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.

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 UGI International 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, the Partnership from time to time enters into price swap and put option agreements to reduce the effects of short-term commodity price volatility.

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, including the cost of financial instruments used to economically hedge purchased gas costs. 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, 2014 and 2013, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 10.9 million dekatherms and 11.7 million dekatherms, respectively. At June 30, 2014, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 9 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 GAAP related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 8).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because most of these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At June 30, 2014 and 2013, the fair values of Electric Utility’s forward purchase power agreements comprising gains of $0.8 and losses of $6.1, respectively, are reflected in current derivative financial instrument assets and liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets and liabilities. At June 30, 2014 and 2013, the volumes of Electric Utility’s forward electricity purchase contracts were 315.8 million kilowatt hours and 327.4 million kilowatt hours, respectively. At June 30, 2014, the maximum period over which these contracts extend is 11 months.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly 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. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 8). Midstream & Marketing from time to time also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. At June 30, 2014 and 2013, the volumes associated with Electric Utility FTRs totaled 232.2 million kilowatt hours and 260.6 million kilowatt hours, respectively. Midstream & Marketing’s FTRs and capacity swap contracts are recorded at fair value with changes in fair value reflected in cost of sales. At June 30, 2014 and 2013, the volumes associated with Midstream & Marketing’s FTRs and NYISO capacity swap contracts totaled 427.7 million kilowatt hours and 1,609.2 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 futures contracts, Intercontinental Exchange (“ICE”) natural gas basis swap contracts, and electricity futures contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge the price of a portion of its anticipated future sales of electricity from its electricity generation facilities. In addition, 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. During the three months ended March 31, 2014, Energy Services determined that it could no longer assert the normal purchases and normal sales exception under GAAP for new contracts entered into for the forward purchase of natural gas and pipeline transportation and, as a result, began accounting for these contracts at fair value on the balance sheet with changes in fair value reflected in net income. These contracts, as well as other Midstream & Marketing derivative instruments described above, are not accounted for as hedges under GAAP. These derivative instruments are recorded at fair value with changes in fair value reflected in income.

At June 30, 2014 and 2013, total volumes associated with Midstream & Marketing’s natural gas futures, forward and pipeline transportation contracts totaled 83.0 million dekatherms and 19.4 million dekatherms, respectively. Total volumes associated with Midstream & Marketing’s electricity call contracts and electricity put contracts totaled 492.5 million kilowatt hours and 193.2 million kilowatt hours at June 30, 2014, and 927.2 million kilowatt hours and 451.0 million kilowatt hours at June 30, 2013, respectively. At June 30, 2014, the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 0.5 million dekatherms and 2.9 million gallons, respectively. At June 30, 2013, the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 2.7 million dekatherms and 1.8 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, 2014 and 2013, total volumes associated with LPG commodity derivative instruments totaled 274.3 million gallons and 236.7 million gallons, respectively. At June 30, 2014, for those LPG commodity derivative instruments accounted for as cash flow hedges, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 21 months with a weighted average of 6 months.

We account for commodity price risk contracts at our UGI International business units, and at the Partnership for commodity derivative instruments entered into prior to April 1, 2014, as cash flow hedges. Effective April 1, 2014, the Partnership determined that on a prospective basis it would not elect cash flow hedge accounting for its commodity derivative transactions. All unrealized and realized gains and losses on the Partnership’s derivative commodity transactions entered into beginning April 1, 2014, are included as a component of cost of sales on the Condensed Consolidated Statements of Income. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in AOCI and, with respect to the Partnership’s contracts, also in 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, 2014, the amount of net gains associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $4.0.

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 its term loans, in each case through the respective scheduled maturity dates. As of June 30, 2014 and 2013, the total notional amount of existing variable-rate debt subject to interest rate swap agreements (excluding Flaga’s cross-currency swap as described below) was €401.1 and €440.5, 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, 2014, we had no unsettled IRPAs. At June 30, 2013, the total notional amount of unsettled IRPAs was $173.

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, also in 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, 2014, 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 $2.7.

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 forecasted to occur during the heating-season months of October through March. At June 30, 2014 and 2013, we were hedging a total of $219.8 and $170.3 of U.S. dollar-denominated LPG purchases, respectively. At June 30, 2014, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 33 months with a weighted average of 15 months. From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. At June 30, 2014 and 2013, we had no euro-denominated net investment hedges.

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 foreign currency exchange 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, 2014, 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 $3.6. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.

From time to time, the Company may enter into foreign currency exchange transactions to economically hedge the local-currency purchase price of anticipated foreign business acquisitions. These transactions do not qualify for hedge accounting treatment and any changes in fair value are recorded in other income, net.

Cross-Currency Swaps

During Fiscal 2013, Flaga entered into a cross-currency swap to hedge its exposure to the variability in expected future cash flows associated with foreign currency and interest rate risk resulting from the issuance of $52 of U.S. dollar-denominated variable-rate debt. The cross-currency hedge includes initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. The cross-currency swap also includes an interest rate swap of a fixed foreign-denominated interest rate to a fixed U.S. dollar-denominated interest rate. We have designated this cross-currency swap as a cash flow hedge. Changes in the fair value of our cross-currency swap are recorded in AOCI to the extent effective in offsetting changes in the underlying foreign currency exchange and interest rate risk. At June 30, 2014, the amount of net losses associated with this cross-currency swap expected to be reclassified into earnings over the next twelve months is not material.

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 contracts generally require cash deposits in margin accounts. At June 30, 2014 and 2013, restricted cash in brokerage accounts totaled $5.9 and $6.0, 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, 2014. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At June 30, 2014, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2014 and 2013:



	Derivative Assets						Derivative (Liabilities)
	Balance Sheet	Fair Value June 30,					Balance Sheet	Fair Value June 30,
	Location	2014			2013		Location	2014			2013
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments and Other assets	$	7.0		$	5.3	Derivative financial instruments and Other noncurrent liabilities	$	(3.1	)	$	(17.9	)
Foreign currency contracts	Derivative financial instruments and Other assets	0.5			1.0		Derivative financial instruments and Other noncurrent liabilities	(4.8		)	(0.4		)
Cross-currency contracts		—			—		Derivative financial instruments and Other noncurrent liabilities	(2.0		)	—
Interest rate contracts	Derivative financial instruments	—			8.1		Derivative financial instruments and Other noncurrent liabilities	(25.2		)	(46.9		)
Total Derivatives Designated as Hedging Instruments		$	7.5		$	14.4		$	(35.1	)	$	(65.2	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	$	1.6		$	0.1	Derivative financial instruments	$	—		$	(7.6	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments and Other assets	$	6.4		$	4.2	Derivative financial instruments and Other noncurrent liabilities	$	(9.8	)	$	(6.6	)
Foreign currency contracts	Derivative financial instruments	—			—		Derivative financial instruments	—			(1.3		)
Total Derivatives Not Designated as Hedging Instruments		$	6.4		$	4.2		$	(9.8	)	$	(7.9	)
Amounts above offset in the Balance Sheet		(1.8		)	—			1.8			—
Total Derivatives		$	13.7		$	18.7		$	(43.1	)	$	(80.7	)

The following tables provide 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, 2014 and 2013:



Three Months Ended June 30,	Gain (Loss) Recognized in AOCI and Noncontrolling Interests						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2014			2013			2014			2013			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	(1.7	)	$	(17.1	)	$	4.3		$	(8.2	)	Cost of sales
Foreign currency contracts	1.1			(0.3		)	(0.2		)	—			Cost of sales
Cross-currency contracts	—			—			(0.1		)	—			Interest expense
Interest rate contracts	(0.6		)	14.0			(3.9		)	(3.6		)	Interest expense / other income, net
Total	$	(1.2	)	$	(3.4	)	$	0.1		$	(11.8	)

	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2014			2013
Commodity contracts	$	(4.9	)	$	(5.7	)							Cost of sales
Commodity contracts	—			(0.1		)							Operating expenses / other income, net
Foreign currency contracts	—			(0.9		)							Other income, net
Total	$	(4.9	)	$	(6.7	)

Nine Months Ended June 30,	Gain (Loss) Recognized in AOCI and Noncontrolling Interests						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2014			2013			2014			2013			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	59.5		$	(21.6	)	$	66.5		$	(51.4	)	Cost of sales
Foreign currency contracts	(1.6		)	(1.4		)	(3.7		)	(0.1		)	Cost of sales
Cross-currency contracts	(1.1		)	—			(0.2		)	—			Interest expense
Interest rate contracts	(4.1		)	23.0			(12.0		)	(10.6		)	Interest expense / other income, net
Total	$	52.7		$	—		$	50.6		$	(62.1	)

	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2014			2013
Commodity contracts	$	(14.3	)	$	8.1								Cost of sales
Commodity contracts	0.1			—									Operating expenses / other income, net
Foreign currency contracts	—			(1.1		)							Other income, net
Total	$	(14.2	)	$	7.0

The amounts of derivative gains or losses representing ineffectiveness were not material for the three- and nine-month periods ended June 30, 2014 and 2013.

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 and contracts that 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.