PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

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

Investment in ETP

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hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.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

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

We are also exposed to commodity price risk on NGLs and residue gas we retain for fees in our midstream operations whereby the Company generally 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 for the residue gas and NGLs. We use derivative swap contracts to hedge forecasted sales of NGL equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

Our trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to our transportation and storage operations and are netted in cost of products sold in our consolidated statements of operations. Additionally, we also have trading activities related to power which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage operations, 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 oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

Derivatives are utilized in our midstream operations in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. We attempt to maintain balanced positions in our marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices.

Prior to the deconsolidation of the Propane Business, we also used propane futures contracts to fix the purchase price related to certain fixed price sales contracts. Prior to the sale of our cylinder exchange business, we used propane futures contracts to secure the purchase price of our propane inventory for a percentage of the anticipated sales.

The following table details ETP’s outstanding commodity-related derivatives:



	December 31, 2012			December 31, 2011
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX ⁽¹⁾	(30,980,000	)	2013-2014	(151,260,000	)	2012-2013
Power (Megawatt):
Forwards	19,650		2013	—		—
Futures	(1,509,300	)	2013	—		—
Options — Calls	1,656,400		2013	—		—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	150,000		2013	(61,420,000	)	2012-2013
Swing Swaps IFERC	(83,292,500	)	2013	92,370,000		2012-2013
Fixed Swaps/Futures	27,077,500		2013	797,500		2012
Forward Physical Contracts	11,689,855		2013-2014	(10,672,028	)	2012
Options — Puts	—		2013	—		—
NGLs (Bbls):
Forwards/Swaps	(30,000	)	2013	—		—
Refined Products (Bbls)	(666,000	)	2013	—		—
Propane (Gallons):
Forwards/Swaps	—		—	38,766,000		2012-2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(18,655,000	)	2013	(28,752,500	)	2012
Fixed Swaps/Futures	(44,272,500	)	2013	(45,822,500	)	2012
Hedged Item — Inventory	44,272,500		2013	45,822,500		2012
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	(8,212,500	)	2013	—		—
Options — Puts	—		—	3,600,000		2012
Options — Calls	—		—	(3,600,000	)	2012
NGLs (Bbls):
Forwards/Swaps	(930,000	)	2013	—		—
Refined Products (Bbls)	(98,000	)	2013	—		—

⁽¹⁾ Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

We expect losses of $6 million related to ETP’s commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

Investment in Regency

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

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

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

The following table details Regency’s outstanding commodity-related derivatives:



	December 31, 2012		December 31, 2011
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	8,395,000	2013-2014	—	—
Propane (Gallons):
Forwards/Swaps	3,318,000	2013	—	—
Natural Gas Liquids (Barrels):
Forwards/Swaps	243,000	2013-2014	—	—
Options — Puts	—	—	110,000	2012
WTI Crude Oil (Barrels):
Forwards/Swaps	356,000	2014	—	—
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	—	—	2,198,000	2012
Propane (Gallons):
Forwards/Swaps	—	—	11,802,000	2012-2013
Natural Gas Liquids (Barrels):
Forwards/Swaps	—	—	533,000	2012-2013
WTI Crude Oil (Barrels):
Forwards/Swaps	—	—	350,000	2012-2014

As of December 31, 2011 all of the Regency’s commodity swap contracts were accounted for as cash flow hedges, and the Regency’s put options were accounted for on mark-to-market basis. On January 1, 2012, Regency, for accounting purposes, de-designated its swap contracts and will account for these contracts using the mark-to-market method of accounting. Regency has less than $1 million in net hedging gains in AOCI, the majority of which will be amortized to earnings over the next 12 months.

Interest Rate Risk

We are exposed to market risk for changes in interest rates. In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We manage our current interest rate exposures by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of anticipated debt issuances. The following is a summary of interest rate swaps outstanding as of December 31, 2012, none of which are designated as hedges for accounting purposes:

Notional Amount

Outstanding

Entity

Term

Type⁽¹⁾

December 31,
2012

December 31, 2011

ETE

March 2017

Pay a fixed rate of 1.25% and receive a floating rate

500

—

ETP

May 2012 ⁽²⁾

Forward starting to pay a fixed rate of 2.59% and receive a floating rate

—

350

ETP

August 2012⁽²⁾

Forward starting to pay a fixed rate of 3.51% and receive a floating rate

—

500

ETP

July 2013 ⁽²⁾

Forward starting to pay a fixed rate of 4.02% and receive a floating rate

400

300

ETP

July 2014 ⁽²⁾

Forward starting to pay a fixed rate of 4.26% and receive a floating rate

400

—

ETP

July 2018

Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%

600

500

Regency

April 2012

Pay a fixed rate of 1.325% and receive a floating rate

—

250

Southern Union

November 2016

Pay a fixed rate of 2.913% and receive a floating rate

N/A

Southern Union

November 2021

Pay a fixed rate of 3.746% and receive a floating rate

450

N/A

(1) Floating rates are based on 3-month LIBOR.

(2) These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.

As of December 31, 2012, Southern Union had no outstanding treasury rate locks; however, certain of its treasury rate locks that settled in prior periods are associated with interest payments on outstanding long-term debt. These treasury rate locks are accounted for as cash flow hedges, with the effective portion of their settled value recorded in AOCI and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

In connection with ETE’s offering of senior notes in September 2010, ETE terminated interest rate swaps with an aggregate notional amount of $1.5 billion and recognized in interest expense $66 million of realized losses on terminated interest rate swaps that had been accounted for as cash flow hedges. In addition to the $66 million of realized losses on hedged interest rate swaps, ETE also paid $102 million to terminate non-hedged interest rate swaps. The $102 million of realized losses on non-hedged interest rate swaps had previously been recognized in net income and therefore the termination of the non-hedged swaps did not impact earnings. The total cash paid to terminate interest rate swaps was $169 million, including realized losses on hedged and non-hedged swaps.

Credit Risk

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

Our counterparties consist primarily of petrochemical companies and other industrial, small to major oil and gas producers, midstream and power generation companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on financial our position or results of operations as a result of counterparty nonperformance.

ETP utilizes master-netting agreements and have maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on the settlement date for non-exchange traded derivatives. ETP exchanges margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. ETP had net deposits with counterparties of $41 million and $66 million as of December 31, 2012 and 2011, respectively.

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

Certain of Southern Union’s derivative instruments contain provisions that require Southern Union’s debt to be maintained at an investment grade credit rating from each of the major credit rating agencies. If Southern Union’s debt were to fall below investment grade, Southern Union would be in violation of these provisions, and the counterparties to the derivative instruments could potentially require Southern Union to post collateral for certain of the derivative instruments. The aggregate fair value of Southern Union’s derivative instruments with credit-risk-related contingent features that are in a net liability position at December 31, 2012 was $4 million, all of which were included in the disposal group held for sale liabilities and December 31, 2012.

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

Derivative Summary

The following table provides a balance sheet overview of the Partnership’s derivative assets and liabilities as of December 31, 2012 and 2011:



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	2012		2011		2012			2011
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	8	$	77	$	(10	)	$	(1	)
Commodity derivatives	—		5		—			(10		)
	8		82		(10		)	(11		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	110	$	227	$	(116	)	$	(251	)
Commodity derivatives	40		1		(44		)	(5		)
Interest rate derivatives	55		36		(235		)	(118		)
Embedded derivatives in Regency Preferred Units	—		—		(25		)	(39		)
	205		264		(420		)	(413		)
Total derivatives	$	213	$	346	$	(430	)	$	(424	)

The commodity derivatives (margin deposits) are recorded in other current assets on our consolidated balance sheets. The remainder of the derivatives are recorded in price risk management assets or price risk management liabilities. As of December 31, 2012 commodity derivative assets of $1 million and commodity derivatives liabilities of $8 million were recorded as non-current assets held for sale and current liabilities held for sale in our consolidated balance sheet. In addition to the above derivatives, $7 million of option premiums included in price risk management liabilities as of December 31, 2012 will amortize in 2013.

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

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



	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Years Ended December 31,
	2012		2011		2010
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	8	$	6	$	50
Interest rate derivatives	—		—		(30		)
Total	$	8	$	6	$	20



	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Years Ended December 31,
		2012		2011		2010
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	14	$	19	$	37
Interest rate derivatives	Interest expense, net	—		—		(87		)
Total		$	14	$	19	$	(50	)



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Years Ended December 31,
		2012		2011		2010
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	54	$	34	$	16
Total		$	54	$	34	$	16



	Location of Gain/ (Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2012			2011			2010
Derivatives in cash flow hedging relationships:
Commodity derivatives – Trading	Cost of products sold	$	(7	)	$	(30	)	$	—
Commodity derivatives – Non-trading	Cost of products sold	26			9			4
Commodity derivatives – Non-trading	Deferred gas purchases	26			—			—
Interest rate derivatives	Losses on non-hedged interest rate derivatives	(19		)	(78		)	(52		)
Embedded derivatives	Other income (expense)	14			18			(8		)
Total		$	40		$	(81	)	$	(56	)