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.

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, 2015 and 2014, total volumes associated with LPG commodity derivative instruments totaled 405.9 million gallons and 274.3 million gallons, respectively. At June 30, 2015, the maximum period over which we are economically hedging our exposure to LPG commodity price risk is 42 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, 2015 and 2014, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 13.1 million dekatherms and 10.9 million dekatherms, respectively. At June 30, 2015, 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 related to these derivative instruments and the fair values of these contracts are reflected in current and noncurrent derivative instrument assets and liabilities in the accompanying 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, 2015 and 2014, the volumes of Electric Utility’s forward electricity purchase contracts were 494.5 million kilowatt hours and 315.8 million kilowatt hours, respectively. At June 30, 2015, 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. 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, 2015 and 2014, the total volumes associated with FTRs and NYISO capacity contracts totaled 494.5 million kilowatt hours and 747.4 million kilowatt hours, respectively. At June 30, 2015, 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 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 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, 2015 and 2014, total volumes associated with Midstream & Marketing’s natural gas futures, forward and pipeline contracts totaled 57.2 million dekatherms and 67.7 million dekatherms, respectively. At June 30, 2015, the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk is 45 months. At June 30, 2015 and 2014, total volumes associated with Midstream & Marketing’s electricity call contracts and electricity put contracts totaled 429.5 million kilowatt hours and 210.5 million kilowatt hours, and 492.5 million kilowatt hours and 193.2 million kilowatt hours, respectively. At June 30, 2015, 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 30 months for electricity call contracts and 15 months for electricity put 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, 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, 2015, the amount of net gains associated with commodity derivative instruments previously designated and qualified as cash flow hedges expected to be reclassified into earnings during the next twelve months is not material.

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 and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on their variable-rate term loans through the respective scheduled maturity dates. As of June 30, 2015 and 2014, the total notional amounts of variable-rate debt subject to interest rate swap agreements (excluding Flaga’s cross-currency swap as described below) were €659.1 and €401.1, 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”). At June 30, 2015 and 2014, we had no unsettled IRPAs.

We account for interest rate swaps and IRPAs as cash flow hedges. At June 30, 2015, 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 $2.6.

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases during the heating-season months of October through March through the use of forward foreign currency exchange contracts. At June 30, 2015 and 2014, we were hedging a total of $227.9 and $219.8 of U.S. dollar-denominated LPG purchases, respectively. At June 30, 2015, 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 33 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, 2015 and 2014, 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, 2015, the amount of net gains 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 $16.1.

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. dollar-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. At June 30, 2015, the amount of net gains associated with this cross-currency swap expected to be reclassified into earnings over 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 form 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, 2015 and 2014, restricted cash in brokerage accounts totaled $45.2 and $5.9, 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, 2015. 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, 2015, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

Fair Value of Derivative Instruments

The following table presents the Company’s derivative assets and liabilities on a gross basis as of June 30, 2015 and 2014:



	June 30, 2015			June 30, 2014 (a)
Derivative assets:
Derivatives designated as hedging instruments:
Commodity contracts	$	—		$	8.1
Foreign currency contracts	29.1			0.8
Cross-currency contracts	8.2			—
Interest rate contracts	1.0			—
	38.3			8.9
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	1.9			2.4
Derivatives not designated as hedging instruments:
Commodity contracts	19.9			22.5
Total derivative assets	$	60.1		$	33.8
Derivative liabilities:
Derivatives designated as hedging instruments:
Commodity contracts	$	—		$	(4.2	)
Foreign currency contracts	(0.1		)	(5.1		)
Cross-currency contracts	—			(2.0		)
Interest rate contracts	(2.0		)	(25.2		)
	(2.1		)	(36.5		)
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	(4.8		)	(0.8		)
Derivatives not designated as hedging instruments:
Commodity contracts	(147.8		)	(25.9		)
Total derivative liabilities	$	(154.7	)	$	(63.2	)


(a)	Certain immaterial amounts have been revised to correct the classification of derivatives.

Offsetting Derivative Assets and Liabilities

Derivative assets and liabilities are presented net by counterparty on our 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 our 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.

The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of June 30, 2015 and 2014:



	Gross Amounts Recognized			Gross Amounts Offset in Balance Sheet			Net Amounts Recognized			Cash Collateral (Received) Pledged		Net Amounts Recognized in Balance Sheet
June 30, 2015
Derivative assets	$	60.1		$	(17.2	)	$	42.9		$	—	$	42.9
Derivative liabilities	$	(154.7	)	$	17.2		$	(137.5	)	$	2.2	$	(135.3	)
June 30, 2014
Derivative assets	$	33.8		$	(20.1	)	$	13.7		$	—	$	13.7
Derivative liabilities	$	(63.2	)	$	20.1		$	(43.1	)	$	—	$	(43.1	)

Effect of Derivative Instruments

The following tables provide information on the effects of derivative instruments in the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three and nine months ended June 30, 2015 and 2014:



	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 Interests into Income
Three Months Ended June 30,	2015			2014			2015			2014
Cash Flow Hedges:
Commodity contracts	$	—		$	(1.7	)	$	0.1		$	4.3		Cost of sales
Foreign currency contracts	(6.4		)	1.1			0.4			(0.2		)	Cost of sales
Cross-currency contracts	(1.5		)	—			8.6			(0.1		)	Interest expense/other operating income, net
Interest rate contracts	0.6			(0.6		)	(11.5		)	(3.9		)	Interest expense
Total	$	(7.3	)	$	(1.2	)	$	(2.4	)	$	0.1

	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Three Months Ended June 30,	2015			2014			Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	(23.5	)	$	(4.9	)	Cost of sales
Commodity contracts	0.3			—			Revenues
Commodity contracts	0.1			—			Operating expenses / other operating income, net
Total	$	(23.1	)	$	(4.9	)

	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 Interests into Income
Nine Months Ended June 30,	2015			2014			2015			2014
Cash Flow Hedges:
Commodity contracts	$	—		$	59.5		$	(2.2	)	$	66.5		Cost of sales
Foreign currency contracts	26.0			(1.6		)	9.6			(3.7		)	Cost of sales
Cross-currency contracts	6.0			(1.1		)	8.5			(0.2		)	Interest expense/other operating income, net
Interest rate contracts	3.0			(4.1		)	(18.9		)	(12.0		)	Interest expense
Total	$	35.0		$	52.7		$	(3.0	)	$	50.6

	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Nine Months Ended June 30,	2015			2014			Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	(328.3	)	$	(14.3	)	Cost of sales
Commodity contracts	(0.5		)	—			Revenues
Commodity contracts	(0.4		)	0.1			Operating expenses/other operating income, net
Total	$	(329.2	)	$	(14.2	)

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 for the three and nine months ended June 30, 2015 and 2014.

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 (see Note 8).

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.