Disclosures About Derivative Instruments and Hedging Activities

6 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Disclosures About Derivative Instruments and Hedging Activities

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 and (2) interest 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 commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations.

Commodity Price Risk

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 March 31, 2014 and 2013, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 9.0 million dekatherms and 10.0 million dekatherms, respectively. At March 31, 2014, the maximum period over which Gas Utility is hedging natural gas market price risk is 11 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 accounting guidance related to rate-regulated entities and reflected in cost of sales through the PGC 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. Because 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 March 31, 2014 and 2013, the fair values of Electric Utility’s forward purchase power agreements comprising net gains of $358 and net losses of $5,458, 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 March 31, 2014 and 2013, the volumes of Electric Utility’s forward electricity purchase contracts were 207.0 million kilowatt hours and 403.2 million kilowatt hours, respectively. At March 31, 2014, the maximum period over which these contracts extend is 8 months.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly auctions. 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 6). At March 31, 2014 and 2013, the volumes associated with Electric Utility FTRs totaled 47.4 million kilowatt hours and 47.5 million kilowatt hours, 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.

Interest Rate Risk

Our long-term debt typically is 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”). We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded in AOCI, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. As of March 31, 2014 we had no unsettled IRPAs. As of March 31, 2013, the total notional amounts of unsettled IRPAs was $173,000.

At March 31, 2014, the amount of net losses associated with settled IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $2,680.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At March 31, 2014 and 2013, there was no restricted cash in brokerage accounts.

The following table provides information regarding the balance sheet location and fair values of our derivative assets and liabilities existing as of March 31, 2014 and 2013:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2014		2013		Location	2014			2013
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Derivative financial instruments	$	—	$	4,229	Derivative financial instruments	$	—		$	(24,298	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	3,153		4,130		Derivative financial instruments and Other noncurrent liabilities	(372		)	(5,467		)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	68		169		Derivative financial instruments	—			—
Total Derivatives		$	3,221	$	8,528		$	(372	)	$	(29,765	)

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for the three and six months ended March 31, 2014 and 2013:

Three Months Ended March 31, :
	Gain (Loss) Recognized in AOCI					Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2014			2013		2014			2013			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—		$	6,116	$	(670	)	$	(202	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income											Location of Gain (Loss) Recognized in Income
	2014			2013
Commodity contracts	$	(18	)	$	107							Operating expenses/other income, net
Six Months Ended March 31, :
	Gain (Loss) Recognized in AOCI					Gain (Loss) Reclassified from AOCI into Income						Location of Gain or
	2014			2013		2014			2013			(Loss) Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—		$	10,452	$	1,339		$	(405	)	Interest expense
Derivatives Not Designated
as Hedging Instruments:	Gain (Loss) Recognized in Income											Location of Gain (Loss) Recognized in Income
	2014			2013
Commodity contracts	$	79		$	105							Operating expenses/other income, net

We are also a party to a number of 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 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 purchase and normal sale 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.