Disclosures About Derivative Instruments and Hedging Activities

9 Months Ended

Jun. 30, 2011

Disclosures About Derivative Instruments and Hedging Activities [Abstract]

Disclosures About Derivative Instruments and Hedging Activities

12. 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. 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. Gains and losses on Gas Utility 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 ASC No. 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 5).

Beginning January 1, 2010, Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. 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 under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At June 30, 2011, the fair values of Electric Utility’s forward purchase power agreements comprising a loss of $10,082 are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the Condensed Consolidated Balance Sheet. In accordance with ASC 980 related to rate regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets on the June 30, 2011 Condensed Consolidated Balance Sheet.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs associated with certain default service customers, 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, 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 relating to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 6). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At June 30, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 287.3 million kilowatt hours and 739.3 million kilowatt hours, respectively. The maximum period which we are currently hedging FTRs is 11 months.

At June 30, 2011, the volume of natural gas associated with our unsettled NYMEX natural gas futures and option contracts totaled 18.6 million dekatherms and the maximum period over which we are currently hedging natural gas futures and option contracts is 16 months. At June 30, 2010, the volume of natural gas associated with unsettled NYMEX natural gas futures contracts and option contracts totaled 11.3 million dekatherms. At June 30, 2011, the volume of electricity under Electric Utility’s forward electricity purchase contracts was 874.4 million kilowatt hours and the maximum period over which these contracts extend is 35 months.

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 accumulated other comprehensive income (“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 June 30, 2011, the total notional amount of our unsettled IRPA contracts was $173,000. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of long-term debt forecasted to occur in September 2012 and September 2013. There were no unsettled IPRA contracts outstanding at June 30, 2010.

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. At such time, gains and losses are recorded in interest expense. At June 30, 2011, the amount of net losses associated with previously settled IRPAs expected to be reclassified into earnings during the next twelve months is $1,165.

Derivative Financial Instrument Credit Risk

Our natural gas exchange-traded futures and options contracts are guaranteed by the NYMEX and have limited credit risk. These contracts generally require cash deposits in margin accounts. At June 30, 2011 and 2010, restricted cash in margin accounts totaled $4,055 and $3,639, respectively. We generally do not have credit-risk-related contingent features in our derivative contracts.

The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2011 and 2010:

As of June 30:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value				Balance Sheet	Fair Value
	Location	2011		2010		Location	2011			2010
Derivatives Designated as Hedging Instruments:
Interest rate contracts	Other assets	$	5,047	$	—
Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments		201		287	Derivative financial instruments and Other noncurrent liabilities	$	(11,132	)	$	(828	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments		128		325
Total Derivatives		$	5,376	$	612		$	(11,132	)	$	(828	)

There amounts of derivative gains or losses representing ineffectiveness were not material in the three or nine months ended June 30, 2011 and 2010. During the three and nine months ended June 30, 2011 and 2010, the amounts of IRPA net losses included in AOCI that were reclassified into net income were not material. Additionally, during nine months ended June 30, 2010, the impact on net income from changes in the fair value of FTRs not accounted for under ASC 980 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.