Utility Regulatory Assets and Liabilities and Regulatory Matters

9 Months Ended

Jun. 30, 2011

Utility Regulatory Assets and Liabilities and Regulatory Matters [Abstract]

Utility Regulatory Assets and Liabilities and Regulatory Matters

7. Utility Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 8 to the Company’s 2010 Annual Financial Statements and Notes. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:

	June 30,		September 30,		June 30,
	2011		2010		2010
Regulatory assets:
Income taxes recoverable	$	92.7	$	82.5	$	95.3
Underfunded pension and postretirement plans		116.0		159.2		10.3
Environmental costs		20.7		22.6		24.3
Deferred fuel and power costs		7.8		36.6		6.3
Other		8.9		5.8		5.5
Total regulatory assets	$	246.1	$	306.7	$	141.7
Regulatory liabilities:
Postretirement benefits	$	11.6	$	10.5	$	10.3
Environmental overcollections		6.2		7.2		8.3
Deferred fuel and power refunds		22.4		8.3		16.6
State tax benefits — distribution system repairs		6.2		6.7		11.0
Total regulatory liabilities	$	46.4	$	32.7	$	46.2

Underfunded pension and postretirement plans. This regulatory asset represents the portion of prior service cost and net actuarial losses associated with pension and postretirement benefits which is probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP relating to accounting for retirement benefits. These costs are amortized over the average remaining future service lives of the plan participants.

Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were required to remeasure the merged plan’s assets and benefit obligations as of December 31, 2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other things, the remeasurement resulted in a decrease in regulatory assets of $43.1 (see Note 8).

Deferred fuel and power — costs and refunds. Gas Utility’s tariffs, and commencing January 1, 2010 Electric Utility’s default service tariffs, contain clauses which permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) rates in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

Gas Utility uses derivative financial instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Unrealized losses on such contracts at June 30, 2011, September 30, 2010 and June 30, 2010 were $1.1, $1.4 and $0.6, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. As more fully described in Note 13, 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. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value, with an associated adjustment to regulatory assets or liabilities in accordance with GAAP relating to rate-regulated entities and Electric Utility’s DS procurement, implementation and contingency plans. At June 30, 2011 and September 30, 2010, the fair values of Electric Utility’s electricity supply contracts were losses of $10.1 and $19.7, respectively, which amounts are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010 through DS rates, realized and unrealized gains or losses on FTRs associated with periods beginning January 1, 2010 are included in deferred fuel and power — costs or refunds. Unrealized gains on FTRs at June 30, 2011, September 30, 2010 and June 30, 2010 were not material.

Other Regulatory Matters

Transfer of CPG Storage Assets. On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of Energy Services. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011 the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets was $10.9. Compliance with the provisions of the PUC Order approving the transfer of the storage assets is not expected to have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.

CPG Base Rate Filing. On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16.5 annually. Among other things, the increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). CPG requested that the new gas rates become effective March 15, 2011. The PUC entered an Order dated March 17, 2011, suspending the effective date for the rate increase to allow for investigation and public hearing. On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. Under the terms of the Joint Petition, CPG will be permitted to increase distribution rates by $8.0 in additional base rate revenue as well as $0.9 in revenues per year for use in CPG’s Energy and Efficiency Conservation Program. On July 19, 2011, a recommended decision was issued by the two assigned administrative law judges (“ALJs”) who recommended that the PUC approve the Joint Petition without modification. The recommended decision of the ALJs is subject to PUC approval. It is anticipated that this process will conclude by the end of Fiscal 2011.