Utility Regulatory Assets and Liabilities and Regulatory Matters

The following regulatory assets and liabilities associated with Utilities are included in our accompanying Consolidated Balance Sheets at September 30:



	2015		2014
Regulatory assets:
Income taxes recoverable	$	115.9	$	110.7
Underfunded pension and postretirement plans	140.8		110.1
Environmental costs	20.0		14.6
Deferred fuel and power costs	—		11.8
Removal costs, net	21.2		16.8
Other	6.3		4.2
Total regulatory assets	$	304.2	$	268.2
Regulatory liabilities (a):
Postretirement benefits	$	20.0	$	18.6
Environmental overcollections	—		0.3
Deferred fuel and power refunds	36.6		0.3
State tax benefits — distribution system repairs	13.3		10.1
Other	1.1		3.2
Total regulatory liabilities	$	71.0	$	32.5

(a) Regulatory liabilities are recorded in other current and other noncurrent liabilities in the Consolidated Balance Sheets.

Income taxes recoverable. This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of the tax benefit on accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 65 years.

Underfunded pension and other postretirement plans. This regulatory asset represents the portion of prior service cost and net actuarial losses associated with pension and other postretirement benefits which are 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. These costs are amortized over the average remaining future service lives of plan participants.

Environmental costs. Environmental costs represent amounts actually spent by UGI Gas to clean up sites in Pennsylvania as well as the portion of estimated probable future environmental remediation and investigation costs principally at manufactured gas plant (“MGP”) sites that CPG and PNG expect to incur in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (see Note 16). Consistent with prior ratemaking treatment, UGI Gas anticipates it will recover in rates, through future base rate proceedings, a five-year average of prudently incurred remediation costs at Pennsylvania sites and UGI Gas is currently amortizing such costs over a five-year period. PNG and CPG are currently recovering and expect to continue to recover environmental remediation and investigation costs in base rate revenues. At September 30, 2015, the period over which PNG and CPG expect to recover these costs will depend upon future remediation activity.

Deferred fuel and power — costs and refunds. Gas Utility’s and Electric Utility’s 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”) tariffs 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 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 instruments are included in deferred fuel costs or refunds. Net unrealized losses on such contracts at September 30, 2015 and 2014 were $3.3 and $1.4, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Prior to March 1, 2015, we did not designate these purchase contracts as NPNS under GAAP. Therefore, we recognized the fair value of these contracts on the balance sheet with an associated adjustment to regulatory assets or liabilities because Electric Utility is entitled to fully recover its prudently incurred DS costs. At September 30, 2015 and 2014, the fair values of Electric Utility’s electricity supply contracts were (losses) gains of $(0.5) and $0.3, respectively. These amounts are reflected in current and noncurrent derivative assets and current and noncurrent derivative liabilities on the Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs and refunds in the table above. 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 (see Note 18).

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 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, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at September 30, 2015 and 2014, were not material.

Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. Consistent with prior ratemaking treatment, UGI Utilities expects to recover these costs over 5 years.

Postretirement benefits. Gas Utility and Electric Utility are recovering ongoing postretirement benefit costs at amounts permitted by the PUC in prior base rate proceedings. With respect to UGI Gas and Electric Utility, the difference between the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits are being deferred for future refund to or recovery from ratepayers. Such amounts are reflected in regulatory liabilities in the table above. In addition, this regulatory liability includes the portion of prior service credits and net actuarial gains associated with certain other postretirement benefit plans.

Environmental overcollections. This regulatory liability represents the difference between amounts recovered in rates and actual costs incurred (net of insurance proceeds) associated with the terms of a consent order agreement between CPG and the Pennsylvania Department of Environmental Protection (“DEP”) to remediate certain gas plant sites.

State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal income tax expense, resulting from the deduction for income tax purposes of repair and maintenance costs associated with Gas Utility or Electric Utility assets which are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.

Other. Other regulatory assets comprise a number of items including, among others, deferred postretirement costs, deferred asset retirement costs, deferred rate case expenses and customer choice implementation costs. At September 30, 2015, UGI Utilities expects to recover these costs over periods of approximately 1 to 20 years.

UGI Utilities does not recover a rate of return on its regulatory assets.

Other Regulatory Matters

Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at five percent of the amount billed to customers. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014, while UGI Gas has not had a general rate filing within the required time period to be eligible. Beginning on April 1, 2015, PNG was able to begin charging a DSIC at a rate other than zero. The impact of the DSIC charge at PNG did not have a material effect on Gas Utility results of operations.