Disclosures About Derivative Instruments and Hedging Activities

12 Months Ended

Sep. 30, 2012

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 September 30, 2012 and 2011, the volumes of natural gas associated with Gas Utility's unsettled NYMEX natural gas futures and option contracts totaled 19.2 million dekatherms and 15.1 million dekatherms, respectively. At September 30, 2012, the maximum period over which Gas Utility is hedging natural gas market price risk is 12 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 Consolidated Balance Sheets in accordance with FASB's guidance in ASC 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 4).

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. 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. Accordingly, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At September 30, 2012 and 2011, the fair values of Electric Utility's forward purchase power agreements comprising losses of $9,207 and $8,655, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the accompanying Consolidated Balance Sheets. In accordance with ASC 980 related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At September 30, 2012 and 2011, the volumes of Electric Utility's forward electricity purchase contracts was 570.4 million kilowatt hours and 788.6 million kilowatt hours, respectively. At September 30, 2012, the maximum period over which these contracts extend is 20 months.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM 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. 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, pursuant to the January 22, 2009, settlement of its DS filing with the PUC, 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 4). Gains and losses associated with periods prior to January 1, 2010, are reflected in cost of sales. At September 30, 2012 and 2011, the volumes associated with Electric Utility FTRs totaled 189.7 million kilowatt hours and 208.6 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. The volumes of gasoline under these contracts 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 September 30, 2012 and 2011, the total notional amounts of our unsettled IRPA contracts was $173,000 and $173,000, respectively. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of long-term debt forecasted to occur in September 2013.

UGI Utilities reclassified pre-tax losses of $682 from AOCI into income during Fiscal 2012 as a result of the discontinuance of cash flow hedge accounting for a portion of expected interest payments associated with the issuance of long-term debt originally anticipated to occur in September 2012. Such losses are included in other income, net, in the Consolidated Statements of Income. The amounts of derivative gains and losses on cash flow hedges representing ineffectiveness were not material for all periods presented.

At September 30, 2012, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months based upon current fair values is $805.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2012, Gas Utility had no restricted cash in brokerage accounts. At September 30, 2011, Gas Utility’s restricted cash in brokerage accounts totaled $4,308.

The following table provides information regarding the balance sheet location and fair values of derivative assets and liabilities existing as of September 30, 2012 and 2011:

	Derivative Assets					Derivative Liabilities
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2012		2011		Location	2012		2011
Derivatives Designated as Hedging Instruments:
Interest rate contracts		$	—	$	—	Derivative financial instruments and Other noncurrent liabilities	$	30,522	$	18,585
Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments	5,303		41		Derivative financial instruments and Other noncurrent liabilities	9,437		11,736
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	165		27			—		—
Total Derivatives		$	5,468	$	68		$	39,959	$	30,321

During the years ended September 30, 2012 and 2011, the total amount of settled IRPA net losses included in AOCI that were reclassified into net income, were $1,164 and $1,164, respectively. During the years ended September 30, 2012 and 2011, the impact of changes in the fair value of FTRs and gasoline futures and swap contracts on our net income was not material.

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, contracts which provide for the purchase and delivery 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.