Disclosures About Derivative Instruments and Hedging Activities

9 Months Ended

Jun. 30, 2011

Disclosures About Derivative Instruments and Hedging Activities [Abstract]

Disclosures About Derivative Instruments and Hedging Activities

13. Disclosures About Derivative Instruments and Hedging Activities

We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk, (2) interest rate risk and (3) foreign currency exchange rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Because most of our derivative instruments generally qualify as hedges under GAAP or are subject to regulatory rate recovery mechanisms, we expect that changes in the fair value of derivative instruments used to manage commodity, interest rate or currency exchange rate risk would be substantially offset by gains or losses on the associated anticipated transactions.

Commodity Price Risk

In order to manage market price risk associated with the Partnership’s fixed-price programs which permit customers to lock in the prices they pay for propane principally during the months of October through March, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic business units and our International Propane operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. In addition, from time to time, the Partnership enters into price swap agreements to provide market price risk support to some of its wholesale customers. These agreements are not designated as hedges for accounting purposes and the volumes of propane subject to these agreements were not material.

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At June 30, 2011 and 2010, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 18.6 million dekatherms and 11.3 million dekatherms, respectively. At June 30, 2011, the maximum period over which Gas Utility is hedging natural gas market price risk is 16 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with ASC No. 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 7).

Beginning January 1, 2010, Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At June 30, 2011, the fair values of Electric Utility’s forward purchase power agreements comprising a loss of $10.1 are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying June 30, 2011 Condensed Consolidated Balance Sheet. In accordance with ASC 980, Electric Utility has recorded equal and offsetting amounts in regulatory assets on the June 30, 2011 Condensed Consolidated Balance Sheet. At June 30, 2011, volumes under Electric Utility’s forward electricity purchase contracts were 874.4 million kilowatt hours and the maximum period over which these contracts extend is 35 months.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs associated with certain default service customers, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010 are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 7). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At June 30, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 287.3 million kilowatt hours and 739.3 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At June 30, 2011 and 2010, the volumes associated with Midstream & Marketing’s FTRs totaled 1,955.2 million kilowatt hours and 1,415.0 million kilowatt hours, respectively.

In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas and electricity futures contracts. In addition, beginning April 1, 2011, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Because the contracts associated with the anticipated sale of stored natural gas or propane do not qualify for hedge accounting treatment, any gains or losses on the derivative contracts are recognized in earnings prior to gains or losses from the sale of the stored gas. Such derivative gains or losses during the three months ended June 30, 2011 were not material. At June 30, 2011, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 2.3 million dekatherms and 0.9 million gallons, respectively.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. Associated volumes, fair values and effects on net income were not material for all periods presented.

At June 30, 2011 and 2010, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:

	Volumes
	June 30,
Commodity	2011		2010
LPG (millions of gallons)		145.0		150.5
Natural gas (millions of dekatherms)		21.2		33.3
Electricity (millions of kilowatt-hours)		1,200.8		928.0

At June 30, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 15 months with a weighted average of 7 months; the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk (excluding Gas Utility) is 30 months with a weighted average of 9 months; and the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity price risk (excluding Electric Utility) is 21 months with a weighted average of 7 months. At June 30, 2011, the maximum period over which we are economically hedging electricity congestion with FTRs (excluding Electric Utility) is 11 months.

We account for commodity price risk contracts (other than those contracts that are not eligible for hedge accounting and Gas Utility and Electric Utility contracts that are subject to regulatory treatment) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in accumulated other comprehensive income (“AOCI”) and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying commodity price risk. When earnings are affected by the hedged commodity, gains or losses are recorded in cost of sales on the Condensed Consolidated Statements of Income. At June 30, 2011, the amount of net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $8.7.

Interest Rate Risk

Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its variable-rate term loan, and Flaga has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on a substantial portion of its term loans, in each case through the respective scheduled maturity dates. As of June 30, 2011 and 2010, the total notional amounts of existing or anticipated variable-rate debt subject to interest rate swap agreements were €398.8 and €706.2, respectively.

Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At June 30, 2011, the total notional amount of unsettled IRPAs was $173.0. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of UGI Utilities’ long-term debt forecasted to occur in September 2012 and September 2013.

As previously disclosed, during the three months ended March 31, 2010, the Partnership’s management determined that it was likely that it would not issue $150 of long-term debt during the summer of 2010. As a result, the Partnership discontinued cash flow hedge accounting treatment for interest rate protection agreements associated with this previously anticipated long-term debt issuance and recorded a $12.2 loss which is reflected in other income, net, on the Condensed Consolidated Statements of Income for the nine months ended June 30, 2010.

We account for interest rate swaps and IRPAs as cash flow hedges. Changes in the fair values of interest rate swaps and IRPAs are recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At such time, gains and losses are recorded in interest expense. At June 30, 2011, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $1.7 (which excludes the impact of AmeriGas Partners’ debt refinancing described in Note 15).

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 30% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At June 30, 2011 and 2010, we were hedging a total of $141.4 and $72.8 of U.S. dollar-denominated LPG purchases, respectively. At June 30, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 32 months with a weighted average of 12 months. We also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our International Propane euro-denominated net investments. At June 30, 2011 and 2010, we were hedging a total of €14.5 and €48.3, respectively, of our euro-denominated net investments. As of June 30, 2011, our foreign currency contracts extend through March 2014.

We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these contracts are recorded in AOCI, to the extent effective in offsetting changes in the underlying currency exchange rate risk, until earnings are affected by the hedged LPG purchase, at which time gains and losses are recorded in cost of sales. At June 30, 2011, the amount of net losses associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $4.0. Gains and losses on net investment hedges remain in AOCI until such foreign net investment is sold or liquidated.

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures and option contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. At June 30, 2011 and 2010, restricted cash in these accounts totaled $10.2 and $22.9, respectively. Although we have concentrations of credit risk associated with derivative financial instruments, the maximum amount of loss, based upon the gross fair values of the derivative financial instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at June 30, 2011. We generally do not have credit-risk-related contingent features in our derivative contracts.

The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2011 and 2010:

	Derivative Assets					Derivative (Liabilities)
		Fair Value					Fair Value
	Balance Sheet	June 30,				Balance Sheet	June 30,
	Location	2011		2010		Location	2011			2010
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments and Other assets	$	6.0	$	0.3	Derivative financial instruments and Other noncurrent liabilities	$	(12.6	)	$	(42.8	)
Foreign currency contracts
	Derivative financial instruments and Other assets		—		16.9	Derivative financial instruments and Other noncurrent liabilities		(6.1	)		—
Interest rate contracts
	Other assets		5.0		—	Derivative financial instruments and Other noncurrent liabilities		(3.6	)		(16.4	)
Total Derivatives Designated as Hedging Instruments		$	11.0	$	17.2		$	(22.3	)	$	(59.2	)
Derivatives Accounted for under ASC 980:
Commodity contracts	Derivative financial instruments	$	0.2	$	0.6	Derivative financial instruments and Other noncurrent liabilities	$	(11.2	)	$	(0.8	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	$	4.5	$	2.8
Total Derivatives		$	15.7	$	20.6		$	(33.5	)	$	(60.0	)

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three and nine months ended June 30, 2011 and 2010:

Three Months Ended June 30,:

	Gain (Loss)						Gain (Loss)						Location of
	Recognized in						Reclassified from						Gain (Loss)
	AOCI and						AOCI and Noncontrolling						Reclassified from
	Noncontrolling Interests						Interests into Income						AOCI and Noncontrolling
	2011			2010			2011			2010			Interests into Income
Cash Flow
Hedges:
Commodity contracts	$	(1.4	)	$	(14.6	)	$	3.9		$	(7.7	)	Cost of sales
Foreign currency contracts		(1.9	)		5.3			—			0.1		Cost of sales
Interest rate contracts		(13.2	)		(6.3	)		(2.4	)		(3.9	)	Interest expense / other income
Total	$	(16.5	)	$	(15.6	)	$	1.5		$	(11.5	)
Net Investment
Hedges:
Foreign currency contracts	$	(0.5	)	$	6.1
	Gain (Loss)
	Recognized in Income												Location of Gain (Loss)
	2011			2010									Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	—		$	(0.1	)							Operating expenses / other income
Commodity contracts		0.2			1.0								Cost of sales
Total	$	0.2		$	0.9

Nine Months Ended June 30,:

	Gain (Loss)						Gain (Loss)						Location of
	Recognized in						Reclassified from						Gain (Loss)
	AOCI and						AOCI and Noncontrolling						Reclassified from
	Noncontrolling Interests						Interests into Income						AOCI and Noncontrolling
	2011			2010			2011			2010			Interests into Income
Cash Flow
Hedges:
Commodity contracts	$	25.4		$	(30.1	)	$	(19.1	)	$	(14.1	)	Cost of sales
Foreign currency contracts		(3.4	)		12.2			(0.7	)		0.7		Cost of sales
Interest rate contracts		11.6			(7.2	)		(9.6	)		(24.4	)	Interest expense /other income
Total	$	33.6		$	(25.1	)	$	(29.4	)	$	(37.8	)
Net Investment
Hedges:
Foreign currency contracts	$	(1.1	)	$	11.2
	Gain (Loss)
	Recognized in Income												Location of Gain (Loss)
	2011			2010									Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	0.3		$	0.1								Operating expenses / other income
Commodity contracts		(0.4	)		1.4								Cost of sales
Total	$	(0.1	)	$	1.5

The amounts of derivative gains or losses representing ineffectiveness were not material for the three and nine months ended June 30, 2011 and 2010.

We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery, or sale, of natural gas, LPG and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchases and normal sales exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.