Note 6 — 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 9 in the Company’s 2015 Annual Report. UGI Utilities currently 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, 2016		September 30, 2015		June 30, 2015
Regulatory assets:
Income taxes recoverable	$	119.6	$	115.9	$	111.8
Underfunded pension and postretirement plans	133.4		140.8		103.2
Environmental costs (a)	60.7		20.0		14.5
Removal costs, net	22.4		21.2		19.6
Other	9.2		6.3		5.1
Total regulatory assets	$	345.3	$	304.2	$	254.2
Regulatory liabilities (b):
Postretirement benefits	$	19.7	$	20.0	$	19.6
Deferred fuel and power refunds	34.4		36.6		45.6
State tax benefits—distribution system repairs	14.6		13.3		10.9
Other	1.2		1.1		1.4
Total regulatory liabilities	$	69.9	$	71.0	$	77.5


(a)	Environmental costs at June 30, 2016, include amounts probable of recovery recorded in conjunction with UGI Gas’ Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (see Note 9).


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

Deferred fuel and power refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that 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 gains (losses) on such contracts at June 30, 2016, September 30, 2015 and June 30, 2015 were $5.5, $(3.3) and $(0.7), respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. For contracts entered into prior to March 1, 2015, we did not elect the NPNS exception under GAAP, and as a result, we recognize 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 DS costs. At September 30, 2015 and June 30, 2015, the fair values of Electric Utility’s electricity supply contracts not subject to NPNS were (losses) of $(0.5) and $(1.4), respectively. These amounts are reflected in current derivative instrument liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power refunds in the table above. At June 30, 2016, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception (see Note 12).

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 June 30, 2016, September 30, 2015, and June 30, 2015, were not material.

Preliminary Stage Information Technology Costs. During the second quarter of Fiscal 2016, we determined that certain preliminary project stage costs associated with an ongoing information technology project at UGI Utilities were probable of future recovery in rates in accordance with GAAP related to regulated entities. As a result, during the second quarter of Fiscal 2016, we capitalized $5.8 of such project costs ($5.4 of which had been expensed prior to Fiscal 2016) and recorded associated increases to utility property, plant and equipment ($2.7) and regulatory assets ($3.1). Subsequently, we continue to capitalize such preliminary stage project costs in accordance with GAAP related to regulated entities.

UGI Gas Base Rate Filing. On January 19, 2016, UGI Utilities filed a rate request with the PUC to increase UGI Gas’s annual base operating revenues for residential, commercial and industrial customers by $58.6. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. UGI Utilities requested that the new gas rates become effective March 19, 2016. The PUC entered an Order dated February 11, 2016, suspending the effective date for the rate increase to no later than October 19, 2016 to allow for investigation and public hearings. On June 30, 2016, a Joint Petition for Approval of Settlement of all issues supported by all active parties was filed with the PUC. Under the terms of the Joint Petition, UGI Utilities will be permitted, effective October 19, 2016, to increase UGI Gas' annual base distribution rates by $27.0. The Joint Petition is subject to receipt of a recommended decision by a PUC administrative law judge and an order of the PUC approving the settlement. The Company cannot predict the ultimate outcome of the rate case review process.

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 had not had a general rate filing within the required time period to be eligible. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from five percent to ten percent of billed distribution revenues. Also in March 2016, UGI Gas sought PUC approval to initiate a DSIC effective November 2017. To date, no action has been taken by the PUC on any of these petitions. The Company cannot predict the timing or outcome of these petitions. The impact of the DSIC charge at PNG and CPG did not have a material effect on Gas Utility results of operations.