Generic Proceeding – Regulated Rate Tariff – Energy Price Setting
Direct Energy Regulated Services (“DERS”), ENMAX Energy Corporation (“EEC”) and EPCOR Energy Alberta GP Inc. (“EEA”) applied for 2014-2018 energy price setting plans (“EPSP”) for their respective regulated rate tariffs (“RRT”). Each of DERS, EEC and EEA are regulated rate option (“RRO”) providers. RRO providers are required to file monthly energy rates with the AUC, and as determined under the sections 103 and 104 of the Electric Utilities Act and the Regulated Rate Option Regulation. The RRO is required to be made available to customers within a service area as an alternative to purchasing electricity services from a retailer.
DERS, EEC and EEA all applied for a pre-tax reasonable return amount of $8.21 per megawatt hour (MWh) for the duration of the EPSP. The AUC denied this request, finding instead that the following all-inclusive after-tax return amounts were reasonable:
(a) $2.83/MWh for DERS;
(b) $2.44/MWh for EEC; and
(c) $2.51/MWh for EEA.
The AUC directed all three companies to file information setting the amount of return that is currently being collected through non-energy charges, and to express those as $/MWh amounts.
With respect to EPSP, DERS made the following requests and on which the AUC made the following findings:
(a) DERS applied to continue the use of block procurement through forward market hedge products. The AUC held that this was a reasonable proposal;
(b) DERS applied to have daily target prices for the forward market hedge products be set by an independent market consultant. The AUC denied this request and directed DERS to set the daily target prices;
(c) DERS applied to set hedge volume targets at the average load requirements. The AUC rejected this proposal, and directed DERS to file an analysis that justifies its hedge volume targets;
(d) DERS proposed no backstop and no self-supply. The AUC accepted the proposal for self-supply, but directed DERS to include a backstop provision in its EPSP;
(e) DERS applied to set the base energy charge using the weighted average price of its forward market hedges during the price setting period, and to gross up the base energy charge for any distribution line losses and unaccounted for energy. The AUC accepted these proposals; and
(f) DERS applied for 50 per cent of cost savings for any daily procurement below the daily target price to be for the credit of DERS. The AUC denied this proposal.
EEA made the following requests and on which the AUC made the following findings, for EEA’s EPSP:
(a) EEA applied to acquire blocks of forward market hedge products through a series of six Natural Gas Exchange (NGX) auctions (plus one contingency auction) over the 120-day allowable price setting window. EEA also applied for seed prices for the NGX auctions to be determined on a confidential basis. The AUC accepted EEA’s proposals;
(b) EEA proposed to retain a backstop supplier, and include the retainer cost as part of the monthly energy charge. The AUC denied this request, and directed EEA to include a different backstop mechanism; and
(c) EEA applied to set the base energy charge using the weighted average price of its forward market hedges during the price setting period, and to gross up the base energy charge for any distribution line losses and unaccounted for energy. The AUC accepted these proposals.
EEC applied to separate the pricing and procurements aspects in its EPSP application. EEC proposed to determine the base energy charge using the NGS Flat RRO 120 Index price, grossed up for any distribution line losses and unaccounted for energy. EEC proposed to manage its procurement entirely at the discretion of EEC’s unregulated trading affiliate, EEC Wholesale Trading. The AUC denied EEC’s proposed EPSP and directed EEC to file a new EPSP proposal.
With respect to risk compensation, DERS and EEA applied for commodity risk compensation (“CRC”) based on a rolling weighted average historical systematic gains and losses over a 12-month period (with DERS proposing an addition of one standard deviation for volatility, and EEA proposing a fixed addition of 4.14 percent.) The AUC denied the request, and directed DERS to adopt an adaptive CRC methodology proposed by the Office of the Utilities Consumer Advocate (“UCA”) which uses the same rolling weighted average, plus a fixed risk cycle component that is adjusted on a yearly basis.
DERS and EEA requested approval of other risk compensation (“ORC”) in five areas: counterparty credit risk; billing error risk; customer class risk; recurring cost forecasting risk; and other administrative risk. The total ORC requested by DERS and EEA was $0.43/MWh and $0.80/MWh respectively. The AUC denied DERS’ ORC requests in all areas. With respect to EEA’s ORC requests, the AUC denied all areas except for recurring cost forecast risk, which the AUC approved $0.07/MWh.
EEC applied for risk compensation for risk associated with load shape, and for the risk associated with residual forecasting of load. EEC proposed an auction process to price the load shape risk, and applied to set the residual forecasting risk compensation at 1.30 percent of the cost of average load. The AUC denied both proposals and directed EEC to file a new EPSP proposal.
Both EEA and DERS applied to have the EPSP term expire on April 30, 2018, which the AUC accepted as reasonable.
The AUC accordingly ordered filings for each of DERS, EEC and EEA as follows:
(a) DERS and EEA must file a compliance filing on or before April 13, 2015; and
(b) EEC must file a new proposal for its 2014-2018 EPSP on or before April 13, 2015.
