516	)

INCOME FROM CONTINUING OPERATIONS		118,211			79,949			45,770			(130,287	)		113,643

INCOME FROM DISCONTINUED OPERATIONS		—			4,568			—			—			4,568

NET INCOME	$	118,211		$	84,517		$	45,770		$	(130,287	)	$	118,211

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the six months ended February 28, 2006

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	(49,672	)	$	446,704		$	41,026		$	—		$	438,058

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		—			(17,124	)		(12,822	)		—			(29,946	)
Working capital settlement on prior year acquisitions		—			19,653			—			—			19,653
Capital invested in subsidiaries		(132,387	)		—			—			132,387			—
Capital expenditures		—			(229,751	)		(25,350	)		—			(255,101	)
Proceeds from the sale of assets		—			2,412			1,463			—			3,875

Net cash used in investing activities		(132,387	)		(224,810	)		(36,709	)		132,387			(261,519	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		824,192			—			188,996			—			1,013,188
Proceeds from short term borrowings from affiliates		883,307			729,390			—			(1,612,697	)		—
Principal payments on debt		(925,192	)		—			(243,130	)		—			(1,168,322	)
Principal payments received from affiliates		(729,390	)		(883,307	)		—			1,612,697			—
Distributions to parent		(4,193	)		(125,402	)		(18,812	)		148,407			—
Distribution from subsidiaries		144,214			—			4,193			(148,407	)		—
Debt issuance costs		(1,196	)		—			—			—			(1,196	)
Equity offering		132,387			—			—			—			132,387
Capital contribution from general partner		2,702			57,387			75,000			(132,387	)		2,702
Unit distributions		(146,369	)		—			—			—			(146,369	)

Net cash provided by (used in) financing activities		180,462			(221,932	)		6,247			(132,387	)		(167,610	)

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,597	)		(38	)		10,564			—			8,929

CASH AND CASH EQUIVALENTS, beginning of period		3,810			38			21,066			—			24,914

CASH AND CASH EQUIVALENTS, end of period	$	2,213		$	—		$	31,630		$	—		$	33,843

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the six months ended February 28, 2005

(see Note 2)

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	(12,387	)	$	146,361		$	22,602		$	—		$	156,576

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		—			(1,102,367	)		(10,703	)		—			(1,113,070	)
Cash invested in subsidiaries		(1,613,195	)		(51	)		—			1,613,195			(51	)
Capital expenditures		—			(50,186	)		(25,041	)		—			(75,227	)
Proceeds from the sale of assets		—			23			2,631			—			2,654

Net cash used in investing activities		(1,613,195	)		(1,152,581	)		(33,113	)		1,613,195			(1,185,694	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,392,001			80,000			109,529			—			1,581,530
Principal payments on debt		(239,000	)		(805,000	)		(83,610	)		95,000			(1,032,610	)
Proceeds from short term borrowings from affiliates		—			174,624			—			—			174,624
Advances from (to) related parties		83,649			(83,649	)		—			—			—
Principal payments received from affiliates		—			95,000			—			(95,000	)		—
Net proceeds from issuance of common units		169,807			—			—			—			169,807
Proceeds from subscribed units		180,000			—			—			—			180,000
Capital contributions		3,520			1,613,195			—			(1,613,195	)		3,520
Distributions to parent		—			(116,703	)		(13,304	)		130,007			—
Distributions from subsidiaries		130,007			—			—			(130,007	)		—
Debt issuance costs		(12,546	)		(3,109	)		—			—			(15,655	)
Unit distributions		(86,533	)		—			—			—			(86,533	)

Net cash provided by financing activities		1,620,905			954,358			12,615			(1,613,195	)		974,683

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(4,677	)		(51,862	)		2,104			—			(54,435	)

CASH AND CASH EQUIVALENTS, beginning of period		9,506			52,054			20,185			—			81,745

CASH AND CASH EQUIVALENTS, end of period	$	4,829		$	192		$	22,289		$	—		$	27,310

19. REPORTABLE SEGMENTS:

The Partnership’s financial statements reflect four reportable segments: ETC OLP’s midstream and transportation and storage operations and HOLP’s retail and wholesale propane operations, including the operations of MP Energy Partnership. Segments below the quantitative thresholds are classified as “other”. None of these segments have ever met any of the quantitative thresholds for determining reportable segments.

Midstream and transportation and storage segment revenues and expenses include intersegment transactions, which are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions. Certain overhead costs relating to a reportable segment have been allocated for purposes of calculating operating income.

The midstream operations focus on the gathering, compression, treating, processing, transportation and marketing of natural gas, primarily on or through the Southeast Texas System, and marketing operations related to our producer services business. Revenue is primarily generated by the volumes of natural gas gathered, compressed, treated, processed, transported, purchased and sold through the Partnership’s pipelines (excluding the transportation pipelines) and gathering systems as well as the level of natural gas and NGL prices. The transportation and storage operations focus on transporting natural gas through the Partnership’s Oasis Pipeline, ET Fuel System, East Texas Pipeline System, and HPL System. Revenue is typically generated from fees charged to customers to reserve firm capacity on or move gas through the pipeline on an interruptible basis. A monetary fee and/or fuel retention are also components of the fee structure. Excess fuel retained after consumption is typically valued at the first of the month published market prices and strategically sold when market prices are favorable. The transportation and storage operations also consist of the HPL System which generates its revenue primarily from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies. The use of the Bammel storage reservoir allows the Partnership to purchase physical natural gas and then sell financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin. The HPL System also transports natural gas for a variety of third party customers. Investment in affiliates relates primarily to the Partnership’s investment in Mid Texas Pipeline System which is included in our transportation and storage segment.

The Partnership’s retail and wholesale propane segments sell products and services to retail and wholesale customers. Intersegment sales by the foreign wholesale operations to the retail propane operations are priced in accordance with the partnership agreement of MP Energy Partnership. The Partnership manages its propane segments separately as each segment involves different distribution, sale, and marketing strategies.

The Partnership evaluates the performance of its operating segments based on operating income exclusive of certain general Partnership selling, general, and administrative expenses, gain (loss) on disposal of assets, minority interests, interest expense, earnings (losses) from equity investments and income tax expense (benefit).

The following table presents the unaudited financial information by segment for the following periods:


	Three Months Ended		Six Months Ended
	February 28, 2006	February 28, 2005	February 28, 2006	February 28, 2005
Volumes:
Midstream
Natural gas MMBtu/d	1,529,856	1,411,800	1,528,616	1,313,254
NGLs Bbls/d	9,537	16,261	9,879	12,931
Transportation and storage
Natural gas MMBtu/d – sold	1,868,486	2,039,179	1,709,049	2,039,179
Natural gas MMBtu/d – transported	4,231,797	3,045,656	4,349,137	3,078,193

Propane gallons sold (in thousands)
Retail	165,758	165,696	254,496	252,131
Wholesale	28,243	25,708	47,844	44,017

Total gallons	194,001	191,404	302,340	296,148


	Three Months Ended						Six Months Ended
	February 28, 2006			February 28, 2005			February 28, 2006			February 28, 2005
Revenues:
Midstream	$	1,205,027		$	781,190		$	2,754,855		$	1,431,802
Eliminations		(611,989	)		(35,390	)		(1,518,793	)		(49,932	)
Transportation and storage		1,490,265			384,726			3,055,775			442,343
Retail propane and other propane related		332,147			284,309			514,178			435,074
Wholesale propane		32,958			23,733			56,899			42,218
Other		1,408			1,276			3,522			2,537

Total	$	2,449,816		$	1,439,844		$	4,866,436		$	2,304,042

Cost of Sales:
Midstream	$	1,160,557		$	739,165		$	2,597,427		$	1,369,600
Eliminations		(611,989	)		(35,390	)		(1,518,793	)		(49,932	)
Transportation and storage		1,236,485			324,783			2,665,788			330,805
Retail propane and other propane related		193,845			160,111			302,315			248,250
Wholesale propane		29,426			22,134			51,711			39,627
Other		507			372			1,010			729

Total	$	2,008,831		$	1,211,175		$	4,099,458		$	1,939,079

Operating Expenses:
Midstream	$	7,104		$	5,551		$	14,342		$	9,467
Transportation and storage		41,809			20,649			88,249			32,827
Retail propane and other propane related		49,004			45,670			96,087			88,200
Wholesale propane		916			852			1,603			1,545
Other		863			829			2,086			1,712

Total	$	99,696		$	73,551		$	202,367		$	133,751

Depreciation and Amortization:
Midstream	$	3,880		$	2,871		$	7,565		$	5,765
Transportation and storage		11,061			5,847			20,795			9,290
Retail propane and other propane related		13,744			13,222			26,954			26,283
Wholesale propane		223			195			407			364
Other		106			97			206			191

Total	$	29,014		$	22,232		$	55,927		$	41,893

Operating Income:
Midstream	$	26,856		$	31,453		$	120,864		$	41,457
Transportation and storage		188,158			28,736			257,431			61,498
Retail propane and other propane related		70,255			62,283			80,734			66,632
Wholesale propane		1,825			23			2,207			(193	)
Other		(68	)		(22	)		220			(95	)
Selling general and administrative expenses not allocated to segments		(6,206	)		(1,500	)		(9,026	)		(2,617	)

Total	$	280,820		$	120,973		$	452,430		$	166,682

Other items not allocated by segment:
Interest expense		(28,542	)		(23,024	)		(56,935	)		(40,355	)
Equity in earnings (losses) of affiliates		106			109			(168	)		145
Gain (loss) on disposal of assets		662			(436	)		534			(527	)
Loss on extinguishment of debt		—			(7,996	)		—			(7,996	)
Interest income and other, net		2,302			235			3,261			369
Minority interests		(549	)		(358	)		(2,104	)		(516	)
Income tax expense		(4,014	)		(3,127	)		(26,425	)		(4,159	)

		(30,035	)		(34,597	)		(81,837	)		(53,039	)

Income from Continuing Operations	$	250,785		$	86,376		$	370,593		$	113,643


	Six Months Ended
	February 28, 2006		February 28, 2005
Additions to Property, Plant and Equipment Including Acquisitions:
Midstream	$	10,245	$	76,476
Transportation and storage		235,391		865,189
Retail propane and other propane related		32,554		33,287
Wholesale propane		298		170
Other		1,973		2,968

Total	$	280,461	$	978,090


	February 28, 2006		August 31, 2005
Total Assets:
Midstream	$	813,651	$	1,024,778
Transportation and storage		2,434,381		2,289,992
Retail propane and other propane related		1,065,735		1,016,313
Wholesale propane		27,420		34,755
Other		72,241		61,068

Total	$	4,413,428	$	4,426,906

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

The following is a discussion of the historical financial condition and results of operations of the Partnership and its subsidiaries, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K and Form 10-K/A for the fiscal year ended August 31, 2005 filed with the Securities and Exchange Commission on November 14, 2005 and December 12, 2005, respectively.

Overview

Midstream and transportation and storage segments

Our midstream and transportation and storage segments are operated by ETC OLP. We own and operate approximately 11,700 miles of natural gas gathering and transportation pipelines, three natural gas processing plants, two of which are currently connected to our gathering systems, fourteen natural gas treating facilities and three natural gas storage facilities.

Midstream segment

Our midstream segment focuses on the transportation, gathering, compression, treating, processing and marketing of natural gas. Our operations are currently concentrated in the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas, the Barnett Shale in north Texas and the Bossier Sands in east Texas. We also conduct marketing operations through our producer services business.

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

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

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

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

Transportation and storage segment

Our transportation and storage segment focuses on the transportation of natural gas through the following pipeline systems:

•

Oasis Pipeline. The Oasis Pipeline is a 583-mile natural gas pipeline that directly connects the Waha Hub, a major natural gas trading center located in the Permian Basin of west Texas, to the Katy Hub, a major natural gas trading center near Houston, Texas.

•

East Texas Pipeline. The East Texas Pipeline connects natural gas supplies in east Texas to the Katy Hub.

•

ET Fuel System. The ET Fuel System, which serves some of the most active drilling areas in the United States, is comprised of approximately 2,000 miles of intrastate natural gas pipeline and related natural gas storage facilities located in Texas. With approximately 460 receipt and/or delivery points, including interconnects with pipelines providing direct access to power plants and interconnects with other intrastate and interstate pipelines, the ET Fuel System is strategically located near high-growth production areas and major markets such as the Waha Hub, the Katy Hub and the Carthage Hub, three major natural gas trading centers located in Texas.

•

HPL System. The HPL System is comprised of approximately 4,200 miles of intrastate natural gas pipeline, 64 Bcf of working gas underground Bammel storage reservoir and related transportation assets. The HPL System has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast, east Texas and the western Gulf of Mexico and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City, Baytown, Beaumont and Port Arthur. The HPL System consists of six main transportation pipelines and three market area loops and has direct access to multiple market hubs at Katy, the Houston Ship Channel, Ague Dulce, and through its operations of the Bammel storage facility.

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

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

We engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir on our HPL System. The Bammel storage reservoir is one of the largest storage facilities in North America with a total working gas capacity of approximately 64 Bcf. The reservoir has a peak withdrawal rate of 1.3 Bcf/d and also has considerable flexibility during injection periods in that the HPL System has engineered an injection well configuration to provide for a 0.6 Bcf/d peak injection rate. Therefore, we purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and

provide for a gross profit margin. Since the acquisition, we have continually managed our positions to enhance the future profitability of our storage position. We may, from time to time, change our scheduled injection and withdrawal plans based on market conditions and adjust the level of working natural gas stored in the Bammel reservoir. We expect margins from the HPL System to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.

As a result of our trading activities discussed in Note 17 in the accompanying condensed consolidated financial statements, and the use of financial derivative instruments that may not qualify for hedge accounting in our midstream and transportation and storage segments, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk management committee which includes members of senior management, and predefined limits and authorizations set forth by our risk management policy.

Retail and wholesale propane segments

Our propane related segments are operated by HOLP and its subsidiaries who are engaged in the sale, distribution and marketing of propane and other related products through its retail, domestic wholesale and foreign wholesale propane segments (the propane segments). HOLP derives its revenue primarily from the retail propane segment. We believe that we are the one of the five largest retail marketers of propane in the United States, based on retail gallons sold. We serve more than 700,000 propane customers from 321 customer service locations in 34 states.

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

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

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

A substantial portion of our propane is used in the heating-sensitive residential and commercial markets causing the temperatures realized in our areas of operations, particularly during the six-month peak-heating season, to have a significant effect on the financial performance of our propane operations. In any given area, sustained warmer-than-normal temperatures will tend to result in reduced propane use, while sustained colder-than-normal temperatures

will tend to result in greater propane use. We use information on normal temperatures in understanding how temperatures that are colder or warmer than normal affect historical results of operations and in preparing forecasts related to our future operations.

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

Amounts discussed below reflect 100% of the results of MP Energy Partnership. MP Energy Partnership is a Canadian general partnership in which HOLP owns a 60% interest. Because MP Energy Partnership is primarily engaged in lower-margin wholesale distribution, its contribution to our net income is not significant.

Current Developments

On February 8, 2006, the Partnership sold and issued 1,069,850 Common Units and 2,570,150 Class F Units representing limited partnership interests in the Partnership to ETE. ETE owns 100% of the 2% general partner interests in ETP GP and 50% of the incentive distribution rights in the Partnership (which it holds through its ownership interests in ETP GP). The price paid for each of the Common Units and Class F Units was equal to $36.37 per unit, the New York Stock Exchange closing price of the Partnership’s Common Units on February 8, 2006. The Common Units and Class F Units were issued to ETE in a private placement that is exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended. Of the aggregate proceeds of $132.4 million from the sale, $75.0 million was used to extinguish the HOLP Senior Revolving Acquisition Facility, to pay down the HOLP Senior Working Capital Facility, and for HOLP general operating purposes. The remaining balance of the proceeds, $57.4 million, was used to pay down existing debt on the ETP Revolving Credit Facility and for general Partnership operating purposes.

Analysis of Historical Results of Operations

We acquired the HPL System on January 26, 2005. The acquisition of HPL affects the comparability of the historical results of operations in our transportation and storage operating segment for the three and six months ended February 28, 2006 compared to the three and six months ended February 28, 2005, as the results of operations for the three and six months ended February 28, 2005 only reflect the impact of this acquisition since January 2005. On November 10, 2005, we purchased the 2% limited partner interest in HPL that we did not already own from AEP for $16.6 million in cash. As a result, HPL became a wholly-owned subsidiary of ETC OLP. We also reached a settlement agreement with AEP related to the inventory and working capital matters associated with the HPL acquisition. The terms of the agreement were not material in relation to our financial position and results of operations.

In addition, we completed the sale of our Oklahoma gathering, treating and processing assets, referred to as the Elk City System, on April 14, 2005. These discontinued operations are presented as net amounts in the condensed consolidated statements of operations, with prior periods restated. Selected operating results for the midstream segment discussed below have been restated for the prior periods presented to reflect the discontinued operations.

Overall Increase in Results of Operations. We have experienced a significant increase in our results of operations for the three and six months ended February 28, 2006 when compared to the same period last year. The increase is principally attributable to the following:

•

Acquisitions. We have been successful in completing various strategic acquisitions during the last twelve to eighteen months by both of our operating partnerships, ETC OLP and HOLP. As discussed above, we completed the acquisition of the HPL System on January 26, 2005. We also acquired the Texas Chalk and Madison System in November 2004. These acquisitions have significantly increased our asset base and operations for the three and six months ended February 28, 2006. In addition, HOLP has made a number of propane acquisitions during the periods presented;

•

Increased volumes and prices. In addition to the acquisitions, we have also experienced increased volumes in our existing operating segments as a result of various strategies we put in place. Commodity

prices have also increased resulting in increased revenues and costs of sales. The average NYMEX settlement price for the natural gas deliveries was $10.13 per MMBtu and $11.30 per MMBtu for the three and six months ended February 28, 2006, respectively, compared to $6.42 per MMBtu and $6.57 per MMBtu for the three and six months ended February 28, 2005, respectively.

Comparative Results for the Three and Six Months Ended February 28, 2006 and 2005

Volume. Volumes of natural gas sales, NGL sales including propane, and natural gas transported by our midstream, transportation and storage, retail propane, and wholesale propane segments are as follows:

Midstream


	Three Months Ended				Six Months Ended
	February 28, 2006	February 28, 2005	Increase (Decrease)		February 28, 2006	February 28, 2005	Increase (Decrease)
Natural gas MMBtu/d	1,529,856	1,411,800	118,056		1,528,616	1,313,254	215,362
NGLs Bbls/d	9,537	16,261	(6,724	)	9,879	12,931	(3,052	)

•

Natural gas sales volumes increased by 118,056 MMBtu/d for the three months ended February 28, 2006 compared to the same period in 2005. The increase was principally attributable to increased marketing efforts by our producer services’ operations to market on and off-system natural gas. Our sales volumes of NGLs vary due to our ability to by-pass our processing plants when conditions exist that make it less favorable to process and extract NGLs from our processing plants. The decrease in NGLs sales volumes is principally due to a change in contract mix with one of our major producers and the election to by-pass our processing plant as a result of less favorable market conditions during the three months ended February 28, 2006 compared to the same period last year.

For the six months ended February 28, 2006, natural gas sales volumes increased by 215,362 MMBtu/d compared to the six months ended February 28, 2005. The increase was principally attributable to the acquisition of the Texas Chalk and Madison Systems on November 1, 2004, as the Texas Chalk and Madison Systems essentially doubled the number of producing wells from 1,000 to 2,000, and increased marketing efforts by our producer services’ operations to market on and off-system natural gas. Our sales volumes of NGLs vary due to our ability to by-pass our processing plants when conditions exist that make it less favorable to process and extract NGLs from our processing plants. The decrease in NGLs sales volumes is principally due to a change in contract mix with one of our major producers and the election to by-pass our processing plant as a result of less favorable market conditions during the latter part of the six months ended February 28, 2006 compared to the same period last year.

Transportation and Storage


	Three Months Ended				Six Months Ended
	February 28, 2006	February 28, 2005	Increase (Decrease)		February 28, 2006	February 28, 2005	Increase (Decrease)
Natural gas MMBtu/d – sold	1,868,486	2,039,179	(170,693	)	1,709,049	2,039,179	(330,130	)
Natural gas MMBtu/d – transported	4,231,797	3,045,656	1,186,141		4,349,137	3,078,193	1,270,944

•

Transported natural gas volumes increased by 1,186,141 MMBtu/d between the three month period ended February 28, 2006 and 2005. The increase in transportation volumes is principally due to the increased volumes experienced in the Oasis Pipeline system, ET Fuel system and East Texas Pipeline system as a result of our effort to secure firm commitments on our transportation assets and a higher price differential between the Waha and Katy market hubs during the periods presented. Natural gas sales volumes on the HPL System for the three months ended February 28, 2006 decreased 170,693 MMBtu/d compared to the three months ended February 28, 2005, principally due to warmer weather during the three months ended February 28, 2006 compared to the same period last year.

For the six months ended February 28, 2006, transported natural gas volumes increased by 1,270,944 MMBtu/d. The increase in transportation volumes is principally due to the increased volumes experienced in the Oasis

Pipeline system, ET Fuel system and East Texas Pipeline system as a result of our effort to secure firm commitments on our transportation assets and a higher price differential between the Waha and Katy market hubs during the periods presented. Natural gas sales volumes on the HPL System for the six months ended February 28, 2006 decreased 330,130 MMBtu/d compared to the six months ended February 28, 2005, principally due to warmer weather during the six-month period ended February 28, 2006 compared to the same period last year.

Propane


	Three Months Ended			Six Months Ended
	February 28, 2006	February 28, 2005	Increase	February 28, 2006	February 28, 2005	Increase
Gallons sold
(in thousands)
Retail	165,758	165,696	62	254,496	252,131	2,365
Wholesale	28,243	25,708	2,535	47,844	44,017	3,827

•

Retail Propane. Of the 0.1 million increase in retail propane gallons sold for the three months ended February 28, 2006, compared to the three months ended February 28, 2005, 7.6 million gallons was primarily the result of volumes sold by customer service locations added through acquisitions, offset by a 7.5 million gallon decrease related to warm weather. The weather in our areas of operations during the three months ended February 28, 2006 was 1.2% warmer than the three months ended February 28, 2005 and 9.2% warmer than normal.

Of the 2.4 million gallon increase in retail propane gallons sold for the six months ended February 28, 2006, compared to the six months ended February 28, 2005, 11.5 million gallons was primarily the result of volumes sold by customer service locations added through acquisitions, offset by a 9.1 million gallon decrease related to warm weather. The weather in our areas of operations during the six months ended February 28, 2006 was 1.2% warmer than six months ended February 28, 2005 and 10.5% warmer than normal.

•

Wholesale Propane. The increase of 2.5 million wholesale propane gallons between the three months ended February 28, 2006 and 2005 is due to an increase of 1.1 million domestic gallons sold as a result of several new customers in our eastern wholesale operations, and an increase of 1.4 million gallons in our foreign wholesale operations which is related to increased marketing efforts in our foreign operations.

For the six months ended February 28, 2006, wholesale propane gallons increased by 3.8 million gallons compared to the same period in 2005. Of this increase, 3.1 million is due to an increase in gallons sold in our U.S. wholesale operations as a result of several new customers in our eastern wholesale and foreign operations, and an increase of 0.7 million gallons in our foreign wholesale operations which is related to increased marketing efforts in our foreign operations.

Consolidated Results


	Three Months Ended									Six Months Ended
(unaudited)	February 28, 2006			February 28, 2005			Increase (Decrease)			February 28, 2006			February 28, 2005			Increase (Decrease)
Consolidated Information:
Revenues	$	2,449,816		$	1,439,844			1,009,972		$	4,866,436		$	2,304,042		$	2,562,394
Cost of sales		2,008,831			1,211,175			797,656			4,099,458			1,939,079			2,160,379

Gross margin		440,985			228,669			212,316			766,978			364,963			402,015

Operating expenses		99,696			73,551			26,145			202,367			133,751			68,616
Selling, general and administrative		31,455			11,913			19,542			56,254			22,637			33,617
Depreciation and amortization		29,014			22,232			6,782			55,927			41,893			14,034

Consolidated operating income		280,820			120,973			159,847			452,430			166,682			285,748

Equity in earnings (losses) of affiliates		106			109			(3	)		(168	)		145			(313	)
Interest expense		(28,542	)		(23,024	)		5,518			(56,935	)		(40,355	)		16,580
Gain (loss) on disposal of assets		662			(436	)		1,098			534			(527	)		1,061
Loss on extinguishment of debt		—			(7,996	)		7,996			—			(7,996	)		7,996
Interest income and other, net		2,302			235			2,067			3,261			369			2,892
Minority interests		(549	)		(358	)		191			(2,104	)		(516	)		1,588
Income tax expense		(4,014	)		(3,127	)		887			(26,425	)		(4,159	)		22,266

Income from continuing operations		250,785			86,376			164,409			370,593			113,643			256,950
Income from discontinued operations, net of income tax expense		—			1,225			(1,225	)		—			4,568			(4,568	)

Net income	$	250,785		$	87,601		$	163,184		$	370,593		$	118,211		$	252,382

See the detailed discussion of revenues, costs of sales, margin, and other operating expense by operating segment below.

Interest Expense. Interest expense increased by $5.5 million for the three months ended February 28, 2006 compared to the three months ended February 28, 2005. The principal factors for the increase are a $12.2 million increase due to borrowings on the Senior Notes and the Revolving Credit Facility in January 2005, offset by a decrease of $7.3 million resulting from the reduction of long term debt in January 2005 and the effects of interest rate swaps accounted for at ETC OLP.

For the six months ended February 28, 2006 compared to the six months ended February 28, 2005, interest expense increased $16.6 million. The principal factors for this increase are a $33.2 million increase due to borrowings on the Senior Notes and the Revolving Credit Facility in January 2005 offset by a decrease of $16.9 million due to the reduction of long term debt in January 2005 and the effects of interest rate swaps accounted for at ETC OLP.

Loss on Extinguishment of Debt. During the three and six months ended February 28, 2005, we refinanced certain debt and wrote off $8.0 million of debt issuance costs associated with the debt that was repaid with the proceeds from the issuance of $750 million of 5.95% senior notes. The write-offs were accounted for as loss on extinguishment of debt.

Income Tax Expense. As a partnership, we are not subject to income taxes. However certain wholly-owned subsidiaries are corporations that are subject to income taxes. The increase in income taxes of $0.9 million for the three months ended February 28, 2006 and $22.3 million for the six months ended February 28, 2006 is attributed principally to higher income in a subsidiary treated as a taxable corporation. The higher income was due to gains on financial derivative activity recognized by this subsidiary. No similar gains were realized by such subsidiary in prior periods.

Income from Continuing Operations. The increase in income from continuing operations of $164.4 million and $256.9 million between the three and six month periods of 2006 and 2005, respectively is principally due to acquisition-related income, increased volumes and margins on our midstream and transportation and storage assets and favorable price movement on our derivative positions during the 2006 period.

Income from Discontinued Operations. On April 14, 2005, we completed the sale of our Oklahoma gathering, treating and processing assets, referred to as the Elk City System. The income from discontinued operations of $1.2 million for the three months ended February 28, 2005 was comprised of revenues from the Elk City System of $40.7 million and costs and expenses of $39.5 million.

For the six months ended February 28, 2005, the income from discontinued operations consisted of revenues of $84.2 million and costs and expenses of $79.6 million, resulting in income from discontinued operations of $4.6 million.

There were no discontinued operations for the three or six months ended February 28, 2006.

Net Income. Net income increased by $163.2 million and $252.4 million between the comparable three and six months periods of February 28, 2006 and 2005. The increase is principally due to the effect of the HPL acquisition described above, together with the favorable price movements on financial derivative positions and increased volumes and margins on our midstream and transportation and storage assets.

THREE AND SIX MONTH OPERATING RESULTS BY SEGMENT

Midstream Segment


	Three Months Ended							Six Months Ended
	February 28, 2006		February 28, 2005		Increase (Decrease)			February 28, 2006		February 28, 2005		Increase
Revenues	$	1,205,027	$	781,190	$	423,837		$	2,754,855	$	1,431,802	$	1,323,053
Cost of sales		1,160,557		739,165		421,392			2,597,427		1,369,600		1,227,827

Gross Margin		44,470		42,025		2,445			157,428		62,202		95,226

Operating expenses		7,104		5,551		1,553			14,342		9,467		4,875
Selling, general and administrative		6,630		2,150		4,480			14,657		5,513		9,144
Depreciation and amortization		3,880		2,871		1,009			7,565		5,765		1,800

Segment operating income	$	26,856	$	31,453	$	(4,597	)	$	120,864	$	41,457	$	79,407

Gross Margin. Midstream’s gross margin increased by $2.4 million. The increase was principally due to increased volumes on our gathering systems which resulted in higher fee-based revenues. The increase was offset by lower margins generated by our producer services between the 2005 and 2006 periods and $2.7 million in losses, including $25.5 million of unrealized losses, associated with certain trading activities during the three months ended February 28, 2006. No margins associated with trading activities were recognized in the comparable 2005 period as we did not commence certain trading activities until the fourth quarter of fiscal year 2005.

For the six months ended February 28, 2006, midstream’s gross margin increased by $95.2 million. The increase was principally due to favorable price movements on financial derivative positions during the 2006 period, higher margins on sales made by our producer services, and increased volumes on our gathering systems which resulted in higher fee-based revenues. During the six months ended February 28, 2006, we also recognized $49.8 million in margin, including $19.1 million of unrealized losses, associated with certain trading activities. No margins associated with trading activities were recognized in the comparable 2005 period as we did not commence certain trading activities until the fourth quarter of fiscal year 2005.

Operating Expenses. Midstream operating expenses increased $1.6 million for the three months ended February 28, 2006 compared to the same period ended February 28, 2005. The increase was principally attributable to $0.7 million in increased measurement expenses, $0.5 million in increased chemical costs and increases of $0.4 million in other operating expenses.

Midstream operating expenses increased $4.9 million for the six months ended February 28, 2006 compared to the six months ended February 28, 2005. The increase was primarily due to $1.5 million in increased measurement expenses, $0.9 million in increased chemical costs, $0.9 million in scheduled compressor and pipeline maintenance expense, $0.7 million in employee costs, and increases of $0.9 million in other operating expenses principally related to the acquisition of the Texas Chalk and Madison Systems in November 2004. The period ended February 28, 2005 contained only four months of operating results from those assets.

Selling, General and Administrative Expenses. The allocation of departmental costs between midstream and the transportation and storage segments are based on factors such as headcount, number of meters, and on-going projects and is intended to fairly present the segment’s operating results. Midstream general and administrative expenses increased $4.5 million from the three months ended February 28, 2005 compared to the same period ended February 28, 2006. Increases of $11.0 million in employee-related costs such as salaries, incentive compensation and healthcare costs, insurance premium increases of $0.6 million, legal fees increases of $0.7 million and increases in other general and administrative expenses of $0.7 million were offset by increases of $8.5 million in departmental costs allocated to the transportation and storage operating segment.

Midstream general and administrative expenses for the six months ended February 28, 2006 increased $9.1 million compared to the six months ended February 28, 2005. The increase was attributable to increases of $19.7 million in employee-related costs such as salaries, incentive compensation and healthcare costs, insurance premium increases of $1.2 million, increases in office-related expenses of $1.7 million, and increases in other general and administrative expenses of $2.1 million. The increase was offset by increases of $15.5 million in departmental costs allocated to the transportation and storage operating segment.

Depreciation and amortization. Midstream depreciation and amortization expense increased $1.0 million between the 2005 and 2006 period principally due to additions to property and equipment subsequent to February 28, 2005.

The increase of $1.8 million for the six month period ended 2006 compared to the same period in 2005 is principally due to the Devon acquisition in November 2004 and other additions to property and equipment subsequent to February 28, 2005.

Transportation and Storage Segment


	Three Months Ended						Six Months Ended
	February 28, 2006		February 28, 2005		Increase		February 28, 2006		February 28, 2005		Increase
Revenues	$	1,490,265	$	384,726	$	1,105,539	$	3,055,775	$	442,343	$	2,613,432
Cost of sales		1,236,485		324,783		911,702		2,665,788		330,805		2,334,983

Gross Margin		253,780		59,943		193,837		389,987		111,538		278,449

Operating expenses		41,809		20,649		21,160		88,249		32,827		55,422
Selling, general and administrative		12,752		4,711		8,041		23,512		7,923		15,589
Depreciation and amortization		11,061		5,847		5,214		20,795		9,290		11,505

Segment operating income	$	188,158	$	28,736	$	159,422	$	257,431	$	61,498	$	195,933

Gross Margin. Transportation and storage gross margin increased between the three months ended February 28, 2005 and 2006 by $193.8 million. The increase in transportation and storage gross margin is principally due to the following:

•

Increased volumes and prices. The increase is principally due to the increase in average natural gas prices period to period which promotes shippers to transport natural gas to more liquid markets such as the Katy Hub and our strategy to pursue additional volumes on our transportation pipeline systems. The price differential between the Waha and Katy market hubs increased between the 2005 and 2006 periods, thereby influencing shippers to transport natural gas to regions where natural gas prices are more favorable. We have also successfully secured more firm contracts as evidenced by our recent transportation agreement with XTO. In addition, our Fort Worth Basin expansion, completed in May 2005, has also allowed shippers to move more gas from the Barnett Shale. We expect our gross margins to continue to increase as a result of this expansion and the recently announced expansion projects; and

•

The inclusion of HPL’s operating results for the three months ended February 28, 2006. As previously noted, HPL was acquired on January 26, 2005. As such, our results for the three months ended February 28, 2005 only include one month of margins related to HPL. For the three months ended February 28, 2006, HPL’s margin was principally affected by increased margins resulting from the withdrawal of natural gas stored in the Bammel storage facilities. During the three months ended February 28, 2006, we withdrew approximately 34.3 Bcf of natural gas to meet our customers’ demands. We also continued to experience increased margins resulting from favorable pricing between the West and East markets in the Houston Ship Channel, however, at lower levels than previous experienced during our three months ended November 30, 2005. Such pricing continues to remain below levels experienced during the three months ended November 30, 2005.

During the three months ended February 28, 2006 we also discontinued application of hedge accounting in connection with certain derivative financial instruments that were qualified for and designated as cash flow hedges related to forecasted sales of natural gas stored in the Partnership’s Bammel storage facilities. The discontinuation resulted from our determination that the originally forecasted sales of natural gas from the storage facilities were no longer probable to occur by the end of the originally specified time period, or within an additional two-month period of time thereafter. The determination was made principally due to the unseasonably warm weather that occurred during January 2006 through March 2006 and our flexibility to make changes to the underlying injection and withdrawal schedule for our storage assets, given changes in market conditions. As a result, during the three months ended February 28, 2006, we recognized previously deferred unrealized gains of approximately $84.7 million from the discontinuation of hedge accounting. Due to the seasonal nature of HPL’s operations, we anticipate margin will significantly decrease in our third fiscal quarter of 2006 as we intend to purchase and store natural gas in this period to meet anticipated demand in the summer of 2006 and winter of 2006-2007.

For the six months ended February 28, 2006 as compared to the same period in 2005, transportation and storage gross margin increased by $278.4 million. The increase in transportation and storage gross margin is principally due to the following:

•

Increased volumes and prices. The increase is principally due to the increase in average natural gas prices period to period which promotes shippers to transport natural gas to more liquid markets such as the Katy Hub and our strategy to pursue additional volumes on our transportation pipeline systems. The price differential between the Waha and Katy market hubs increased between the 2005 and 2006 periods, thereby, influencing shippers to transport natural gas to regions where natural gas prices are more favorable. We have also successfully secured more firm contracts as evidenced by our recent transportation agreement with XTO. In addition, our Fort Worth Basin expansion, completed in May 2005, has also allowed shippers to move more gas from the Barnett Shale. We expect margins to continue to increase as a result of this expansion and the recently announced expansion projects. Our margins for the six months ended February 28, 2006 were also affected favorably by higher than normal temperatures during September and October 2005 in regions where our assets are located. The higher temperatures required more demand for natural gas to be used by electricity-producing power plants connected to these assets; and

•

The inclusion of HPL’s operating results for the six months ended February 28, 2006. For the six months ended February 28, 2006, HPL’s margin was principally affected by increased margins resulting from favorable pricing between the West and East markets in the Houston Ship Channel. The favorable pricing was attributed to the effects of the hurricanes that struck the east Texas and Louisiana coastlines in August and September 2005. However, such margins were at lower levels than previous experienced during our three months ended November 30, 2005. Such pricing continues to remain at or below levels experienced during the three months ended November 30, 2005. As noted above, margins were also affected by the sale of natural gas during the six months ended February 28, 2006 that was held in storage; and

•

As a result of the discontinuation of hedge accounting (refer to full discussion above in the three month period results), we recognized previously deferred unrealized gains of approximately $84.7 million for the six months ended February 28, 2006.

Operating Expenses. Transportation and storage operating expenses increased $21.2 million when comparing the three months ended February 28, 2006 to the same prior period ended February 28, 2005. The increase was principally attributable to increases of $9.5 million in operating expenses related to the HPL acquisition, $10.4 million related to compressor fuel consumption resulting from higher throughput volumes and increased gas prices during the period ended February 28, 2006, $0.8 million increase in property taxes, and increases of $0.5 million, in the aggregate, in other operating expenses. Excluding the impact of volumetric changes, our fuel consumption costs are directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel consumption costs and decreases in natural gas prices tend to decrease our fuel consumption costs.

Transportation and storage operating expenses increased $55.4 million when comparing the six months ended February 28, 2006 to the same prior period ended February 28, 2005. The increase was principally attributable to increases of $26.8 million in operating expenses related to the HPL acquisition, $26.0 million related to compressor fuel consumption resulting from higher throughput volumes and increased gas prices during the period ended February 28, 2006, $1.7 million increase in property taxes, and increases of $0.9 million, in the aggregate, in other operating expenses.

Selling, General and Administrative Expenses. Transportation and storage general and administrative expenses increased $8.0 million for the three months ended February 28, 2006 compared to the three months ended February 28, 2005. The increase was principally due to $8.5 million in certain departmental costs allocated from the midstream segments offset by a decrease of $0.5 million in other general and administrative expenses. The increase in allocated departmental costs is due to the increase in employee headcount resulting primarily from the HPL acquisition.

Transportation and storage general and administrative expenses increased $15.6 million for the six months ended February 28, 2006 compared to the six months ended February 28, 2005 principally due to an increase in certain departmental costs allocated from the midstream segment. The increase in allocated departmental costs is due to the increase in employee headcount resulting primarily from the HPL acquisition.

Depreciation and amortization. Transportation and storage depreciation and amortization expense increased $5.2 million from the three months ended February 28, 2005 to the three months ended February 28, 2006. The increase was principally due to the HPL acquisition in January 2005, the Fort Worth Basin expansion project completed in May 2005, and additional compressors and equipment added to existing systems.

Transportation and storage depreciation and amortization expense increased $11.5 million from the six months ended February 28, 2005 to the six months ended February 28, 2006. The increase was principally due to the HPL acquisition in January 2005, the Fort Worth Basin expansion project completed in May 2005, and additional compressors and equipment added to existing systems.

Retail Propane Segment


	Three Months Ended				Increase (Decrease)			Six Months Ended				Increase
	February 28, 2006		February 28, 2005		Increase (Decrease)			February 28, 2006		February 28, 2005		Increase
Retail propane revenues	$	312,227	$	265,233	$	46,994		$	474,420	$	397,980	$	76,440
Other propane related revenues		19,920		19,076		844			39,758		37,094		2,664
Retail propane cost of sales		188,679		154,655		34,024			291,061		237,189		53,872
Other propane related cost of sales		5,166		5,456		(290	)		11,254		11,061		193

Gross margin		138,302		124,198		14,104			211,863		186,824		25,039

Operating expenses		49,004		45,670		3,334			96,087		88,200		7,887
Selling, general and administrative		5,299		3,023		2,276			8,088		5,709		2,379
Depreciation and amortization		13,744		13,222		522			26,954		26,283		671

Segment operating income	$	70,255	$	62,283	$	7,972		$	80,734	$	66,632	$	14,102

Revenues. Retail propane revenue between the three months ended February 28, 2006 and 2005, increased $47.0 million of which $14.3 million was due to the increase in volumes sold by customer service locations added through acquisitions and $46.9 million is due to higher selling prices. These increases were offset by a decrease of $14.2 million due to the adverse impact of weather related volumes described above. Other propane related revenues increased $0.8 million for the three months ended February 28, 2006 compared to the same three-month period last year primarily due to increases resulting from acquisitions.

Of the total increase in retail propane revenue of $76.4 million between the six months ended February 28, 2006 and 2005, $21.4 million is due to the increase in volumes sold by customer service locations added through acquisitions and $72.0 million is due to higher selling prices.. These increases were offset by a decrease of $17.0 million due to the adverse impact of weather related volumes described above. Other propane related revenues increased $2.7 million for the six months ended February 28, 2006 compared to the same six-month period last year primarily due to other propane related revenues of companies we have acquired between the two periods.

Costs of Sales. Retail propane cost of sales during the three months ended February 28, 2006 compared to the three months ended February 28, 2005 increased by $34.0 million, of which $33.9 million was due to higher cost of fuel, $8.6 million was due to cost of fuel sold by customer service locations added through acquisitions, offset by an $8.5 million decrease due to the impact of weather related volumes described above.

During the six months ended February 28, 2006 compared to the six months ended February 28, 2005, retail propane cost of sales increased by $53.9 million of which $13.1 million is a result of an overall increase in gallons sold by customer service locations added through acquisitions, $51.2 million is due to higher cost of fuel offset by a decrease of $10.4 million due to the impact of weather related volumes described above.

Gross Margin. The overall increase in gross margins for the three and six-month comparable periods ending February 28, 2006 and 2005 is a function of acquisition related increases and higher sales prices.

Operating Expenses. Operating expenses increased $3.3 million during the three months ended February 28, 2006 compared to the same three-month period last year due to a combination of a $1.7 million increase in our employee base from acquisitions and annual salary increases, $0.7 million higher fuel costs to run our vehicles and other vehicle expenses, and a $1.8 million general increase in other operating expenses also from acquisitions, offset by a $0.9 million net decrease in business insurance.

During the six months ended February 28, 2006, operating expenses increased by $7.9 million compared to the same six month period last year due to a combination of a $4.2 million increase in our employee base from acquisitions and annual salary increases, $1.4 million higher fuel costs to run our vehicles and other vehicle expenses, and a $2.6 million general increase in other operating expenses also from acquisitions, offset by a $0.3 million net decrease in business insurance.

Selling, General and Administrative Expenses. The increase for the three and six-month comparable periods of February 28, 2006 and 2005 is primarily due to increases in executive bonuses and deferred compensation awards.

Operating Income. Operating income increased by $8.0 million during the three months ended February 28, 2006 compared to the three months ended February 28, 2005. This variance is primarily due to the changes in revenues and expenses described above.

For the six months ended February 28, 2006, total operating income increased by $14.1 million compared to the six months ended February 28, 2005. This variance is primarily due to the changes in revenues and expenses described above.

Wholesale Propane Segment


	Three Months Ended				Increase		Six Months Ended					Increase
	February 28, 2006		February 28, 2005		Increase		February 28, 2006		February 28, 2005			Increase
Revenues	$	32,958	$	23,733	$	9,225	$	56,899	$	42,218		$	14,681
Cost of sales		29,426		22,134		7,292		51,711		39,627			12,084

Gross margin		3,532		1,599		1,933		5,188		2,591			2,597

Operating expenses		916		852		64		1,603		1,545			58
Selling, general and administrative		568		529		39		971		875			96
Depreciation and amortization		223		195		28		407		364			43

Segment operating income (loss)	$	1,825	$	23	$	1,802	$	2,207	$	(193	)	$	2,400

Revenues. Of the increase in wholesale revenue of $9.2 million from the three months ended February 28, 2006 compared to the same three-month period last year, $3.1 million is primarily related to the increase in gallons sold to new customers in our eastern wholesale and foreign operations, and $6.1 million is related to higher selling prices.

Of the increase of $14.7 million in wholesale revenue from the six months ended February 28, 2006 compared to same six month period last year, $4.9 million is primarily related to the increase in gallons sold to new customers in our eastern wholesale and foreign operations and $9.8 million is related to higher selling prices.

Costs of Sales. Total wholesale cost of sales increased by $7.3 million in the three months ended February 28, 2006 compared to the three months ended February 28, 2005 proportionate to the increase in revenues described above. Wholesale propane cost of sales increased by $4.7 million due to higher selling prices, and by $2.6 million due to the increase in customers in our eastern wholesale operations described above.

For the six months ended February 28, 2006 compared to the same six-month period last year, total cost of sales increased by $12.1 million. Of the increase, $7.9 million is due to higher selling prices and $4.2 million is due to the increase in customers in our eastern wholesale operations described above.

Gross Margin. The overall increases in gross margin for both the three-month and six-month periods ended February 28, 2006 and 2005, are primarily a function of the activities described above in revenues and costs related to the new customers in our eastern wholesale and foreign operations.

Operating Income (Loss). The increase in operating income during the three and six-month periods ended February 28, 2006 of $1.8 million and $2.4 million, respectively, is primarily due to the changes in revenues and expenses described above.

Other


	Three Months Ended						Increase (Decrease)			Six Months Ended					Increase
	February 28, 2006			February 28, 2005			Increase (Decrease)			February 28, 2006		February 28, 2005			Increase
Revenue	$	1,408		$	1,276		$	132		$	3,522	$	2,537		$	985
Cost of sales		507			372			135			1,010		729			281
Operating expenses		863			829			34			2,086		1,712			374
Depreciation and amortization		106			97			9			206		191			15

Other operating income (loss)	$	(68	)	$	(22	)	$	(46	)	$	220	$	(95	)	$	315

Unallocated selling, general and administrative expenses	$	6,206		$	1,500		$	4,706		$	9,026	$	2,617		$	6,409

Unallocated Selling, General and Administrative Expenses. The selling, general and administrative expenses that relate to the general operations of the Partnership are not allocated to our segments.

The increases of $4.7 million and $6.4 million in the total unallocated selling, general, and administrative expenses during the three and six months ended February 28, 2006, respectively compared to the same three and six-month periods last year are primarily due to the $1.5 million increase in professional fees which is related to our ongoing efforts to comply with the Sarbanes Oxley Act and a $3.4 million increase in additional executive bonuses and non-cash compensation during fiscal year 2006.

INCOME TAXES

As a Partnership we generally are not subject to income tax. We are, however, subject to a statutory requirement that our non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of our total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation. Accordingly, certain activities that generate non-qualified income are conducted through taxable corporate subsidiaries (“C corporations”). These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the periods ended February 28, 2006 and 2005, our non-qualifying income did not exceed the statutory limit.

The difference between the statutory rate and the effective rate is summarized as follows:


	Three Months Ended				Six Months Ended
	February 28, 2006		February 28, 2005		February 28, 2006		February 28, 2005
Federal statutory tax rate	35.0	%	35.0	%	35.0	%	35.0	%
State income tax rate net of federal benefit	3.4	%	3.6	%	3.4	%	3.7	%
Partnership earnings not subject to tax at the Partnership level:	(36.8	)%	(35.1	)%	(31.8	)%	(35.2	)%

Effective tax rate	1.6	%	3.5	%	6.6	%	3.5	%

Income tax expense consists of the following current and deferred amounts:


	Three Months Ended						Six Months Ended
	February 28, 2006			February 28, 2005			February 28, 2006			February 28, 2005
Current income tax expense (benefit):
Federal	$	12,853		$	(25	)	$	28,117		$	2,134
State		950			(42	)		1,288			342
Deferred income tax expense (benefit):
Federal		(9,288	)		2,713			(2,625	)		1,379
State		(501	)		481			(355	)		304

Total	$	4,014		$	3,127		$	26,425		$	4,159

LIQUIDITY AND CAPITAL RESOURCES

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

Future capital requirements of our business will generally consist of:

•

maintenance capital expenditures which includes capital expenditures made to connect additional wells to our natural gas systems in order to maintain or increase throughput on existing assets for which we expect to expend approximately an additional $15.0 million during the current fiscal year, and capital expenditures to extend the useful lives of our propane assets in order to sustain our operations, including vehicle replacements on our propane vehicle fleet for which we expect to expend approximately an additional $5.0 million;

•

growth capital expenditures, mainly for constructing new pipelines, processing plants and treating plants for which we expect to expend approximately an additional $315.0 million during the current fiscal year; and customer propane tanks for which we expect to expend approximately an additional $10.0 million; and

•

acquisition capital expenditures including acquisition of new pipeline systems and propane operations.

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

•

maintenance capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities described below;

•

growth capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities, the issuance of additional Common Units or a combination thereof; and

•

acquisition capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities, other lines of credit, long-term debt, the issuance of additional Common Units or a combination thereof.

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

In connection with the HPL acquisition, we now engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. Natural gas is typically purchased and held in storage during the summer months and sold during the winter months. Although we intend to fund natural gas purchases with cash generated from operations, from time to time we may need to finance the purchase of natural gas to be held in storage with borrowings from our current credit facilities. We intend to repay these borrowings with cash generated from operations when the gas is sold.

Cash Flows

Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, including the recently acquired HPL System, and other factors.

Operating Activities. Cash provided by operating activities during the six months ended February 28, 2006, was $438.1 million as compared to cash provided by operating activities of $156.6 million for the six months ended

February 28, 2005. The net cash provided by operations for the six months ended February 28, 2006 consisted of net income of $370.6 million, non-cash charges of $64.0 million, principally depreciation and amortization, stock based compensation expense, and deferred taxes, and operating funds received of $3.5 million which decreased components of working capital. Various components of working capital changed significantly from the prior period due to factors such as the variance in the timing of accounts receivable collections, payments on accounts payable, and the timing of the purchase and sale of inventories related to the propane and transportation and storage operations. Increased fuel prices also contributed to increases in accounts receivable balances with customers, accounts payable for fuel, and inventory costs.

Investing Activities. Cash used in investing activities during the six months ended February 28, 2006 of $261.5 million is comprised of cash paid for acquisitions of $29.9 million and $255.1 million invested for maintenance and growth capital expenditures needed to sustain operations at current levels and to support growth of operations. Cash used in investing activities was offset by proceeds from the sale of idle property of $3.9 million and cash received for a working capital settlement on the HPL acquisition of $19.6 million. The cash paid for acquisitions included $16.6 million paid for the acquisition of the 2% remaining interests in the HPL System and $0.5 million for the remaining interests in the Dorado System, each of which we did not previously own, and cash paid for retail propane acquisitions of $12.8 million.

Financing Activities. Cash used in financing activities during the six months ended February 28, 2006 was $167.6 million. Cash used during the period primarily reflects $146.4 million of distributions by us to our Common Unitholders, and to our General Partner’s for its 2% interest and for its incentive distributions, and a net reduction in our debt of $155.1 million during the six months ended February 28, 2006. The debt reduction was primarily funded through the sale of 1,069,850 Common Units and 2,570,150 Class F Units to ETE for which we received net proceeds of $132.4 million. Our General Partner contributed $2.7 million to us to maintain its 2% ownership in us during the six months ended February 28, 2006. We also paid other financing costs of $1.2 million during the six months ended February 28, 2006.

Financing and Sources of Liquidity

Description of Indebtedness

The Partnership’s indebtedness consists of $750.0 million in principal amount of 5.95% Senior Notes due 2015, $400.0 million in principal amount of 5.65% Senior Notes due 2012 and a Revolving Credit Facility that allows for borrowings of up to $900.0 million through December 10, 2010. We also currently maintain a separate working capital facility for HOLP. The terms of our indebtedness and our Operating Partnerships are described in more detail in the Partnership’s Annual Report on Form 10-K for fiscal 2005, as amended on Form 10-K/A as filed with the Securities and Exchange Commission on November 14, 2005, and December 12, 2005, respectively.

Energy Transfer Partners Facilities

On December 13, 2005, we entered into a $900.0 million Revolving Credit Facility which is available through December 10, 2010, which replaced our previous revolving credit facility. Amounts borrowed under the Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The Revolving Credit Facility also offers a Swingline loan option with the maximum borrowing of $50.0 million at a daily rate based on LIBOR. The maximum commitment fee payable on the unused portion of the facility is 0.25%. The facility is unsecured by and has equal rights to the holders of the Partnership’s other current and future unsecured debt. As of February 28, 2006, there was $100.0 million outstanding under the Revolving Credit Facility and no amounts outstanding under the Swingline option. We also had $9.9 million in Letters of Credit outstanding, which reduce the amount available for borrowing under the Revolving Credit Facility. Letter of Credit Exposure plus borrowings under the Revolving Credit Facility cannot exceed the $900.0 million maximum Revolving Credit Facility, which is expandable to $1.0 billion. The weighted average interest rate was 5.32% as of February 28, 2006. Our available amount under the facility is $790.0 million at February 28, 2006.

HOLP Facilities

Effective September 1, 2005, HOLP entered into the Second Amendment to the Third Amended and Restated Credit Agreement. The amendment states that in no event shall the Letter of Credit Exposure exceed $15,000 at any time. All of the remaining terms, provisions and conditions of the existing Credit Agreement continue in full force and effect as within the March 31, 2004 Third Amended and Restated Credit Amendment noted below.

The Third Amended and Restated Credit Agreement includes a $75.0 million Senior Revolving Working Capital Facility available through December 31, 2006. Amounts borrowed under the Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 6.270% for the amount outstanding at February 28, 2006. The maximum commitment fee payable on the unused portion of the facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10.0 million for a period of not less than 30 consecutive days at least one time during each fiscal year. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Working Capital Facility. As of February 28, 2006, the Senior Revolving Working Capital Facility had a balance outstanding of $21.2 million, all of which was current, and $6.1 in outstanding Letters of Credit. Letter of Credit exposure plus the Working Capital Loan cannot exceed the $75.0 million maximum Working Capital Facility.

Prior to February 28, 2006, HOLP also maintained a $75.0 million Senior Revolving Acquisition Facility for acquisitions of propane-related businesses. Amounts borrowed under the Acquisition Credit Facility bore interest at a rate based on either a Eurodollar rate or a prime rate. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP and the capital stock of HOLP’s subsidiaries secured the Senior Revolving Acquisition Facility. As of February 28, 2006, HOLP used proceeds received from the sale of Common and Class F Units to ETE to extinguish the debt and cancelled this facility. HOLP will obtain funds for making acquisitions from the revenues generated from its operations and the operations of it subsidiaries, and from contributions from the Partnership. Pursuant to the Partnership’s Revolving Credit Facility a maximum of $100.0 million per year may be contributed to HOLP annually from funds received in equity offerings of the Partnership. As of February 28, 2006, $75.0 million has been contributed to HOLP under this arrangement.

Cash Distributions

We will use our cash provided by operating and financing activities from the Operating Partnerships to provide distributions to our Unitholders. Under the Partnership Agreement, we will distribute to our partners an amount equal to all of our Available Cash for such quarter within 45 days after the end of each fiscal quarter. Available Cash generally means, with respect to any quarter of the Partnership, all cash on hand at the end of such quarter less the amount of cash reserves established by the General Partner in its reasonable discretion that is necessary or appropriate to provide for future cash requirements. Our commitment to our Unitholders is to distribute the increase in our cash flow while maintaining prudent reserves for the Partnership’s operations. On October 14, 2005, we paid a quarterly distribution of $0.50 per unit, or $2.00 per unit annually to Unitholders of record as of the close of business on September 30, 2005. This distribution represented an increase of $0.05 per unit on an annualized basis over the distribution paid for the third quarter of fiscal 2005. On January 13, 2006, we paid a cash distribution of $0.55 per unit, or $2.20 per unit annually to Unitholders of record as of the close of business on January 4, 2006. The current distribution includes incentive distributions payable to the General Partner to the extent the quarterly distribution exceeds $0.275 per unit (an annualized rate of $1.10). On March 7, 2006, the Partnership declared a cash distribution for the second quarter ended February 28, 2006 of $0.5875 per Common Unit, or $2.35 per unit annually, an increase of $0.15 per Common Unit on an annualized basis. The distribution is payable on April 14, 2006 to Unitholders of record at the close of business on March 24, 2006.

New Accounting Standards

FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”). In March 2005, the Financial Accounting Standards Board (“FASB”) published FIN 47. This interpretation clarified that the term “conditional asset retirement obligation” as used in SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement of the obligation are uncertain. These conditional obligations were not previously addressed by SFAS 143. FIN 47 will require the Partnership to accrue the fair value of a liability for the conditional asset retirement obligation when incurred – generally upon acquisition, construction or development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement of a conditional asset retirement should be factored into the measurement of the liability when a range of scenarios can be determined. FIN 47 clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. Management intends to adopt FIN 47 no later than the end of the fiscal year ending August 31, 2006, and does not expect the adoption to have a material impact on our consolidated results of operations, cash flows or financial position.

SFAS No. 154, Accounting Changes and Error Correction – a replacement of APB Opinion No. 20 and FASB Statement No. 3. (“SFAS 154”) In May 2005, the FASB issued SFAS 154 which requires that the direct effect of voluntary changes in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Indirect effects of a change should be recognized in the period of the change. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. We will adopt the provisions of SFAS 154 as applicable when required.

EITF Issue No. 04-05, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights (“EITF 04-05”). EITF 04-05 provides guidance in determining whether a general partner controls a limited partnership by determining the limited partners’ substantive ability to dissolve (liquidate) the limited partnership as well as assessing the substantive participating rights of the limited partners within the limited partnership. EITF 04-05 states that if the limited partners do not have substantive ability to dissolve (liquidate) or have substantive participating rights, the general partner is presumed to control that partnership and would be required to consolidate the limited partnership. This EITF is effective in fiscal periods beginning after December 15, 2005. Although this EITF does not directly impact us, it could potentially impact our general partner. We are currently reviewing the potential impact of EITF 04-05 on our general partner.

EITF Issue No. 04-13, Accounting for Purchases and Sales of Inventory With the Same Counterparty (“EITF 04-13”). EITF 04-13 In EITF 04-13, the Task Force reached a tentative conclusion that inventory purchases and sales transactions with the same counterparty that are entered into in contemplation of one another should be combined for purposes of applying Accounting Principles Board Opinion No. 29, “Accounting for Nonmonetary Transactions.” The tentative conclusions reached by the Task Force are required to be applied to transactions completed in reporting periods beginning after March 15, 2006. The adoption of this EITF will not have a material impact on our results of operations, financial position or cash flows.

FSP FAS 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation That Allows for Cash Settlement upon the Occurrence of a Contingent Event”, (“FSP 123R4”) In February 2006, the FASB issued this Staff Position to address the classification of options and similar instruments issued as employee compensation that allow for cash settlement upon the occurrence of a contingent event. The guidance amends SFAS 123(R). FSP 123R4 provides that cash settlement features that can be exercised only upon the occurrence of a contingent event that is outside the employee’s control does not require classifying the option or similar instrument as a liability until it becomes probable that the event will occur. FSP 123R4 applies only to options or similar instruments issued as part of employee compensation arrangements. The guidance in FSP 123R4 is effective immediately. The adoption of FSP 123R4 had no impact on us.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

The information contained in Item 3 updates and should be read in conjunction with information set forth in Part II, Item 7A in our Annual Report on Form 10-K for the year ended August 31, 2005, as amended on Form 10-K/A as filed with the Securities and Exchange Commission on November 14, 2005, and December 12, 2005, respectively, in addition to the interim unaudited consolidated financial statements, accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K.

The following table provides a summary of our commodity-related price risk management assets and liabilities at February 28, 2006:


	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Mark to Market Derivatives

(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(10,194,105	)	2006-2009	$	(10,038	)

Swing Swaps IFERC	Gas	(66,692,579	)	2006-2008	$	3,391

Fixed Swaps/Futures	Gas	750,000		2006-2007	$	50,391

Options	Gas	(1,392,000	)	2006-2008	$	27,324

Forward Physical Contracts	Gas	(12,632,000	)	2006-2008	$	(27,324	)

(Trading)
Basis Swaps IFERC/NYMEX	Gas	4,657,500		2006-2007	$	28,650

Swing Swaps IFERC	Gas	775,000		2006	$	(425	)

Forward Physical Contracts	Gas	(678,900	)	2006	$	(191	)

Cash Flow Hedging Derivatives

(Non-Trading)
Fixed Swaps/Futures	Gas	(17,552,500	)	2006-2007	$	23,237

Fixed Index Swaps	Gas	1,090,000		2006	$	2,092

Basis Swaps IFERC/NYMEX	Gas	(14,155,000	)	2006-2007	$	2,665

Credit Risk

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

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

Sensitivity analysis

The table below summarizes our commodity-related financial derivative instruments and fair values as of February 28, 2006. It also assumes a hypothetical 10% change in the underlying price of the commodity and its effect.


	Notional Volume MMBTU		Fair Value			Effect of Hypothetical 10% Change
Non-Trading Derivatives:
Fixed Swaps/Futures	(16,802,500	)	$	73,628		$	17,675
Basis Swaps IFERC/NYMEX	(24,349,105	)	$	(7,373	)	$	1,522
Fixed Index Swaps	1,090,000		$	2,092		$	726
Options	(1,392,000	)	$	27,324		$	7,340
Swing Swaps IFERC	(66,692,579	)	$	3,391		$	167
Forward Physical Contracts	(12,632,000	)	$	(27,324	)	$	7,340

Trading Derivatives:
Basis Swaps IFERC/NYMEX	4,657,500		$	28,650		$	687
Fixed Index Swaps	775,000		$	(425	)	$	36
Forward Physical Contracts	(678,900	)	$	(191	)	$	251

Interest Rate Risk

We are exposed to changes in interest rates, primarily as a result of our variable rate debt and, in particular, our revolving credit facility. To the extent interest rates increase, our interest expense for our revolving debt will also increase. At February 28, 2006, we had $121.2 million of variable rate debt outstanding that is not hedged. A hypothetical change of 100 basis points in the underlying interest rate would have an effect of $1.2 million in increased interest expense on an annual basis.

Treasury locks with a notional amount of $200.0 million were outstanding as of February 28, 2006 and had a fair value of $4.8 million which was recorded as unrealized gains in OCI and a component of price risk management assets on the condensed consolidated balance sheet. A hypothetical change of 100 basis points on the underlying interest rates of the treasury locks outstanding at February 28, 2006 would have an effect of $15.5 million on the value of the locks. We expect to enter into additional treasury locks and similar financial instruments in the future.

We also have long-term debt instruments which are typically issued at fixed interest rates. Prior to or when these debt obligations mature, we may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.

ITEM 4. CONTROLS AND PROCEDURES

An evaluation was performed under the supervision and with the participation of our management, including the Co-Chief Executive Officers and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a–15(e) and 15d–15(e) of the Securities Exchange Act of 1934, as amended) as of February 28, 2006. Our management, including the Co-Chief Executive Officers and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. The inherent limitations in all control systems include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Based upon the evaluation, our management, including the Co-Chief Executive Officers and Chief Financial Officer of our General Partner, concluded that our disclosure controls and procedures are adequate and effective to ensure that information required to be disclosed by us in our periodic filings under the Securities and Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)–15 or Rule 15d–15(f) of the Exchange Act) during the three months ended February 28, 2006 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II OTHER INFORMATION

ITEM 6. EXHIBITS

(a)

Exhibits

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


	Exhibit Number	Description
(1)	3.1	Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(8)	3.1.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(13)	3.1.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(16)	3.1.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(16)	3.1.4	Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(21)	3.1.5	Amendment No. 5 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(21)	3.1.6	Amendment No. 6 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(34)	3.1.7	Amendment No. 7 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(35)	3.1.8	Amendment No. 8 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(1)	3.2	Agreement of Limited Partnership of Heritage Operating, L.P.

(10)	3.2.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

(16)	3.2.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

(21)	3.2.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

(21)	3.3	Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P.

(15)	3.4	Amended Certificate of Limited Partnership of Heritage Operating, L.P.

(17)	4.1	Registration Rights Agreement for Limited Partner Interests of Heritage Propane Partners, L.P.

(21)	4.2	Unitholder Rights Agreement dated January 20, 2004 among Heritage Propane Partners, L.P., Heritage Holdings, Inc., TAAP LP and La Grange Energy, L.P.

(27)	4.3	Indenture dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.

(28)	4.4	First Supplemental Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors names therein and Wachovia Bank, National Association, as trustee.

(37)	4.5	Second Supplemental Indenture dated as of February 24, 2005 to Indenture dated as of January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.


		Exhibit Number	Description
(38)		4.6	Notation of Guaranty.

(29)		4.7	Registration Rights Agreement, dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors and Wachovia Bank, National Association as trustee.

(39)		4.8	Joinder to Registration Rights Agreement, dated February 24, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors and Wachovia Bank, National Association as trustee.

(41)		4.9	Third Supplemental Indenture dated as of July 29, 2005 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.

(42)		4.10	Registration Rights Agreement, dated July 29, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and the initial purchasers thereto.

(1)		10.2	Form of Note Purchase Agreement (June 25, 1996).

(2)		10.2.1	Amendment of Note Purchase Agreement (June 25, 1996) dated as of July 25, 1996.

(3)		10.2.2	Amendment of Note Purchase Agreement (June 25, 1996) dated as of March 11, 1997.

(5)		10.2.3	Amendment of Note Purchase Agreement (June 25, 1996) dated as of October 15, 1998.

(6)		10.2.4	Second Amendment Agreement dated September 1, 1999 to June 25, 1996 Note Purchase Agreement.

(9)		10.2.5	Third Amendment Agreement dated May 31, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.

(8)		10.2.6	Fourth Amendment Agreement dated August 10, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.

(11)		10.2.7	Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.

(21)		10.2.8	Sixth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.

(1)		10.3	Form of Contribution, Conveyance and Assumption Agreement among Heritage Holdings, Inc., Heritage Propane Partners, L.P. and Heritage Operating, L.P.

(15)	**	10.6.3	Second Amended and Restated Restricted Unit Plan dated as of February 4, 2002.

(25)	**	10.6.4	2004 Unit Plan.

(26)	**	10.6.5	Form of Grant Agreement.

(4)		10.16	Note Purchase Agreement dated as of November 19, 1997.

(5)		10.16.1	Amendment dated October 15, 1998 to November 19, 1997 Note Purchase Agreement.

(6)		10.16.2	Second Amendment Agreement dated September 1, 1999 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.

(7)		10.16.3	Third Amendment Agreement dated May 31, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.

(8)		10.16.4	Fourth Amendment Agreement dated August 10, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.

(11)		10.16.5	Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.


	Exhibit Number	Description
(22)	10.16.6	Sixth Amendment Agreement dated as of November 18, 2003 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.

(8)	10.17	Contribution Agreement dated June 15, 2000 among U.S. Propane, L.P., Heritage Operating, L.P. and Heritage Propane Partners, L.P.

(8)	10.17.1	Amendment dated August 10, 2000 to June 15, 2000 Contribution Agreement.

(8)	10.18	Subscription Agreement dated June 15, 2000 between Heritage Propane Partners, L.P. and individual investors.

(8)	10.18.1	Amendment dated August 10, 2000 to June 15, 2000 Subscription Agreement.

(13)	10.18.2	Amendment Agreement dated January 3, 2001 to the June 15, 2000 Subscription Agreement.

(14)	10.18.3	Amendment Agreement dated October 5, 2001 to the June 15, 2000 Subscription Agreement.

(8)	10.19	Note Purchase Agreement dated as of August 10, 2000.

(11)	10.19.1	Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.

(12)	10.19.2	First Supplemental Note Purchase Agreement dated as of May 24, 2001 to the August 10, 2000 Note Purchase Agreement.

(22)	10.19.3	Sixth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.

(15)	10.26	Assignment, Conveyance and Assumption Agreement between U.S. Propane, L.P. and Heritage Holdings, Inc., as the former General Partner of Heritage Propane Partners, L.P. dated as of February 4, 2002.

(15)	10.27	Assignment, Conveyance and Assumption Agreement between U.S. Propane, L.P. and Heritage Holdings, Inc., as the former General Partner of Heritage Operating, L.P., dated as of February 4, 2002.

(18)	10.28	Assignment for Contribution of Assets in Exchange for Partnership Interest dated December 9, 2002 amount V-1 Oil Co., the shareholders of V-1 Oil Co., Heritage Propane Partners, L.P. and Heritage Operating, L.P.

(19)	10.30	Acquisition Agreement dated November 6, 2003 among the owners of U.S. Propane, L.P. and U.S. Propane, L.L.C. and La Grange Energy, L.P.

(19)	10.31	Contribution Agreement dated November 6, 2003 among La Grange Energy, L.P. and Heritage Propane Partners, L.P. and U.S. Propane, L.P.

(20)	10.31.1	Amendment No. 1 dated December 7, 2003 to Contribution Agreement dated November 6, 2003 among La Grange Energy, L.P. and Heritage Propane Partners, L.P. and U.S. Propane, L.P.

(19)	10.32	Stock Purchase Agreement dated November 6, 2003 among the owners of Heritage Holdings, Inc. and Heritage Propane Partners, L.P.

(23)	10.35	Purchase and Sale Agreement between TXU Fuel Company and Energy Transfer Partners, L.P. dated April 25, 2004.

(23)	10.35.1	First Amendment to Purchase and Sale Agreement and Closing Agreement between TXU Fuel Company and Energy Transfer Partners, L.P. dated June 1, 2004.

(24)	10.36	Third Amended and Restated Credit Agreement amount Heritage Operating L.P. and the Banks dated March 31, 2004.


		Exhibit Number	Description
(30)		10.40	Credit Agreement, dated January 18, 2005, among Energy Transfer Partners, L.P., Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Fleet National Bank, as syndication agent, BNP Paribas and The Royal Bank of Scotland, PLC, as co-documentation agents, and other lenders party thereto.

(40)		10.40.1	First Amendment, dated as of February 24, 2005, to Credit Agreement, dated January 18, 2005, among Energy Transfer Partners, L.P., Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Fleet National Bank, as syndication agent, BNP Paribas and The Royal Bank of Scotland, PLC, as co-documentation agents, and other lenders party thereto.

(31)		10.41	Guaranty, dated January 18, 2005, by the Subsidiary Guarantors in favor of Wachovia Bank, National Association, as the administrative agent for the lenders.

(40)		10.41.1	Guaranty Supplement dated February 24, 2005.

(32)		10.42	Purchase and Sale Agreement, dated January 26, 2005, among HPL Storage, LP and AEP Energy Services Gas Holding Company II, L.L.C., as Sellers and La Grange Acquisition, L.P., as Buyer.

(33)		10.43	Cushion Gas Litigation Agreement, dated January 26, 2005, by and among AEP Energy Services Gas Holding Company II, L.L.C. and HPL Storage LP, as Sellers, and La Grange Acquisition, L.P., as Buyer, and AEP Asset Holdings LP, AEP Leaseco LP, Houston Pipe Line Company, LP and HPL Resources Company LP, as Companies.

(36)		10.44	Loan Agreement, dated as of January 26, 2005 between La Grange Acquisition, L.P., as Borrower, and La Grange Energy, L.P., as Lender.

(43)	**	10.45	Summary of Director Compensation.

(44)		10.46	Credit Agreement, effective as of December 13, 2005, among the Partnership, Wachovia Bank, National Association as administrative agent, LC issuer and swingline lender, Bank of America, N.A. and Citibank, N.A., as co-syndication agents. BNP Paribas and The Royal Bank of Scotland PLC New York Branch, as co-documentation agents, and the other lenders party thereto.

(45)		10.47	Guaranty, effective as of December 13, 2005, by the Subsidiary Guarantors in favor of Wachovia Bank, National Association, as administrative agent for the lenders.

(43)		21.1	List of Subsidiaries.

(*)		31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(*)		31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(*)		32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(*)		32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(*)		99.1	Financial Statements of Energy Transfer Partners GP, L.P. as of February 28, 2006

(*)		99.2	Financial Statements of Energy Transfer Partners, L.L.C. as of February 28, 2006

*	Filed herewith.

**	Denotes a management contract or compensatory plan or arrangement.

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

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

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

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

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

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

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

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

(9)	File as Exhibit 10.16.3.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(26)	Incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed November 1, 2004.

(27)	Incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed January 19, 2005.

(28)	Incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed January 19, 2005.

(29)	Incorporated by reference to Exhibit 4.3 to the Registrant’s Form 8-K filed January 19, 2005.

(30)	Incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed January 19, 2005.

(31)	Incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed January 19, 2005.

(32)	Incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed February 1, 2005.

(33)	Incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed February 1, 2005.

(34)	Incorporated by reference to Exhibit 3.1.7 to the Registrant’s Form 8-K filed March 16, 2005.

(35)	Incorporated by reference to Exhibit 3.1.8 to the Registrant’s Form 8-K filed February 9, 2006.

(36)	Incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed March 17, 2005.

(37)	Incorporated by reference to Exhibit 10.45 to the Registrant’s Form 10-Q for the quarter ended February 28, 2005.

(38)	Incorporated by reference to Exhibit 10.46 to the Registrant’s Form 10-Q for the quarter ended February 28, 2005.

(39)	Incorporated by reference to Exhibit 10.39.1 to the Registrant’s Form 10-Q for the quarter ended February 28, 2005.

(40)	Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended February 29, 2005.

(41)	Incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed August 2, 2005.

(42)	Incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed August 2, 2005.

(43)	Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K/A for the year ended August 31, 2005.

(44)	Incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed December 16, 2005.

(45)	Incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed December 16, 2005.

SIGNATURE

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


	ENERGY TRANSFER PARTNERS, L.P.

	By:	Energy Transfer Partners, GP, L.P.,
		its General Partner

	By:	Energy Transfer Partners, L.L.C., its General Partner

Date: April 10, 2006	By:	/s/ H. Michael Krimbill
		H. Michael Krimbill
		(President and officer duly authorized to sign on behalf of the registrant)