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 November 30, 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 and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

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 January 7, 2007, the registrant had units outstanding as follows:


Energy Transfer Partners, L.P.		110,890,596 Common Units
		26,086,957 Class G 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 – November 30, 2006 and August 31, 2006	1

	Condensed Consolidated Statements of Operations – Three Months Ended November 30, 2006 and 2005	3

	Consolidated Statements of Comprehensive Income (Loss) – Three Months Ended November 30, 2006 and 2005	4

	Consolidated Statement of Partners’ Capital – Three Months Ended November 30, 2006	5

	Condensed Consolidated Statements of Cash Flows – Three Months Ended November 30, 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	37

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	48

ITEM 4.	CONTROLS AND PROCEDURES	49

PART II	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	50

ITEM 1A.	RISK FACTORS	50

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	52

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	52

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	52

ITEM 5.	OTHER INFORMATION	52

ITEM 6.	EXHIBITS	52

SIGNATURES		59

Forward-Looking Statements

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

Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see the Partnership’s Annual Report on Form 10-K for the fiscal year ended August 31, 2006 filed with the Securities and Exchange Commission on November 13, 2006.

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

Dekatherm		million British thermal units. A therm factor is used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used.

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)


	November 30, 2006		August 31, 2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	34,746	$	26,041
Marketable securities		2,596		2,817
Accounts receivable, net of allowance for doubtful accounts		598,854		675,545
Accounts receivable from related companies		1,239		897
Inventories		499,648		387,140
Deposits paid to vendors		79,227		87,806
Exchanges receivable		28,045		23,221
Price risk management assets		30,099		56,139
Prepaid expenses and other		40,414		42,198

Total current assets		1,314,868		1,301,804

PROPERTY, PLANT AND EQUIPMENT, net		3,566,558		3,313,649
ADVANCES TO AND INVESTMENT IN AFFILIATES		999,056		41,344
GOODWILL		603,035		604,409
INTANGIBLES AND OTHER LONG-TERM ASSETS, net		191,230		193,807

Total assets	$	6,674,747	$	5,455,013

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)


	November 30, 2006		August 31, 2006
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	580,176	$	603,140
Accounts payable to related companies		1,742		650
Exchanges payable		32,580		24,722
Customer advances and deposits		101,771		108,836
Accrued and other current liabilities		248,613		201,646
Price risk management liabilities		43,359		36,918
Current maturities of long-term debt		40,828		40,578

Total current liabilities		1,049,069		1,016,490

LONG-TERM DEBT, less current maturities		2,548,344		2,589,124
DEFERRED INCOME TAXES		107,438		106,842
OTHER NON-CURRENT LIABILITIES		7,587		5,695

COMMITMENTS AND CONTINGENCIES

		3,712,438		3,718,151

PARTNERS’ CAPITAL:
General Partner		117,631		82,450
Limited Partners:
Common Unitholders (110,889,264 and 110,726,999 units authorized, issued and outstanding at November 30, 2006 and August 31, 2006, respectively)		1,583,799		1,647,345
Class E Unitholders (8,853,832 units authorized, issued and outstanding at November 30, 2006 and August 31, 2006 – held by subsidiary and reported as treasury units)		—		—
Class G Unitholders (26,086,957 and 0 units authorized, issued and outstanding at November 30, 2006 and August 31, 2006, respectively)		1,201,276		—

		2,902,706		1,729,795

Accumulated other comprehensive income, per accompanying statements		59,603		7,067

Total partners’ capital		2,962,309		1,736,862

Total liabilities and partners’ capital	$	6,674,747	$	5,455,013

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 November 30,
	2006			2005
REVENUES:
Midstream and transportation and storage	$	1,062,444		$	2,208,533
Propane and other		326,001			208,087

Total revenues		1,388,445			2,416,620

COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage		883,983			1,959,368
Cost of products sold, propane and other		203,360			131,259
Operating expenses		132,381			102,671
Depreciation and amortization		33,809			26,913
Selling, general and administrative		27,070			24,799

Total costs and expenses		1,280,603			2,245,010

OPERATING INCOME		107,842			171,610

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(41,462	)		(28,393	)
Equity in earnings (losses) of affiliates		4,887			(274	)
Gain (loss) on disposal of assets		1,944			(128	)
Interest and other income, net		1,671			959

INCOME BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS		74,882			143,774

Income tax expense		3,596			22,411

INCOME BEFORE MINORITY INTERESTS		71,286			121,363

Minority interests		(254	)		(1,555	)

NET INCOME		71,032			119,808

GENERAL PARTNER’S INTEREST IN NET INCOME		53,301			20,483

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	17,731		$	99,325

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.15		$	0.76

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		119,487,795			106,894,514

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.15		$	0.76

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		119,779,848			107,180,936

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 (LOSS)

(in thousands)

(unaudited)


	Three Months Ended November 30,
	2006			2005
Net income	$	71,032		$	119,808

Other comprehensive income:
Reclassification adjustment for gains and losses on derivative instruments included in net income accounted for as cash flow hedges, before taxes of $(4) and $698		(455	)		100,550
Change in value of derivative instruments accounted for as cash flow hedges, before taxes of $530 and $185		53,736			26,731
Change in value of available-for-sale securities, before taxes of $(2) and ($1)		(221	)		(132	)
Change in income tax expense related to items of other comprehensive income		(524	)		(882	)

Comprehensive income	$	123,568		$	246,075

Reconciliation of Accumulated Other Comprehensive Income (Loss)
Balance, beginning of period	$	7,067		$	(85,317	)

Current period reclassification to earnings		(451	)		99,852
Current period change in value		52,987			26,415

Balance, end of period	$	59,603		$	40,950

Components of Accumulated Other Comprehensive Income (Loss)

Other comprehensive income (loss) related to:
Commodity related derivative hedges, net of taxes of $645 and $185	$	63,798		$	37,618
Interest rate derivative hedges, net of taxes of ($5) and $698		(4,277	)		2,528
Available-for-sale securities, net of taxes of ($3) and ($1)		82			804

Balance, end of period	$	59,603		$	40,950

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 Three months Ended November 30, 2006

(in thousands)

(unaudited)


				Limited Partners
	General Partner			Common Unitholders			Class G Unitholders
Balance, August 31, 2006	$	82,450		$	1,647,345		$	—
Distributions to partners		(42,609	)		(83,165	)		—
Issuance of Class G units to Energy Transfer Equity, LP		—			—			1,200,000
General Partner capital contribution		24,489			—			—
Unit-based compensation expense		—			3,164			—
Net income		53,301			16,455			1,276

Balance, November 30, 2006	$	117,631		$	1,583,799		$	1,201,276

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)


	Three Months Ended November 30,
	2006			2005
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	174,452		$	11,717

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		(32,839	)		(27,856	)
Working capital settlement on prior year acquisitions		—			19,653
Capital expenditures		(237,113	)		(87,069	)
Advances to and investment in affiliates		(952,825	)		—
Proceeds from the sale of assets		7,519			541

Net cash used in investing activities		(1,215,258	)		(94,731	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,591,315			635,792
Principal payments on debt		(1,631,383	)		(491,867	)
Net proceeds from issuance of Class G Units		1,200,000			—
Capital contribution from General Partner		24,489			—
Distributions to partners		(125,774	)		(67,806	)
Debt issuance costs		(9,136	)		(104	)

Net cash provided by financing activities		1,049,511			76,015

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		8,705			(6,999	)

CASH AND CASH EQUIVALENTS, beginning of period		26,041			24,914

CASH AND CASH EQUIVALENTS, end of period	$	34,746		$	17,915

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, 2006, 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 as of November 30, 2006 and for the three months ended November 30, 2006 and 2005, 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, management 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 November 30, 2006, and the Partnership’s results of operations and cash flows for the three-month periods ended November 30, 2006 and 2005, respectively. 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, 2006, as filed with the Securities and Exchange Commission on November 13, 2006.

Certain prior period amounts have been reclassified to conform to the 2006 presentation. These reclassifications have no impact on net income or total partners’ capital.

Business Operations

In order to simplify the obligations of Energy Transfer Partners, L.P. under the laws of several jurisdictions in which we conduct business, our activities are conducted through three 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 engaged in midstream and transportation and storage natural gas operations, Heritage Operating L.P. (“HOLP”), a Delaware limited partnership engaged in retail and wholesale propane operations, and Titan Energy Partners, LP (“Titan”), a Delaware limited partnership engaged in retail propane operations (collectively the “Operating Partnerships”). The Partnership, the Operating Partnerships, and their other subsidiaries are collectively referred to in this report as “we”, “us”, “ETP”, “Energy Transfer” or the “Partnership”. Subsequent to November 30, 2006 and in connection with the final step to acquire the Transwestern Pipeline, Transwestern Pipeline Company, LLC became an operating partnership. See Note 3.

2.	ESTIMATES AND SIGNIFICANT ACCOUNTING POLICIES:

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) 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 months ended November 30, 2006 represents the actual results in all material respects.

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

Regulatory Assets and Liabilities

As a result of our acquisition of Transwestern on December 1, 2006, we will be subject to regulation by certain state and federal authorities. Transwestern will become part of our interstate transportation segment and will have accounting policies that conform to FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation, which will be in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies will allow us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the Consolidated Statement of Operations by an unregulated company. These deferred assets and liabilities will be reported in our results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheet and would be included in the Consolidated Statement of Operations for the period in which the discontinuance of regulatory accounting treatment occurs.

New Accounting Standards

FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. Earlier application is permitted as long as the enterprise has not yet issued financial statements, including interim financial statements, in the period of adoption. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that fiscal year. We are currently evaluating FIN 48 and have not yet determined the impact of such on our financial statements. We plan to adopt this statement on September 1, 2007.

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. Management adopted the provisions of SFAS 154 September 1,

2006, as required. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors that occur in the future, but management does not expect SFAS 154 to have a material impact on our consolidated results of operations, cash flows or financial position.

SFAS No. 155, Accounting for Certain Hybrid Financial Instruments – An Amendment of FASB Statements No. 133 and 140 (“SFAS 155”). SFAS 155 is effective for all financial instruments acquired, issued, or subject to a remeasurement (new basis) event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Early application is permitted only if: (a) it occurs at the beginning of an entity’s fiscal year and (b) the entity has not yet issued any interim or annual financial statements for that fiscal year. We intend to adopt this statement when required at the start of fiscal year beginning September 1, 2007. The adoption of this statement is not expected to have a significant impact on us.

SFAS No. 157, Fair Value Measurement, (“SFAS 157”). This new standard provides guidance for using fair value to measure assets and liabilities. The FASB believes the standard also responds to investors’ requests for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The standard clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. Under SFAS 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. In this standard, the FASB clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, SFAS 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including any financial statements for an interim period within that fiscal year. We are currently evaluating this statement and have not yet determined the impact of such on our financial statements. We plan to adopt this statement when required at the start of our fiscal year beginning September 1, 2008.

EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (that is, Gross Versus Net Presentation) (“EITF 06-3”). This accounting guidance requires companies to disclose their policy regarding the presentation of tax receipts on the face of their income statements. The scope of this guidance includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and some excise taxes (gross receipts taxes are excluded). This guidance is effective for interim and annual reporting periods beginning after December 15, 2006 with earlier application permitted. As a matter of policy, we report such taxes on a net basis. We will adopt this EITF during our 2007 fiscal year.

SEC Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB No. 108”). In September 2006, the Securities and Exchange Commission (SEC) provided guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB No. 108 establishes a dual approach that requires quantification of financial statement errors based on the effects of the error on each of the company’s financial statements and the related financial statement disclosures. SAB No. 108 is effective for fiscal years ending after November 15, 2006. We are presently reviewing the impact of the adoption of SAB 108. However, we do not expect such adoption to have a material impact on our consolidated financial statements. We expect to adopt SAB 108 by August 31, 2007.

3.	SIGNIFICANT ACQUISITIONS:

Fiscal year 2007 acquisitions

In September 2006 we acquired two small gathering systems in east and north Texas for an aggregate purchase price of $30,589 in cash. The purchase and sale agreement for the gathering system in north Texas also has a contingent payment not to exceed $25,000 to be determined eighteen months from the closing date. We will record the required adjustment to the purchase price allocation when the amount of actual contingent consideration is determinable beyond a reasonable doubt. These systems provide us with additional capacity in the Barnett Shale and in the Travis Peak area of east Texas and are included in our midstream operating segment. The cash paid for acquisitions was financed primarily from the ETP Revolving Credit Facility. In the aggregate, these acquisitions were not material for pro forma disclosure purposes.

On November 1, 2006, pursuant to agreements entered into with GE Energy Financial Services (“GE”) and Southern Union Company (“Southern Union”), we acquired the member interests in CCE Holdings, LLC (“CCEH”) from GE and certain other investors for $1,000,000. The member interests acquired represented a 50% ownership in CCEH. CCEH owns, among other pipelines, Transwestern Pipeline, a 2,500 mile interstate natural gas pipeline. In a second and related transaction, CCEH redeemed ETP’s 50% interest ownership in CCEH in exchange for 100% ownership of Transwestern Pipeline Company, LLC (“Transwestern”) on December 1, 2006, following which Southern Union owned all of the member interests of CCEH. Following the final step, Transwestern became a new operating subsidiary of ETP. In connection with the December 1 transaction, we assumed approximately $520,000 of long-term indebtedness of Transwestern and received cash of approximately $55,000 (of which $48,763 was received prior to November 30, 2006 from CCEH and was recorded as a reduction of our equity investment in CCEH). We financed a portion of the purchase price with the proceeds from our issuance of 26,086,957 Class G Units to Energy Transfer Equity, L.P. simultaneous with the closing on November 1, 2006.

During the quarter ended November 30, 2006, HOLP and Titan collectively acquired substantially all of the assets of two propane businesses. The aggregate purchase price for these acquisitions totaled $2,592 which included $2,250 of cash paid, net of cash acquired, and liabilities assumed of $342. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. The cash paid for acquisitions was financed primarily with the Senior Revolving Acquisition Facilities.

Except for the acquisition of the 50% member interests in CCEH, these acquisitions were accounted for under the purchase method of accounting in accordance with SFAS No. 141 and the purchase prices were allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition. The acquisition of the 50% member interest in CCEH was accounted for under the equity method of accounting in accordance with APB Opinion No. 18 as discussed below. As a result of the December 1 transaction noted above, the acquisition of 100% of Transwestern will be accounted for under the purchase method of accounting as of December 1, 2006. Pro forma effects of the CCEH acquisition (using the equity method of accounting) are discussed below.

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed based on their fair values for these acquisitions occurring during the period ended November 30, 2006:


	Midstream and Transportation and Storage Acquisitions (Aggregated)		Propane Acquisitions (Aggregated)
Accounts receivable	$	—	$	108
Inventory		—		43
Prepaid and other current assets		—		24
Property, plant, and equipment		30,589		1,207
Intangibles and other assets		—		475
Goodwill		—		735

Total assets acquired		30,589		2,592

Customer advances and deposits		—		(26	)
Long-term debt		—		(316	)

Total liabilities assumed		—		(342	)

Net assets acquired	$	30,589	$	2,250

We recorded the following intangible assets in conjunction with these acquisitions:


Customer lists (15 years)	$	159
Non-compete agreements (10 years)		316

Total amortized intangible assets		475

Goodwill		735

Total intangible assets and goodwill acquired	$	1,210

Goodwill was warranted because these acquisitions enhance our current operations, and certain acquisitions are expected to reduce costs through synergies with existing operations. We expect all of the goodwill acquired to be tax deductible.

Fiscal year 2006 acquisitions

On June 1, 2006, we acquired all the propane operations of Titan for cash of approximately $548,000, after working capital adjustments and net of cash acquired, and liabilities assumed of approximately $46,000. We accounted for the Titan acquisition as a business combination using the purchase method of accounting in accordance with the provisions of SFAS 141. The purchase price has been initially allocated based on the estimated fair value of the individual assets acquired and the liabilities assumed at the date of the acquisition based on the preliminary results of an independent appraisal. We expect to complete the purchase allocation during our second quarter of fiscal year 2007 upon the completion of the independent appraisal. The Titan operations have been included since the date of acquisition, thus the condensed consolidated results of operations for the three months ended November 30, 2006 include the Titan results of operations for the entire period. However, the three months ended November 30, 2005 does not include any of the Titan results of operations.

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the three months ended November 30, 2006 and 2005 are presented as if the CCEH acquisition had been made on September 1, 2005.


	Three Months Ended November 30,
	2006		2005
Revenues	$	1,388,445	$	2,416,620
Net income	$	79,536	$	125,438
Limited Partners’ interest in net income	$	26,066	$	100,469
Basic earnings per Limited Partner Unit	$	0.19	$	0.76
Diluted earnings per Limited Partner Unit	$	0.19	$	0.67

The pro forma consolidated results of operations include adjustments to give effect to depreciation of the equity basis difference allocated to depreciable and amortizable assets, interest expense on acquisition debt, and certain other adjustments. The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

4.	INVESTMENTS IN AFFILIATES:

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

We record our share of net income or loss from these equity investments in Equity in Earnings of Affiliates in our condensed consolidated statement of operations. The balance of our advances to and investments in affiliates at November 30, 2006 consisted primarily of our investment in CCEH of $956,348 and advances to and investments in other equity affiliates of $42,708. Our equity investment in CCEH includes equity earnings

since our acquisition on November 1, 2006 of approximately $5,100 and is net of $48,763 in distributions received from CCEH prior to November 30, 2006.

The following table presents summarized financial information of CCEH since the date of our acquisition (November 1, 2006):


	For the One Month Ended November 30, 2006
Revenues	$	19,361

Operating income	$	10,018

Equity earnings	$	5,202

Net Income	$	10,949

Our 50% share of net income	$	5,474
Less - amortization of our investment in excess of net assets allocated to property and equipment for November, 2006		(363	)

Reported equity earnings	$	5,111

5.	CASH, CASH EQUIVALENTS AND SUPPLEMENTAL CASH FLOW INFORMATION:

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

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

The net change in cash due to changes in operating assets and liabilities (net of acquisitions) is comprised as follows:


	Three Months Ended November 30,
	2006			2005
Net income	$	71,032		$	119,808

Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		33,809			26,913
Amortization of finance costs charged to interest		839			677
Provision for loss on accounts receivable		390			127
Non-cash compensation on unit grants		3,164			447
Deferred income taxes		106			5,928
(Gain) loss on disposal of assets		(1,944	)		128
Undistributed earnings of affiliates, net		(4,887	)		271
Minority interests		144			1,495
Changes in assets and liabilities:
Accounts receivable		75,630			(62,306	)
Accounts receivable from related companies		(341	)		2,818
Inventories		(112,465	)		(279,042	)
Deposits paid to vendors		8,579			(1,278	)
Exchanges receivable		(4,824	)		6,819
Prepaid expenses and other		1,809			(15,095	)
Intangibles and other long-term assets		733			103
Accounts payable		(14,512	)		123,362
Accounts payable to related companies		1,092			(700	)
Customer advances and deposits		(7,092	)		(62,144	)
Exchanges payable		7,858			991
Accrued and other current liabilities		27,784			37,622
Other long-term liabilities		2,713			(961	)
Income taxes payable		1,190			13,065
Price risk management liabilities, net		83,645			92,669

Net cash provided by operating activities	$	174,452		$	11,717

Supplemental cash flow information is as follows:


	Three Months Ended November 30,
	2006		2005
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest, net of $4,802 and $307 capitalized for November 30, 2006 and 2005, respectively	$	22,695	$	10,654

Cash paid during the period for income taxes	$	3,037	$	3,007

6.	ACCOUNTS RECEIVABLE:

Our 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, prepayment, or master set off agreement). Management reviews midstream and transportation and storage accounts receivable balances bi-weekly. Credit limits are assigned and monitored for all counterparties of the midstream and transportation and storage operations. Management believes that the occurrence of bad debts in our midstream and transportation and storage segments was not significant for the three months ended November 30, 2006 therefore, an allowance for doubtful accounts for the midstream and transportation and storage segments was not deemed necessary. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. There was no bad debt expense recognized for the three months ended November 30, 2006 and 2005 in the midstream and transportation and storage segments.

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

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

Accounts receivable consisted of the following:


	November 30, 2006			August 31, 2006
Accounts receivable - midstream and transportation and storage	$	470,191		$	570,569
Accounts receivable - propane		132,880			108,976
Less - allowance for doubtful accounts		(4,217	)		(4,000	)

Total, net	$	598,854		$	675,545

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


	November 30, 2006			August 31, 2006
Balance, beginning of the period	$	4,000		$	4,076
Provision for loss on accounts receivable		390			1,723
Accounts receivable written off, net of recoveries		(173	)		(1,799	)

Balance, end of period	$	4,217		$	4,000

7.	INVENTORIES:

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


	November 30, 2006		August 31, 2006
Natural gas, propane and other NGLs	$	483,936	$	371,430
Appliances, parts and fittings and other		15,712		15,710

Total inventories	$	499,648	$	387,140

8.	GOODWILL:

Goodwill is associated with acquisitions made for our midstream, transportation and storage, and retail propane segments. Goodwill is tested for impairment annually at August 31, in accordance with Statement of Accounting Standards No. 142, Goodwill and Other Intangible Assets, (“SFAS 142”). The changes in the carrying amount of goodwill for the three month period ended November 30, 2006 were as follows:


	Midstream		Transportation and Storage		Retail Propane			Total
Balance, beginning of period	$	13,409	$	10,327	$	580,673		$	604,409
Purchase accounting adjustments		—		—		(367	)		(367	)
Goodwill acquired		—		—		735			735
Sale of operations		—		—		(1,742	)		(1,742	)

Balance, end of period	$	13,409	$	10,327	$	579,299		$	603,035

The final assessment of asset values related to the Titan acquisition is expected to be completed in the second quarter of fiscal year 2007 upon the completion of the final independent appraisal. There is no guarantee that the preliminary allocation will not change.

9.	INCOME TAXES:

As a limited partnership, we are generally not subject to income tax. We are, however, subject to a statutory requirement that our non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of our total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation. Accordingly, certain activities that generate non-qualified income are conducted through taxable corporate subsidiaries (“C corporations”). These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the periods ended November 30, 2006 and 2005, our non-qualifying income did not, or was not expected to, exceed the statutory limit.

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

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


	Three Months Ended November 30,
	2006		2005
Current provision:
Federal	$	3,151	$	15,264
State		340		338

		3,491		15,602

Deferred provision:
Federal		69		6,663
State		36		146

Total		105		6,809

Total Tax Provision	$	3,596	$	22,411

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


	Three Months Ended November 30,
	2006		2005
Federal statutory tax rate	35.0	%	35.0	%
State income tax rate net of federal benefit	3.5	%	3.6	%
Earnings not subject to tax at the Partnership level	(33.7	)%	(23.0	)%

Effective tax rate	4.8	%	15.6	%

10.

INCOME PER LIMITED PARTNER UNIT:

Our 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 priority income allocations for incentive distributions, if any, to our 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. Basic net income per limited partner unit, however, is computed in accordance with EITF Issue No. 03-6, Participating Securities and the Two-Class method under FASB Statement No. 128 (“EITF 03-6”), by dividing limited partners’ interest in net income by the weighted average number of Common and Class G Units outstanding. In periods when our aggregate net income exceeds the aggregate distributions, EITF 03-6 requires us to present earnings per unit as if all of the earnings for the periods were distributed (see table below) and requires a separate computation for each quarter and year-to-date. 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 we distribute to our limited partners with respect to any quarter exceeds levels specified in the Partnership Agreement. 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 G Units outstanding and of 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 November 30,
	2006			2005
Net income	$	71,032		$	119,808
Adjustments:
General Partner’s incentive distributions		(51,880	)		(18,087	)
General Partner’s equity ownership		(1,421	)		(2,396	)

Limited Partner’s interest in net income		17,731			99,325
Additional earnings allocation to General Partner		—			(18,300	)

Net income available to limited partners	$	17,731		$	81,025

Weighted average limited partner units – basic		119,487,795			106,894,514

Basic net income per limited partner unit	$	0.15		$	0.76

Weighted average limited partner units		119,487,795			106,894,514
Dilutive effect of Unit Grants		292,053			286,422

Weighted average limited partner units, assuming dilutive effect of Unit Grants		119,779,848			107,180,936

Diluted net income per limited partner unit	$	0.15		$	0.76

11.

DEBT OBLIGATIONS:

On October 23, 2006, ETP issued a total of $800,000 aggregate principal amount of Senior Notes comprised of $400,000 of 6.125% Senior Notes due 2017 (the “2017 Notes”) and $400,000 of 6.625% Senior Notes due 2036 (the “2036 Notes” and together with the 2017 Notes, the “Notes”). The Partnership used the proceeds of approximately $791,000 (net of bond discounts of $2,612 and financing costs of $6,050) from the issuance of the Notes to repay borrowings and accrued interest outstanding under the ETP Revolving Credit Facility, to pay expenses associated with the offering and for general partnership purposes. Interest on the notes will be due semiannually and will accrue from October 23, 2006. The Partnership may redeem some or all of the Notes at any time, or from time to time, pursuant to the terms of the Indenture. All of the Partnership’s obligations under the Notes are fully and unconditionally guaranteed by ETC OLP and Titan and substantially all of their present and future wholly-owned subsidiaries. These notes have been registered under the Securities Act pursuant to our S-3 Registration Statement which provided for the sale of a combination of units and debt totaling $1,500,000.

We have a $1,500,000 Amended and Restated Revolving Credit Facility (the “ETP Revolving Credit Facility”) available through June 29, 2011. Amounts borrowed under the ETP Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. There is also a Swingline loan option with a maximum borrowing of $75,000 at a daily rate based on LIBOR. The commitment fee payable on the unused portion of the facility varies based on our credit rating with a maximum fee of 0.175%. As of November 30, 2006, there was a balance of $325,254 in revolving credit loans (including $15,254 in Swingline loans) and $19,451 in letters of credit. The weighted average interest rate on the total amount outstanding at November 30, 2006, was 5.871%. The total amount available under the ETP Revolving Credit Agreement as of November 30, 2006, which is reduced by any amounts outstanding under the Swingline loan and letters of credit, was $1,155,295. The ETP Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP and Titan and all of their direct and indirect wholly-owned subsidiaries. The ETP Revolving Credit Facility is unsecured and has equal rights to holders of our other current and future unsecured debt.

A $75,000 Senior Revolving Facility (“the HOLP Facility”) is available to HOLP through June 30, 2011. The HOLP Facility has a swingline loan option with a maximum borrowing of $10,000 at a prime rate. Amounts borrowed under the HOLP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 6.466% for the amount outstanding at November 30, 2006. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined in the HOLP Facility credit agreement, with a maximum fee of 0.50%. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets, merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secure the HOLP Facility. As of November 30, 2006, there was a balance of $45,000 in revolving credit loans. A Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of

the HOLP Facility. There were outstanding Letters of Credit of $1,002 at November 30, 2006. The sum of the loans made under the HOLP Facility plus the Letter of Credit Exposure and the aggregate amount of all swingline loans cannot exceed the $75,000 maximum amount of the HOLP Facility. The amount available at November 30, 2006 was $28,998.

12.

PARTNERS’ CAPITAL AND UNIT-BASED COMPENSATION PLANS:

Limited Partner Units

Limited Partner interests are represented by Common, Class E and Class G Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement, as amended. As of November 30, 2006, we had limited partner interests represented by 110,889,264 Common Units and 26,086,957 Class G Units issued and outstanding, an aggregate 98% Limited Partner interest. There are also 8,853,832 Class E Units outstanding that are reported as treasury units, which units are entitled to receive distributions in accordance with their terms.

Common Units

The change in Common Units during the three month period ended November 30, 2006 is as follows:


		November 30, 2006
Balance, beginning of period		110,726,999
Issuance of restricted Common Units under our unit-based compensation plans		162,265

Balance, end of period		110,889,264

Of the total restricted Common Units issued during the period, 2,333 were Director Awards under our Restricted Unit Plan which vested on September 1, 2006. As of November 30, 2006, there are 1,333 unvested awards remaining under the Restricted Unit Plan (which was terminated in June 2004). No additional grants have been, or will be, made under the Restricted Unit Plan.

Class G Units

The change in Class G Units during the three month period ended November 30, 2006 is as follows:


		November 30, 2006
Balance, beginning of period		—
Issuance of Class G Units to Energy Transfer Equity, LP		26,086,957

Balance, end of period		26,086,957

On November 1, 2006, we issued 26,086,957 Class G Units to Energy Transfer Equity, LP (“ETE”) for aggregate proceeds of $1,200,000 in order to fund a portion of the Transwestern Acquisition and to repay indebtedness we incurred in connection with the Titan acquisition. The Class G Units, a newly created class of our limited partner interests, were issued to ETE at a price of $46.00 per unit, based upon a market discount from the closing price of our Common Units on October 31, 2006. The terms of the Class G Units provide that they may be converted to Common Units upon approval of a majority of the votes cast by the holders of our 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 G Units, the Class G Units will share in Partnership distributions and are entitled to all items of Partnership income, gain, loss, deduction and credit as if the Class G Units were Subordinated Units. Upon receiving the requisite approval by our Common Unitholders under a proposal to convert the Class G Units to Common Units, all Class G Units shall convert to Common Units on a one-for-one basis. The Class G Units were issued to ETE pursuant to a customary agreement, and registration rights have been granted to ETE.

Quarterly Distributions of Available Cash

On October 16, 2006, we paid a quarterly distribution related to the fourth quarter of our fiscal year 2006 of $0.75 per Common Unit, or $3.00 per unit annually, to Unitholders of record at the close of business on October 5, 2006.

On December 19, 2006, we declared a per unit cash distribution of $0.7678, or $3.075 per Limited Partner Unit annually (a $0.0178 increase per Limited Partner Unit) for the quarter ended November 30, 2006, which will be paid on January 15, 2007 to Unitholders of record at the close of business on January 4, 2007.

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 (all from Available Cash from Operating Surplus) related to the three months ended November 30, 2006 was as follows:


Limited Partners -
Common Units	$	85,247
Class E Units		3,121
Class G Units		20,054

General Partners -
2% Ownership		3,271
Incentive Distribution Rights		51,880

	$	163,573

Unit Based Compensation Plans

We follow the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004) Accounting for Stock-based Compensation (“SFAS 123R”) for our unit-based compensation plans. Adoption of SFAS 123R did not have a material effect on our net income. As provided in SFAS 123R, the Partnership values the unit awards based on the per unit grant-date market value reduced by the present value of the distributions expected to be paid on the units during the requisite service period. The present value of expected service period distributions is computed based on the risk-free interest rate, the expected life of the unit grants and the expected unit distributions.

We recognized compensation expense of $3,164 and $447 for the three months ended November 30, 2006 and 2005, respectively, related to unit-based compensation plans.

2004 Unit Plan

Employee Grants.

The Compensation Committee, in its discretion, may from time to time grant awards to any employee, upon such terms and conditions as it may determine appropriate and in accordance with specific general guidelines as defined by the Plan. All outstanding awards shall fully vest into units upon any Change in Control as defined by the Plan, or upon such terms as the Compensation Committee may require at the time the award is granted.

Employee grants awarded under the 2004 unit plan will vest over a three-year period based upon the achievement of certain performance criteria. The expected life of each grant is assumed to be the minimum vesting period under certain performance criteria of each grant. Vesting occurs based upon the total return to our Unitholders as compared to a group of Master Limited Partnership peer companies. One third of the awards will vest and convert to Common Units annually based on achievement of the performance criteria. Management deems it probable that all units will vest; thus, compensation expense was recorded. 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.

We assumed a weighted average risk-free interest rate of 4.40% for the three months ended November 30, 2006 in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each employee grant. For the employee awards granted during the three months ended November 30, 2006, the grant-date average per unit cash distributions were estimated to be $5.16. Upon vesting, ETP Common Units are issued.

The following table shows the activity of the awards granted for the three months ended November 30, 2006:


	Number of Units		Weighted Average Fair Value Per Unit
Unvested awards as of August 31, 2006	357,750		$	24.96

Awards granted November 1, 2006	399,500			43.36
Awards vested September 1, 2006	(151,905	)		23.78
Awards vested November 1, 2006	(2,334	)		23.78

Unvested awards as of November 30, 2006	603,011		$	37.55

The total expected compensation expense to be recognized related to the unvested employee awards as of November 30, 2006 is $9,802 for the remainder of fiscal year 2007, $5,328 for fiscal year 2008, and $1,806 for fiscal year 2009.

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 ETP LLC, the Partnership, or a subsidiary (“Director Participant”), who is elected or appointed to the Board for the first time shall automatically receive, on the date of his or her election or appointment, an award of up to 2,000 ETP Common Units (the “Initial Director’s Grant”). Each September 1 that this Plan is in effect, each Director Participant who is in office on such September 1, shall automatically receive an award of Units equal to $15 (changed to $25 in October 2006, as discussed below) divided by the fair market value of a Common Unit on such date (“Annual Director’s Grant”). Each grant of an award to a Director Participant will vest at the rate of one third per year, beginning on the first anniversary date of the Award; provided however, notwithstanding the foregoing, (i) all awards to a Director Participant shall become fully vested upon a change in control, as defined by the Plan, unless voluntarily waived by such Director Participant, and (ii) all awards which have not yet vested on the date a Director Participant ceases to be a director shall vest on such terms as may be determined by the Compensation Committee.

We assumed a weighted average risk-free interest rate of 3.85% for the three months ended November 30, 2006, in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each Director Grant. For the Director Awards granted during the three months ended November 30, 2006, the grant-date average per unit cash distributions were estimated to be $4.67.

The following table shows the activity of the Director Grants for the three months ended November 30, 2006:


	Number of Units		Weighted Average Fair Value Per Unit
Unvested awards as of August 31, 2006	15,951		$	22.54

Awards vested September 1, 2006	(5,693	)		20.10
Annual Director’s Grants awarded October 17, 2006	3,240			41.47

Unvested awards as of November 30, 2006	13,498		$	28.11

The total expected compensation expense to be recognized related to the unvested Director Awards as of November 30, 2006 is expected to be $126 for the remainder of fiscal year 2007, $57 for fiscal year 2008, and $14 for fiscal year 2009.

On October 17, 2006, the Compensation Committee recommended, following its receipt and review of an independent third-party compensation study, and the Board of Directors approved, an amendment to the 2004 Unit Plan to provide that Annual Director’s Grants shall be equal to $25 divided by the fair market value of Common Units on that date. All other Annual Director’s Grants shall be measured at September 1 of each year. On October 17, 2006, 3,240 Annual Director Grants were awarded.

Long-Term Incentive Grants

The Compensation Committee may, from time to time, grant awards under the Plan to any executive officer or any employee it designates as a participant in accordance with general guidelines under the Plan. As of November 30, 2006, there have been no Long-Term Incentive Grants made under the Plan.

13.

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL LIABILITIES:

Commitments

In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that such terms are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.

On October 3, 2006, we entered into a long-term agreement with CenterPoint Energy Resources Corp (“CenterPoint”) to provide the natural gas utility with firm transportation and storage services on our HPL System located along the Texas gulf coast region. Under the terms of this agreement, CenterPoint has contracted for 129 Bcf per year of firm transportation capacity combined with 10 Bcf of working gas storage capacity in our Bammel Storage facility. Under the new agreement with CenterPoint, we will no longer need to utilize predominately all of the Bammel Storage facility’s working gas capacity for supplying CenterPoint’s winter needs. This will reduce our working capital requirements that were necessary to finance the working gas while in storage and will provide us an opportunity to offer storage to third parties. This agreement goes into effect beginning April 1, 2007.

We assumed in our HPL acquisition a contract with a service provider which obligated us to obtain certain compression, measurement and other services through 2007 with monthly payments of approximately $1,700. We terminated the measurement portion of this contract in October 2006 for a payment of approximately $7,000. The remaining compression services total approximately $800 per month through October 2007.

Contingencies

Prior to our completion of the Transwestern Pipeline acquisition on December 1, 2006, our pipelines were intrastate and not generally subject to federal regulation. However, our subsidiaries make deliveries and sales to points or other parties, including other interstate pipelines, designated for interstate delivery. As part of industry-wide inquiries into the natural gas market disruptions occurring around the times of the hurricanes of late 2005, we have participated in discussions with, and have provided information to, industry regulators concerning transactions by our subsidiaries during our fiscal 2006 first and second quarters. We believe, after due inquiry, that our transactions complied in all material respects with applicable rules and regulations. These regulatory inquiries have not yet been concluded. While we are unable to predict the final outcome of these inquiries, management believes it is probable that the industry regulators will require a payment in order to conclude the inquiries. Accordingly, management has provided an accrual at November 30, 2006 for our best estimate of the payment amount that will be required to conclude these inquiries in a negotiated settlement process. We do not expect that any expenditures incurred in connection therewith in excess of the accrual provided as of November 30, 2006 will have a material impact on our financial condition, results of operations or liquidity in any future periods.

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. 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 and Titan are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverages and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us and our Operating Partnerships from material expenses related to product liability, personal injury or property damage in the future.

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

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against us. Although any litigation is inherently uncertain, based on past experience, the information currently available and the availability of insurance coverage, and in the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, may have a significant effect on the results of operations for a single period. However, we believe that such matters will not have a material adverse effect on our financial position. 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, we accrue the related deductible.

As of November 30, 2006 and August 31, 2006, an accrual of $30,275 and $32,148, respectively, was recorded as accrued and other current liabilities on our condensed consolidated balance sheets for our contingencies and current litigation matters, excluding accruals related to environmental matters.

Environmental

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

In July 2001, HOLP acquired a company that had previously received a request for information from the U.S. Environmental Protection Agency (the “EPA”) regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred long before the facility acquired by HOLP was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater

remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called Superfund). We have not received any follow-up correspondence from the EPA on the matter since our acquisition of the predecessor company in 2001. Based upon information currently available to HOLP, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on our financial condition or results of operations.

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

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

Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites on which HOLP presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, HOLP obtained indemnification rights for expenses associated with any remediation from the former owners or related entities. We have not been named as a potentially responsible party at any of these sites, nor have our operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in our November 30, 2006 or August 31, 2006 condensed consolidated balance sheets. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition or results of operations.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

As of November 30, 2006 and August 31, 2006, an accrual on an undiscounted basis of $4,412 and $4,387, respectively, was recorded in our condensed consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover material environmental liabilities related to certain matters assumed in connection with the HPL acquisition and the potential environmental liabilities for three sites that were formerly owned by Titan or its predecessors. A receivable of $388 was recorded in our condensed consolidated balance sheets as of November 30, 2006 and August 31, 2006 to account for a predecessor’s share of certain environmental liabilities of ETC OLP.

In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The final rule was effective as of January 14, 2004. Based on the results of our current pipeline integrity testing programs, we estimate that compliance with this final rule for our existing transportation assets will result in capital costs of $20,221 during the period between the remainder of calendar year 2006 to 2008, as well as operating and maintenance costs of $22,881 during that period. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

14.

PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Accounting for Derivative Instruments and Hedging Activities

We apply Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) as amended to account for our derivative financial instruments. This statement requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at fair value. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related

results on the hedged item in the statement of operations and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.

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

We use a combination of financial instruments including, but not limited to, futures, price swaps, options and basis swaps to manage our exposure to market fluctuations in the prices of natural gas and NGLs. We enter into these financial instruments with brokers who are clearing members with NYMEX and directly with counterparties in the over-the-counter (“OTC”) market. We are subject to margin deposit requirements under the OTC agreements and NYMEX positions. NYMEX requires brokers to obtain an initial margin deposit based on an expected volume of the trade when the financial instrument is initiated. This amount is paid to the broker by both counterparties of the financial instrument to protect the broker from default by one of the counterparties when the financial instrument settles. We also have maintenance margin deposits with certain counterparties in the OTC market. The payments on margin deposits occur when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on the settlement date. We had net deposits with derivative counterparties of $79,227 and $87,806 as of November 30, 2006 and August 31, 2006, respectively, reflected as deposits paid to vendors on our consolidated balance sheets.

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGL and propane prices. To reduce the impact of this price volatility, we primarily use derivative commodity instruments (futures and swaps) to manage our exposure to fluctuations in margins. We have established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings. Furthermore, on a bi-weekly basis, management reviews the creditworthiness of the derivative counterparties to manage against the risk of default.

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

Non-trading Activities

We utilize various exchange-traded and over-the-counter commodity financial instrument contracts to limit our exposure to margin fluctuations in natural gas, NGL and propane prices. These contracts consist primarily of futures and swaps and are recorded at fair value on the consolidated balance sheets. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in Accumulated Other Comprehensive Income (“OCI”) until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as cash flow hedges are included in cost of products sold in the period the hedged transactions occur. Gains and losses deferred in OCI related to cash flow hedges remain in OCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For those financial derivative instruments that do not qualify for hedge accounting, the change in market value is recorded in cost of products sold in the consolidated statements of operations. We reclassified into earnings losses of $3,169 and gains of $101,314 for the three months ended November 30, 2006 and 2005, respectively, related to commodity financial instruments that were previously reported in OCI.

We expect gains of $64,447 to be reclassified into earnings over the balance of the fiscal year related to income currently reported in OCI. The amount ultimately realized, however, will differ as commodity prices change. The majority of our commodity-related derivatives are expected to settle within the next two years.

In the course of normal operations, we routinely enter into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs, that under SFAS 133, qualify for and are designated as a normal purchase and sales contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for using accrual accounting. For contracts that are not designated as normal purchase and sales contracts, the change in market value is recorded in costs of products sold in the consolidated statements of operations. In connection with the HPL acquisition, we acquired certain physical forward contracts that contain embedded options. These contracts have not been designated as normal purchase and sale 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 options.

Trading Activities

Trading activities are monitored independently by our 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 derivative contracts that are entered into for trading purposes, subject to limits, are recognized on the consolidated balance sheets at fair value, and changes in the fair value of these derivative instruments are recognized in midstream and transportation and storage revenue in the consolidated statements of operations on a net basis. Net gains associated with trading activities for the three months ended November 30, 2006 and 2005 were $2,963, net of unrealized losses of $11,199, and $52,579, net of unrealized gains of $6,414, respectively.

The following table details the outstanding commodity-related derivatives as of November 30, 2006 and August 31, 2006, respectively:


November 30, 2006:	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	39,593,125		2006-2009	$	483
Swing Swaps IFERC	Gas	(8,399,704	)	2006-2008		211
Fixed Swaps/Futures	Gas	(1,837,500	)	2006-2007		(817	)
Forward Physical Contracts	Gas	(3,008,649	)	2006-2008		(10,433	)
Options	Gas	88,000		2006-2008		12,159
Forward/Swaps - in Gallons	Propane	19,614		2006-2007		(1,935	)

(Trading)
Basis Swaps IFERC/NYMEX	Gas	(1,627,500	)	2006-2008	$	10,323
Swing Swaps IFERC	Gas	(1,705,000	)	2006		(570	)
Forward Physical Contracts	Gas	—		2006		943

Cash Flow Hedging Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(50,212,500	)	2006-2007	$	(18,405	)
Fixed Swaps/Futures	Gas	(55,065,000	)	2006-2007		103,446


August 31, 2006:
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	33,711,140		2006-2009	$	(6,247	)
Swing Swaps IFERC	Gas	(37,220,448	)	2006-2008		2,618
Fixed Swaps/Futures	Gas	3,607,500		2006-2007		(170	)
Forward Physical Contracts	Gas	(7,986,000	)	2006-2008		(21,653	)
Options	Gas	(1,046,000	)	2006-2008		21,653
Forward/Swaps - in Gallons	Propane	24,066,000		2006-2007		199

(Trading)
Basis Swaps IFERC/NYMEX	Gas	(2,572,500	)	2006-2008	$	21,995
Swing Swaps IFERC	Gas	—		2006		(31	)
Forward Physical Contracts	Gas	(455,000	)	2006		(68	)

Cash Flow Hedging Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(34,585,000	)	2006-2007	$	(2,987	)
Fixed Swaps/Futures	Gas	(37,872,500	)	2006-2007		2,043

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

Interest Rate Risk

We are exposed to market risk for changes in interest rates related to our bank credit facilities. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements which allow us to effectively convert a portion of variable rate debt into fixed rate debt.

We entered into treasury locks and interest rate swaps with a notional amount of $300,000 during the third fiscal quarter of 2006. We elected to not apply hedge accounting to these financial instruments. Accordingly, changes in the fair value of these instruments are recorded as interest expense on the consolidated statements of operations. These instruments settled during the three months ended November 30, 2006 for a gain of $567.

We entered into forward starting interest swaps with a notional value of $400,000 during the three months ended August 31, 2006. The fair value of the swaps was recorded as a liability of $20,280 and $8,699 on the consolidated balance sheets as of November 30, 2006 and August 31, 2006, respectively. The swaps were accounted for as cash flow hedges under SFAS 133 and recorded as a component of OCI.

In connection with the Titan acquisition, we assumed a three year LIBOR interest rate swap with a notional amount of $125,000. The fair value of this swap as of November 30, and August 31, 2006 was a liability and asset of $764 and $519, respectively, and was recorded as a component of price risk management assets and liabilities in the consolidated balance sheet. We elected to not apply hedge accounting to these financial instruments. Accordingly, changes in the fair value of these instruments are recorded as interest expense on the condensed consolidated statements of operations.

We reclassified into earnings gains of $2,713 and losses of $764 for the three months ended November 30, 2006 and 2005, respectively, related to interest rate swaps that were previously reported in OCI. We expect gains of $219 to be reclassified into earnings over the next twelve months related to income on interest rate financial instruments currently reported in OCI. The amount ultimately realized, however, will differ as interest rates change.

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


	Three Months Ended November 30,
	2006			2005
*Commodity-related*
Unrealized gains (losses) recognized in revenues and cost of products sold related to commodity-related derivative activity, excluding ineffectiveness	$	(7,932	)	$	73,553
Ineffective portion of derivatives qualifying for hedge accounting		2,585			(18,322	)
Realized gains (losses) included in revenues and cost of products sold		10,977			(9,293	)

*Interest rate swaps*
Unrealized gains (losses) on interest rate swap included in interest expense, excluding ineffectiveness	$	(1,912	)	$	620
Ineffective portion of derivatives qualifying for hedge accounting		(2,825	)		—
Realized gains (losses) on interest rate swap included in interest expense		793			143

Credit Risk

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

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

15.

RELATED PARTY TRANSACTIONS:

Related company receivables and payables as of November 30, 2006 and August 31, 2006 relate to activities in the normal course of business and such amounts are immaterial.

As of November 30, 2006 and August 31, 2006, we had advances due from a propane joint venture of $6,232 and $3,775, respectively, which are included in advances to and investments in affiliates on our condensed consolidated balance sheets.

Our natural gas midstream and transportation and storage operations secure compression services from 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”. Our 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. During the three months ended November 30, 2006 and 2005, we made payments totaling $250 and $279, respectively, to the ETG Entities for compression services provided to and utilized in our natural gas midstream and transportation and storage operations. As of November 30, 2006 and August 31, 2006, accounts payable to ETG related to compressor leases were not significant.

16.

SUMMARIZED CONDENSED CONSOLIDATING FINANCIAL STATEMENTS:

Our Revolving Credit Facility and Senior Notes are fully and unconditionally guaranteed by ETC OLP and Titan and all of their direct and indirect wholly-owned subsidiaries (the “Subsidiary Guarantors”). HOLP and its direct and indirect subsidiaries and Heritage Holdings, Inc. do not guarantee our Revolving Credit Facility and Senior Notes. The Subsidiary Guarantors jointly and severally guarantee, on an unsecured senior basis, our obligations under our Revolving Credit Facility and Senior Notes. Following are our unaudited condensed consolidating financial information including our midstream and propane Subsidiary Guarantors, our 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 November 30, 2006

(In thousands)


	Parent		Midstream Guarantor Subsidiaries		Propane Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidation Adjustments			Consolidated
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	1,460	$	—	$	11,189	$	22,097	$	—		$	34,746
Marketable securities		—		—		—		2,596		—			2,596
Accounts receivable, net		—		470,190		24,769		103,895		—			598,854
Accounts receivable from related companies		590,918		15,682		78,806		5,361		(689,528	)		1,239
Inventories		—		376,307		14,332		109,009		—			499,648
Deposits paid to vendors		—		79,227		—		—		—			79,227
Exchanges receivable		—		28,045		—		—		—			28,045
Price risk management assets		—		30,099		—		—		—			30,099
Prepaid expenses and other		399		18,244		4,055		17,716		—			40,414

Total current assets		592,777		1,017,794		133,151		260,674		(689,528	)		1,314,868

PROPERTY, PLANT AND EQUIPMENT, net		—		2,839,444		186,210		540,904		—			3,566,558
ADVANCES TO AND INVESTMENT IN AFFILIATES		4,832,301		31,814		—		134,820		(3,999,879	)		999,056
GOODWILL		—		23,736		257,315		321,984		—			603,035
INTANGIBLES AND OTHER LONG-TERM ASSETS, net		19,516		7,230		68,366		96,118		—			191,230

Total assets	$	5,444,594	$	3,920,018	$	645,042	$	1,354,500	$	(4,689,407	)	$	6,674,747

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	—	$	482,100	$	11,735	$	86,341		—		$	580,176
Accounts payable to related companies		33,160		593,487		11,452		52,957		(689,314	)		1,742
Exchanges payable		—		32,580		—		—		—			32,580
Customer advances and deposits		—		6,315		26,086		69,370		—			101,771
Accrued and other current liabilities		34,557		145,456		18,470		50,344		(214	)		248,613
Price risk management liabilities		20,280		21,037		2,042		—		—			43,359
Current maturities of long-term debt		—		—		924		39,904		—			40,828

Total current liabilities		87,997		1,280,975		70,709		298,916		(689,528	)		1,049,069

LONG-TERM DEBT, net of discount, less current maturities		2,270,362		—		575		277,407		—			2,548,344
DEFERRED INCOME TAXES		—		51,068		—		56,370		—			107,438
OTHER NONCURRENT LIABILITIES		—		1,978		3,607		2,002		—			7,587

COMMITMENTS AND CONTINGENCIES

		2,358,359		1,334,021		74,891		634,695		(689,528	)		3,712,438

PARTNERS’ CAPITAL		3,086,235		2,585,997		570,151		719,805		(3,999,879	)		2,962,309

Total liabilities and partners’ capital	$	5,444,594	$	3,920,018	$	645,042	$	1,354,500	$	(4,689,407	)	$	6,674,747

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

As of August 31, 2006

(In thousands)


	Parent		Midstream Guarantor Subsidiaries		Propane Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidation Adjustments			Consolidated
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	728	$	—	$	2,182	$	23,131	$	—		$	26,041
Marketable securities		—		—		—		2,817		—			2,817
Accounts receivable, net		—		570,569		18,154		86,822		—			675,545
Accounts receivable from related companies		399,140		14,675		21,618		1,007		(435,543	)		897
Inventories		—		289,003		13,507		84,630		—			387,140
Deposits paid to vendors		—		87,806		—		—		—			87,806
Exchanges receivable		—		23,221		—		—		—			23,221
Price risk management assets		629		55,143		367		—		—			56,139
Prepaid expenses and other		673		26,751		2,893		11,881		—			42,198

Total current assets		401,170		1,067,168		58,721		210,288		(435,543	)		1,301,804

PROPERTY, PLANT AND EQUIPMENT, net		—		2,596,015		201,893		515,741		—			3,313,649
ADVANCES TO AND INVESTMENT IN AFFILIATES		3,834,189		32,036		—		136,353		(3,961,234	)		41,344
GOODWILL		—		23,736		278,835		301,838		—			604,409
INTANGIBLES AND OTHER LONG-TERM ASSETS, net		14,034		6,828		79,612		93,333		—			193,807

Total assets	$	4,249,393	$	3,725,783	$	619,061	$	1,257,553	$	(4,396,777	)	$	5,455,013

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	1,244		522,191		4,955		74,750		—		$	603,140
Accounts payable to related companies		28,706		404,505		—		2,863		(435,424	)		650
Exchanges payable		—		24,722		—		—		—			24,722
Customer advances and deposits		—		16,524		24,623		67,689		—			108,836
Accrued and other current liabilities		16,555		129,326		22,512		33,372		(119	)		201,646
Price risk management liabilities		8,699		28,219		—		—		—			36,918
Current maturities of long-term debt		—		—		871		39,707		—			40,578

Total current liabilities		55,204		1,125,487		52,961		218,381		(435,543	)		1,016,490

LONG-TERM DEBT, net of discount, less current maturities		2,330,281		—		679		258,164		—			2,589,124
DEFERRED INCOME TAXES		—		51,253		—		55,589		—			106,842
OTHER NONCURRENT LIABILITIES		—		3,838		—		1,857		—			5,695

COMMITMENTS AND CONTINGENCIES

		2,385,485		1,180,578		53,640		533,991		(435,543	)		3,718,151

PARTNERS’ CAPITAL		1,863,908		2,545,205		565,421		723,562		(3,961,234	)		1,736,862

Total liabilities and partners’ capital	$	4,249,393	$	3,725,783	$	619,061	$	1,257,553	$	(4,396,777	)	$	5,455,013

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended November 30, 2006

(In thousands)


	Parent			Midstream Guarantor Subsidiaries			Propane Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidation Adjustments			Consolidated
REVENUES:
Midstream and transportation and storage	$	—		$	1,062,444		$	—		$	—		$	—		$	1,062,444
Propane and other		—			—			84,685			241,316			—			326,001

Total revenue		—			1,062,444			84,685			241,316			—			1,388,445

COSTS AND EXPENSES:
Cost of products sold - midstream and transportation and storage		—			883,983			—			—			—			883,983
Cost of products sold - propane and other		—			—			52,724			150,636			—			203,360
Operating expenses		—			51,685			22,135			58,561			—			132,381
Depreciation and amortization		—			16,916			2,864			14,029			—			33,809
Selling, general and administrative		3,635			16,492			1,192			5,751			—			27,070

Total costs and expenses		3,635			969,076			78,915			228,977			—			1,280,603

OPERATING INCOME (LOSS)		(3,635	)		93,368			5,770			12,339			—			107,842

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(38,454	)		233			(1,303	)		(6,423	)		4,485			(41,462	)
Equity in earnings (losses) of affiliates		108,682			(224	)		—			(1	)		(103,570	)		4,887
Gain on disposal of assets		—			36			—			1,908			—			1,944
Interest and other income (expense), net		4,439			1,760			(9	)		(34	)		(4,485	)		1,671

INCOME BEFORE INCOME TAX EXPENSE AND MINORITY INTEREST		71,032			95,173			4,458			7,789			(103,570	)		74,882

Income tax expense (benefit)		—			1,994			(1	)		1,603			—			3,596

INCOME BEFORE MINORITY INTERESTS		71,032			93,179			4,459			6,186			(103,570	)		71,286

Minority interests		—			—			—			(254	)		—			(254	)

NET INCOME	$	71,032		$	93,179		$	4,459		$	5,932		$	(103,570	)	$	71,032

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended November 30, 2005

(In thousands)


	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES:
Midstream and transportation and storage	$	—		$	2,208,533		$	—		$	—		$	2,208,533
Propane and other		—			—			208,087			—			208,087

Total revenues		—			2,208,533			208,087			—			2,416,620

COSTS AND EXPENSES:
Cost of products sold - midstream and transportation and storage		—			1,959,368			—			—			1,959,368
Cost of products sold - propane and other		—			—			131,259			—			131,259
Operating expenses		—			53,677			48,994			—			102,671
Depreciation and amortization		—			13,419			13,494			—			26,913
Selling, general and administrative		2,820			18,787			3,192			—			24,799

Total costs and expenses		2,820			2,045,251			196,939			—			2,245,010

OPERATING INCOME (LOSS)		(2,820	)		163,282			11,148			—			171,610

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(20,604	)		(2,320	)		(7,730	)		2,261			(28,393	)
Equity in earnings (losses) of affiliates		141,321			(251	)		(23	)		(141,321	)		(274	)
Gain (loss) on disposal of assets		—			10			(138	)		—			(128	)
Interest and other income (expense), net		1,911			1,402			(93	)		(2,261	)		959

INCOME BEFORE INCOME TAX EXPENSE AND MINORITY INTEREST		119,808			162,123			3,164			(141,321	)		143,774

Income tax expense		—			19,005			3,406			—			22,411

INCOME (LOSS) BEFORE MINORITY INTERESTS		119,808			143,118			(242	)		(141,321	)		121,363

Minority interests		—			(1,349	)		(206	)		—			(1,555	)

NET INCOME (LOSS)	$	119,808		$	141,769		$	(448	)	$	(141,321	)	$	119,808

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the three months ended November 30, 2006

(In thousands)


	Parent			Midstream Guarantor Subsidiaries			Propane Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	109,848		$	191,078		$	5,034		$	(2,613	)	$	(128,895	)		174,452

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		—			(30,589	)		(712	)		(1,538	)		—			(32,839	)
Capital expenditures		—			(218,506	)		(3,321	)		(15,286	)		—			(237,113	)
Advances to and investment in affiliates		(951,237	)		—			—			(1,588	)		—			(952,825	)
Proceeds from the sale of assets		—			195			—			7,324			—			7,519

Net cash used in investing activities		(951,237	)		(248,900	)		(4,033	)		(11,088	)		—			(1,215,258	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,507,599			—			—			83,716			—			1,591,315
Principal payments on debt		(1,564,969	)		(5,163	)		(677	)		(60,574	)		—			(1,631,383	)
Proceeds from borrowings from affiliates		1,586,604			1,737,487			36,560			—			(3,360,651	)		—
Payments on borrowings from affiliates		(1,774,046	)		(1,558,728	)		(27,877	)		—			3,360,651			—
Net proceeds from issuance of Common Units		1,200,000			—			—			—						1,200,000
Capital contribution from General Partner		24,489			—			—			—			—			24,489
Distributions to parent		—			(115,774	)		—			(10,000	)		125,774			—
Distributions to partners		(128,895	)		—			—			—			3,121			(125,774	)
Debt issuance costs		(8,661	)		—			—			(475	)		—			(9,136	)

Net cash provided by financing activities		842,121			57,822			8,006			12,667			128,895			1,049,511

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		732			—			9,007			(1,034	)		—			8,705

CASH AND CASH EQUIVALENTS, beginning of period		728			—			2,182			23,131			—			26,041

CASH AND CASH EQUIVALENTS, end of period	$	1,460		$	—		$	11,189		$	22,097		$	—		$	34,746

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the three months ended November 30, 2005

(In thousands)


	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	59,666		$	20,011		$	2,094		$	(70,054	)	$	11,717

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		—			(17,124	)		(10,732	)		—			(27,856	)
Working capital settlement on prior year acquisitions		—			19,653			—			—			19,653
Capital expenditures		—			(73,281	)		(13,788	)		—			(87,069	)
Proceeds from the sale of assets		—			118			423			—			541

Net cash used in investing activities		—			(70,634	)		(24,097	)		—			(94,731	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		520,007			—			115,785			—			635,792
Principal payments on debt		(407,668	)		—			(84,199	)		—			(491,867	)
Proceeds from borrowings from affiliates		343,709			447,339			—			(791,048	)		—
Payments on borrowings from affiliates		(447,339	)		(343,709	)		—			791,048			—
Distributions to parent		—			(53,007	)		(13,925	)		66,932			—
Distributions to partners		(70,928	)		—			—			3,122			(67,806	)
Other		(104	)		—			—			—			(104	)

Net cash provided by financing activities		(62,323	)		50,623			17,661			70,054			76,015

DECREASE IN CASH AND CASH EQUIVALENTS		(2,657	)		—			(4,342	)		—			(6,999	)

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

CASH AND CASH EQUIVALENTS, end of period	$	1,153		$	38		$	16,724		$	—		$	17,915

17.

REPORTABLE SEGMENTS:

As of November 30, 2006, our financial statements reflect four reportable segments:

ETC OLP:

•

midstream operations

•

transportation and storage operations

HOLP and Titan:

•

retail propane operations

HOLP:

•

wholesale propane operations, including the operations of MP Energy Partnership

Beginning December 1, 2006, with the completion of our acquisition of Transwestern Pipeline, we will have an additional reporting segment for our interstate transportation operations.

Segments below the quantitative thresholds are classified as “other”. None of the components of the “other” segment have ever met any of the quantitative thresholds for determining reportable segments. Management has combined the domestic wholesale propane and foreign wholesale propane segments into one segment for all periods presented in this report. The combined segment is referred to as the wholesale propane segment.

Midstream and transportation and storage segment revenues and expenses include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions. 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, blending, processing, 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 our 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 our Oasis Pipeline, ET Fuel System, East Texas Pipeline System, HPL System and Fort Worth Basin Pipeline. Revenue is typically generated from fees charged to customers to reserve firm capacity on or move gas through the pipeline on an interruptible basis. A monetary fee and/or fuel retention are also components of the fee structure. Excess fuel retained after consumption is typically valued at the first of the month published market prices and strategically sold when market prices are high. The transportation and storage operations also consist of the HPL System which generates revenue primarily from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies. The use of the Bammel storage reservoir allows us to purchase physical natural gas and then sell financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin. The HPL System also transports natural gas for a variety of third party customers.

Our retail and wholesale propane segments sell products and services to retail and wholesale customers. Intersegment sales by the foreign wholesale segment to the domestic segment are priced in accordance with the partnership agreement of MP Energy Partnership. We manage our propane segments separately as each segment involves different distribution, sale, and marketing strategies.

We evaluate the performance of our operating segments based on operating income exclusive of general partnership selling, general, administrative expenses, gain (loss) on disposal of assets, minority interests, interest expense, earnings (losses) from equity investments and income tax expense (benefit).

Investment in affiliates and equity in earnings (losses) of affiliates related to our investment in Mid-Texas is included in our midstream segment and transportation and storage segment. Our investment in CCEH as of

November 30, 2006 is included in the “other” segment for the following segment asset disclosure. This 50% ownership in CCEH was redeemed in connection with the December 1, 2006 acquisition of Transwestern Pipeline.

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


	Three Months Ended November 30,
	2006			2005
Volumes:
Midstream
Natural gas MMBtu/d		979,978			1,527,391
NGLs bbls/d		11,569			10,217
Transportation and storage
Natural gas MMBtu/d – transported		4,800,086			4,465,189
Natural gas MMBtu/d – sold		1,021,297			1,551,365

Propane gallons (in thousands)
Retail		140,631			88,738
Wholesale		23,283			19,601

Total gallons		163,914			108,339


	Three Months Ended November 30,
	2006			2005
Revenues:
Midstream	$	608,183		$	1,549,828
Eliminations		(356,592	)		(906,804	)
Transportation and storage		810,853			1,565,509
Retail propane and other propane related		295,239			182,031
Wholesale propane		29,037			23,942
Other		1,725			2,114

Total revenues	$	1,388,445		$	2,416,620

Cost of Sales:
Midstream	$	558,718		$	1,436,870
Eliminations		(356,592	)		(906,804	)
Transportation and storage		681,857			1,429,302
Retail propane and other propane related		175,350			108,471
Wholesale propane		27,542			22,285
Other		468			503

Total cost of sales	$	1,087,343		$	2,090,627

Depreciation and Amortization:
Midstream	$	4,619		$	3,685
Transportation and storage		12,297			9,734
Retail propane and other propane related		16,592			13,210
Wholesale propane		176			184
Other		125			100

Total depreciation and amortization	$	33,809		$	26,913

Operating Income (Loss):
Midstream	$	31,569		$	94,008
Transportation and storage		61,799			69,273
Retail propane and other propane related		17,858			10,482
Wholesale propane		298			382
Other		(45	)		285
Selling general and administrative expenses not allocated to segments		(3,637	)		(2,820	)

Total operating income	$	107,842		$	171,610


Other items not allocated by segment:
Interest expense	$	(41,462	)	$	(28,393	)
Equity in earnings (losses) of affiliates		4,887			(274	)
Gain (loss) on disposal of assets		1,944			(128	)
Interest and other income, net		1,671			959
Income tax expense		(3,596	)		(22,411	)
Minority interests		(254	)		(1,555	)

		(36,810	)		(51,802	)

Net income	$	71,032		$	119,808


	Three Months Ended November 30,
	2006			2005
Additions to Property, Plant and Equipment Including Acquisitions (accrual basis):
Midstream	$	60,483		$	4,607
Transportation and storage		199,889			83,698
Retail propane and other propane related		25,582			21,334
Wholesale propane		12			141
Other		490			186

Total	$	286,456		$	109,966


	November 30, 2006			August 31, 2006
Total Assets:
Midstream	$	676,511		$	682,652
Transportation and storage		3,229,029			3,029,124
Retail propane and other propane related		1,681,390			1,619,732
Wholesale propane		52,302			39,816
Other		1,035,515			83,689

Total	$	6,674,747		$	5,455,013

18.

SUBSEQUENT EVENTS:

On December 13, 2006, we announced that we had entered into an agreement with Kinder Morgan Energy Partners, L.P. for a 50/50 joint development of the Midcontinent Express Pipeline (“MEP”). The approximately 500-mile pipeline, which will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transco in Butler, Alabama, will have an initial capacity of 1.4 Bcf per day. Pending necessary regulatory approvals, the approximately $1,250,000 pipeline project is expected to be in service by February 2009. MEP has prearranged binding commitments from multiple shippers for 800,000 dekatherms per day which includes a binding commitment from Chesapeake Energy Marketing, Inc., an affiliate of Chesapeake Energy Corporation for 500,000 dekatherms per day. MEP has executed a firm capacity lease agreement for up to 500,000 dekatherms per day with Enogex, a subsidiary of OGE Energy, an Oklahoma intrastate pipeline, to provide a seamless transportation path from various locations in Oklahoma into and through MEP.

The new pipeline will also interconnect with Natural Gas Pipeline Company of America, a wholly-owned subsidiary of Kinder Morgan, Inc., and with our previously announced 36-inch pipeline extending from the Barnett Shale and interconnecting with our Texoma pipeline near Paris, Texas.

In December 2006 we purchased a gathering system in north Texas for $32,000, subject to adjustments as defined in the agreements. The gathering system consists of approximately 36 miles of pipeline and has an estimated capacity of 70 MMcf/d. We expect the gathering system will allow us to continue expanding in the Barnett Shale area of north Texas.

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

AND RESULTS OF OPERATIONS

The following is a discussion of our historical financial condition and results of operations of our 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 for the fiscal year ended August 31, 2006 filed with the Securities and Exchange Commission on November 13, 2006. Our Management’s Discussion and Analysis includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors. Tabular dollar amounts (except per unit data) are in thousands.

Overview

Midstream and Transportation and Storage Segments

Through ETC OLP, we own and operate intrastate natural gas gathering and transportation pipelines, natural gas treating and processing assets located in Texas and Louisiana, and three natural gas storage facilities located in Texas. These assets include approximately 12,000 miles of intrastate pipeline in service, with an additional 600 miles of intrastate pipeline under construction. In connection with the acquisition of Transwestern on December 1, 2006, we also own 2,500 miles of interstate pipelines. The operating results for Transwestern will be included in our results on a consolidated basis beginning December 1, 2006 and reported as a separate operating segment (interstate transportation).

Our midstream segment results are derived primarily from margins we realize for natural gas volumes that are gathered, transported, purchased and sold through our pipeline systems, processed at our processing and treating facilities, and the volumes of NGLs processed at our facilities. We also market natural gas on our pipeline systems in addition to other pipeline systems to realize incremental revenue on gas purchased, increase pipeline utilization and provide other services that are valued by our customers. In addition and in accordance with our commodity risk management policy, we generate income from limited trading activities. Our trading activities include purchasing and selling natural gas and the use of financial instruments, including basis and gas daily contracts.

Our transportation and storage segment consists of natural gas gathering and intrastate transportation pipelines as well as three natural gas storage facilities with approximately 78 Bcf in storage capacity. The results from our transportation and storage segment are primarily derived from the fees we charge to transport natural gas on our pipelines, including a fuel retention component. We also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies on the HPL System. Generally, HPL purchases its natural gas from either the market (including purchases from our midstream segment’s producer services) and from producers at the wellhead. To the extent the natural gas comes from producers, it is purchased at a discount to a specified price and resold to customers at the index price.

We also utilize our Bammel storage reservoir to engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. 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.

As a result of our trading activities and the use of derivative financial instruments that may not qualify for hedge accounting in our midstream and transportation and storage segments, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk management committee, which includes members of senior management, and predefined limits and authorizations set forth by our risk management policy as discussed in Note 14 in the accompanying condensed consolidated financial statements.

Retail and Wholesale Propane Segments

Our propane related segments are operated by HOLP, Titan and their respective subsidiaries engaged in the sale, distribution and marketing of propane and other related products through their retail and wholesale segments, (the propane segments). HOLP and Titan derive their revenue primarily from the retail propane segment. We believe

that we are the third largest retail propane marketer in the United States, based on retail gallons sold. We serve more than one million propane customers from 442 customer service locations in 41 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 have no control. Product supply contracts are generally 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 for future resale significant volumes of propane for storage during periods of low demand, which generally occur during the summer months, at the then current market price, both at our customer service locations and in major storage facilities. In particular, our propane business is largely seasonal and dependent upon weather conditions in our service areas.

Historically, approximately two-thirds of our retail propane volume and substantially all of our propane-related operating income is attributable to sales during the six-month peak-heating season of October through March. This generally results in higher operating revenues and net income in the propane segments during the period from October through March of each year, and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Consequently, sales and operating profits for the propane segments are concentrated in our first and second fiscal quarters; however, cash flow from operations is generally greatest during our second and third fiscal quarters when customers pay for propane purchased during the six-month peak-heating season. Sales to industrial and agricultural customers are much less weather sensitive.

A substantial portion of our propane is used in the heating-sensitive residential and commercial markets causing the temperatures 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 about normal temperatures to help us understand 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.

Trends and Outlook

We believe our operations are positioned to provide increasing operating results based on the current levels of contracted and expected capacity to be taken by our customers, our expansion plans that we expect to complete in fiscal year 2007, and our acquired Titan operations. Additionally, on December 1, 2006, our acquisition of Transwestern Pipeline became final. We expect this transaction to be immediately accretive to our Common Unitholders.

We expect our propane-related segment to realize overall volume increases during fiscal year 2007 due to the effects of the Titan acquisition. However, continued warmer than normal weather will negatively impact volumes. We expect to be able to offset the impact of weather-related reduced volumes with reduced operating costs and improved gross margins to the extent our marketplace will allow it. We also plan to continue our active propane acquisition strategy and to expand our internal growth initiatives.

Recent Developments

Transwestern Pipeline. On November 1, 2006, pursuant to agreements entered into with GE Energy Financial Services (“GE”) and Southern Union Company (“Southern Union”), we acquired the member interests in CCE

Holdings, LLC (“CCEH”) from GE and certain other investors for $1.0 billion. The member interests acquired represented a 50% ownership in CCEH. CCEH owns, among other pipelines, the Transwestern Pipeline, a 2,500 mile interstate natural gas pipeline. In a second and related transaction, CCEH redeemed ETP’s 50% interest ownership in CCEH in exchange for 100% ownership of Transwestern Pipeline Company, LLC (“Transwestern”) on December 1, 2006, following which Southern Union will own all of the member interests of CCEH. Following the final step, Transwestern became a new operating subsidiary of ETP. In connection with the December 1 transaction, we assumed approximately $520.0 million of long-term indebtedness of Transwestern and received cash of approximately $55.0 million (of which approximately $49.0 million was received prior to November 30, 2006). We financed a portion of the purchase price with the proceeds from our issuance of approximately 26.1 million Class G Units issued to Energy Transfer Equity, L.P. simultaneous with the closing on November 1, 2006.

Midcontinent Express Pipeline. On December 13, 2006, we announced that we had entered into an agreement with Kinder Morgan Energy Partners, L.P. for a 50/50 joint development of the Midcontinent Express Pipeline (“MEP”). The approximately 500-mile pipeline, which will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transco in Butler, Alabama, will have an initial capacity of 1.4 Bcf per day. Pending necessary regulatory approvals, the approximately $1.3 billion pipeline project is expected to be in service by February 2009. MEP has prearranged binding commitments from multiple shippers for 800,000 dekatherms per day which includes a binding commitment from Chesapeake Energy Marketing, Inc., an affiliate of Chesapeake Energy Corporation for 500,000 dekatherms per day. MEP has executed a firm capacity lease agreement for up to 500,000 dekatherms per day with Enogex, a subsidiary of OGE Energy, an Oklahoma intrastate pipeline, to provide a seamless transportation path from various locations in Oklahoma into and through MEP.

North Texas gathering system. In December 2006 we purchased a gathering system in north Texas for $32.0 million, subject to adjustments as defined in the agreements. The gathering system consists of approximately 36 miles of pipeline and has an estimated capacity of 70 MMcf/d. We expect the gathering system will allow us to continue expanding in the Barnet Shale area of north Texas.

Analytical Analysis

The comparability of our condensed consolidated financial statements is affected by our purchase of 50% of CCEH in November 2006 and Titan in June 2006. See Note 3 to our condensed consolidated financial statements for a detailed discussion of our significant acquisitions during the three months ended November 30, 2006. The comparability is also affected by natural gas prices, mainly in our producer services’ revenues and natural gas sales on our HPL system. Excluding the impact from volumetric changes, our revenues in these areas are affected by changes in natural gas prices. Since we buy and sell natural gas primarily based on either first of month index prices, gas daily average prices or a combination of both, our revenues tend to be higher when natural gas prices are high and our revenues tend to be lower when natural gas prices are lower. However, a change in natural gas prices is only one of several elements that impact our overall margin. Other factors include, but are not limited to, volumetric changes, our hedging strategies and the use of financial instruments, fee-based revenues, and basis differences between market hubs.

Analysis of Operating Data

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 November 30,		Increase (Decrease)
	2006	2005	Increase (Decrease)
Natural gas MMBtu/d	979,978	1,527,391	(547,413	)
NGLs Bbls/d	11,569	10,217	1,352

•

For the three months ended November 30, 2006, natural gas sales volumes decreased by 547,413 MMBtu/d compared to the three months ended November 30, 2005. The decrease was principally due to less favorable market conditions during the fiscal 2007 period resulting in lower sales volumes conducted by our producer services’ operations. Our NGL sales volumes 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 increase in NGL sales volumes is principally due to favorable market conditions to

process and extract NGLs during the three months ended November 30, 2006 compared to the same period last year.

Transportation and Storage


	Three Months Ended November 30,		Increase (Decrease)
	2006	2005	Increase (Decrease)
Natural gas MMBtu/d – transported	4,800,086	4,465,189	334,897
Natural gas MMBtu/d – sold	1,021,297	1,551,365	(530,068	)

•

For the three months ended November 30, 2006, transported natural gas volumes increased by 334,897 MMBtu/d. The increase in transportation volumes is principally due to the increased volumes experienced in the ET Fuel system and East Texas Pipeline system as a result of the continued effort to secure long-term shipper contracts and the completion of phase I of the 42” pipeline project in late August 2006. Natural gas sales volumes on the HPL System for the three months ended November 30, 2006 decreased 530,068 MMBtu/d compared to the three months ended November 30, 2005, principally due to reduced demand as a result of moderate weather conditions throughout the first quarter of fiscal year 2007.

Propane


	Three Months Ended November 30,		Increase (Decrease)
	2006	2005	Increase (Decrease)
Propane gallons sold
(in thousands)
Retail	140,631	88,738	51,893
Wholesale	23,283	19,601	3,682

•

Retail Propane. The retail propane operations reflect significant increases in the quarter ended November 30, 2006 as compared to the quarter ended November 30, 2005 due to the Titan acquisition in June 2006. Synergies and blended operations have taken place over the course of the past six months with this acquisition to gain efficiencies and cost savings. Of the Titan locations that are identifiable as operating on a stand-alone basis, these locations contributed 41.1 million of the net gallon increase in retail propane gallons sold for the three months ended November 30, 2006, compared to the three months ended November 30, 2005. The remainder of the increased volumes is attributed to the increased volumes in the blended locations from the Titan acquisition and to a lesser extent other acquisition related volumes offset by warmer weather. The weather in our areas of operations during the three months ended November 30, 2006 was 12.2% warmer than the three months ended November 30, 2005 and 3.3% warmer than normal.

•

Wholesale Propane. For the three months ended November 30, 2006, sales of wholesale propane gallons increased by 3.7 million gallons compared to the three months ended November 30, 2005. The increase is due to an increase of 5.2 million gallons in our Canadian wholesale operations related to increased marketing efforts in our Canadian operations, offset by a decrease of 1.5 million gallons sold in our U.S. wholesale operations.

Analysis of Results of Operations

Three Months Ended November 30, 2006 Compared to Three Months Ended November 30, 2005.

Consolidated Results


	Three Months Ended November 30,						Amount of Change
	2006			2005			Amount of Change
Revenues	$	1,388,445		$	2,416,620		$	(1,028,175	)
Cost of sales		1,087,343			2,090,627			(1,003,284	)

Gross margin		301,102			325,993			(24,891	)

Operating expenses		132,381			102,671			29,710
Selling, general and administrative		27,070			24,799			2,271
Depreciation and amortization		33,809			26,913			6,896

Consolidated operating income		107,842			171,610			(63,768	)

Interest expense		(41,462	)		(28,393	)		(13,069	)
Equity in earnings (losses) of affiliates		4,887			(274	)		5,161
Gain (loss) on disposal of assets		1,944			(128	)		2,072
Interest and other income, net		1,671			959			712
Income tax expense		(3,596	)		(22,411	)		18,815
Minority interests		(254	)		(1,555	)		1,301

Net income	$	71,032		$	119,808		$	(48,776	)

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

Interest Expense. For the three months ended November 30, 2006 compared to the three months ended November 30, 2005, interest expense increased $13.1 million. The principal factor for this increase is a net $9.5 million increase in interest expense related to increased borrowings on the Partnership’s Senior Notes and Revolving Credit Facility, and an increase of $3.6 million related to interest rate swaps. The increased borrowings were a result of the CCEH and Titan acquisitions.

Equity in Earnings (Losses) of Affiliates. The increase of $5.2 million in equity in earnings (losses) of affiliates for the three months ended November 30, 2006 compared to the three months ended November 30, 2005 is due to our ownership of CCEH for the month of November 2006 which we did not own last year. Our share of CCEH’s net income was $5.1 million for the month of November 2006.

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 decreased expense of $18.8 million for the three months ended November 30, 2006 is attributed principally to lower income due to gains on financial derivative activity recognized by a taxable subsidiary during the three months ended November 30, 2005 that were not realized by such subsidiary in the current three-month period.

Net Income. The decrease of $48.8 million in net income between the comparable three month periods of November 30, 2006 and 2005 is a result of many different factors as discussed in greater detail in the discussion of Operating Results by Segment that follows.

Operating Results by Segment

Midstream Segment


	Three Months Ended November 30,				Amount of Change
	2006		2005		Amount of Change
Revenues	$	608,183	$	1,549,828	$	(941,645	)
Cost of sales		558,718		1,436,870		(878,152	)

Gross margin		49,465		112,958		(63,493	)

Operating expenses		8,887		7,238		1,649
Selling, general and administrative		4,390		8,027		(3,637	)
Depreciation and amortization		4,619		3,685		934

Segment operating income	$	31,569	$	94,008	$	(62,439	)

Gross Margin. For the three months ended November 30, 2006, midstream’s gross margin decreased by $63.5 million primarily due to the following factors:

•

Decrease in net trading revenues. The decrease was due to gains recognized during the three months ending November 30, 2005 as a result of the volatility caused by the hurricanes that struck the east Texas and Louisiana coastlines in August and September 2005.

•

Decrease in non-trading margin from our marketing activities. The prior period benefited from favorable pricing conditions attributed to the effects of the hurricanes. Due to price fluctuations between market hubs (i.e., Waha, Katy, etc.), our marketing activities realized higher margins during the three months ended November 30, 2005. In the fiscal 2007 period, the market conditions were less favorable resulting in lower margins on buying and selling natural gas between the west and east Texas markets. The period was also impacted by a decrease in the value of our non-trading open derivatives position as of November 30, 2006 as compared to November 30, 2005.

The decrease was offset by an increase in processing margin and fee-based revenue. The increase was due to the favorable processing conditions that we continued to experience in our first fiscal quarter of 2007. Liquid prices remained high while natural gas prices continued to decline or remain relatively low, thereby making processing more attractive. This resulted in higher margins in the current period as compared to the same period last year.

Operating Expenses. Midstream operating expenses increased $1.6 million and was primarily driven by increased compressor rentals of $0.8 million, increased pipeline maintenance of $0.4 million and increased employee-related costs such as salaries, incentive compensation and healthcare costs of $0.3 million.

Selling, General and Administrative Expenses. Midstream selling, general and administrative expenses for the three months ended November 30, 2006 decreased $3.6 million compared to the three months ended November 30, 2005. The decrease was attributable to a $0.9 million decrease in employee-related costs such as salaries, incentive compensation and healthcare costs, a one-time $0.9 million reimbursement of administrative costs related to the North Side Loop pipeline project from the project partner, a $0.5 million decrease due to more measurement expense being allocated to the transportation segment this period, and a $1.3 million decrease of allocated overhead due to more corporate overhead being allocated to the transportation segment. The allocation of departmental costs between the midstream and the transportation and storage segments is based on factors such as headcount, number of meters, and on-going projects and is intended to fairly present the segment’s operating results.

Depreciation and Amortization. Midstream depreciation and amortization expense increased $1.0 million for the three months ended November 30, 2006 compared to the same three month period in 2005 principally due to additions to property and equipment subsequent to November 30, 2005.

Transportation and Storage Segment


	Three Months Ended November 30,				Amount of Change
	2006		2005		Amount of Change
Revenues	$	810,853	$	1,565,509	$	(754,656	)
Cost of sales		681,857		1,429,302		(747,445	)

Gross margin		128,996		136,207		(7,211	)

Operating expenses		42,798		46,439		(3,641	)
Selling, general and administrative		12,102		10,761		1,341
Depreciation and amortization		12,297		9,734		2,563

Segment operating income	$	61,799	$	69,273	$	(7,474	)

Gross Margin. For the three months ended November 30, 2006 as compared to three months ended November 30, 2005, transportation and storage gross margin decreased by $7.2 million, principally due to lower natural gas prices. Excluding the impact of volumetric changes, our fuel retention fees are directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel retention fees and decreases in natural gas prices tend to decrease our fuel retention fees. Our average natural gas prices for retained fuel decreased from a range of $10.00-$11.00/MMBtu during the first quarter of fiscal 2006 to $5.00-$6.00/MMBtu during the first quarter of fiscal 2007. The decrease was offset by the following:

•

Volumes. Volumes, overall, on our transportation pipelines were higher during the first fiscal quarter ended 2007 compared to the same period last year which offset some of the decreased revenues caused by lower natural gas prices. The increase in volumes were principally due to continued efforts to secure long-term shipper contracts and the completion of phase I of the 42” pipeline project in late August 2006.

•

Margin increase on HPL. HPL’s margin increased $11.7 million between the two periods. The increase was due to HPL experiencing a significant loss on settled derivatives during the fiscal 2006 period which offset higher margins due to favorable conditions in east Texas and margin on gas sold from our Bammel facility and delivered to a customer in September 2005. There were minimal sales of natural gas sold from our Bammel facility during the three months ended November 30, 2006.

Operating Expenses. Transportation and storage operating expenses decreased $3.6 million when comparing the three months ended November 30, 2006 to the corresponding three month period in 2005. The decrease was primarily attributable to a decrease of $8.2 million in fuel consumption and a decrease of $2.3 million in operation overhead/electricity. These decreases were offset by a $1.8 million increase in compressor rentals, a $1.9 million increase in ad valorem taxes, a $1.9 million increase in professional fess due to the EMS contract buyout and a $1.0 million increase in employee related costs such as salaries, incentive compensation and healthcare costs.

Selling, General and Administrative Expenses. Transportation and storage selling, general and administrative expenses increased $1.3 million for the three months ended November 30, 2006 compared to the three months ended November 30, 2005 principally due to an increase in certain departmental costs allocated from the midstream segment. The increase in allocated departmental costs is primarily due to the significance of the operations added to the transportation segment from the various construction projects.

Depreciation and Amortization. Transportation and storage depreciation and amortization expense increased $2.6 million for the three months ended November 30, 2006 compared to the three months ended November 30, 2005, principally due to additions to property and equipment, most notably the North Side Loop pipeline and phase I of the 42” pipeline project.

Retail Propane Segment


	Three Months Ended November 30,				Amount of Change
	2006		2005		Amount of Change
Retail propane revenues	$	266,090	$	162,194	$	103,896
Other propane related revenues		29,149		19,837		9,312
Retail propane cost of sales		167,619		102,383		65,236
Other propane related cost of sales		7,731		6,088		1,643

Gross margin		119,889		73,560		46,329

Operating expenses		78,988		47,081		31,907
Selling, general and administrative		6,451		2,787		3,664
Depreciation and amortization		16,592		13,210		3,382

Segment operating income	$	17,858	$	10,482	$	7,376

Revenues. Of the total increase in retail propane revenue of $103.9 million between the three months ended November 30, 2006 and 2005, $78.1 million is due to the increase in volumes sold by customer service locations added through the identifiable Titan locations. Revenues also increased in relation to the increased volumes from the blended locations as discussed above, the increase in volumes sold by customer service locations added through other propane acquisitions and, to a lesser extent, higher selling prices over the same period last year. These increases were offset by a decrease due to the adverse impact of weather related volume decreases described above. Other propane related revenues increased $9.3 million for the three months ended November 30, 2006 compared to 2005 primarily due to the Titan acquisition in June, 2006.

Costs of Sales. During the three months ended November 30, 2006 compared to the three months ended November 30, 2005, retail propane cost of sales increased by $65.2 million of which $51.3 million is a result of an overall increase in gallons sold by the identifiable customer service locations added through the Titan acquisitions. Cost of sales increased also in relation to the increased volumes as described above, and, to a lesser extent, increases in the cost of fuel for the quarter ended November 30, 2006 as compared to the quarter ended November 30, 2005, offset by the decrease in volumes due to the warm weather.

Gross Margin. The overall increase in gross margins for the three months ended November 30, 2006 compared to the three months ended November 30, 2005 is primarily related to the Titan acquisition in June 2006.

Operating Expenses. During the three months ended November 30, 2006, operating expenses increased by $31.9 million compared to the same three month period last year due to a combination of a $21.4 million increase due to the identifiable Titan operations, increases in our employee base from other acquisitions and annual salary increases, higher fuel costs to run our vehicles and other vehicle expenses, and general increases in other operating expenses including safety training costs of the newly acquired employees from the Titan and other acquisitions and other acquisition related costs.

Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses for the comparable three month periods of November 30, 2006 and 2005 is primarily due to increases in administrative bonuses, salaries and deferred compensation expense related to increases in staffing and additional restricted unit awards outstanding and the addition of administrative employees from the Titan acquisition.

Operating Income. For the three months ended November 30, 2006, total operating income increased by $7.4 million compared to the three months ended November 30, 2005, due to the changes in revenues and expenses described above.

Wholesale Propane Segment


	Three Months Ended November 30,				Amount of Change
	2006		2005		Amount of Change
Revenues	$	29,037	$	23,942	$	5,095
Cost of sales		27,542		22,285		5,257

Gross margin		1,495		1,657		(162	)

Operating expenses		531		687		(156	)
Selling, general and administrative		490		404		86
Depreciation and amortization		176		184		(8	)

Segment operating income (loss)	$	298	$	382	$	(84	)

Revenues. Of the $5.1 million increase in wholesale revenue for the three months ended November 30, 2006 compared to the same three months in 2005, $4.5 million is related to the increase in gallons sold to new customers in our eastern wholesale and Canadian operations and $0.6 million is related to higher selling prices.

Costs of Sales. For the three months ended November 30, 2006 compared to the corresponding three months in 2005, total cost of sales increased by $5.3 million. Of the increase, $1.0 million is due to higher selling prices and $4.3 million is due to the increase in customers in our eastern wholesale operations described above.

Other


	Three Months Ended November 30,					Amount of Change
	2006			2005		Amount of Change
Revenues	$	1,725		$	2,114	$	(389	)
Cost of sales		468			503		(35	)
Operating expenses		1,177			1,226		(49	)
Depreciation and amortization		125			100		25

Other operating income (loss)	$	(45	)	$	285	$	(330	)

Unallocated selling, general and administrative expenses	$	3,637		$	2,820	$	817

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.

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 three months ended November 30, 2006 and 2005, our non-qualifying income was not expected to, or did not, exceed the statutory limit.

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


	Three Months Ended November 30,
	2006		2005
Federal statutory tax rate	35.0	%	35.0	%
State income tax rate net of federal benefit	3.5	%	3.6	%
Earnings not subject to tax at the Partnership level	(33.7	)%	(23.0	)%

Effective tax rate	4.8	%	15.6	%

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


	Three Months Ended November 30,
	2006		2005
Current provision:
Federal	$	3,151	$	15,264
State		340		338
Deferred provision:
Federal		69		6,663
State		36		146

Total income tax expense	$	3,596	$	22,411

We do not expect our tax payments in any year to differ significantly from our current tax provisions.

Liquidity and Capital Resources

Our ability to satisfy our obligations and pay distributions to our partners 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 will generally consist of:

•

maintenance capital expenditures, which include 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 $36.4 million for the remainder of the 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 $13.1 million for the remainder of the fiscal year. Due to the recent acquisition of 100% of Transwestern, we have not completed our review of Transwestern’s maintenance capital expenditures but expect it to be more than $15.0 million for the remainder of the fiscal year;

•

growth capital expenditures, mainly for constructing new pipelines, processing plants and treating plants for which we expect to expend approximately $979.5 million for the remainder of the fiscal year, including $220.0 million related to Transwestern; and customer propane tanks for which we expect to expend approximately $16.4 million for the remainder of the fiscal year; and

•

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

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

•

maintenance capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities described below, which will be repaid by subsequent seasonal reductions in inventory and accounts receivable;

•

growth capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities and 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.

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 Transwestern and Titan operations, and other factors.

Operating Activities. Cash provided by operating activities during the three months ended November 30, 2006, was $174.5 million as compared to cash provided by operating activities of $11.7 million for the three months ended November 30, 2005. The net cash provided by operations for the three months ended November 30, 2006 consisted of net income of $71.0 million, non-cash charges of $31.7 million, principally depreciation and amortization, unit based compensation expense, and deferred taxes, and cash from changes in operating assets and liabilities of $71.8 million. Various components of operating assets and liabilities 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. Accounts receivable and accounts payable both decreased during the three months ended November 30, 2006 due primarily to decreases in the volumes and prices in the midstream and transportation and storage operating segment.

Investing Activities. Cash used in investing activities during the three months ended November 30, 2006 of $1.2 billion is comprised primarily of cash paid for our investment in CCEH of $1.0 billion (net of the receipt of $49.0 million from CCEH as per the terms of our acquisition agreement), other acquisitions of $32.8 million and $237.1 million invested for maintenance and growth capital expenditures needed to sustain operations.

Financing Activities. Cash provided by financing activities was $1.1 billion for the three months ended November 30, 2006. We received $1.2 billion in proceeds from the sale of Class G Units to ETE and our General Partner contributed $24.5 million to maintain its two percent ownership in us. We used $1.0 billion of the proceeds to fund the purchase of the member interests of CCEH and the remainder was used to repay the indebtedness we incurred in connection with the Titan acquisition as discussed above in Note 3 to our condensed consolidated financial statements. On October 23, 2006, we received proceeds of $800.0 million from the issuance of senior notes (see Note 11 to our condensed consolidated financial statements above) of which we used approximately $791.0 million to repay borrowings under the Partnership’s revolving credit facility. During the three months ended November 30, 2006, we paid distributions of $125.8 million to our partners.

Financing and Sources of Liquidity

On October 23, 2006, we closed the issuance, under our $1.5 billion S-3 Registration Statement, of $400 million of 6.125% senior notes due 2017 and $400 million of 6.625% senior notes due 2036, and received net proceeds of approximately $791 million. We used the net proceeds of approximately $791 million from the issuance of the Notes to repay borrowings and accrued interest outstanding under our Revolving Credit Facility, to pay expenses associated with the offering and for general partnership purposes. Interest on the 2017 senior notes is payable semiannually on February 15 and August 15 of each year, beginning February 15, 2007, and interest on the 2036 senior notes is payable semiannually on April 15 and October 15 of each year, beginning April 15, 2007. All of the Partnership’s obligations under the Notes are fully and unconditionally guaranteed by ETC OLP and Titan and substantially all of their present and future wholly-owned subsidiaries.

During fiscal year 2006, we filed a Registration Statement on Form S-3 with the Securities and Exchange Commission to register a $1.0 billion aggregate offering price of Common Units representing our Limited Partner interests. Through November 30, 2006, we have not made any sales under this Registration Statement.

Description of Indebtedness

Our indebtedness as of November 30, 2006 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, $400.0 million in principal amount of 6.125% Senior Notes due 2017, $400.0 million in principal amount of 6.625% Senior Notes due 2036 and a Revolving Credit Facility that allows for borrowings of up to $1.5 billion available through June 29, 2011. We also currently maintain separate credit facilities for HOLP. The terms of our indebtedness and our Operating Partnerships are described in more detail in our Annual Report on Form 10-K for fiscal 2006 filed with the Securities and Exchange Commission on November 13, 2006.

Energy Transfer Partners Facilities

We have a $1.5 billion Amended and Restated Revolving Credit Facility (the “ETP Revolving Credit Facility”) available through June 29, 2011. Amounts borrowed under the ETP Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. There is also a Swingline loan option with a maximum borrowing of $75.0 million at a daily rate based on LIBOR. The commitment fee payable on the unused portion of the facility varies based on our credit rating with a maximum fee of 0.175%. As of November 30, 2006, there was a balance of $325.3 million in revolving credit loans (including $15.3 million in Swingline loans) and $19.5 million in letters of credit. The weighted average interest rate on the total amount outstanding at November 30, 2006, was 5.871%. The total amount available under the ETP Revolving Credit Agreement as of November 30, 2006, which is reduced by any amounts outstanding under the Swingline loan and letters of credit, was $1.2 billion. The ETP Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP and Titan and all of their direct and indirect wholly-owned subsidiaries. The ETP Revolving Credit Facility is unsecured and has equal rights to holders of our other current and future unsecured debt.

On October 18, 2006 we paid and retired a $250.0 million unsecured Revolving Credit Facility which matured under its terms on December 1, 2006. Amounts borrowed under this facility bore interest at a rate based on either a Eurodollar rate or a base rate. The maximum commitment fee payable on the unused portion of the facility was 0.25%. The $250.0 million Revolving Credit Facility was fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP.

HOLP Facilities

A $75.0 million Senior Revolving Facility (“the Facility”) is available through June 30, 2011. The Facility has a swingline loan option with a maximum borrowing of $10.0 million at a prime rate. Amounts borrowed under the Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 6.466% for the amount outstanding at November 30, 2006. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined, with a maximum fee of 0.50%. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets, merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secure the Facility. As of November 30, 2006, there was a balance of $45.0 million in revolving credit loans. A Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of the Facility. There were outstanding Letters of Credit of $1.0 million at November 30, 2006. The sum of the loans made under the Facility plus the Letter of Credit Exposure and the aggregate amount of all swingline loans cannot exceed the $75.0 maximum amount of the Facility. The amount available under the Facility at November 30, 2006 was $29.0 million.

Cash Distributions

We will use our cash provided by operating and financing activities from the Operating Partnerships to provide distributions to our Unitholders. Under the Partnership Agreement, we will distribute to our partners within 45 days after the end of each fiscal quarter, an amount equal to all of our Available Cash for such quarter. Available Cash generally means, with respect to any quarter of the Partnership, all cash on hand at the end of such quarter less the amount of cash reserves established by the General Partner in its reasonable discretion that is necessary or appropriate to provide for future cash requirements. Our commitment to our Unitholders is to distribute the increase

in our cash flow while maintaining prudent reserves for our operations. On October 16, 2006, we paid a quarterly distribution of $0.75 per Common Unit, or $3.00 per unit annually, to Unitholders of record at the close of business on October 5, 2006. On December 19, 2006, we declared a per unit cash distribution of $0.7678, or $3.075 per Limited Partner Unit annually (a $0.0178 increase per Limited Partner Unit) for the quarter ended November 30, 2006, which will be paid on January 15, 2007 to Unitholders of record at the close of business on January 4, 2007. 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).

New Accounting Standards

See Note 2 to our condensed consolidated financial statements.

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, 2006, in addition to the interim unaudited condensed 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 November 30, 2006:


November 30, 2006:	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	39,593,125		2006-2009	$	483
Swing Swaps IFERC	Gas	(8,399,704	)	2006-2008		211
Fixed Swaps/Futures	Gas	(1,837,500	)	2006-2007		(817	)
Forward Physical Contracts	Gas	(3,008,649	)	2006-2008		(10,433	)
Options	Gas	88,000		2006-2008		12,159
Forward/Swaps - in Gallons	Propane	19,614		2006-2007		(1,935	)

(Trading)
Basis Swaps IFERC/NYMEX	Gas	(1,627,500	)	2006-2008	$	10,323
Swing Swaps IFERC	Gas	(1,705,000	)	2006		(570	)
Forward Physical Contracts	Gas	—		2006		943

Cash Flow Hedging Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(50,212,500	)	2006-2007	$	(18,405	)
Fixed Swaps/Futures	Gas	(55,065,000	)	2006-2007		103,446

Credit Risk

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

Sensitivity Analysis

The table below summarizes our commodity-related financial derivative instruments and fair values as of November 30, 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	(56,902,500	)	$	102,629		$	49,377
Basis Swaps IFERC/NYMEX	(10,619,375	)		(17,922	)		2,074
Swing Swaps IFERC	(8,399,704	)		211			563
Options	88,000			12,159			2,883
Forward Physical Contracts	(3,008,649	)		(10,433	)		5,917
Propane Forwards/Swaps (in Gallons)	19,614			(1,935	)		(1,872	)

Trading Derivatives
Swing Swaps IFERC	(1,705,000	)		(570	)		1,212
Basic Swaps IFERC/NYMEX	(1,627,500	)		10,323			184
Forward Physical Contracts	—			943			1,367

The fair values of the commodity-related financial positions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10 percent change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in our consolidated results of operations or in accumulated other comprehensive income. In the event of an actual 10 percent change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10 percent due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps).

Interest Rate Risk

We entered into forward starting interest swaps with a notional value of $400.0 million during the three months ended August 31, 2006. The fair value of the swaps was recorded as a liability of $21.0 million and $8.7 million on the consolidated balance sheets as of November 30, 2006 and August 31, 2006. A hypothetical change of 1% on the underlying interest rate would have an effect of $32.3 million on the value of the swap as of November 30, 2006.

In connection with the Titan acquisition, we assumed a three year LIBOR interest rate swap with a notional amount of $125.0 million. The fair value of this swap as of November 30, and August 31, 2006 was a liability and asset of $0.8 million and $0.5 million, respectively, and was recorded as a component of price risk management assets and liabilities in the consolidated balance sheet. A hypothetical change of 1% on the underlying interest rate would have an effect of $2.7 million on the value of the swap as of November 30, 2006.

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 November 30, 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 November 30, 2006, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting except as relates to the Titan acquisition.

We continue to evaluate Titan’s business and are making various changes to its operating and organizational structure based on our business plan. We are in the process of implementing our internal control structure over the operations of Titan. We expect that this effort will continue into future fiscal quarters of 2007 due to the magnitude of the business.

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended August 31, 2006.

ITEM 1A. RISK FACTORS

As of November 30, 2006, there had been no significant change in our risk factors from those discussed in our Form 10-K for the year ended August 31, 2006. The acquisition of Transwestern and operations in the interstate transportation business results in additional risk factors, including the following:

The pipeline businesses are subject to competition.

The interstate pipeline business of Transwestern competes with those of other interstate and intrastate pipeline companies in the transportation of natural gas. The principal elements of competition among pipelines are rates, terms of service and the flexibility and reliability of service. Natural gas competes with other forms of energy available to our customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the demand for natural gas in the areas served by Transwestern.

The success of the pipelines depends on the continued development of additional natural gas reserves in the vicinity of our facilities and our ability to access additional reserves to offset the natural decline from existing wells connected to our systems.

The amount of revenue generated by Transwestern depends substantially upon the volume of natural gas transported. As the reserves available through the supply basins connected to Transwestern’s systems naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission. Investments by third parties in the development of new natural gas reserves connected to Transwestern’s facilities depend on many factors beyond Transwestern’s control.

The inability to continue to access Tribal lands could adversely affect Transwestern’s ability to operate its pipeline system and the inability to recover the cost of right-of-way grants on tribal lands could adversely affect its financial results.

Transwestern’s ability to operate its pipeline system on certain Tribal lands (lands held in trust by the United States for the benefit of a Native American Tribe) will depend on its success in maintaining existing rights-of-way and obtaining new rights-of-way on those Tribal lands. Securing additional rights-of-way is also critical to Transwestern’s ability to pursue expansion projects including Transwestern’s proposed expansion of its San Juan lateral in New Mexico. We cannot assure that Transwestern will be able to acquire new rights-of-way on Tribal lands or maintain access to existing rights-of-way upon the expiration of the current grants. Our financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.

Transwestern is subject to FERC rate-making policies that could have an adverse impact on our ability to establish rates that would allow us to recover the full cost of operating the pipeline.

Rate-making policies by FERC could affect Transwestern’s ability to establish rates, or to charge rates that would cover future increases in its costs, or even to continue to collect rates that cover current costs. Natural gas companies may not charge rates that have been determined not to be just and reasonable by FERC. The rates, terms and conditions of service provided by natural gas companies are required to be on file with FERC in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. We cannot assure you that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas capacity and transportation facilities. Any successful complaint or protest against Transwestern’s rates could reduce our revenues associated with providing transmission services. We cannot assure you that we will be able to recover all of Transwestern’s costs through existing or future rates.

Transwestern is subject to regulation by FERC in addition to FERC rules and regulations related to the rates it can charge for its services.

FERC’s regulatory authority also extends to:

•

operating terms and conditions of service;

•

the types of services Transwestern may offer to its customers;

•

construction of new facilities;

•

acquisition, extension or abandonment of services or facilities;

•

accounts and records; and

•

relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.

FERC action in any of these areas or modifications of its current regulations can impair Transwestern’s ability to compete for business, the costs it incurs in its operations, the construction of new facilities or its ability to recover the full cost of operating its pipeline. For example, the development of uniform interstate gas quality standards by FERC could create two distinct markets for natural gas – an interstate market subject to uniform minimum quality standards and an intrastate market with no uniform minimum quality standards. Such a bifurcation of markets could make it difficult for our pipelines to compete in both markets or to attract certain gas supplies away from the intrastate market. The time FERC takes to approve the construction of new facilities could raise the costs of our projects to the point where they are no longer economic.

FERC has authority to review pipeline contracts. If FERC determines that a term of any such contract deviates in a material manner from a pipeline’s tariff, FERC typically will order the pipeline to remove the term from the contract and execute and refile a new contract with FERC or, alternatively, to amend its tariff to include the deviating term, thereby offering it to all shippers. If FERC audits a pipeline’s contracts and finds deviations that appear to be unduly discriminatory, FERC could conduct a formal enforcement investigation, resulting in serious penalties and/or onerous ongoing compliance obligations.

Should Transwestern fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the recently enacted Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1,000,000 per day for each violation.

Finally, we cannot give any assurance regarding the likely future regulations under which we will operate Transwestern or the effect such regulation could have on our business, financial condition, and results of operations.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not applicable.

ITEM 5. OTHER INFORMATION

Not applicable.

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.

(49)	3.1.9	Amendment No. 9 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P.

(47)	3.1.10	Amendment No. 10 to Amended and Restated Agreement of Limited Partnership of Energy Transfer 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.


	Exhibit Number	Description
(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.

(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.

(43)	4.11	Form of Senior Indenture of Energy Transfer Partners, L.P.

(43)	4.12	Form of Subordinated Indenture of Energy Transfer Partners, L.P.

(53)	4.13	Fourth Supplemental Indenture dated as of June 29, 2006 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P, the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.

(46)	4.14	Fifth Supplemental Indenture dated as of October 23, 2006 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P, the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.

(47)	4.15	Registration Rights Agreement, dated November 1, 2006, between Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P.

(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.


	Exhibit Number	Description
(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.

(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.

(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.


	Exhibit Number	Description
(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 among Heritage Operating L.P. and the Banks dated March 31, 2004.

(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.

(53)	**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.

(48)	10.48	Credit Agreement dated as of May 31, 2006, among Energy Transfer Partners, L.P., as the Borrower, Credit Suisse, Cayman Islands Branch as administrative agent, and the other lenders party hereto Credit Suisse Securities (USA) LLC and Banc of America Securities, LLC, as joint lead arrangers and co-documentation and syndication agents.


	Exhibit Number	Description
(48)	10.49	Amended and Restated Credit Agreement dated as of June 29, 2006, among Energy Transfer Partners, L.P., as the Borrower, 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, as co-documentation agents, Deutsche Bank Securities, Inc., Credit Suisse, Cayman Islands Branch, UBS Securities, LLC, JPMorgan Chase Bank, N.A. and Suntrust Bank as senior managing agents and the other lenders party hereto Wachovia Capital Markets, LLC as sole lead arranger and sole book manager.

(48)	10.50	Guarantee for the Amended and Restated Credit Agreement dated as of June 29, 2006.

(50)	10.51	Purchase and Sale Agreement, dated as of September 14, 2006, among Energy Transfer Partners, L.P. and EFS-PA, LLC (a/k/a GE Energy Financial Services), CDPQ Investments (U.S.), Inc., Lake Bluff, Inc., Merrill Lynch Ventures, L.P. and Kings Road Holdings I, LLC.

(51)	10.52	Redemption Agreement, dated September 14, 2006, between Energy Transfer Partners, L.P. and CCE Holdings, LLC.

(52)	10.53	Letter Agreement, dated September 14, 2006, between Energy Transfer Partners, L.P. and Southern Union Company.

(53)	10.54	Fourth Amended and Restated Credit Agreement dated as of August 31, 2006 between and among Heritage Operating L.P., as the Borrower, and the Banks now or hereafter signatory parties hereto, as lenders “Banks” and Bank of Oklahoma, National Association as administrative agent and joint lead arranger for the Banks, JPMorgan Chase Bank, N.A., as syndication agent for the Banks, and J.P. Morgan Securities Inc., as joint lead arranger for the Banks.

(53)	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

*	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.

(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 28, 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.

(46)	Incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed October 25, 2006.

(47)	Incorporated by reference to Exhibit 3.1.10 to the Registrant’s Form 8-K filed November 3, 2006.

(48)	Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2006.

(49)	Incorporated by reference to Exhibit 3.1.9 to the Registrant’s Form 8-K filed May 3, 2006.

(50)	Incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed September 18, 2006.

(51)	Incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed September 18, 2006.

(52)	Incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed September 18, 2006.

(53)	Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K for the year ended August 31, 2006.

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: January 9, 2007	By:	/s/ H. Michael Krimbill
		H. Michael Krimbill
		(President and Chief Financial Officer duly authorized to sign on behalf of the registrant)