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Utility Regulatory Assets and Liabilities and Regulatory Matters | 6 Months Ended
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Mar. 31, 2017
Regulated Operations [Abstract] |
Utility Regulatory Assets and Liabilities and Regulatory Matters | 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 8 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 our accompanying Condensed Consolidated Balance Sheets:
|  | March 31, 2017 |  | September 30, 2016 |  | March 31, 2016
Regulatory assets: |  |  |  |  |  |
Income taxes recoverable |  | $ | 120.3 |  |  | $ | 115.7 |  |  | $ | 118.2 |
Underfunded pension and postretirement plans |  | 175.6 |  |  | 183.1 |  |  | 135.8 |
Environmental costs |  | 62.2 |  |  | 59.4 |  |  | 60.5 |
Deferred fuel and power costs |  | 1.3 |  |  | 0.1 |  |  | — |
Removal costs, net |  | 28.8 |  |  | 27.9 |  |  | 25.0 |
Other |  | 6.5 |  |  | 8.9 |  |  | 8.7 |
Total regulatory assets |  | $ | 394.7 |  |  | $ | 395.1 |  |  | $ | 348.2 |
Regulatory liabilities (a): |  |  |  |  |  |
Postretirement benefits |  | $ | 17.0 |  |  | $ | 17.5 |  |  | $ | 19.3 |
Deferred fuel and power refunds |  | 13.8 |  |  | 22.3 |  |  | 30.8 |
State tax benefits — distribution system repairs |  | 16.1 |  |  | 15.1 |  |  | 14.2 |
Other |  | 3.6 |  |  | 0.7 |  |  | 2.5 |
Total regulatory liabilities |  | $ | 50.5 |  |  | $ | 55.6 |  |  | $ | 66.8 |
(a) | Regulatory liabilities 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 gains (losses) on such contracts at March 31, 2017, September 30, 2016 and March 31, 2016 were $2.0, $4.3 and $(1.9), respectively. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At March 31, 2017, September 30, 2016 and March 31, 2016, substantially 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 March 31, 2017, September 30, 2016, and March 31, 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 $21.7 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. Unless a settlement is reached sooner, this review process is expected to last up to nine months from the date of filing; however, 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 $27.0 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 April 20, 2017, the PUC voted 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 the issuance of a final order of the PUC. On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism 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.

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