Note 5 — 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 4 in the Company’s 2016 Annual Report. Other than removal costs, UGI Utilities currently does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with UGI Utilities are included in the accompanying Condensed Consolidated Balance Sheets:



	June 30, 2017		September 30, 2016		June 30, 2016
Regulatory assets:
Income taxes recoverable	$	122,733	$	115,643	$	119,604
Underfunded pension and postretirement plans	171,833		183,129		133,356
Environmental costs	61,616		59,397		60,716
Deferred fuel and power costs	7,024		151		—
Removal costs, net	29,405		27,956		22,444
Other	6,136		8,865		9,180
Total regulatory assets	$	398,747	$	395,141	$	345,300
Regulatory liabilities:
Postretirement benefits	$	16,715	$	17,519	$	19,671
Deferred fuel and power refunds	12,587		22,299		34,432
State tax benefits — distribution system repairs	16,662		15,086		14,604
Other	2,706		665		1,149
Total regulatory liabilities (a)	$	48,670	$	55,569	$	69,856


(a)	Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “Other current liabilities” 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 (losses) gains on such contracts at June 30, 2017, September 30, 2016, and June 30, 2016, were $(73), $4,263 and $5,483, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At June 30, 2017, September 30, 2016, and June 30, 2016, all Electric Utility forward electricity purchase contracts were subject to the NPNS exception (see Note 10).

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, 2017, September 30, 2016, and June 30, 2016, were not material.

Base Rate Filings. On January 19, 2017, PNG filed a rate request with the PUC to increase PNG’s base operating revenues for residential, commercial and industrial customers by $21,700 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. PNG requested that the new gas rates become effective March 20, 2017. The PUC entered an Order dated February 9, 2017, suspending the effective date for the rate increase to allow for investigation and public hearings. On June 30, 2017, all active parties supported the filing of a Joint Petition for Approval of Settlement of all issues with the PUC. Under the terms of the Joint Petition, UGI Utilities will be permitted, effective October 20, 2017, to increase PNG’s annual base distribution rates by $11,250. On July 25, 2017, the PUC administrative law judge recommended that the settlement be adopted without modification. Although the Company expects to receive the final order from the PUC approving the settlement by October 2017, the Company cannot predict the timing or the ultimate outcome of the rate case review process.

On October 14, 2016, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for a $27,000 annual base distribution rate increase for UGI Gas. The increase became effective on October 19, 2016.

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 5% of distribution charges billed to customers.

PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014. 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 5% to 10% of billed distribution revenues. On May 10, 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at the Company’s Long-term Infrastructure Improvement Plan filing in 2018.

On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. Revenue collected pursuant to the mechanism will be subject to refund and recoupment based on the PUC’s final resolution of certain matters set aside for hearing before an administrative law judge. UGI Gas will be permitted to recover revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess of the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case. Achievement of that threshold is not likely to occur prior to September 30, 2017.