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

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month's financial results for the midstream and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month's financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

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

Revenue Recognition

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

 

Investment in ETP

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

ETP's intrastate transportation and storage and interstate transportation operations' results are determined primarily by the amount of capacity its customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, ETP's customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Excess fue l retained after consumption is typically valued at market prices.

ETP's intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, ETP purchases natural gas from the market, including purchases from ETP's midstream marketing operations, and from producers at the wellhead.

In addition, ETP's intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers' working natural gas in its storage facilities. ETP also engages in natural gas storage transactions in which it seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover its carrying costs and provide for a gross profit margin. ETP expects margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, ETP cannot assure that management's expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which it operates, competitive factors in the energy industry, and other issues.

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

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

 

ETP conducts marketing activities in which it markets the natural gas that flows through its assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through its assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

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

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

Investment in Regency

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

Regulatory Accounting - Regulatory Assets and Liabilities

Certain of our subsidiaries are subject to regulation by certain state and federal authorities and has accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management's assessment of the probability of recovery or pass through of regulato ry assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheets for the period in which the discontinuance of regulatory accounting treatment occurs.

 

Cash, Cash Equivalents and Supplemental Cash Flow Information

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

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

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

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

 

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

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

 

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

 

Marketable Securities

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

Accounts Receivable

Our subsidiaries assess the credit risk of their customers. Certain of our subsidiaries deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guarantee prepayment, master setoff agreement or collateral). Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and specific identification.

Inventories

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

Inventories consisted of the following:

 

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

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

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

Exchanges

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

 

Other Current Assets

Other current assets consisted of the following:

 

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

Property, Plant and Equipment

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

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

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

 

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

 

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

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

 

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

Advances to and Investment in Affiliates

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

See Note 4 for a discussion of these joint ventures.

Goodwill

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

 

Changes in the carrying amount of goodwill were as follows:

 

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

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

Intangibles and Other Assets

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

 

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

 

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

 

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

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

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

 

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

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

 

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

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. Our annual impairment test is performed as of August 31 for reporting units within ETP's intrastate transportation and storage, midstream, and retail propane operations and as of December 31 for all others, including Regency's reporting units. No impairment of intangible assets was required during the periods presented in these consolidated financial statements.

Asset Retirement Obligation

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

 

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

 

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

Deposits or advances are received from ETP and Regency's customers as prepayments for natural gas deliveries in the following month and from ETP's propane customers as security or prepayments for future propane deliveries. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of December 31, 2010 was $10.23 billion and $9.38 billion, respectively. As of December 31, 2009, the aggregate fair value and carrying amount of our consolidated debt obligations was $8.25 billion and $7.79 billion, respectively.

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

 

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

 

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

 

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

 

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

 

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

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

Shipping and Handling Costs

Shipping and handling costs related to fuel sold are included in cost of products sold. ETP's shipping and handling costs related to fuel consumed for compression and treating are included in operating expenses and totaled $43.3 million, $55.9 million and $112.0 million for the years ended December 31, 2010, 2009 and 2008, respectively. ETP does not separately charge propane shipping and handling costs to customers.

Costs and Expenses

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

We record the collection of taxes to be remitted to governmental authorities on a net basis.

Issuances of Subsidiary Units

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

Income Taxes

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

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

Those subsidiaries which are taxable corporations follow the asset and liability method of accounting for income taxes, under which deferred income taxes are recorded based upon differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets are received and liabilities settled.

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

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

 

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

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

Accounting for Derivative Instruments and Hedging Activities

For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.

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

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

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

If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in Accumulated Other Comprehensive Income ("AOCI") until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge's change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

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

Allocation of Income (Loss)

For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests (see Note 8).