Note 12 — 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. Although our commodity derivative instruments extend over a number of years, a significant portion of our commodity derivative instruments economically hedge commodity price risk during the next twelve months.

Commodity Price Risk

In order to manage market price risk associated with the Partnership’s fixed-price programs, 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. The Partnership from time to time enters into price swap and put option agreements to reduce the effects of short-term commodity price volatility. At June 30, 2016 and 2015, total volumes associated with LPG commodity derivative instruments totaled 406.4 million gallons and 405.9 million gallons, respectively. At June 30, 2016, the maximum period over which we are economically hedging our exposure to LPG commodity price risk is 39 months.

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 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, 2016 and 2015, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 13.4 million dekatherms and 13.1 million dekatherms, respectively. At June 30, 2016, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 15 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 because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 6).

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. For such contracts entered into by Electric Utility prior to March 1, 2015, Electric Utility chose not to elect the NPNS exception under GAAP and the fair values of these contracts are reflected in current derivative instrument liabilities on the Condensed Consolidated Balance Sheets. Associated gains and losses on these forward contracts are recorded in regulatory assets and liabilities on the Condensed Consolidated Balance Sheets in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6). Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet. At June 30, 2016, all of our Electric Utility’s forward electricity purchase contracts were subject to the NPNS exception. At June 30, 2015, the volumes of Electric Utility’s forward purchase contracts for which NPNS had not been elected was 494.5 million kilowatt hours.

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. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts and 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. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6). At June 30, 2016 and 2015, the total volumes associated with FTRs and NYISO capacity contracts totaled 80.6 million kilowatt hours and 494.5 million kilowatt hours, respectively. At June 30, 2016, the maximum period over which we are economically hedging electricity congestion and locational basis differences is 11 months.

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 and forward contracts, Intercontinental Exchange (“ICE”) natural gas basis swap contracts, and electricity futures and forward 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 electric generation facilities. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas or propane. Because it could no longer assert the NPNS exception under GAAP for new contracts entered into for the forward purchase of natural gas and pipeline transportation, beginning in the second quarter of Fiscal 2014 Energy Services began recording these contracts at fair value with changes in fair value reflected in cost of sales.

At June 30, 2016 and 2015, total volumes associated with Midstream & Marketing’s natural gas futures, forward and pipeline contracts totaled 79.6 million dekatherms and 120.8 million dekatherms, respectively. At June 30, 2016 and 2015, total volumes associated with Midstream & Marketing’s natural gas basis swap contracts totaled 106.3 million dekatherms and 63.9 million dekatherms, respectively. At June 30, 2016, the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk is 53 months. At June 30, 2016 and 2015, total volumes associated with Midstream & Marketing’s electricity long forward and futures contracts and electricity short forward and futures contracts totaled 558.0 million kilowatt hours and 344.7 million kilowatt hours, and 429.5 million kilowatt hours and 210.5 million kilowatt hours, respectively. At June 30, 2016, the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity commodity price risk (excluding Electric Utility) is 36 months for electricity call contracts and 36 months for electricity put contracts. At June 30, 2016, the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 1.8 million dekatherms and there were no propane storage NYMEX contracts. At June 30, 2015, the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 0.8 million dekatherms and 2.0 million gallons, respectively.

At June 30, 2016, there were no amounts remaining in AOCI related to commodity derivative hedges.

Interest Rate Risk

France SAS’s and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. France SAS and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rates of interest on their variable-rate term loans through April 2019 in the case of France SAS’s swap agreements and, through the respective scheduled maturity dates in the case of Flaga’s long-term debt agreements. The France SAS swaps were originally executed in Fiscal 2015, at which time such swaps were designated in a cash flow hedging relationship associated with €600 notional amount of term loan debt issued in conjunction with the Totalgaz Acquisition. In March 2016, France SAS amended the terms of its pay-fixed, receive-variable interest rate swap agreements associated with the €600 term loan debt to purchase a 0% floor that is identical to the 0% floor embedded in France SAS’s term loan debt. In conjunction with the amendments, in March 2016 France SAS paid its interest rate swap counterparties €7.7, which amount substantially equaled the interest rate swaps’ fair value. Concurrent with the amendments to the interest rate swaps, the swaps were simultaneously de-designated and re-designated as cash flow hedges of future anticipated interest payments associated with the €600 term loan debt. The amended swaps fix the underlying euribor rate on the €600 term loan at 0.18%. As of June 30, 2016 and 2015, the total notional amounts of variable-rate debt subject to interest rate swap agreements (excluding Flaga’s cross-currency swap as described below) were €645.8 and €659.1, 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”). On March 31, 2016, concurrent with the pricing of the Senior Notes to be issued under the 2016 Note Purchase Agreement, UGI Utilities settled all of its then-existing IRPA contracts associated with such debt at a loss of $36.0. Because these IRPA contracts qualified for and were designated as cash flow hedges, the loss recognized in connection with the settled IRPAs has been recorded in AOCI and will be recognized in interest expense as the associated future interest expense impacts earnings. See Note 8 for additional information on the 2016 Note Purchase Agreement. At June 30, 2016 and 2015, we had no unsettled IRPAs.

We account for interest rate swaps and IRPAs as cash flow hedges. At June 30, 2016, 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 $3.3.

Foreign Currency Exchange Rate Risk

In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, we hedge a portion of their anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March through the use of forward foreign currency exchange contracts. At June 30, 2016 and 2015, we were hedging a total of $316.8 and $227.9 of our foreign operations’ anticipated U.S. dollar-denominated LPG purchases, respectively. At June 30, 2016, the maximum period over which we are hedging our exposure to the variability in cash flows associated with U.S. dollar-denominated purchases of LPG is 38 months. From time to time 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, 2016 and 2015, 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. At June 30, 2016, the amount of net gains associated with currency rate risk expected to be reclassified into earnings during the next twelve months based upon current fair values is $12.3.

Cross-Currency Swaps

From time to time, Flaga enters into cross-currency swaps to hedge its exposure to the variability in expected future cash flows associated with the foreign currency and interest rate risk of U.S. dollar-denominated debt. These cross-currency hedges include initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. These cross-currency swaps also include interest rate swaps of a fixed foreign-denominated interest rate to a fixed U.S. dollar-denominated interest rate. We designate these cross-currency swaps as cash flow hedges. At June 30, 2016 and 2015, cross-currency swaps were hedging foreign currency risk associated with interest and principal payments on $59.1 and $52.0 of Flaga U.S. dollar-denominated debt, respectively.

At June 30, 2016, the amount of net losses associated with this cross-currency swap expected to be reclassified into earnings during the next twelve months is not material.

Derivative Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative 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 commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30, 2016 and 2015, restricted cash in brokerage accounts totaled $9.6 and $45.2, respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at June 30, 2016. 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, 2016, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

Offsetting Derivative Assets and Liabilities

Derivative assets and liabilities (and cash collateral received and pledged) are presented net by counterparty on the Condensed Consolidated Balance Sheets if the right of offset exists. Our derivative instruments include both those that are executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a financial intermediary, exchange or clearinghouse to enter, execute or clear the transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency or other conditions.

In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on the Condensed Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements.

Fair Value of Derivative Instruments

The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of June 30, 2016 and 2015:



	June 30, 2016			June 30, 2015
Derivative assets:
Derivatives designated as hedging instruments:
Foreign currency contracts	$	18.6		$	29.1
Cross-currency contracts	0.3			8.2
Interest rate contracts	—			1.0
	18.9			38.3
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	5.7			1.9
Derivatives not designated as hedging instruments:
Commodity contracts	64.5			19.9
Total derivative assets - gross	89.1			60.1
Gross amounts offset in the balance sheet	(36.8		)	(17.2		)
Cash collateral received	(2.3		)	—
Total derivative assets - net	$	50.0		$	42.9
Derivative liabilities:
Derivatives designated as hedging instruments:
Foreign currency contracts	$	(0.8	)	$	(0.1	)
Interest rate contracts	(3.8		)	(2.0		)
	(4.6		)	(2.1		)
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	(0.6		)	(4.8		)
Derivatives not designated as hedging instruments:
Commodity contracts	(70.8		)	(147.8		)
Total derivative liabilities - gross	(76.0		)	(154.7		)
Gross amounts offset in the balance sheet	36.8			17.2
Cash collateral pledged	—			2.2
Total derivative liabilities - net	$	(39.2	)	$	(135.3	)

Effect of Derivative Instruments

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, 2016 and 2015:



Three Months Ended June 30,:
	Gain (Loss) Recognized in AOCI						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income
Cash Flow Hedges:	2016			2015			2016			2015
Commodity contracts	$	—		$	—		$	—		$	0.1		Cost of sales
Foreign currency contracts	11.5			(6.4		)	0.2			0.4			Cost of sales
Cross-currency contracts	0.3			(1.5		)	0.1			8.6			Interest expense/other operating income, net
Interest rate contracts	(0.6		)	0.6			(1.3		)	(11.5		)	Interest expense
Total	$	11.2		$	(7.3	)	$	(1.0	)	$	(2.4	)

	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2016			2015			Location of Gain (Loss) Recognized in Income
Commodity contracts	$	44.8		$	(23.5	)	Cost of sales
Commodity contracts	0.1			0.3			Revenues
Commodity contracts	—			0.1			Operating expenses / other operating income, net
Total	$	44.9		$	(23.1	)

Nine Months Ended June 30,:
	Gain (Loss) Recognized in AOCI						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income
Cash Flow Hedges:	2016			2015			2016			2015
Commodity contracts	$	—		$	—		$	—		$	(2.2	)	Cost of sales
Foreign currency contracts	6.2			26.0			17.4			9.6			Cost of sales
Cross-currency contracts	—			6.0			0.3			8.5			Interest expense/other operating income, net
Interest rate contracts	(32.2		)	3.0			(3.2		)	(18.9		)	Interest expense
Total	$	(26.0	)	$	35.0		$	14.5		$	(3.0	)

	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2016			2015			Location of Gain (Loss) Recognized in Income
Commodity contracts	$	(7.4	)	$	(328.3	)	Cost of sales
Commodity contracts	1.9			(0.5		)	Revenues
Commodity contracts	(0.1		)	(0.4		)	Operating expenses/other operating income, net
Total	$	(5.6	)	$	(329.2	)

For the three months ended June 30, 2016, the amounts of derivative gains or losses representing ineffectiveness were not material. For the nine months ended June 30, 2016, the amounts of derivative gains or losses representing ineffectiveness were losses of $5.5, which are recorded in other operating income, net, on the Condensed Consolidated Statements of Income and are related to interest rate contracts at UGI France. For the three and nine months ended June 30, 2016, the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing were not material. For the three and nine months ended June 30, 2015, the amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material.

In May 2015, the Company prepaid term loans outstanding under Antargaz’ 2011 Senior Facilities Agreement. In conjunction with the prepayment, the Company also settled its associated pay-fixed, receive-variable interest rate swaps, and discontinued cash flow hedge accounting treatment for such swaps. During the three months ended June 30, 2015, the Company recorded a pre-tax loss of $9.0 associated with the discontinuance of cash flow hedge accounting for the swaps, which amount is included in interest expense on the Condensed Consolidated Statements of Income.

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 that provide for the purchase and delivery, or sale, of energy products, 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, certain of these contracts qualify for NPNS 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.